FERC to suspend JP MorganÂ’s market-based rate authority

By Federal Energy Regulatory Commission


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The Federal Energy Regulatory Commission recently suspended the electric market-based rate authority of JP Morgan Ventures Energy Corp. for submitting false information to the Commission.

The suspension prohibits JP Morgan Ventures from selling power at market-based rates for six months effective April 1, 2013.

FERC is suspending JP Morgan VenturesÂ’ market-based sales rate authority because the company made factual misrepresentations and omitted material information over the course of several months of communications with the California Independent System Operator California ISO and in filings to the Commission in connection with requests for information involving bidding activities in the California market.

The nature of JP Morgan VenturesÂ’ violations is critically important in this case, FERC said. The Commission grants market-based rate authority to companies on the presumption that they will not engage in fraud, deception or misrepresentation. The provision of false, misleading or inaccurate information undermines the integrity of the FERC decision-making process, the smooth operation of markets and FERCÂ’s ability to ensure just and reasonable rates for customers. The Commission continuously has warned market participants of the consequences associated with failing to abide by FERC rules and regulations.

Under FERCÂ’s decision, the suspension delay to April 2013 will give the California ISO and its market participants time to take necessary steps to maintain system reliability during the suspension period. It also will give JP Morgan Ventures time to make alternative arrangements to fulfill any existing contractual obligations.

During the suspension period, JP Morgan Ventures will only be allowed to participate in wholesale electricity markets by either scheduling quantities of energy products without an associated price or by specifying a zero-price in its offer as provided in the pertinent tariffs. JP Morgan VenturesÂ’ rate will be capped at the higher of the applicable locational marginal price or its default energy bid. Such a cap will ensure that load-serving entities have access to adequate generating capacity to serve demand. Alternatively, JP Morgan Ventures would have the option to request cost-based rates.

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Covid-19 puts brake on Turkey’s solar sector

Turkey Net Metering Suspension freezes regulator reviews, stalling rooftop solar permits and grid interconnections amid COVID-19, pausing licensing workflows, EPC pipelines, and electricity bill credits that drive commercial and household prosumer adoption.

 

Key Points

A pause on technical reviews freezing net metering applications and slowing rooftop solar deployment in Turkey.

✅ Monthly technical committee meetings suspended indefinitely

✅ Rooftop solar permits and grid interconnections on hold

✅ EPC firms urge remote evaluations for transparency

 

The decision by the Turkish Energy Market Regulatory Authority to halt part of the system of processing net metering applications risks bringing the only vibrant segment of the nation’s solar industry to a grinding halt, a risk amplified as global renewables face Covid-19 disruptions across markets.

The regulator has suspended monthly meetings of the committee which makes technical evaluations of net metering applications, citing concerns about the spread of Covid-19, which has already seen U.S. utility-scale solar face delays this year.

The availability of electricity bill credits for net-metering-approved households which inject surplus power into the grid, similar to how British households can sell power back to energy firms, has seen the rooftop projects the scheme is typically associated with remain the only source of new solar generation capacity in Turkey of late.

However the energy regulator’s decision to suspend technical evaluation committee meetings until further notice has seen the largely online licensing process for new solar systems practically cease; by contrast, Berlin is being urged to remove PV barriers to keep projects moving.

The Turkish solar industry has claimed the move is unnecessary, with solar engineering, procurement and construction services businesses pointing out the committee could meet to evaluate projects remotely. It has been argued such a move would streamline the application process and make it more transparent, regardless of the current public health crisis.

 

Net metering 

Turkey introduced net metering for rooftop installations last May and pv magazine has reported the specifics of the scheme, amid debates like New England's grid upgrade costs over who pays.

National grid operator Teias confirmed recently the country added 109 MW of new solar capacity in the first quarter, most of it net-metered rooftop systems, even as Australian distributors warn excess solar can strain local networks.

Net metering has been particularly attractive to commercial electricity users because the owners of small and medium-sized businesses pay more for power, as solar reshapes electricity prices in Northern Europe, than either households or large scale industrial consumers.

Until the recent technical committee decision by the regulator, the chief obstacle to net metering adoption had been the nation’s economic travails. The Turkish lira has lost 14% of its value since January and around 36% over the last two years. The central bank has been using its foreign reserves to support state lenders and the lira but the national currency slipped near an all-time low on Friday and foreign analysts predict the central bank reserves could run dry in July.

The level of exports shipped last month was down 41% on April last year and imports fell 28% by the same comparison, further depressing the willingness of companies to make capital investments such as rooftop solar.

 

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Alberta set to retire coal power by 2023, ahead of 2030 provincial deadline

Alberta coal phaseout accelerates as utilities convert to natural gas, cutting emissions under TIER regulations and deploying hydrogen-ready, carbon capture capable plants, alongside new solar projects in a competitive, deregulated electricity market.

 

Key Points

A provincewide shift from coal to natural gas and renewables, cutting power emissions years ahead of the 2030 target.

✅ Capital Power, TransAlta converting coal units to gas

✅ TIER pricing drives efficiency, carbon capture readiness

✅ Hydrogen-ready turbines, solar projects boost renewables

 

Alberta is set to meet its goal to eliminate coal-fired electricity production years earlier than its 2030 target, amid a broader shift to cleaner energy in the province, thanks to recently announced utility conversion projects.

Capital Power Corp.’s plan to spend nearly $1 billion to switch two coal-fired power units west of Edmonton to natural gas, and stop using coal entirely by 2023, was welcomed by both the province and the Pembina Institute environmental think-tank.

In 2014, 55 per cent of Alberta’s electricity was produced from 18 coal-fired generators. The Alberta government announced in 2015 it would eliminate emissions from coal-fired electricity generation by 2030.

Dale Nally, associate minister of Natural Gas and Electricity, said Friday that decisions by Capital Power and other utilities to abandon coal will be good for the environment and demonstrates investor confidence in Alberta’s deregulated electricity market, where the power price cap has come under scrutiny.

He credited the government’s Technology Innovation and Emissions Reduction (TIER) regulations, which put a price on industrial greenhouse gas emissions, as a key factor in motivating the conversions.

“Capital Power’s transition to gas is a great example of how private industry is responding effectively to TIER, as it transitions these facilities to become carbon capture and hydrogen ready, which will drive future emissions reductions,” Nally said in an email.

Capital Power said direct carbon dioxide emissions at its Genesee power facility near Edmonton will be about 3.4 million tonnes per year lower than 2019 emission levels when the project is complete.

It says the natural gas combined cycle units it’s installing will be the most efficient in Canada, adding they will be capable of running on 30 per cent hydrogen initially, with the option to run on 95 per cent hydrogen in future with minor investments.

In November, Calgary-based TransAlta Corp. said it will end operations at its Highvale thermal coal mine west of Edmonton by the end of 2021 as it switches to natural gas at all of its operated coal-fired plants in Canada four years earlier than previously planned.

The Highvale surface coal mine is the largest in Canada, and has been in operation on the south shore of Wabamun Lake in Parkland County since 1970.

The moves by the two utilities and rival Atco Ltd., which announced three years ago it would convert to gas at all of its plants by this year, mean significant emissions reduction and better health for Albertans, said Binnu Jeyakumar, director of clean energy for Pembina.

“Alberta’s early coal phaseout is also a great lesson in good policy-making done in collaboration with industry and civil society,” she said.

“As we continue with this transformation of our electricity sector, it is paramount that efforts to support impacted workers and communities are undertaken.”

She added the growing cost-competitiveness of renewable energy, such as wind power, makes coal plant retirements possible, applauding Capital Power’s plans to increase its investments in solar power.

In Ontario, clean power policy remains a focus as the province evaluates its energy mix.

The company announced it would go ahead with its 75-megawatt Enchant Solar power project in southern Alberta, investing between $90 million and $100 million, and that it has signed a 25-year power purchase agreement with a Canadian company for its 40.5-MW Strathmore Solar project now under construction east of Calgary.
 

 

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Duke Energy Florida to build its largest battery storage projects yet

Duke Energy Florida battery storage will add 22 MW across Trenton, Cape San Blas and Jennings, improving grid reliability, outage resilience, enabling peak shaving and deferring distribution upgrades to increase efficiency and customer value.

 

Key Points

Three lithium battery projects totaling 22 MW to improve Florida grid reliability, outage resilience and efficiency.

✅ 22 MW across Trenton, Cape San Blas and Jennings sites

✅ Enhances outage resilience and grid reliability

✅ Defers costly distribution upgrades and improves efficiency

 

Duke Energy Florida (DEF) has announced three battery energy storage projects, totaling 22 megawatts, that will improve overall reliability and support critical services during power outages.

Duke Energy, the nation's largest electric utility, unveils its new logo. (PRNewsFoto/Duke Energy) (PRNewsfoto/Duke Energy)

Collectively, the storage facilities will enhance grid operations, increase efficiencies and improve overall reliability for surrounding communities, with virtual power plant programs offering a model for coordinating distributed resources.

They will also provide important backup generation during power outages, a service that is becoming increasingly important with the number and intensity of storms that have recently impacted the state.

As the grid manager and operator, DEF can maximize the versatility of battery energy storage systems (BESS) to include multiple customer and electric system benefits such as balancing energy demand, managing intermittent resources, increasing energy security and deferring traditional power grid upgrades.

These benefits help reduce costs for customers and increase operational efficiencies.

The 11-megawatt (MW) Trenton lithium-based battery facility will be located 30 miles west of Gainesville in Gilchrist County. The energy storage project will continue to improve power reliability using newer technologies.

The 5.5-MW Cape San Blas lithium-based battery facility will be located approximately 40 miles southeast of Panama City in Gulf County. The project will provide additional power capacity to meet our customers' rising energy demand in the area. This project is an economical alternative to replacing distribution equipment necessary to accommodate local load growth.

The 5.5-MW Jennings lithium-based battery facility will be located 1.5 miles south of the Florida-Georgia border in Hamilton County. The project will continue to improve power reliability through energy storage as an alternative solution to installing new and more costly distribution equipment.

Currently the company plans to complete all three projects by the end of 2020.

"These battery projects provide electric system benefits that will help improve local reliability for our customers and provide significant energy services to the power grid," said Catherine Stempien, Duke Energy Florida state president. "Duke Energy Florida will continue to identify opportunities in battery storage technology which will deliver efficiency improvements to our customers."

 

Additional renewables projects

As part of DEF's commitment to renewables, the company is investing an estimated $1 billion to construct or acquire a total of 700 MW of cost-effective solar power facilities and 50 MW of battery storage through 2022.

Duke Energy is leading the industry deployment of battery technology, with SDG&E's Emerald Storage project underscoring broader adoption across the sector today. Last fall, the company and University of South Florida St. Petersburg unveiled a Tesla battery storage system that is connected to a 100-kilowatt (kW) solar array – the first of its kind in Florida.

This solar-battery microgrid system manages the energy captured by the solar array, situated on top of the university's parking garage, and similar low-income housing microgrid financing efforts are expanding access. The solar array was constructed three years ago through a $1 million grant from Duke Energy. The microgrid provides a backup power source during a power outage for the parking garage elevator, lights and electric vehicle charging stations. Click here to learn more.

In addition to expanding its battery storage technology and solar investments, DEF is investing in transportation electrification to support the growing U.S. adoption of electric vehicles (EV), including EV charging infrastructure, 530 EV charging stations and a modernized power grid to deliver the diverse and reliable energy solutions customers want and need.

 

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Changes Coming For Ontario Electricity Consumers

Ontario Electricity Billing Changes include OEB-backed shifts to time-of-use or tiered pricing, landlord blanket elections, LDC implementation guidance, a customer choice webpage with a bill calculator, and ENDM rate mitigation messaging.

 

Key Points

They are OEB measures enabling TOU-to-tiered switching, landlord elections, LDC guidance, and ENDM bill messages.

✅ Option to switch from TOU to tiered pricing

✅ Landlord blanket elections on tenant turnover

✅ ENDM-led bill info and rate mitigation messaging

 

By David Stevens, Aird & Berlis LLP

Electricity consumers in Ontario may see a couple of electricity rate changes in their bills in the coming months.

First, as we have already discussed, as of November 1, 2020, regulated price plan customers will have the option to switch to "tiered pricing" instead of time-of-use (TOU) pricing structures. Those who switch to "tiered pricing" will see changes in their electricity bills.

The Ontario Energy Board (OEB) has now issued final amendments to the Standard Supply Service Code to support the customer election process necessary to switch from TOU pricing to tiered pricing. The main change from what was already published in previous OEB notices is that landlords will be permitted to make a "blanket election" between TOU pricing and tiered pricing that will apply each time a tenant's account reverts back to the landlord on turnover of the rental unit. In its most recent notice, the OEB acknowledges that implementing the new customer billing option as of Nov. 1 (less than two months from now) will be challenging and directs Local Distribution Companies (LDCs) who cannot meet this date to be immediately in touch with the OEB. Finally, the OEB indicates that there will be a dedicated "customer choice webpage for consumers, including a bill calculator" in place by early October.

Second, as of January 1, 2021 low-volume consumers will see additional messaging on their bills to inform them of available rate mitigation programs.

A recent proposal posted on Ontario's Regulatory Registry indicates that the Ministry of Energy, Northern Development and Mines (ENDM) proposes that LDCs and Utility Sub-Meter Providers will be required to include a new on-bill message for low-volume consumers that "will direct customers to ENDM's new web page for further information about how the province provides financial support to electricity consumers." This new requirement is planned to be in place as of January 1, 2021. In conjunction with this requirement, the ENDM plans to launch a new web page that will provide "up-to-date information about electricity bills," including information about rate mitigation programs available to consumers. Parties are invited to submit comments on the ENDM proposal by October 5, 2020.

 

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U.S Bans Russian Uranium to Bolster Domestic Industry

U.S. Russian Uranium Import Ban reshapes nuclear fuel supply, bolstering energy security, domestic enrichment, and sanctions policy while diversifying reactor-grade uranium sources and supply chains through allies, waivers, and funding to sustain utilities and reliability.

 

Key Points

A U.S. law halting Russian uranium imports to boost energy security diversify nuclear fuel and revive U.S. enrichment.

✅ Cuts Russian revenue; reduces geopolitical risk.

✅ Funds U.S. enrichment; supports reactor fuel supply.

✅ Enables waivers to prevent utility shutdowns.

 

In a move aimed at reducing reliance on Russia and fostering domestic energy security for the long term, the United States has banned imports of Russian uranium, a critical component of nuclear fuel. This decision, signed into law by President Biden in May 2024, marks a significant shift in the U.S. nuclear fuel supply chain and has far-reaching economic and geopolitical implications.

For decades, Russia has been a major supplier of enriched uranium, a processed form of uranium used to power nuclear reactors. The U.S. relies on Russia for roughly a quarter of its enriched uranium needs, feeding the nation's network of 94 nuclear reactors operated by utilities which generate nearly 20% of the country's electricity. This dependence has come under scrutiny in recent years, particularly following Russia's invasion of Ukraine.

The ban on Russian uranium is a multifaceted response. First and foremost, it aims to cripple a key revenue stream for the Russian government. Uranium exports are a significant source of income for Russia, and by severing this economic tie, the U.S. hopes to weaken Russia's financial capacity to wage war.

Second, the ban serves as a national energy security measure. Relying on a potentially hostile nation for such a critical resource creates vulnerabilities. The possibility of Russia disrupting uranium supplies, either through political pressure or in the event of a wider conflict, is a major concern. Diversifying the U.S. nuclear fuel supply chain mitigates this risk.

Third, the ban is intended to revitalize the domestic uranium mining and enrichment industry, building on earlier initiatives such as Trump's uranium order announced previously. The U.S. has historically been a major uranium producer, but environmental concerns and competition from cheaper foreign sources led to a decline in domestic production. The ban, coupled with $2.7 billion in federal funding allocated to expand domestic uranium enrichment capacity, aims to reverse this trend.

The transition away from Russian uranium won't be immediate. The law includes a grace period until mid-August 2024, and waivers can be granted to utilities facing potential shutdowns if alternative suppliers aren't readily available. Finding new sources of enriched uranium will require forging partnerships with other uranium-producing nations like Kazakhstan, Canada on minerals cooperation, and Australia.

The long-term success of this strategy hinges on several factors. First, successfully ramping up domestic uranium production will require overcoming regulatory hurdles and addressing environmental concerns, alongside nuclear innovation to modernize the fuel cycle. Second, securing reliable alternative suppliers at competitive prices is crucial, and supportive policy frameworks such as the Nuclear Innovation Act now in law can help. Finally, ensuring the continued safe and efficient operation of existing nuclear reactors is paramount.

The ban on Russian uranium is a bold move with significant economic and geopolitical implications. While challenges lie ahead, the potential benefits of a more secure and domestically sourced nuclear fuel supply chain are undeniable. The success of this initiative will be closely watched not only by the U.S. but also by other nations seeking to lessen their dependence on Russia for critical resources.

 

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West Coast consumers won't benefit if Trump privatizes the electrical grid

BPA Privatization would sell the Bonneville Power Administration's transmission lines, raising FERC-regulated grid rates for ratepayers, impacting hydropower and the California-Oregon Intertie under the Trump 2018 budget proposal in the Pacific Northwest region.

 

Key Points

Selling Bonneville's transmission grid to private owners, raising rates and returns, shifting costs to ratepayers.

✅ Trump 2018 budget targets BPA transmission assets for sale.

✅ Higher capital costs, taxes, and profit would raise transmission rates.

✅ California-Oregon Intertie and hydropower flows face price impacts.

 

President Trump's 2018 budget proposal is so chock-full of noxious elements — replacing food stamps with "food boxes," drastically cutting Medicaid and Medicare, for a start — that it's unsurprising that one of its most misguided pieces has slipped under the radar.

That's the proposal to privatize the government-owned Bonneville Power Administration, which owns about three-quarters of the high-voltage electric transmission lines in a region that includes California, Washington state and Oregon, serving more than 13.5 million customers. By one authoritative estimate, any such sale would drive up the cost of transmission by 26%-44%.

The $5.2-billon price cited by the Trump administration, moreover, is nearly 20% below the actual value of the Bonneville grid — meaning that a private buyer would pocket an immediate windfall of $1.2 billion, at the expense of federal taxpayers and Bonneville customers.

Trump's plan for Portland, Ore.-based Bonneville is part of a larger proposal to sell off other government-owned electricity bodies, including the Colorado-based Western Area Power Administration and the Oklahoma-based Southwestern Power Administration. But Bonneville is by far the largest of the three, accounting for nearly 90% of the total $5.8 billion the budget anticipates collecting from the sales. The proposal is also part of the administration's

Both plans are said to be politically dead-on-arrival in Washington. But they offer a window into the thinking in the Trump White House.

"The word 'muddle' comes to mind," says Robert McCullough, a respected Portland energy consultant, referring to the justification for the privatization sale included in the Trump budget.

The White House suggests that selling the Bonneville grid would result in lower costs. But that narrative, McCullough wrote in a blistering assessment of the proposal, "displays a severe lack of understanding about the process of setting transmission rates."

McCullough's assessment is an update of a similar analysis he performed when the privatization scheme was first raised by the Trump administration last year. In that analysis issued in June, McCullough said the proposal "raises the question of why these valuable assets would be sold at a discount — and who would get the benefit of the discounted price."

The implications of a sale could be dire for Californians. Bonneville is the majority owner of the California-Oregon Intertie, an electrical transmission system that carries power, including Columbia River-generated hydropower and other clean-energy generation in British Columbia that supports the regional exchange, south to California in the summer and excess California generation to the Pacific Northwest in the winter.

But the idea has drawn fire throughout the region. When it was first broached last year, the Public Power Council, an association of utilities in the Northwest, assailed it as an apparent "transfer of value from the people of the Northwest to the U.S. Treasury," drawing parallels to Manitoba Hydro governance issues elsewhere.

The region's political leaders had especially harsh words for the idea this time around. "Oregonians raised hell last year when Trump tried to raise power bills for Pacific Northwesterners by selling off Bonneville Power, and yet his administration is back at it again," Sen. Ron Wyden (D-Ore.) said after the idea reappeared. "Our investment shouldn't be put up for sale to free up money for runaway military spending or tax cuts for billionaires." Sen. Maria Cantwell (D-Wash.) promised in a statement to work to "stop this bad idea in its tracks."

The notion of privatizing Bonneville predates the Trump administration; it was raised by Bill Clinton and again by George W. Bush, who thought the public would gain if the administration could sell its power at market rates. Both initiatives failed.

The same free-enterprise ideology underlies the Trump proposal. Privatizing the transmission lines "encourages a more efficient allocation of economic resources and mitigates unnecessary risk to taxpayers," the budget asserts. "Ownership of transmission assets is best carried out by the private sector where there are appropriate market and regulatory incentives."

But that's based on a misunderstanding of how transmission rates are set, McCullough says. Transmission is essentially a monopoly enterprise, with rates overseen by the Federal Energy Regulatory Commission based on the grid's costs, and with federal scrutiny of public utilities such as the TVA underscoring that oversight. There's very little in the way of market "incentives" involved in transmission, since no one has come forward to build a competing grid.

Those include the owners' cost of capital — which would be much higher for a private owner than a government agency, McCullough observes, as Hydro One investor uncertainty demonstrates in practice. A private owner, unlike the government-owned Bonneville, also would owe federal income taxes, which would be passed on to consumers.

Then there's the profit motive. Bonneville "currently sells and delivers its power at cost," McCullough wrote last year. "Under a private regime, an investor-owned utility would likely charge a higher rate of return, a pattern seen when UK network profits drew regulatory rebukes."

None of these considerations appears to have been factored into the White House budget proposal. "Either there's an unsophisticated person at the Office of Management and Budget thinking up these numbers himself," McCullough told me, "or there would seem to be ongoing negotiations with an unidentified third party." No such buyer has emerged in the past, however.

What's left is a blind faith in the magic of the market, compounded by ignorance about how the transmission market operates. Put it together, and there's reason to wonder if Trump is even serious about this plan.

 

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