Power plant concerns analysts

Taltson Hydro Electric Heating directs surplus hydro power in the South Slave to space heat via discounted rates, displacing diesel and cutting greenhouse gas emissions, with rebates, separate metering, and backup systems shaping adoption.

Key Points

An initiative using Taltson's surplus hydro to heat buildings, discount rates replace diesel and cut emissions.

✅ 6.3 cents/kWh heating rate needs separate metering, backup heat

✅ 4-6 MW surplus hydro; outages require diesel; rebates available

✅ Program may be curtailed if new mines or mills demand power

A Northwest Territories green energy advocate says there's an obvious way to expand demand for electricity in the territory's South Slave region without relying on new mining developments — direct it toward heating.

One of the reasons the N.W.T. has always had some of the highest electricity rates in Canada is that a small number of people have to shoulder the huge costs of hydro facilities and power plants.

But some observers point out that residents consume as much energy for heat as they do for conventional uses of electricity, such as lighting and powering appliances. Right now almost all of that heat is generated by expensive oil imported from the United States.

The Northwest Territories Power Corporation says the 18-megawatt Taltson hydro system that serves the South Slave typically has four to six megawatts of excess generating capacity, even as record demand in Yukon is reported. It says using some of that to generate heat is a government priority.

But renewable energy advocate and former N.W.T. MP Dennis Bevington, who lives in the South Slave and heats his home using electricity, says the government is not making it easy for people to tap into that surplus to heat their homes and businesses, a debate that some say would benefit from independent planning at the national level.

Discount rate for heating, but there are catches
The power corporation offers hydro electricity from Taltson to use for heating at a much lower price than it charges for electricity generally. The discounted rate is not available to residential customers.

According to the corporation, consumers pay only 6.3 cents per kilowatt hour compared to the regular rate of just under 24 cents, while Manitoba Hydro financial pressures highlight the risks of expanding demand without new generation.

But to distinguish between the two, users are required to cover the cost of installing a separate power meter. Bevington, who developed the N.W.T.'s first energy strategy, says that is an unnecessary expense.

Taltson expansion key to reducing N.W.T.'s greenhouse gas emissions, says gov't
"The billing is how you control that," he said. "You establish an average electrical use in the winter months. That could be the base rate. Then, if you use power in the winter months above that, you get the discount."

Users are also required to have a back-up heating system. Taltson hydro power offers heating on the understanding that when the hydro system is down — such as during power outages or annual summer maintenance of the hydro system — electricity is not available for heating.
The president and CEO of the power corporation says there's a good reason for that. "The diesels are more expensive to run and they're actually greenhouse gas emitting," said Noel Voykin. "The whole idea of this [electric heat] program is to provide clean energy that is not otherwise being used."

According to the corporation, there have been huge savings for the few who have tapped into the hydro system to heat their buildings, and across Canada utilities are exploring novel generation such as NB Power's Belledune seawater project to diversify supply.

It's being used to heat Aurora College's Breynat Hall, and Joseph B. Tyrrell Elementary School and the transportation department garage in Fort Smith, N.W.T. Electricity is also used to heat the Jackfish power plant in the North Slave region.

The corporation says that during a four-year period, this saved more than 600,000 litres of diesel fuel and reduced greenhouse gas emissions by about 1,700 tonnes.

Bevington says the most obvious place to expand the use of electrical heat is to government housing.

"We have a hundred public housing units in Fort Smith," he said. "The government is putting diesel into those units [for heating] and they could be putting in their own electricity."

Heating a tiny part of energy market
The corporation says it sells only about 2.5 megawatts of electricity for heating each year, which is less than four per cent of the power it sells in the region. It says with some upgrades, another two megawatts of electricity could be made available for electrical heat.

Bevington says the corporation could do more to market electricity for heating. Voykin said that's the government's job. There are three programs that offer rebates to residents and businesses converting to electric heating.

If you build it, will they come? N.W.T. gov't hopes hydro expansion will attract investment
There are better options than billion dollar Taltson expansion, say energy leaders
There may be a reason why the government and the corporation are not more aggressively promoting using surplus electricity in the Taltson system for heating, as large hydro ambitions have reopened old wounds in places like Quebec and Newfoundland and Labrador during recent debates.

It is anticipating that new industrial customers may require that excess capacity in the coming years, and experiences elsewhere show that accommodating new energy-intensive customers can be challenging for utilities. Voykin said those potential new customers include a proposed mine at Pine Point and a pellet mill in Enterprise, N.W.T., even as biomass use faces environmental pushback in some regions.

The corporation says any surplus power in the system will be sold at standard rates to any new industrial customers instead of at discount rates for heating. If that requires cutting back on the heating program, it will be cut back.

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Automaker EV Fast-Charging Network will deploy 30,000 DC fast chargers across US and Canada, supporting CCS and NACS, integrating Tesla compatibility, easing range anxiety, and expanding highway and urban charging infrastructure with amenities and uptime.

Key Points

A $1B joint venture by seven automakers to build 30,000 DC fast chargers with CCS and NACS across the US and Canada.

✅ 30,000 DC fast chargers by 2030 across US and Canada

✅ Supports CCS and NACS; Tesla compatibility planned

✅ Launching mid-2024; focus on highways, urban hubs, amenities

Seven major automakers announced a plan on Wednesday to nearly double the number of fast chargers in the United States in an effort to address one of the main reasons that people hesitate to buy electric cars, even as the age of electric cars accelerates.

The carmakers — BMW Group, General Motors, Honda, Hyundai, Kia, Mercedes-Benz Group and Stellantis — will initially invest at least $1 billion in a joint venture that will build 30,000 charging ports on major highways and other locations in the United States and Canada.

The United States and Canada have about 36,000 fast chargers — those that can replenish a drained battery in 30 minutes or less. In some sparsely populated areas, such chargers can be hundreds of miles apart. Surveys show that fear about not being able to find a charger during longer journeys is a major reason that some car buyers are reluctant to buy electric vehicles.

Sales of electric vehicles have risen quickly in the United States as the market hits an inflection point, but there are signs that demand is softening. As a result, Tesla, Ford and other carmakers have cut prices in recent months and are offering incentives. Popular models that had long waiting lists last year are now available in a few days or weeks.

Major carmakers are investing billions of dollars to manufacture electric vehicles and batteries and to establish supplier networks. Having staked their futures on the technology, they have a strong incentive to ensure that electric vehicles catch on with car buyers, even as gas-electric hybrids help bridge the transition.

The chargers installed by the joint venture will have plugs designed for the connections used by most carmakers other than Tesla, as well as the standard developed by Tesla, amid fights for control over charging, that Ford, G.M. and other companies have said they intend to switch to in 2025.

“The better experience people have, the faster E.V. adoption will grow,” Mary T. Barra, the chief executive of General Motors, said in a statement.

The seven automakers plan to formalize the joint venture and announce its name by the end of the year, Chris Martin, a Honda spokesman, said. The first chargers will begin operating around the middle of 2024, he said, with all 30,000 in place by the end of the decade.

The joint venture is open to adding other partners, he said. Among major automakers, Ford was a notable absence from the announcement on Wednesday. The company said in a statement on Wednesday that it would continue to iThe partnership also does not include Volkswagen. The company is a majority shareholder of Electrify America, one of the largest fast-charging providers.

Tesla accounts for more than half the fast chargers in the United States and has said it will open its networks to other car brands, though, so far, it has only made fewer than 100 ports available. Owners of Ford and G.M. vehicles, among others, will be able to connect to 12,000 Tesla fast chargers using an adapter beginning next year. In 2025, Ford and G.M. plan to make models designed to take the Tesla plug without an adapter.

The decision by the seven carmakers to form the joint venture is an indication that they do not intend to rely solely on Tesla, which dominates sales of electric vehicles, for charging.

The chargers being built by the joint venture will be concentrated in urban areas and along major highways, especially those used most heavily by vacationers and other travelers, the companies said in a joint statement. Charging stations will be close to restrooms, restaurants and other amenities. The partners said they would try to take advantage of federal and state funds available for charging infrastructure amid questions about whether the U.S. has the power to charge it at scale.

Most electric vehicle owners charge at home and rarely need to use public chargers. Home chargers typically replenish batteries overnight. Most public chargers, about 125,000 in the United States and Canada, also operate relatively slowly — taking four to 10 hours to do the job.nvest in its own network, which allows Ford owners to charge from a variety of providers with one mobile phone app.

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Clean Energy Tax Incentives could expand under Democratic proposals, including ITC, PTC, and EV tax credits, boosting renewable energy, energy storage, and grid modernization within a broader infrastructure package influenced by Green New Deal goals.

Key Points

Federal incentives like ITC, PTC, and EV credits that cut costs and speed renewables, storage, and grid upgrades.

✅ Proposes permanence for ITC, PTC, and EV tax credits

✅ Could accelerate solar, wind, storage, and grid upgrades

✅ Passage depends on bipartisan infrastructure compromise

The 115th U.S. Congress has not even adjourned for the winter, and already a newly resurgent Democratic Party is making demands that reflect its majority status in the U.S. House come January.

Climate appears to be near the top of the list. Last Thursday, Senator Chuck Schumer (D-NY), the Democratic Leader in the Senate, sent a letter to President Trump demanding that any infrastructure package taken up in 2019 include “policies and funding to transition to a clean energy economy and mitigate the risks that the United States is already facing due to climate change.”

And in a list of policies that Schumer says should be included, the top item is “permanent tax incentives for domestic production of clean electricity and storage, energy efficient homes and commercial buildings, electric vehicles, and modernizing the electric grid.”

In concrete terms, this could mean an extension of the Investment Tax Credit (ITC) for solar and energy storage, the Production Tax Credit (PTC) for wind and the federal electric vehicle (EV) tax credit program as well.

Pressure from the Left

This strong statement on climate change, clean energy and infrastructure investment comes as at least 30 incoming members of the U.S. House of Representatives have signed onto a call for the creation of a committee to explore a “Green New Deal” and to move the nation to 100% renewable energy by 2030.*

It also comes as Schumer has come under fire by activists for rumors that he plans to replace Senator Maria Cantwell (D-Washington) with coal state Democrat Joe Manchin (D-West Virginia) as the top Democrat on the Senate Energy and Natural Resources Committee.

As such, one possible way to read these moves is that centrist leaders like Schumer are responding to pressure from an energized and newly elected Left wing of the Democratic Party. It is notable that Schumer’s program includes many of the aims of the Green New Deal, while avoiding any explicit use of that phrase.

Implications of a potential ITC extension

The details of levels and timelines are important here, particularly for the ITC.

The ITC was set to expire at the end of 2016, but was extended in legislative horse-trading at the end of 2015 to a schedule where it remains at 30% through the end of 2019 and then steps down for the next three years, and disappears entirely for residential projects. Since that extension the IRS has issued guidance around the use of co-located energy storage, as well as setting a standard under which PV projects can claim the ITC for the year that they begin construction.

This language around construction means that projects can start work in 2019, complete in 2023 and still claim the 30% ITC, and this may be why we at pv magazine USA are seeing an unprecedented boom in project pipelines across the United States.

Of course, if the ITC were to become permanent some of those projects would be pushed out to later years. But as we saw in 2016, despite an extension of the ITC many projects were still completed before the deadline, leading to the largest volume of PV installed in the United States in any one year to date.

This means that if the ITC were extended by the end of 2020, we could see the same thing all over again – a boom in projects created by the expected sunset, and then after a slight lull a continuation of growth.

Or it is possible that a combination of raw economics, increased investor and utility interest, and accelerating renewable energy mandates will cause solar growth rates to continue every year, and that any changes in the ITC will only be a bump against a larger trend.

While the basis for expiration of the EV tax credit is the number of vehicles sold, not any year, both the battery storage and EV industries, which many see at an inflection point, could see similar effects if the ITC and EV tax credits are made permanent.

Will consensus be reached?

It is also unclear that any such infrastructure package will be taken up by Republicans, or that both parties will be able to come to a compromise on this issue. While the U.S. Congress passed an infrastructure bill in 2017, given the sharp and growing differences between the two parties, and divergent trade approaches such as the 100% tariff on Chinese-made EVs, it is not clear that they will be able to come to a meaningful compromise during the next two years.

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Georgia Power June bill credit delivers PSC-approved savings, lower fuel rates, and COVID-19 relief for residential customers, driven by natural gas prices and 2018 earnings, with typical 1,000 kWh users seeing June bill reductions.

Key Points

A PSC-approved one-time credit and lower fuel rates reducing June bills for Georgia Power residential customers.

✅ $11.29 credit for 1,000 kWh usage on June bills

✅ Fuel rate cut saves $10.26 per month from June to September 2020

✅ PSC-approved $51.5M credit based on Georgia Power's 2018 results

Georgia Power announced that the typical residential customer using 1,000-kilowatt hours will receive an $11.29 credit on their June bill, reflecting a lump-sum credit model also used elsewhere.

This reflects implementation of a one-time $51.5 million credit for customers, similar to Gulf Power's bill decrease efforts, approved by the Georgia Public Service Commission, as a result of

Georgia Power's 2018 financial results.

Pairing the June credit with new, lower fuel rates recently announced, the typical residential customer would see a reduction of $21.55 in June, even as some regions face increases like Pennsylvania's winter price hikes elsewhere.

The amount each customer receives will vary based on their 2018 usage. Georgia Power will apply the credit to June bills for customers who had active accounts as of Dec. 31, 2018, and are still active or receiving a final bill as of June 2020, and the company has issued pandemic scam warnings to help customers stay informed.

Fuel rate lowered 17.2 percent

In addition to the approved one-time credit in June, the Georgia PSC recently approved Georgia Power’s plan to reduce its fuel rates by 17.2 percent and total billings by approximately $740 million over a two-year period. The implementation of a special interim reduction will provide customers additional relief during the COVID-19 pandemic through even lower fuel rates over the upcoming 2020 summer months. The lower fuel rate and special interim reduction will lower the total bill of a typical residential customer using an average of 1,000-kilowatt hours by a total of $10.26 per month from June through September 2020.

The reduction in the company’s fuel rate is driven primarily by lower natural gas prices, even as FPL proposed multiyear rate hikes in Florida, as a result of increased natural gas supplies, which the company is able to take advantage of to benefit customers due to its diverse generation sources.

February bill credit due to tax law savings

Georgia Power completed earlier this year the third and final bill credit associated with the Tax Cuts and Jobs Act of 2017, resulting in credits totaling $106 million. The typical residential customer using an average of 1,000 kilowatt-hours per month received a credit of approximately $22 on their February Georgia Power bill, a helpful offset as U.S. electric bills rose 5% in 2022 according to national data.

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China Solar Grid Parity signals unsubsidized industrial and commercial PV, rooftop solar, and feed-in tariff guarantees competing with grid electricity and coal power prices, driven by cost declines, policy reform, and technology advances.

Key Points

Point where PV in China meets or beats grid electricity, enabling unsubsidized industrial and commercial solar.

✅ City-level analysis shows cheaper PV than grid in 344 cities.

✅ 22% can beat coal power prices without subsidies.

✅ Soft-cost, permitting, and finance reforms speed uptake.

Solar power has become cheaper than grid electricity across China, a development that could boost the prospects of industrial and commercial solar, according to a new study.

Projects in every city analysed by the researchers could be built today without subsidy, at lower prices than those supplied by the grid, and around a fifth could also compete with the nation’s coal electricity prices.

They say grid parity – the “tipping point” at which solar generation costs the same as electricity from the grid – represents a key stage in the expansion of renewable energy sources.

While previous studies of nations such as Germany, where solar-plus-storage costs are already undercutting conventional power, and the US have concluded that solar could achieve grid parity by 2020 in most developed countries, some have suggested China would have to wait decades.

However, the new paper published in Nature Energy concludes a combination of technological advances, cost declines and government support has helped make grid parity a reality in Chinese today.

Despite these results, grid parity may not drive a surge in the uptake of solar, a leading analyst tells Carbon Brief.

Competitive pricing

China’s solar industry has rapidly expanded from a small, rural program in the 1990s to the largest in the world, with record 2016 solar growth underscoring the trend. It is both the biggest generator of solar power and the biggest installer of solar panels.

The installed capacity of solar panels in China in 2018 amounted to more than a third of the global total, with the country accounting for half the world’s solar additions that year.

Since 2000, the Chinese government has unveiled over 100 policies supporting the PV industry, and technological progress has helped make solar power less expensive. This has led to the cost of electricity from solar power dropping, as demonstrated in the chart below.

In their paper, Prof Jinyue Yan of Sweden’s Royal Institute of Technology and his colleagues explain that this “stunning” performance has been accelerated by government subsidies, but has also seen China overinvesting in what some describe as a clean energy's dirty secret of “redundant construction and overcapacity”. The authors write:

“Recently, the Chinese government has been trying to lead the PV industry onto a more sustainable and efficient development track by tightening incentive policies with China’s 531 New Policy.”

The researchers say the subsidy cuts under this policy in 2018 were a signal that the government wanted to make the industry less dependent on state support and shift its focus from scale to quality.

This, they say, has “brought the industry to a crossroads”, with discussions taking place in China about when solar electricity generation could achieve grid parity.

In their analysis, Yan and his team examined the prospects for building industrial and commercial solar projects without state support in 344 cities across China, attempting to gauge where or whether grid parity could be achieved.

The team estimated the total lifetime price of solar energy systems in all of these cities, taking into account net costs and profits, including project investments, electricity output and trading prices.

Besides establishing that installations in every city tested could supply cheaper electricity than the grid, they also compared solar to the price of coal-generated power. They found that 22% of the cities could build solar systems capable of producing electricity at cheaper prices than coal.

Embracing solar

Declining costs of solar technology, particularly crystalline silicon modules, mean the trend in China is also playing out around the world, with offshore wind cost declines reinforcing the shift. In May, the International Renewable Energy Agency (IRENA) said that by the beginning of next year, grid parity could become the global norm for the solar industry, and shifting price dynamics in Northern Europe illustrate the market impact.

Kingsmill Bond, an energy strategist at Carbon Tracker, says this is the first in-depth study he has seen looking at city-level solar costs in China, and is encouraged by this indication of solar becoming ever-more competitive, as seen in Germany's recent solar boost during the energy crisis. He tells Carbon Brief:

“The conclusion that industrial and commercial solar is cheaper than grid electricity means that the workshop of the world can embrace solar. Without subsidy and its distorting impacts, and driven by commercial gain.”

On the other hand, Jenny Chase, head of solar analysis at BloombergNEF, says the findings revealed by Yan and his team are “fairly old news” as the competitive price of rooftop solar in China has been known about for at least a year.

She notes that this does not mean there has been a huge accompanying rollout of industrial and commercial solar, and says this is partly because of the long-term thinking required for investment to be seen as worthwhile.

The lifetime of a PV system tends to be around two decades, whereas the average lifespan of a Chinese company is only around eight years, according to Chase. Furthermore, there is an even simpler explanation, as she explains to Carbon Brief:

“There’s also the fact that companies just can’t be bothered a lot of the time – there are roofs all over Europe where solar could probably save money, but people are not jumping to do it.”

According to Chase, a “much more exciting” development came earlier this year, when the Chinese government developed a policy for “subsidy-free solar”.

This involved guaranteeing the current coal-fired power price to solar plants for 20 years, creating what is essentially a low feed-in tariff and leading to what she describes as “a lot of nice, low-risk projects”.

As for the beneficial effects of grid parity, based on how things have played out in countries where it has already been achieved, Chase says it does not necessarily mean a significant uptake of solar power will follow:

“Grid parity solar is never as popular as subsidised solar, and ironically you don’t generally have a rush to build grid parity solar because you may as well wait until next year and get cheaper solar.”

Policy proposals

In their paper, Yan and his team lay out policy changes they think would help provide an economic incentive, in combination with grid parity, to encourage the uptake of solar power systems.

Technology costs may have fallen for smaller solar projects of the type being deployed on the rooftops of businesses, but they note that the so-called “soft costs” – including installation and maintenance – tend to be “very impactful”.

Specifically, they say aspects such as financing, land acquisition and grid accommodation, which make up over half the total cost, could be cut down:

“Labour costs are not significant [in China] because of the relatively low wages of direct labour and related installation overhead. Customer acquisition has largely been achieved in China by the mature market, with customers’ familiarity with PV systems, and with the perception that PV systems are a reliable technology. However, policymakers should consider strengthening the targeted policies on the following soft costs.”

Among the measures they suggest are new financing schemes, an effort to “streamline” the complicated procedures and taxes involved, and more geographically targeted government policies, alongside innovations like peer-to-peer energy sharing that can improve utilization.

As their analysis showed the price of solar electricity had fallen further in some cities than others, the researchers recommend targeting future subsidies at the cities that are performing less well – keeping costs to a minimum while still providing support when it is most needed.

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Energy Transition Grid Reforms address transmission capacity, interconnection, congestion management, and flexibility markets, enabling renewable integration and grid stability while optimizing network charges and access in Australia, Ireland, and Great Britain.

Key Points

Measures to expand transmission, boost flexibility, and manage congestion for reliable, low-carbon electricity systems.

✅ Transmission upgrades and interconnectors ease congestion

✅ Flexible markets, DER, and storage bolster grid stability

✅ Evolving network charges and access incentivize siting

Electricity networks globally are experiencing significant increases in the volume of renewable capacity as countries seek to decarbonise their power sectors, even as clean energy's 'dirty secret' highlights integration trade-offs, without impacting the security of supply. The scale of this change is creating new challenges for power networks and those responsible for keeping the lights on.

The latest insight paper from Cornwall Insight – Market design amidst global energy transition – looks into this issue. It examines the outlook for transmission networks, and how legacy design and policies are supporting decarbonisation, aligning with IRENA findings on renewables and shaping the system. The paper focuses on three key markets; Australia, Ireland and Great Britain (GB).

Australia's main priority is to enhance transmission capacity and network efficiency; as concerns over excess solar risking blackouts grow in distribution networks, without this, the transmission system will be a barrier to growth for decentralised flexibility and renewables. In contrast, GB and Ireland benefit from interconnection with other national markets. This provides them with additional levers that can be pulled to manage system security and supply. However, they are still trying to hone and optimise network flexibility in light of steepening decarbonisation objectives.

Unsurprisingly, renewable energy resources have been growing in all three markets, with Ireland regarded as a leader in grid integration, with this expected to continue for the foreseeable future. Many of these projects are often located in places where network infrastructure is not as well developed, creating pressure on system operation as a result.

In all three markets, unit charges are rising, driven by a reduced charging base as decentralised energy grows quickly. This combination of changes is leading to network congestion, a challenge mirrored by the US grid overhaul for renewables underway, as transmission network development struggles to keep up, and flexibility markets are being optimised and changed.

In summary, reforms are on-going in each jurisdiction to accommodate the rapid physical transformation of the generation mix. Each has its objectives and tensions which are reflective of wider global reform programmes being undertaken in most developed, liberalised and decarbonising energy markets.

Gareth Miller, CEO of Cornwall Insight, said: “Despite differences in market design and characteristics, all three markets are grappling with similar issues, that comes from committing to deep decarbonisation. This includes the most appropriate methods for charging for networks, managing access to them and dealing with issues such as network congestion and constraint.

“In all three countries, renewable projects are often placed in isolated locations, as seen in Scotland where more pylons are needed to keep the lights on, away from the traditional infrastructure that is closer to demand. However, as renewable growth is set to continue, the networks will need to transition from being demand-centric to more supply orientated.

“Both system operators and stakeholders will need to continually evaluate their market structures and designs to alleviate issues surrounding locational congestion and grid stability. Each market is at very different stages in the process in trying to improve any problems implementing solutions to allow for higher efficiencies in renewable energy integration.

“It is uncertain whether any of the proposed changes will fundamentally resolve the issues that come with increased renewables on the system. However, despite marked differences, they certainly could all learn from each other and elements of their network arrangements, as well as from US decarbonisation strategies research.”

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