Time for a clean energy bank

By Roanoke Times


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President Obama's decision to drastically slash the budget of the Yucca Mountain repository project in Nevada has cast the Nuclear Waste Fund in an entirely different light. Since 1983, Virginians have paid $672 million into the federal fund, which was created to finance the project.

This is not small change, though it might seem so at a time of huge federal bailouts of banks. Nationally, payments to the Nuclear Waste Fund have reached $24 billion, though less than $10 billion of that amount has actually been spent on the project. The rest of the money has gone into the U.S. Treasury to help balance the federal budget.

Each year the fund collects about $750 million, paid by utilities but based on a ratepayer fee of one-tenth of a cent for each kilowatt-hour of nuclear-generated electricity. The fee is part of everyone's monthly electricity bill.

Now might be the time to scale back payments.

Although the Department of Energy will need some money for nuclear waste management, it's nowhere near the level that was anticipated in the early 1980s. It was back then that Congress approved legislation requiring the Energy Department to take possession of used nuclear fuel beginning in 1998. That deadline passed but nothing was done.

Today the used fuel — more than 57,000 metric tons — is stored at nuclear power plant sites around the country. It is safe and secure, and there's no reason why it can't be kept in concrete-and-steel dry casks at the plant sites for many decades.

Often mistaken for nuclear waste, the used fuel should be transported to several regional sites for interim storage. But still in need of resolution is the question of reuse: 95 percent of the energy from the original nuclear fuel remains in the used fuel.

Other countries, such as France and Japan, reprocess used fuel so that valuable plutonium and uranium can be chemically converted into mixed-oxide fuel and used in a reactor to produce more electricity. The United States needs to develop an affordable and proliferation-proof method for reprocessing used fuel.

Reprocessing not only extends global uranium resources but cuts down significantly on the volume, heat and toxicity of nuclear waste. With reprocessing, one repository would be needed to hold the remaining waste, not multiple repositories. This would benefit consumers.

Meanwhile, nothing should be allowed to get in the way of maintaining nuclear power as part of the nation's portfolio of energy sources.

Solar and wind energy can't provide large amounts of "base-load" electricity that's needed around the clock, day after day. But U.S. nuclear power plants now have average capacity factors — a measure of reliability — that exceed 90 percent. The performance over the past decade of both the Surry and Lake Anna nuclear plants in Virginia has been outstanding.

Because nuclear plants don't pollute the air or emit greenhouse gases, no time should be lost in proceeding with the licensing and construction of new reactors. Currently, electricity companies have submitted applications for combined construction and operating licenses for 17 new nuclear plants, and another seven applications are expected by the end of this year.

Obtaining the necessary financing to build nuclear plants is the challenge.

It is very difficult for electricity companies to come up with the money unless they can get government assistance in the form of loan guarantees. Congress has authorized such loan guarantees for clean energy projects, but most of the assistance is going to solar and wind energy.

Now is the time for Congress to pass legislation establishing a clean energy bank to provide loan guarantees for new nuclear plants. But first it should scale back payments to the Nuclear Waste Fund.

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China's nuclear energy on steady development track, say experts

China Nuclear Power Expansion accelerates with reactor approvals, Hualong One and CAP1400 deployments, rising gigawatts, clean energy targets, carbon neutrality goals, and grid reliability benefits to meet coastal demand and reduce emissions.

 

Key Points

An accelerated reactor buildout to add clean capacity, curb emissions, and improve grid reliability nationwide.

✅ Approvals surge for Hualong One and CAP1400 third-gen reactors

✅ Capacity targets approach 100 GW installed by 2030

✅ Supports carbon neutrality, energy security, and lower costs

 

While China has failed to accomplish its 2020 nuclear target of 58 gigawatts under operation and 30 GW under construction, insiders are optimistic about prospects for the nonpolluting energy resource in China over the next five years as the country has stepped up nuclear approvals and construction since 2020.

China expects to record 49 operating nuclear facilities and capacity of more than 51 GW as of the end of 2020. Nuclear power currently makes up around 2.4 percent of the country's total installed energy capacity, said the China Nuclear Energy Association. There are 19 facilities that have received approval and are under construction, with capacity exceeding 20 GW, ranking top globally as nuclear project milestones worldwide continue, it said.

"With surging power demand from coastal regions, more domestic technology, including next-gen nuclear, will be adopted with installations likely nearing 100 GW by the end of 2030," said Wei Hanyang, a power market analyst at Bloomberg New Energy.

Following the Fukushima nuclear reactor disaster in 2011 in Japan, China has, like many countries including Japan, Germany and Switzerland, suspended nuclear power project approvals for a period, including construction of the pilot project of Shidaowan nuclear power plant in Shandong province that uses CAP1400 technology, based on third-generation Westinghouse AP1000 reactor technology.

As China promotes greener development and prioritizes safety and security of nuclear power plant construction, it has pledged to hit peak emissions before 2030 and achieve carbon neutrality by 2060, with electricity meeting 60% of energy use by 2060 according to Shell, the Shidaowan plant, originally scheduled to launch construction in 2014 and enter service in 2018, is expected to start fuel loading and begin operations this year.

Joseph Jacobelli, an independent energy analyst and executive vice-president for Asia business at Cenfura Ltd, a smart energy services company, said recent developments confirm China's ongoing commitment to further boost the country's nuclear sector.

"The nuclear plants can help meet China's goal of reducing greenhouse gas emissions as the country reduces coal power production and provide air pollution-free energy at a lower cost to consumers. China's need for clean energy means that nuclear power generation definitely has an important place in the long-term energy mix," Jacobelli said.

He added that Chinese companies' cost control capabilities and technological advancements, and operational performance improvements such as the AP1000 refueling outage record, are also likely to continue providing domestic companies with advantages, as the cost per kilowatt-hour is very important, especially as solar, wind and other clean energy solutions become even cheaper over the next few years.

China approved two nuclear projects in 2020- Hainan Changjiang nuclear power plant unit 2 and Zhejiang San'ao nuclear power plant unit 1. This is after the country launched three new nuclear power plants in 2019 in the provinces of Shandong, Fujian and Guangdong, which marked the end of a moratorium on new projects.

The Zhejiang San'ao nuclear power plant saw concrete poured for unit 1 on Dec 31, according to its operator China General Nuclear. It will be the first of six Hualong One pressurized water reactors to be built at the site as well as the first Chinese nuclear power plant project to involve private capital.

Jointly invested, constructed and operated by CGN, Zheneng Electric Power, Wenzhou Nuclear Energy Development, Cangnan County Haixi Construction Development and Geely Maijie Investment, the project creates a new model of mixed ownership of nuclear power enterprises, said CGN.

The world's first Hualong One reactor at unit 5 of China National Nuclear Corp's Fuqing nuclear plant in Fujian province was connected to the grid in November. With the start of work on San'ao unit 1, China now has further seven Hualong One units under construction, including Fuqing 6, which is scheduled to go online this year.

CNNC is also constructing one unit at Taipingling in Guangdong and two at Zhangzhou in Fujian province. CGN is building two at its Fangchenggang site in Guangxi Zhuang autonomous region. In addition, two Hualong One units are under construction at Karachi in Pakistan, while CGN proposes to use a UK version of the Hualong One at Bradwell in the United Kingdom, aligning with the country's green industrial revolution strategy.

 

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Cheaper electricity rate for customers on First Nations not allowed, Manitoba appeal court rules

Manitoba Hydro Court Ruling affirms the Public Utilities Board exceeded its jurisdiction by ordering a First Nations rate class, overturning an electricity rates appeal tied to geography, poverty, and regulatory authority in Manitoba.

 

Key Points

A decision holding the PUB lacked authority to create a First Nations rate class, restoring uniform electricity pricing.

✅ Court says PUB exceeded jurisdiction creating on-reserve rate

✅ Equalized electricity pricing reaffirmed across Manitoba

✅ Geography, not poverty, found decisive in unlawful rate class

 

Manitoba Hydro was wrongly forced to create a new rate class for electricity customers living on First Nations, the Manitoba Court of Appeal has ruled. 

The court decided the Public Utilities Board "exceeded its jurisdiction" by mandating Indigenous customers on First Nations could have a different electricity rate from other Manitobans. 

The board made the order in 2018, which exempted those customers from the general rate increase that year of 3.6 per cent.

"The directive constituted the creation and implementation of general social policy, an area outside of the PUB's jurisdiction and encroaching into areas that are better suited to the federal and provincial government," says the decision, which was released Tuesday.

Hydro's appeal of the PUB's decision went to court earlier this year.

At the time, the Crown corporation acknowledged many Indigenous people on First Nations live in poverty, but it argued the Public Utilities Board was overstepping its authority in trying to address the issue by creating a new rate class.

It also argued it was against provincial law to charge different rates in different areas of the province.

The PUB, however, insisted that legislation gives it the right to decide which factors are relevant when considering electricity prices, such as social issues. 

Special Manitoba Hydro rate class needed to offset challenges of living on First Nations, appeal court hears
Manitoba Hydro can appeal order to create special First Nation rate
The board had heard evidence that some customers were making "unacceptable" sacrifices to keep the lights on each month.

Decision 'heavy-handed': AMC
The Assembly of Manitoba Chiefs, an intervener in the appeal, had backed the utility board's position. It said on-reserve customers are disproportionately vulnerable to rate hikes over time.

Grand Chief Arlen Dumas said Wednesday he was surprised by the court's ruling. 

He argued Indigenous people are unduly excluded in the setting of electricity rates in Manitoba.

"I will be speaking with my federal and provincial counterparts on how we deal with this issue, because I think it's the wrong [decision]. It's heavy-handed and we need to address it."

The appeal court judges said there is past precedent for setting equal electricity rates, regardless of where customers live. Legislation to that effect was made in the early 2000s and a few years ago, the PUB recognized that geographical limitations should not be imposed on a class of customers.

Since the board's new order didn't extend the same savings to First Nations members who don't live on reserve but face similar financial circumstances, it is clear the deciding factor was geography, rather than poverty or treaty status, the judges said.

Manitoba Hydro temporarily cutting 200 jobs, many of them front-line workers
"In my view, the PUB erred in law when it created an on-reserve class based solely on a geographic region of the province in which customers are located," the decision read.

While Manitoba Hydro objected to the PUB's order in 2018, it still devoted money to create the new customer class.

Spokesperson Bruce Owen said the utility is still studying the impact of the court's decision, but it appreciates the ruling.  

"We all recognize that many people on First Nations have challenges, but our argument was solely on whether or not the PUB had the authority to create a special rate class based on where people live."

Owen added that Hydro recognizes electricity rates can be a hardship on individuals facing poverty. He said those considerations are part of the discussions the corporation has with the utilities board.

 

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US Electricity Market Reforms could save Consumers $7bn

PJM and MISO Electricity-Market Reforms promise consumer savings by enabling renewables, wind, solar, and storage participation in wholesale markets, enhancing grid flexibility, reliability services, and real-time pricing across the Midwest, Great Lakes, and Mid-Atlantic.

 

Key Points

Market rule updates enabling renewables and storage, improving reliability and lowering consumer costs.

✅ Removes barriers to renewables, storage, demand response

✅ Improves intermarket links and real-time price signals

✅ Rewards flexible resources and reliability services

 

Electricity-market reforms to enable more renewables generation and storage in the Midwest, Great Lakes, and Mid-Atlantic could save consumers in the US and Canada more than $6.9 billion a year, according to a new report.

The findings may have major implications for consumer groups, large industrial companies, businesses, and homeowners in those regions, said the Wind-Solar Alliance, (WSA), which commissioned the Customer Focused and Clean report.

The WSA is a non-profit organisation supporting the growth of renewables. American Wind Energy Association CEO Tom Kiernan is listed as WSA secretary, amid ongoing debates about the US wind market today.

"Consumers are looking for clean energy, affordable and reliable energy that will keep their monthly electricity bills low," said Kristin Munsch, president of the Board of the Consumer Advocates of the PJM States, which represents over 65 million consumers in 13 states.

"There is great potential to achieve those goals with the cost-effective integration of wind, solar and battery storage plants into our wholesale power markets."

The report found the average residential customer in the PJM and Midcontinent Independent System Operator (MISO) regions, covering 29 US states and the Canadian province of Manitoba, could each save up to $48 a year as lower wholesale electricity prices materialize with significantly more wind, solar and storage on the grid.

The average annual home electricity, for example in New Jersey, in the PJM region, was just over $106 in 2018, according to the US Energy Information Administration.

The latest report quantifies the findings of a previous one for the WSA, published in November 2018, which found that outdated wholesale market rules in the US were preventing full participation by renewable energy, including wind power.

 

Outdated rules

"The existing wholesale power market rules were largely developed for slower-to-react conventional generators, such as coal and nuclear plants," said Michael Milligan, president of Milligan Grid Solutions and co-author of the new report.

"This report demonstrates the benefits of updating the rules to better accommodate the characteristics and potential contributions of wind and solar and other newer sources of low-cost generation."

With more renewables generation on the grid, customers would benefit the most from increasing power-system flexibility through market structures, the new report concluded. It called for the removal of artificial barriers preventing renewables, storage and demand response from participating in markets.

The report also advocated improving the connections between markets, thereby lowering transaction costs of imports and exports between neighbouring systems.

"There are currently artificial barriers that are preventing the full participation of renewables, storage and other new technologies in the PJM and MISO markets," said Michael Goggin, vice president of Grid Strategies and co-author of the report.

"Providing consumers with a real-time price signal that allows them to adjust their demand, rewarding flexible resources for their capabilities through improved market design, and allowing renewable and storage resources to participate in reliability-services markets would yield the greatest consumer benefits," he said.

PJM and MISO, which incorporate some of the windiest areas of the country, are currently reviewing their market designs as part of a broader grid overhaul underway.

 

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Idaho Power Settlement Could Close Coal Plant, Raise Rates

Idaho Power Valmy Settlement outlines early closure of the North Valmy coal-fired plant in Nevada, accelerated depreciation recovery, a 1.17% base-rate increase, and impacts for customers, NV Energy co-ownership, and Idaho Public Utilities Commission review.

 

Key Points

A proposed agreement to close North Valmy early, recover costs via a 1.17% rate hike, and seek PUC approval.

✅ Unit 1 closes 2019; Unit 2 closes 2025 in Nevada.

✅ 1.17% base-rate hike; about $1.20 per 1,000 kWh monthly bill.

✅ Idaho PUC comment deadline May 25; NV Energy co-owner.

 

State regulators have set a May 25 deadline for public comment on a proposed settlement related to the early closure of a coal-fired plant co-owned by Idaho Power, even as some utilities plan to keep a U.S. coal plant running indefinitely in other jurisdictions.

The settlement calls for shuttering Unit 1 of the North Valmy Power Plant in Nevada in 2019, with Unit 2 closing in 2025, amid regional coal unit retirements debates. The units had been slated for closure in 2031 and 2035, respectively.

If approved by the Idaho Public Utilities Commission, the settlement would increase base rates by approximately $13.3 million, or 1.17 percent, in order to allow the company to recover its investment in the plant on an accelerated basis.

That equates to an additional $1.20 on the monthly bill of the typical residential customer using 1,000 kilowatt-hours of energy per month.

Idaho Power, which co-owns the plant with NV Energy, maintains that closing Valmy early rather than continuing to operate it until it is fully depreciated in 2035, will ultimately save customers $103 million in today's dollars.

The company said a significant decrease in market prices for electricity has made it uneconomic to operate the plant except during extremely cold or hot weather, when the demand for energy peaks, a trend underscored by transactions involving the San Juan Generating Station deal elsewhere. The company also said plant balances have increased by approximately $70 million since its last general rate case in 2011, due to routine maintenance and repairs, as well as investments required to meet environmental regulations.

The proposed settlement reflects a number of changes to Idaho Power's original proposal regarding Valmy, and comes in the wake of discussions with interested parties in February and April, against the backdrop of a broader energy debate over plant closures and reliability.

In its initial application, filed in October, Idaho Power proposed closing both units in 2025. The original proposal would have increased base rates by $28.5 million, or about 2.5 percent, in order to allow the company to recover its costs associated with the plant's accelerated depreciation, decommissioning and anticipated investments, with cautionary examples such as the Kemper power plant costs illustrating potential risks.

Concurrently, Idaho Power asked for commission approval to adjust depreciation rates for its other plants and equipment based on the result of a study it conducts every five years, as outlined in Case IPC-E-16-23. The adjustment would have led to a $6.7 million increase to base rates.

The two requests filed in October would have increased customer costs by a total of $35.2 million or 3.1 percent, leading to a $3.08 increase on the bills of the typical residential customer who uses 1,000 kilowatt-hours per month.

The proposed settlement submitted to the Commission on May 4 calls for $13,285,285 to be recovered from all customer classes through base rates until 2028, all related to the Valmy shutdown. That is an increase of 1.17 percent and would result in a $1.20 increase on the bills of the typical residential customer who uses 1,000 kilowatt-hours per month.

 

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Secret Liberal cabinet document reveals Electricity prices to soar

Ontario Hydro Rate Relief Plan delivers short-term electricity bill cuts, while leaked cabinet forecasts show inflation-linked hikes, borrowing costs, and a Clean Energy Adjustment under the province's long-term energy plan.

 

Key Points

A provincial plan that cuts bills now but defers costs, projecting rate hikes and adding a Clean Energy Adjustment.

✅ 25% cut now, after 8% HST relief; extra 17% reduction applied.

✅ Forecast: inflation-linked hikes later; borrowing adds long-term costs.

✅ Clean Energy Adjustment line to repay deferred system costs.

 

The short-term gain of a 25 per cent hydro rate cut this summer could lead to long-term pain as a leaked cabinet document forecasts prices jumping again in five years.

In the briefing materials leaked and obtained by the Progressive Conservatives, rates will start rising 6.5 per cent a year in 2022 and top out at 10.5 per cent in 2028, when average monthly bills hit $215.

That would be up from $123 this year once the rate cut — the subject of long-awaited legislation to lower electricity rates unveiled Thursday by Energy Minister Glenn Thibeault — takes full effect. There will be another 17-per-cent cut in addition to the 8 per cent taken off bills in January when the provincial portion of the HST was waived.

The leaked papers overshadowed Thibeault’s efforts to tout the price break, which will be followed with four years of hydro rate increases at 2 per cent, roughly the rate of inflation.

Thibeault charged that the Conservatives used an “outdated” document to distract from the fact that they are the only major party without a plan for dealing with skyrocketing hydro rates, with a year to go until next June’s provincial election.

“It’s not a coincidence,” he told reporters, denying any plans for an eventual 10.5-per-cent rate hike and promising the government’s new long-term energy plan, due in a few months, will have better numbers.

“We are working hard right now to continue to pull costs out of the system.”

Opposition parties said the Liberal plan doesn’t deal with the underlying problems that have made electricity expensive and simply borrows money to spread the costs over a longer period of time, with $25 billion in interest charges over 30 years.

Some observers also noted that a deal with Quebec would not reduce hydro bills, highlighting concerns about lasting affordability.

“The price of electricity is going to skyrocket after the next election,” warned Conservative MPP Todd Smith (Prince Edward—Hastings).

“The government isn’t being honest with the people of Ontario when it comes to the price of electricity.”

The documents show average monthly bills peaking at $231 in the year 2047, before falling back to $210 the following year once the 30 years of interest payments are over.

Conservative sources say they obtained the papers stamped “confidential cabinet document” from a whistleblower after Thibeault’s rate cut plan was presented to cabinet ministers at a meeting in early March.

There is no date on the document, which the energy minister alternately dismissed as “inaccurate” or possibly one of many that have been prepared with different options in mind.

“We’ve had hundreds of briefings with hundreds of documents … I can’t comment on one graph when we’ve been looking at hundreds of scenarios.”

New Democrats, who have proposed a scheme to cut rates, if elected, also called the government plan an election ploy with Liberals lagging in the polls.

“We’re going to take on a huge debt so (Premier) Kathleen Wynne can look good on the hustings in the next few months, and for decades we’re going to pay for it,” said MPP Peter Tabuns (Toronto-Danforth).

Thibeault acknowledged the Liberal plan will start repaying borrowed money in the mid- or late 2020s and it will show up separately on hydro bills as the “Clean Energy Adjustment”, a kind of electricity recovery rate that could raise costs.

 

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Imported coal volumes up 17% during Apr-Oct as domestic supplies shrink

India Thermal Power Coal Imports surged 17.6% as CEA-monitored plants offset weaker CIL and SCCL supplies, driven by Saubhagya-led electricity demand, regional power deficits, and varied consumption across Uttar Pradesh, Bihar, Maharashtra, and Gujarat.

 

Key Points

Fuel volumes imported for Indian thermal plants, tracked by CEA, reflecting shifts in CIL/SCCL supply, demand, and regional power deficits.

✅ Imports up 17.6% as domestic CIL/SCCL deliveries lag targets

✅ Saubhagya-driven demand lifts generation in key beneficiary states

✅ Industrial slowdowns cut usage in Maharashtra, Tamil Nadu, Gujarat

 

The receipt of imported coal by thermal power plants, where plant load factors have risen, has shot up by 17.6 per cent during April-October. The coal import volumes refer to the power plants monitored by the Central Electricity Authority (CEA), and come amid moves to ration coal supplies as electricity demand surges, a power update report from CARE Ratings showed.

Imports escalated as domestic supplies by Coal India Ltd (CIL) and another state run producer- Singareni Collieries Company Ltd (SCCL) dipped in the period, after earlier shortages that have since eased in later months. Rate of supplies by the two coal companies to the CEA monitored power stations stood at 80.4 per cent, indicating a shortfall of 19.6 per cent against the allocated quantity.

According to the study by CARE Ratings, total coal supplied by CIL and SCCL to the power sector stood at 315.9 million tonnes (mt) during April-October as against 328.5 mt in the comparable period of last fiscal year.

The study noted that growth in power generation during the April-October 2019, with India now the third-largest electricity producer globally, was on account of higher demand from Pradhan Mantri Sahaj Bijli Har Ghar Yojana or Saubhagya Scheme beneficiary states. Providing connection to households in order to achieve 100% per cent electrification has in part helped the sector avert de-growth, as part of efforts to rewire Indian electricity and expand access.

Large states namely Uttar Pradesh, Bihar, Punjab, West Bengal and Rajasthan have recorded over five per cent growth in consumption of power. These states along with Odisha, Madhya Pradesh and Assam accounted for 75 per cent of the beneficiaries under the Saubhagya Scheme (Household Electrification Scheme). The ongoing economic downturn has led to a sharp fall in electricity demand from industrialised states. Maharashtra, which is also the largest power consuming state in India, recorded a decline in consumption of 5.6 per cent.

Other states namely Tamil Nadu, Telangana, Gujarat and Odisha too recorded fall in power consumed, echoing global dips in daily electricity demand seen later during the pandemic. These states house large clusters of mining, automobile, cement and other manufacturing industries, and a decline in these sectors led to fall in demand for power across these states. - The demand-supply gap or power deficit has remained at 0.6 per cent during the April-October 2019. North-East reported 4.8 per cent of power deficit followed by Northern Region at 1.3 per cent. Within Northern Region, Jammu & Kashmir and Uttar Pradesh accounted for 65 per cent and 30 per cent respectively of the regions power supply deficit.

 

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