Electricity News in August 2019
Energy Vault Lands $110M From SoftBank’s Vision Fund for Gravity Storage
Energy Vault Gravity Storage uses crane-stacked concrete blocks to deliver long-duration, grid-scale renewable energy; a SoftBank Vision Fund-backed, pumped-hydro analog enabling baseload power and a lithium-ion alternative with proprietary control algorithms.
Key Points
Gravity-based cranes stack blocks to store and dispatch power for hours, enabling grid-scale, low-cost storage.
✅ 4 MW/35 MWh modules; ~9-hour duration
✅ Estimated $200-$250/kWh; lower LCOE than lithium-ion
✅ Backed by SoftBank Vision Fund; Cemex and Tata support
Energy Vault, the Swiss-U.S. startup that says it can store and discharge electrical energy through a super-sized concrete-and-steel version of a child’s erector set, has landed a $110 million investment from Japan’s SoftBank Vision Fund to take its technology to commercial scale.
Energy Vault, a spinout of Pasadena-based incubator Idealab and co-founded by Idealab CEO and billionaire investor Bill Gross, unstealthed in November with its novel approach to using gravity to store energy.
Simply put, Energy Vault plans to build storage plants — dubbed “Evies” — consisting of a 35-story crane with six arms, surrounded by a tower consisting of thousands of concrete bricks, each weighing about 35 tons.
This plant will “store” energy by using electricity to run the cranes that lift bricks from the ground and stack them atop of the tower, and “discharge” energy by reversing that process. It’s a mechanical twist on the world’s most common energy storage technology, pumped hydro, which “stores” energy by pumping water uphill, and lets it fall to spin turbines when electricity is needed, even as California funds 100-hour long-duration storage pilots to expand flexibility worldwide.
But behind this simplicity lies some heavy-duty software to orchestrate the cranes and blocks, with a "unique stack of proprietary algorithms" to balance energy supply and demand, volatility, grid stability, weather elements and other variables.
CEO and co-founder Robert Piconi said in a November interview with GTM that the standard array would deliver 4 megawatts/35 megawatt-hours of storage, which translates to nearly 9 hours of duration — the equivalent of building the tower to its height, and then reducing it to ground level. It can be built on-site in partnership with crane manufacturers and recycled concrete material, and can run fully automated for decades with little deterioration, he said.
And the cost, which Piconi pegged in the $200 to $250 per kilowatt-hour range, with room to decline further, is roughly 50 percent below the upfront price of the conventional storage market today, and 80 percent below it on levelized cost, he said, a trend utilities see benefits in as they plan resources.
The result, according to Wednesday’s statement, is a technology that could allow “renewables to deliver baseload power for less than the cost of fossil fuels 24 hours a day,” in applications such as community microgrids serving low-income housing.
Wednesday’s announcement builds on a recent investment from Mexico's Cemex Ventures, the corporate venture capital unit of building materials giant Cemex, along with a promise of deployment support from Cemex's strategic network, and also follows project financing for a California green hydrogen microgrid led by the company. Piconi said in November that the company had sufficient investment from two funding rounds to carry it through initial customer deployments, though he declined to disclose figures.
This is the first energy storage investment for Vision Fund, the $100 billion venture fund set up by SoftBank founder Masayoshi Son. While large by startup standards, it’s in keeping with the capital costs that Energy Vault will face in scaling up its technology to meet its commitments, amid mounting demand in regions like Ontario energy storage that face supply crunches. Those include a 35 megawatt-hour order with Tata Power Company, the energy-producing arm of the Indian industrial conglomerate, first unveiled in November, as well as plans to demonstrate its first storage tower in northern Italy in 2019.
For Vision Fund, it’s also an unusual choice for a storage investment, given that the vast majority of venture capital in the industry today is being directed toward lithium-ion batteries, and even Mercedes-Benz energy storage ventures targeting the U.S. market. Lithium-ion batteries are limited in terms of how many hours they can provide cost-effectively, with about 4 hours being seen as the limit today.
The search for long-duration energy storage has driven investment into flow battery technologies such as grid-scale vanadium systems deployed on utility networks, compressed-air energy storage and variations on gravity-based storage, including a previous startup backed by Gross and Idealab, Energy Cache, whose idea of using a ski lift carrying buckets of gravel up a hill to store energy petered out with a 50-kilowatt pilot project.
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PG&E Wildfire Assistance Program Accepting Applications for Aid
PG&E Wildfire Assistance Program offers court-approved aid and emergency grants for Northern California wildfires and Camp Fire victims, covering unmet needs, housing, and essentials; apply online by November 15, 2019 under Chapter 11-funded eligibility.
Key Points
A $105M, court-approved aid fund offering unmet-needs payments and emergency support for 2017-2018 wildfire victims.
✅ $5,000 Basic Unmet Needs per household, self-certified
✅ Supplemental aid for extreme circumstances after basic grants
✅ Apply online; deadline November 15, 2019; identity required
Beginning today, August 15, 2019, those displaced by the 2017 Northern California wildfires and 2018 Camp fire can apply for aid through an independently administered Wildfire Assistance Program funded by Pacific Gas and Electric Company (PG&E). PG&E’s $105 million fund, approved by the judge in PG&E’s Chapter 11 cases and related bankruptcy plan, is intended to help those who are either uninsured or need assistance with alternative living expenses or other urgent needs. The court-approved independent administrator is set to file the eligibility criteria as required by the court and will open the application process.
“Our goal is to get the money to those who most need it as quickly as possible. We will prioritize wildfire victims who have urgent needs, including those who are currently without adequate shelter,” said Cathy Yanni, plan administrator. Yanni is partnering with local agencies and community organizations to administer the fund, and PG&E also supports local communities through property tax contributions to counties.
“We appreciate the diligent work of the fund administrator in quickly establishing a way to distribute these funds and ensuring the program supports those with the most immediate needs. PG&E is focused on helping those impacted by the devastating wildfires in recent years and strengthening our energy system to reduce wildfire risks and prevent utility-caused catastrophic fires. We feel strongly that helping these communities now is the right thing to do,” said Bill Johnson, CEO and President of PG&E Corporation.
Applicants can request a “Basic Unmet Needs” payment of $5,000 per household for victims who establish basic eligibility requirements and self-certify that they have at least $5,000 of unmet needs that have not been compensated by the Federal Emergency Management Agency (FEMA). Payments are to support needs such as water, food, prescriptions, medical supplies and equipment, infant formula and diapers, personal hygiene items, and transportation fuels beyond what FEMA covered in the days immediately following the declared disasters, aligning with broader health and safety actions the company has taken.
Those who receive basic payments may also qualify for a “Supplemental Unmet Needs” payment. These funds will be available only after “Basic Unmet Needs” payments have been issued. Supplemental payments will be available to individuals and families who currently face extreme or extraordinary circumstances as compared to others who were impacted by the 2017 and 2018 wildfires, including areas affected by power line-related fires across California.
To qualify for the payments, applicants’ primary residence must have been within the boundary of the 2017 Northern California wildfires or the 2018 Camp fire in Butte County. Applicants also must establish proof of identity and certify that they are not requesting payments for an expense already paid for by FEMA.
Applicants can find more information and apply for assistance at https://www.norcalwildfireassistanceprogram.com/. The deadline to file for aid is November 15, 2019.
The $105 million being provided by PG&E was made available from the company’s cash reserves. PG&E will not seek cost recovery from its customers, and its rates are set to stabilize in 2025 according to recent guidance.
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Perry presses ahead on advanced nuclear reactors
Advanced Nuclear Reactors drive U.S. clean energy with small modular reactors, a new test facility at Idaho National Laboratory, and public-private partnerships accelerating nuclear innovation, safety, and cost reductions through DOE-backed programs and university simulators.
Key Points
Advanced nuclear reactors are next-gen designs, including SMRs, offering safer, cheaper, low-carbon power.
✅ DOE test facility at Idaho National Laboratory
✅ Small modular reactors with passive safety systems
✅ University simulators train next-gen nuclear operators
Energy Secretary Rick Perry is advancing plans to shift the United States towards next-gen nuclear power reactors.
The Energy Department announced this week it has launched a new test facility at the Idaho National Laboratory where private companies can work on advanced nuclear technologies, as the first new U.S. reactor in nearly seven years starts up, to avoid the high costs and waste and safety concerns facing traditional nuclear power plants.
“[The National Reactor Innovation Center] will enable the demonstration and deployment of advanced reactors that will define the future of nuclear energy,” Perry said.
With climate change concerns growing and net-zero emissions targets emerging, some Republicans and Democrats are arguing for the need for more nuclear reactors to feed the nation’s electricity demand. But despite nuclear plants’ absence of carbon emissions, the high cost of construction, questions around what to do with the spent nuclear rods and the possibility of meltdown have stymied efforts.
A new generation of firms, including Microsoft founder Bill Gates’ Terra Power venture, are working on developing smaller, less expensive reactors that do not carry a risk of meltdown.
“The U.S. is on the verge of commercializing groundbreaking nuclear innovation, and we must keep advancing the public-private partnerships needed to traverse the dreaded valley of death that all too often stifles progress,” said Rich Powell, executive director of ClearPath, a non-profit advocating for clean energy and green industrial strategies worldwide.
The new Idaho facility is budgeted at $5 million under next year’s federal budget, even as the cost of U.S. nuclear generation has fallen to a ten-year low, which remains under negotiation in Congress.
On Thursday another advanced nuclear developer working on small modular systems, Oregon-based NuScale Power, announced it was building three virtual nuclear control rooms at Texas A&M University, Oregon State University and the University of Idaho, with funding from the Energy Department.
The simulators will be open to researchers and students, to train on the operation of smaller, modular reactors, as well as the general public.
NuScale CEO John Hopkins said the simulators would “help ensure that we educate future generations about the important role nuclear power and small modular reactor technology will play in attaining a safe, clean and secure energy future for our country.”
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New bill would close loophole that left hundreds of Kentucky miners with cold checks
Kentucky Coal Wage Protection Bill strengthens performance bond enforcement, links Energy and Environment Cabinet and Labor Cabinet notifications, addresses Blackjewel bankruptcy fallout, safeguards unpaid miners, ties mining permits to payroll bonds, penalizes violators via revocations.
Key Points
A Kentucky plan to enforce wage bonds and revoke mining permits to protect miners after bankruptcies.
✅ Requires wage bonds for firms under 5 years
✅ Links Energy and Environment Cabinet and Labor Cabinet
✅ Violators face permit revocation in 90 days
Following the high-profile bankruptcy of a coal company that left hundreds of Kentucky miners with bad checks last month, Sen. Johnny Ray Turner (D-Prestonsburg) said he will pre-file a bill Thursday aimed at closing a loophole that allowed the company to operate in violation of state law.
The bill would also compel state agencies to determine whether other companies are currently in violation of the law, and could revoke mining permits if the companies don't comply.
Turner's bill would amend an already-existing law that requires coal and construction companies that have been operating in Kentucky for less than five years to post a performance bond to protect wages if the companies cease their operations.
Blackjewel LLC., which employed hundreds of miners in Eastern Kentucky, failed to post that bond. When it shut its mines down and filed for bankruptcy last month, it left hundreds of miners without payment for 3 weeks and one day of work.
The bond issue has sparked criticism from various state officials, including Attorney General Andy Beshear, who said Tuesday that he would investigate whether other companies are currently in violation, similar to an external investigation of utility workers in another jurisdiction.
Blackjewel issued cold checks to its employees June 28, and when the checks bounced days later, many employees were left with bank accounts overdrawn by more than $1,000. The bankruptcy left many miners and their families with concerns over upcoming bill and mortgage payments, and, as unpaid days off at utilities elsewhere show, the strain on workers can be severe, and fostered a ongoing protest that blocked a train hauling coal from one of the company's Harlan County mines.
Blackjewel had been operating in Kentucky for about two years before it filed for bankruptcy, so it should have paid the performance bond, according to state law.
David A. Dickerson, the Kentucky Labor Cabinet Secretary, said the law as it's currently written does not set up any mechanism that notifies the cabinet, or provides comparable public reporting at large utility projects elsewhere, when a company opens in Kentucky that is supposed to pay the bond.
That allowed Blackjewel to operate for two years without any protection for workers before it closed its mines. Had the company posted the bond according to state law, miners likely would have been paid for the work they had already completed, officials said.
The law requires companies to set aside enough money to cover payroll for four weeks.
Turner's bill would compel the state Energy and Environment Cabinet to notify the Labor Cabinet's Department of Workplace Standards of any application for a mining permit from a company that has been doing business in Kentucky for less than five years.
It also compels the EEC to notify the Labor Cabinet of any companies that already have permits that are subject to the bond.
"It should have already been that way, but I'm happy so our children don't have to go through this," said Jeff Willig, a former Blackjewel miner who helped launch the protest at the railroad.
Willig said he and other miners will continue to block the tracks until they receive payment for their past work.
Any company currently operating in violation of the law would have 90 days to become compliant before its mining permits are revoked. New companies that are applying for permits will be required post the bond before permits are issued.
"Hopefully it will take care of the loopholes that had been exploited by Blackjewel," Turner said.
The bill will be taken up by the legislature when it returns to session in January. It would also cover attorneys' fees if workers are forced to sue their employer to cover wages, underscoring broader worker safety concerns during health emergencies.
Turner said he has reached out to Republican leadership in the Senate, and expects the bill to have bipartisan support come January.
Turner announced the legislation at a press conference in Harlan, the county with the highest population of Blackjewel employees affected by the bankruptcy, and as prolonged utility outages after tornadoes have strained other Kentucky communities.
State rep. Angie Hatton (D-Whitesburg) was also in attendance, along with rep. Chris Fugate (R-Chavies) and state Sen. Morgan McGarvey (D-Louisville).
Hatton said the bankruptcy has had serious economic impact throughout Eastern Kentucky, including in Letcher County, which is home to more than 130 former Blackjewel workers.
"This is something that has done a lot of damage to Eastern Kentucky," Hatton said.
Hatton plans to file the same bill in the state House of Representatives.
Fugate commended community members in Harlan County and elsewhere who have banded together in support of the miners by donating children's clothing, school supplies, food and other goods, while other regions have created a coal transition fund to help displaced workers.
Mosley called the bankruptcy "totally unprecedented" and said the current performance bond law, which has been on-the-books since 1986, lacked the enforcement necessary to protect miners in bankruptcies like Blackjewel's, even as a workplace safety fine in another case shows regulatory consequences in other industries.
"There was a law, there wasn't good enough process," Mosley said.
Blackjewel received court approval to sell many of its mines last month, including many in Kentucky, to Kopper Glo Mining, LLC.
As part of the sale agreement, Kopper Glo said it would pay $450,000 to cover the past wages of Blackjewel miners, and collect a per ton fee accumulating up to $550,000 that it will also contribute to pay back wages.
That total $1 million is less than half of all back wages owed to Blackjewel miners, but attorneys who filed a class action suit against the company said miners have a priority lien on the purchase price. That could allow former Blackjewel employees to make good on their back wages as bankruptcy proceedings continue.
Mosley said he spoke with a Kopper Glo official Thursday, who said the company is working to re-open the mines as quickly as possible. The official did not give an exact timeline.
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Hydro-Quebec won't ask for rate hike next year
Hydro-Quebec Rate Freeze maintains current electricity rates, aligned with Bill 34, inflation indexing, and energy board oversight, delivering rebates to residential, commercial, and industrial customers and projecting nearly $1 billion in savings across Quebec.
Key Points
A Bill 34 policy holding power rates, adding 2020 rebates, and indexing 2021-2024 rates to inflation for Quebec customers.
✅ 2020-21 rates frozen; savings near $1B over five years.
✅ $500M rebate: residential, commercial, industrial shares.
✅ 2021-2024 rates index to inflation; five-year reviews after 2025.
Hydro-Quebec Distribution will not file a rate adjustment application with the province’s energy board this year, amid a class-action lawsuit alleging customers were overcharged.
In a statement released on Friday the Crown Corporation said it wants current electricity rates to be maintained for another year, as pandemic-driven demand pressures persist, starting April 1. That is consistent with the recently tabled Bill 34, and echoes Ontario legislation to lower electricity rates in its aims, which guarantees lower electricity rates for Quebecers.
The bill also provides a $500 million rebate in 2020, similar to a $535 million refund previously issued, half of which will go to residential customers while $190 million will go to commercial customers and another $60 million to industrial ones.
Hydro-Quebec said the 2020-21 rate freeze will generate savings of nearly $1 billion for its clients over the next five years, even as Manitoba Hydro scales back increases in a different market.
Bill 34, which was tabled in June, also proposes to set rates based on inflation for the years 2021 to 2024, contrasting with Ontario rate increases over the same period. After 2025 Hydro-Quebec would have to ask the energy board to set new rates every five years, as opposed to the current annual system, while BC Hydro is raising rates by comparison.
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Hydro One Q2 profit plunges 23% as electricity revenue falls, costs rise
Hydro One Q2 Earnings show lower net income and EPS as mild weather curbed electricity demand; revenue missed Refinitiv estimates, while tree-trimming costs rose and the dividend remained unchanged for Ontario's grid operator.
Key Points
Hydro One Q2 earnings fell to $155M, EPS $0.26, revenue $1.41B; costs rose, demand eased, dividend held at $0.2415.
✅ Net income $155M; EPS $0.26 vs $0.34 prior year
✅ Revenue $1.41B; missed $1.44B estimate
✅ Dividend steady at $0.2415 per share
Hydro One Ltd.'s (H.TO 0.25%) second-quarter profit fell by nearly 23 per cent from last year to $155 million as the electricity utility reported spending more on tree-trimming work due to milder temperatures that also saw customers using less power, notwithstanding other periods where a one-time court ruling gain shaped quarterly results.
The Toronto-based company - which operates most of Ontario's power grid - and whose regulated rates are subject to an OEB decision, says its net earnings attributable to shareholders dropped to 26 cents per share from 34 cents per share when Hydro One had $200 million in net income.
Adjusted net income was also 26 cents per share, down from 33 cents per diluted share in the second quarter of 2018, while executive pay, including the CEO salary, drew public scrutiny during the period.
Revenue was $1.41 billion, down from $1.48 billion, while revenue net of purchased power was $760 million, down from $803 million, and across the sector, Manitoba Hydro's debt has surged as well.
Separately, Ontario introduced a subsidized hydro plan and tax breaks to support economic recovery from COVID-19, which could influence consumption patterns.
Analysts had estimated $1.44 billion of revenue and 27 cents per share of adjusted income, and some investors cite too many unknowns in evaluating the stock, according to financial markets data firm Refinitiv.
The publicly traded company, which saw a share-price drop after leadership changes and of which the Ontario government is the largest shareholder, says its quarterly dividend will remain at 24.15 cents per share for its next payment to shareholders in September.
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More Managers Charged For Price Fixing At Ukraine Power Producer
DTEK Rotterdam+ price-fixing case scrutinizes alleged collusion over coal-based electricity tariffs in Ukraine, with NABU probing NERC regulators, market manipulation, consumer overpayment, and wholesale pricing tied to imported coal benchmarks.
Key Points
NABU probes alleged DTEK-NERC collusion to inflate coal power tariffs via Rotterdam+; all suspects deny wrongdoing.
✅ NABU alleges tariff manipulation tied to coal import benchmarks.
✅ Four DTEK execs and four NERC officials reportedly charged.
✅ Probe centers on 2016-2017 overpayments; defendants contest.
Two more executives of DTEK, Ukraine’s largest private power and coal producer and recently in energy talks with Octopus Energy, have been charged in a criminal case on August 14 involving an alleged conspiracy to fix electricity prices with the state energy regulator, Interfax reported.
They are Ivan Helyukh, the CEO of subsidiary DTEK Grid, which operates as Ukraine modernizes its network alongside global moves toward a smart electricity grid, and Borys Lisoviy, a top manager of power generation company Skhidenergo, according to Kyiv-based Concorde Capital investment bank.
Ukraine’s Anti-Corruption Bureau (NABU) alleges that now four DTEK managers “pressured” and colluded with four regulators at the National Energy and Utilities Regulatory Commission to manipulate tariffs on electricity generated from coal that forced consumers to overpay, reflecting debates about unjustified profits in the UK, $747 million in 2016-2017.
DTEK allegedly benefited $560 million in the scheme.
All eight suspects are charged with “abuse of office” and deny wrongdoing, similar to findings in a B.C. Hydro regulator report published in Canada.
There is “no legitimate basis for suspicions set out in the investigation,” DTEK said in an August 8 statement.
Suspect Dmytro Vovk, the former head of NERC, dismissed the investigation as a “wild goose chase” on Facebook.
In separate statements over the past week, DTEK said the managers who are charged have prematurely returned from vacation to “fully cooperate” with authorities in order to “help establish the truth.”
A Kyiv court on August 14 set bail at $400,000 for one DTEK manager who wasn’t named, as enforcement actions like the NT Power penalty highlight regulatory consequences.
The so-called Rotterdam+ pricing formula that NABU has been investigating since March 2017, similar to federal scrutiny of TVA rates, was in place from April 2016 until July of this year.
It based the wholesale price of electricity by Ukrainian thermal power plants on coal prices set in the Rotterdam port plus delivery costs to Ukraine.
NABU alleges that at certain times it has not seen documented proof that the purchased coal originated in Rotterdam, insisting that there was no justification for the price hikes, echoing issues around paying for electricity in India in some markets.
Ukraine started facing thermal-coal shortages after fighting between government forces and Russia-backed separatists in the eastern part of the country erupted in April 2014. A vast majority of the anthracite-coal mines on which many Ukrainian plants rely are located on territory controlled by the separatists.
Overnight, Ukraine went from being a net exporter of coal to a net importer and started purchasing coal from as far away as South Africa and Australia.
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Alberta Electricity market needs competition
Alberta Electricity Market faces energy-only vs capacity debate as transmission, distribution, and administration fees surge; rural rates rise amid a regulated duopoly of investor-owned utilities, prompting calls for competition, innovation, and lower bills.
Key Points
Alberta's electricity market is an energy-only system with rising delivery charges and limited rural competition.
✅ Energy-only design; capacity market scrapped
✅ Delivery charges outpace energy on monthly bills
✅ Rural duopoly limits competition and raises rates
Last week, Alberta’s new Energy Minister Sonya Savage announced the government, through its new electricity rules, would be scrapping plans to shift Alberta’s electricity to a capacity market and would instead be “restoring certainty in the electricity system.”
The proposed transition from energy only to a capacity market is a contentious subject as a market reshuffle unfolds across the province that many Albertans probably don’t know much about. Our electricity market is not a particularly glamorous subject. It’s complicated and confusing and what matters most to ordinary Albertans is how it affects their monthly bills.
What they may not realize is that the cost of their actual electricity used is often just a small fraction of their bill amid rising electricity prices across the province. The majority on an average electricity bill is actually the cost of delivering that electricity from the generator to your house. Charges for transmission, distribution and franchise and administration fees are quickly pushing many Alberta households to the limit with soaring bills.
According to data from Alberta’s Utilities Consumer Advocate (UCA), and alongside policy changes, in 2004 the average monthly transmission costs for residential regulated-rate customers was below $2. In 2018 that cost was averaging nearly $27 a month. The increase is equally dramatic in distribution rates which have more than doubled across the province and range wildly, averaging from as low as $10 a month in 2004 to over $80 a month for some residential regulated-rate customers in 2018.
Where you live determines who delivers your electricity. In Alberta’s biggest cities and a handful of others the distribution systems are municipally owned and operated. Outside those select municipalities most of Alberta’s electricity is delivered by two private companies which operate as a regulated duopoly. In fact, two investor-owned utilities deliver power to over 95 per cent of rural Alberta and they continue to increase their share by purchasing the few rural electricity co-ops that remained their only competition in the market. The cost of buying out their competition is then passed on to the customers, driving rates even higher.
As the CEO of Alberta’s largest remaining electricity co-op, I know very well that as the price of materials, equipment and skilled labour increase, the cost of operating follows. If it costs more to build and maintain an electricity distribution system there will inevitably be a cost increase passed on to the consumer. The question Albertans should be asking is how much is too much and where is all that money going with these private- investor-owned utilities, as the sector faces profound change under provincial leadership?
The reforms to Alberta’s electricity system brought in by Premier Klein in the late 1900s and early 2000s contributed to a surge in investment in the sector and led to an explosion of competition in both electricity generation and retail.
More players entered the field which put downward pressure on electricity rates, encouraged innovation and gave consumers a competitive choice, even as a Calgary electricity retailer urged the government to scrap the overhaul. But the legislation and regulations that govern rural electricity distribution in Alberta continue to facilitate and even encourage the concentration of ownership among two players which is certainly not in the interests of rural Albertans.
It is also not in the spirit of the United Conservative Party platform commitment to a “market-based” system. A market-based system suggests more competition. Instead, what we have is something approaching a monopoly for many Albertans. The UCP promised a review of the transition to a capacity market that would determine which market would be best for Alberta, and through proposed electricity market changes has decided that we will remain an energy-only market.
Consumers in rural Alberta need electricity to produce the goods that power our biggest industries. Instead of regulating and approving continued rate increases from private multinational corporations, we need to drive competition and innovation that can push rates down and encourage growth and investment in rural-based industries and communities.
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What Will Drive Utility Revenue When Electricity Is Free?
AI-Powered Utility Customer Experience enables transparency, real-time pricing, smart thermostats, demand response, and billing optimization, helping utilities integrate distributed energy resources, battery storage, and microgrids while boosting customer satisfaction and reducing costs.
Key Points
An approach where utilities use AI and real-time data to personalize service, optimize billing, and cut energy costs.
✅ Real-time pricing aligns retail and wholesale market signals
✅ Device control via smart thermostats and home energy management
✅ Analytics reveal appliance-level usage and personalized savings
The latest electric utility customer satisfaction survey results from the American Customer Satisfaction Index (ACSI) Energy Utilities report reveal that nearly every investor-owned utility saw customer satisfaction go down from 2018 to 2019. Residential customers are sending a clear message in the report: They want more transparency and control over energy usage, billing and ways to reduce costs.
With both customer satisfaction and utility revenues on the decline, utilities are facing daunting challenges to their traditional business models amid flat electricity demand across many markets today. That said, it is the utilities that see these changing times as an opportunity to evolve that will become the energy leaders of tomorrow, where the customer relationship is no longer defined by sales volume but instead by a utility company's ability to optimize service and deliver meaningful customer solutions.
We have seen how the proliferation of centralized and distributed renewables on the grid has already dramatically changed the cost profile of traditional generation and variability of wholesale energy prices. This signals the real cost drivers in the future will come from optimizing energy service with things like batteries, microgrids and peer-to-peer trading networks. In the foreseeable future, flat electricity rates may be the norm, or electricity might even become entirely free as services become the primary source of utility revenue.
The key to this future is technological innovation that allows utilities to better understand a customer’s unique needs and priorities and then deliver personalized, well-timed solutions that make customers feel valued and appreciated as their utility helps them save and alleviates their greatest pain points.
I predict utilities that adopt new technologies focused on customer experience, aligned with key utility trends shaping the sector, and deliver continual service improvements and optimization will earn the most satisfied, most loyal customers.
To illustrate this, look at how fixed pricing today is applied for most residential customers. Unless you live in one of the states with deregulated utilities where most customers are free to choose a service provider in a competitive marketplace, as consumers in power markets increasingly reshape offerings, fixed-rate tariffs or time-of-use tariffs might be the only rate structures you have ever known, though new utility rate designs are being tested nationwide today. These tariffs are often market distortions, bearing little relation to the real-time price that the utility pays on the wholesale market.
It can be easy enough to compare the rate you pay as a consumer and the market rate that utilities pay. The California ISO has a public dashboard -- as do other grid operators -- that shows the real-time marginal cost of energy. On a recent Friday, for example, a buyer in San Francisco could go to the real-time market and procure electricity at a rate of around 9.5 cents per kilowatt-hour (kWh), yet a residential customer can pay the utility PG&E between 22 cents and 49 cents per kWh amid major changes to electric bills being debated, depending on usage.
The problem is that utility customers do not usually see this data or know how to interpret it in a way that helps add value to their service or drive down the cost.
This is a scenario ripe for innovation. Artificial intelligence (AI) technologies are beginning to be applied to give customers the transparency and control over the energy they desire, and a new type of utility is emerging using real-time pricing signals from wholesale markets to give households hassle-free energy savings. Evolve Energy in Texas is developing a utility service model, even as Texas utilities revisit smart home network strategies, that delivers electricity to consumers at real-time market prices and connects to smart thermostats and other connected devices in the home for simple monitoring and control -- all managed via an intuitive consumer app.
My company, Bidgely, partners with utilities and energy retailers all over the world to apply artificial intelligence and machine learning algorithms to customer data in order to bring transparency to their electricity bills, showing exactly where the customers’ money is going down to the appliance and offering personalized, actionable advice on how to save.
Another example is from energy management company Keewi. Its wireless outlet adaptors are revealing real-time energy usage information to Texas A&M dorm residents as well as providing students the ability to conserve energy through controlling items in their rooms from their smartphones.
These are but a few examples of innovations among many in play that answer the consumer demand for increased transparency and control over energy usage.
Electric service providers will be closely watching how consumers respond to AI-driven innovation, including providers in traditionally regulated markets that are exploring equitable regulation approaches now, to stay aligned with policy and customer expectations. While regulated utilities have no reason to fear that their customers might sign up with a competitor, they understand that the revenues from electricity sales are going down and the deployment of distributed energy resources is going up. Both trends were reflected in a March report from Bloomberg New Energy Finance (via ThinkProgress) that claimed unsubsidized storage projects co-located with solar or wind are starting to compete with coal and gas for dispatchable power. Change is coming to regulated markets, and some of that change can be attributed to customer dissatisfaction with utility service.
Like so many industries before, the utility-customer relationship is on track to become less about measuring unit sales and more about driving revenue through services and delivering the best customer value. Loyal customers are most likely to listen and follow through on the utility’s advice and to trust the utility for a wide range of energy-related products and services. Utilities that make customer experience the highest priority today will emerge tomorrow as the leaders of a new energy service era.
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Solar Now ‘cheaper Than Grid Electricity’ In Every Chinese City, Study Finds
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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Latvia eyes electricity from Belarus nuclear plant
Latvia Astravets electricity imports weigh AST purchases from the Belarusian nuclear plant, impacting the Baltic grid, Lithuania market, energy security, and cross-border trading as Latvia seeks to mitigate supply risks and stabilize power flows.
Key Points
Proposed AST purchases of power from Belarus's Astravets plant to bolster Baltic grid supply via Lithuania.
✅ AST evaluates imports to mitigate supply risk
✅ Energy could enter Lithuania via existing trading route
✅ Debate centers on nuclear safety and Baltic grid impacts
Latvia’s electricity transmission system operator, AST, is looking at the possibility of purchasing electricity from the soon-to-be completed Belarusian nuclear power plant in Astravets, at a time when Ukraine's electricity exports have resumed in the region, long criticised by the Lithuanian government, Belsat TV has reported.
According to the Latvian media, the Latvian government is seeking to mitigate the risk of a possible drop in electricity supplies amid price spikes in Ireland highlighting dispatchable power concerns, given that energy trading between the Baltic states and third parties is currently carried out only through the Belarusian-Lithuanian border, including Latvian imports from Lithuania.
If AST starts importing electricity from the Belarusian plant to Latvia, in a pattern similar to Georgia's electricity imports during peak demand, the energy is expected to enter the Lithuanian market as well.
Such cross-border flows also mirror responses to Central Asia's electricity shortages seen recently.
The Lithuanian government has repeatedly criticised the nuclear power over national security and environmental safety concerns, as well as a number of emergencies that took place during construction, particularly as Europe is losing nuclear power and confronting energy security challenges.
Debates over infrastructure and safety have also intensified by projects like power lines to reactivate Zaporizhzhia in Ukraine.
The first Astravets reactor, which is being built close to the Lithuanian border in the Hrodno region, is expected to be operational by the end of 2019, a year that saw Belgium's nuclear exports rise across Europe.
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BNEF Report: Wind and Solar Will Provide 50% of Electricity in 2050
BNEF 2019 New Energy Outlook projects surging renewable energy demand, aggressive decarbonization, wind and solar cost declines, battery storage growth, coal phase-out, and power market reform to meet Paris Agreement targets through 2050.
Key Points
Bloomberg's NEO 2019 forecasts power demand, renewables growth, and decarbonization pathways through 2050.
✅ Predicts wind/solar to ~50% of global electricity by 2050
✅ Foresees coal decline; Asia transitions slower than Europe
✅ Calls for power market reform and battery integration
In a report that examines the ways in which renewable energy demand is expected to increase, Bloomberg New Energy Finance (BNEF) finds that “aggressive decarbonization” will be required beyond 2030 to meet the temperature goals of the Paris Agreement on climate change.
Focusing on electricity, BNEF’s 2019 New Energy Outlook (NEO) predicts a 62% increase in global power demand, leading to global generating capacity tripling between now and 2050, when wind and solar are expected to make up almost 50% of world electricity, as wind and solar gains indicate, due to decreasing costs.
The report concludes that coal will collapse everywhere except Asia, and, by 2032, there will be more wind and solar electricity than coal-fired electricity. It forecasts that coal’s role in the global power mix will decrease from 37% today, as renewables surpass 30% globally, to 12% by 2050 with the virtual elimination of oil as a power-generating source.
Highlighting regional differences, the report finds that:
Western European economies are already on a strong decarbonization path due to carbon pricing and strong policy support, with offshore wind costs dropping bolstering progress;
by 2040, renewables will comprise 90% of the electricity mix in Europe, with wind and solar accounting for 80%;
the US, with low-priced natural gas, and China, with its coal-fired plants, will transition more slowly even as 30% from wind and solar becomes feasible; and
China’s power sector emissions will peak in 2026 and then fall by more than half over the next 20 years, as solar PV growth accelerates, with wind and solar increasing from 8% to 48% of total electricity generation by 2050.
Power markets must be reformed to ensure wind, solar and batteries are properly remunerated for their contributions to the grid.
The 2019 report finds that wind and solar now represent the cheapest option for adding new power-generating capacity in much of the world, amid record-setting momentum, which is expected to attract USD 13.3 trillion in new investment. While solar, wind, batteries and other renewables are expected to attract USD 10 trillion in investment by 2050, the report warns that curbing emissions will require other technologies as well.
Speaking about the report, Matthias Kimmel, NEO 2019 lead analyst, said solar photovoltaic modules, wind turbines and lithium-ion batteries are set to continue on aggressive cost reduction curves of 28%, 14% and 18%, respectively, for every doubling in global installed capacity. He explained that by 2030, energy generated or stored and dispatched by these technologies will undercut electricity generated by existing coal and gas plants.
To achieve this level of transition and decarbonization, the report stresses, power markets must be reformed to ensure wind, solar and batteries are “properly remunerated for their contributions to the grid.”
Additionally, the 2019 NEO includes a number of updates such as:
- new scenarios on global warming of 2°C above preindustrial levels, electrified heat and road transport, and an updated coal phase-out scenario;
- new sections on coal and gas power technology, the future grid, energy access, and costs related to decarbonization technology such as carbon capture and storage (CCS), biogas, hydrogen fuel cells, nuclear and solar thermal;
- sub-national results for China;
- the addition of commercial electric vehicles;
- an expanded air-conditioning analysis; and
- modeling of Brazil, Mexico, Chile, Turkey and Southeast Asia in greater detail.
Every year, the NEO compares the costs of competing energy technologies, informing projections like US renewables at one-fourth in the near term. The 2019 report brought together 65 market and technology experts from 12 countries to provide their views on how the market might evolve.
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As Alberta electricity generators switch to gas, power price cap comes under spotlight
Alberta Energy-Only Electricity Market faces capacity market debate, AESO price cap review, and coal-to-gas shifts by TransAlta and Capital Power, balancing reliability with volatility as investment signals evolve across Alberta's grid.
Key Points
An energy market paying generators only for electricity sold, with AESO oversight and a price cap guiding new capacity.
✅ AESO reviewing $999 per MW-h wholesale price cap.
✅ UCP retained energy-only; capacity market plan cancelled.
✅ TransAlta and Capital Power shift to coal-to-gas.
The Kenney government’s decision to cancel the redesign of Alberta’s electricity system to a capacity market won’t side-track two of the province’s largest power generators from converting coal-fired facilities to burn natural gas as part of Alberta’s shift from coal to cleaner energy overall.
But other changes could be coming to the province’s existing energy-only electricity market — including the alteration of the $999 per megawatt-hour (MW-h) wholesale price cap in Alberta.
The heads of TransAlta Corp. and Capital Power Corp. are proceeding with strategies to convert existing coal-fired power generating facilities to use natural gas in the coming years.
Calgary-based TransAlta first announced in 2017 that it would make the switch, as the NDP government was in the midst of overhauling the electricity sector and wind generation began to outpace coal in the province.
At the time, the Notley government planned to phase out coal-fired power by 2030, even as Alberta moved to retire coal by 2023 in practice, and shift Alberta into an electricity capacity market in 2021.
Such a move, made on the recommendation of the Alberta Electric System Operator (AESO), was intended to reduce price volatility and ensure system reliability.
Under the energy-only market, generators receive payments for electricity produced and sold into the grid. In a capacity market, generators are also paid for having power available on demand, regardless of how often they sell energy into the provincial grid.
The UCP government decided last month to ditch plans for a capacity market after consulting with the sector, saying it would be better for consumers.
On a conference call, TransAlta CEO Dawn Farrell said the company will convert coal-fired generating plants to burn gas, although it may alter the mix between simple conversions and switching to so-called “hybrid” plants.
(A hybrid conversion is a larger and more-expensive switch, as it includes installing a new gas turbine and heat-recovery steam generator, but it creates a highly efficient combined cycle unit.)
“Our view is fundamentally that carbon will be priced over the next 20 years no matter what,” she said Friday.
“We cannot get off coal fast enough in this company, and gas right now in Alberta is extremely inexpensive…
“So our coal-to-gas strategy is completely predicated on our belief that it’s not smart to be in carbon-intensive fuels for the future.”
Elsewhere in Canada, the Stop the Shock campaign has advocated for reviving coal power, underscoring ongoing policy debates.
The company said it’s planning the coal-to-gas conversion and re-powering of some or all of the units at its Keephills and Sundance facilities to gas-fired generation sometime between 2020 and 2023.
Similarly, Capital Power CEO Brian Vaasjo said the Edmonton-based company is moving ahead with a project that will allow it to burn both coal and natural gas at its Genesee generating station, even as Ontario’s energy minister sought to explore a halt to natural gas generation elsewhere.
In June, the company announced it would spend an estimated $50 million between 2019 and 2021 to allow it to use gas at the facility.
“What we’re doing is going to be dual fuel, so we will be able to operate 100 per cent natural gas or 100 per cent coal and everything in between,” Vaasjo said in an interview.
“You can expect to see we will be burning coal in the winter when natural gas prices are high, and we will be burning natural gas in summer when gas prices are real low.”
The transition comes as the government’s decision to stick with the energy-only market has been welcomed by players in the industry, and as Alberta's electricity future increasingly leans on wind resources.
A study by electricity consultancy EDC Associates found the capacity market would result in consumers paying an extra $1.4 billion in direct costs in 2021-22, as it required more generation to come online earlier than expected.
These additional costs would have accumulated to $10 billion by 2030, said EDC chief executive Duane-Reid Carlson.
For Capital Power, the decision to stick with the current system makes the province more investable in the future. Vaasjo said there was great uncertainty about the transition to a capacity market, and the possibility of rules shifting further.
Officials with Enmax Corp. said the city-owned utility would not have invested in future generation under the proposed capacity market.
“There is no short-term need (today) for new generation, so we’re just looking at the market and saying, ‘OK, as it evolves, we will see what happens,’” said Enmax vice-president Tim Boston.
Sticking with the energy-only market doesn’t mean Alberta will keep the existing rules.
In a July 25 letter, Alberta Energy Minister Sonya Savage directed AESO chair Will Bridge to examine if changes to the existing market are needed and report back by July 2020.
AESO, which manages the power grid, has been asked to investigate whether the current price cap of $999 per megawatt-hour (MW-h) should be changed.
The price ceiling hasn’t been altered since the energy-only market was implemented by the Klein government about two decades ago.
While allowing prices to go higher would increase volatility, reflecting lessons from Europe’s power crisis about scarcity pricing, during periods of rising demand and limited supply, it would send a signal to generators when investment in new generation is required, said Kent Fellows, a research associate at the University of Calgary’s School of Public Policy.
“Keeping the price (cap) too low could end up costing us more in the long run,” he said.
In a 2016 report, AESO said the province examined raising the price cap to $5,000 per MW-h, but “determined that it was unlikely to be successful in attracting investment due to increased price volatility.”
However, the amount of future generation that will be required in Alberta has been scaled back by the province.
In the United States, the Electricity Reliability Council of Texas (ERCOT) allows wholesale power prices in the state to climb to a cap of $9,000 per megawatt hours as demand rises — as it did Tuesday in the midst of a heat wave, according to Bloomberg.
Jim Wachowich, legal counsel for the Consumers’ Coalition of Alberta, said while few players are exposed to spot electricity prices, he has yet to be convinced raising the cap would be good for Albertans.
“Someone has to show me the evidence, and I suspect that’s what the minister has asked the AESO to do,” he said.
Generators say they believe some tinkering is needed to the energy-only market to ensure new generation is built when it’s required.
“The No. 1 change that the government has to … think about is in pricing,” added Farrell.
“If you don’t have enough of a price signal in an energy-only market to attract new capital, you won’t get new capital — and you’ll run up against the wall.”
