Regulators OK Alabama Power cut; more may follow

Crosbie Hydro Energy Action Plan outlines rate mitigation for Muskrat Falls, leveraging Nalcor oil revenues, export sales, Holyrood savings, and potential Hydro-Quebec taxation to keep Newfoundland and Labrador electricity rates near 14.67 cents/kWh.

Key Points

PC plan to cap post-Muskrat rates by using Nalcor revenues, exports, and savings, with optional Accord funds.

✅ $575.4M yearly to hold rates near 14.67 cents/kWh

✅ Sources: Nalcor oil $231M, Holyrood $150M, rates/dividends $123.4M

✅ Options: export sales, restructuring, Atlantic Accord, HQ tax

Newfoundland and Labrador PC Leader Ches Crosbie says Muskrat Falls won't drive up electricity rates, a goal consistent with an agreement to shield ratepayers from cost overruns, if he's elected premier.

According to Crosbie, who presented the party's Crosbie Hydro Energy Action Plan — acronym CHEAP — at a press conference Monday, $575.4 million is needed per year in order to keep rates from ballooning past 14.67 cents per kilowatt hour.

Here's where he thinks the money could come from:

• Hydro rates and dividends — $123.4 million
• Export sales — $40.1 million
• Nalcor restructuring — $30 million
• Holyrood savings — $150  million
• Nalcor oil revenue — $231 million

The oil money, Crosbie said, isn't going into government coffers but being invested into the offshore which, he said, is a good place for it.

"But the plan from the beginning around Muskrat Falls was that if there was need for it — for mitigation for rates — that those revenues and operating cash flows from Nalcor oil and gas would be available to be recycled into rate mitigation, as reflected in a recent financial update on the pandemic's impact. and that's what we're going to have to do," he said.

According to Crosbie, his numbers come from the preliminary stage of the Public Utilities Board process, even as rate mitigation talks have lacked public details.

This is a recent aerial view of the Muskrat Falls project in central Labrador. The project is more than 90 per cent complete, with first power forecast for late 2019, alongside Ottawa's $5.2B support for the project. (Nalcor)

"I'm telling you this is the best information available to anyone outside of government," he said. "We're working on what we can."

The PUB estimated Nalcor restructuring could save between $10 million and $15 million, according to Crosbie, but he figures there's "enough duplication and overpayment involved in the way things are now set up that we can find $30 million there."

Currently, provincial ratepayers pay about 12 cents per kilowatt hour as electricity users have started paying for Muskrat Falls costs.

Crosbie's $575.4-million figure would put rates at 14.67 cents per kilowatt-hour in 2021, where his plan pledges to keep them.

A recent Public Utilities Board Report says there's a potential $10 million to $15 million in savings from Nalcor, but Crosbie says he can find $30 million. (CBC)

"The promise is that Muskrat Falls, when it comes online — comes in service — will not increase your rates. Between now and when that happens there are rate increases already in the pipeline up to that level of [14.67 cents per kilowatt-hour] … so that is the baseline target rate at which rates will be kept.

"In other words, Muskrat will not drive up prices for electricity to consumers beyond that point."

In addition to those savings, Crosbie's plan outlined two further steps.

"We think it could be done out of the resources that I've just identified now, but if there's a problem with that, and as a temporary measure, we can use a modest amount of the Atlantic Accord review, fiscal review, revenues," he said.

Plan 'nothing new'

Premier Dwight Ball slammed the plan at the House of Assembly on Monday, saying it lacked insight.

"It was a copy and paste exercise," he told reporters. "There's nothing new in that plan. Not at all."

"We're not leaving any stone unturned of where the opportunity would be to actually generate revenue," he said.  "We are genuinely concerned about rate mitigation and we've got to get a plan in place."

Potential to tax Hydro-Québec

Crosbie also said there's potential to tax Hydro-Québec.

According to Crosbie, tax exemptions that expired in 2016 allow the province to tax exports from the Upper Churchill, which, he said, could result in "hundreds of millions or billions" in revenue.

"It's not my philosophy to immediately go and do that because that would generate litigation — who needs more of that? — but we do need to let Quebec know that we're very aware of that, and aware of that opportunity, and invite them to come talk about a whole host of issues," Crosbie said.

Crosbie said the tax would also have to be applied to domestic consumption.

"But so massive is the potential revenue from the Upper Churchill export that there would be ways to mitigate that and negate the effect of that on consumers in the province."

Crosbie said with the Atlantic Accord revenue, he could still present a balanced budget by 2022.

Related News

• Electricity Forum News

• Climate Change News

Texas wholesale electricity price spike disrupts ERCOT markets as Griddy and other retail energy providers face surge pricing; customers confront spot market exposure, fixed-rate plan switching, demand response appeals, and deep-freeze grid constraints across Texas.

Key Points

An extreme ERCOT market surge sending real-time rates to caps, exposing Griddy users and driving provider-switch pleas.

✅ Wholesale index plans pass through $9,000/MWh scarcity pricing.

✅ Retailers urge switching; some halt enrollments amid volatility.

✅ Demand response incentives and conservation pleas reduce load.

Some retail power companies in Texas are making an unusual plea to their customers amid a winter storm that has sent electricity prices skyrocketing: Please, leave us.

Power supplier, Griddy, told all 29,000 of its customers that they should switch to another provider as spot electricity prices soared to as high as $9,000 a megawatt-hour. Griddy’s customers are fully exposed to the real-time swings in wholesale power markets, so those who don’t leave soon will face extraordinarily high electricity bills.

“We made the unprecedented decision to tell our customers — whom we worked really hard to get — that they are better off in the near term with another provider,” said Michael Fallquist, chief executive officer of Griddy. “We want what’s right by our consumers, so we are encouraging them to leave. We believe that transparency and that honesty will bring them back” once prices return to normal.

Texas is home to the most competitive electricity market in America. Homeowners and businesses shopping for electricity churn power providers there like credit cards. In the face of such cutthroat competition, retail power providers in the region have grown accustomed to offering new customers incredibly low rates, incentives and, at least in Griddy’s case, unusual plans that allow customers to pay wholesale power prices as opposed to fixed ones.

The ruthless nature of the business has power traders speculating over which firms might have been caught short this week in the most dramatic run-up in spot power prices they’ve ever seen, and even talk of a market bailout has surfaced.

Not all companies are asking customers to leave. Others are just pleading for them to cut back to reduce blackout risks during extreme weather.

Pulse Power, based in The Woodlands, Texas, is offering customers a chance to win a Tesla Model 3, or free electricity for up to a year if they reduce their power usage by 10% in the coming days. Austin-based Bulb is offering $2 per kilowatts-hour, up to $200, for any energy customers save.

Griddy, however, is in a different position. Its service is simple — and controversial. Members pay a $9.99 monthly fee and then pay the cost of spot power traded on Texas’s power grid based on the time of day they use it. Earlier this month, that meant customers were saving money — and at times even getting paid — to use electricity at night. But in recent days, the cost of their power has soared from about 5 to 6 cents a kilowatt-hour to $1 or more. That’s when Fallquist knew it was time to urge his customers to leave.

“I can tell you it was probably one of the hardest decisions we’ve ever made,” he said. “Nobody ever wants to see customers go.”

Griddy isn’t the only one out there actively encouraging its customers to leave. People were posting similar pleas on Twitter over the holiday weekend from other Texas utilities and retail power providers offering everything from $100 rebates to waived cancellation fees as incentives to switch.

Customers may not even be able to switch. Rizwan Nabi, president of energy consultancy Riz Energy in Houston, said several power providers in Texas have told him they aren’t accepting new customers due to this week’s volatile prices, while grid improvements are debated statewide.

Hector Torres, an energy trader in Texas, who is a Griddy customer himself, said he tried to switch services over the long weekend but couldn’t find a company willing to take him until Wednesday, when the weather is forecast to turn warmer.

Related News

• Electricity Forum News

• Energy Policy News

Alberta Rate of Last Resort streamlines electricity regulations to stabilize the default rate, curb price volatility, and protect rural communities, low-income households, and seniors while preserving competition in the province's energy market.

Key Points

Alberta's Rate of Last Resort sets biennial default electricity prices, curbing volatility and protecting customers.

✅ Biennial default rate to limit price spikes

✅ Focus on rural, senior, and low-income customers

✅ Encourages competitive contracts and market stability

The Alberta government is overhauling its electricity regulations as part of a market overhaul aimed at reducing spikes in electricity prices for consumers and businesses. The new rules, set to be introduced this spring, are intended to stabilize the default electricity rate paid by many Albertans.

Background on the Rate of Last Resort

Albertans currently have the option to sign up for competitive contracts with electricity providers. These contracts can sometimes offer lower rates than the default electricity rate, officially known as the Regulated Rate Option (RRO). However, these competitive rates can fluctuate significantly. Currently, those unable to secure these contracts or those who are on the default rate are experiencing rising electricity prices and high levels of price volatility.

To address this, the Alberta government is renaming the default rate as the Rate of Last Resort designation (RoLR) under the new framework. This aims to reduce the sense of security that some consumers might associate with the current name, which the government feels is misleading.

Key Changes Under New Regulations

The new regulations, which include proposed market changes that affect pricing, focus on:

• Price Stabilization: Default electricity rates will be set every two years for each utility provider, providing greater predictability by enabling a consumer price cap and reducing the potential for extreme price swings.
• Rural and Underserved Communities: The changes are intended to particularly benefit rural Albertans and those on the default rate, including low-income individuals and seniors. These groups often lack access to the competitive rates offered by some providers and have been disproportionately affected by recent price increases.
• Promoting Economic Stability: The goal is to lower the cost of utilities for all Albertans, leading to overall lower costs of living and doing business. The government anticipates these changes will create a more attractive environment for investment and job creation.

Opposition Views

Critics argue that limiting the flexibility of prices for the default electricity rate could interfere with market dynamics and stifle market competition among providers. Some worry it could ultimately lead to higher prices in the long term. Others advocate directly subsidizing low-income households rather than introducing broad price controls.

Balancing Affordability and the Market

The Alberta government maintains that the proposed changes will strike a balance between ensuring affordable electricity for vulnerable Albertans and preserving a competitive energy market. Provincial officials emphasize that the new regulations should not deter consumers from seeking out competitive rates if they choose to.

The Path Ahead

The new electricity regulations are part of the Alberta government's broader Affordable Utilities Program, alongside electricity policy changes across the province. The legislation is expected to be introduced and debated in the provincial legislature this spring with the potential of coming into effect later in the year. Experts expect these changes will significantly impact the Alberta electricity market and ignite further discussion about how best to manage rising utility costs for consumers and businesses.

Related News

• Electricity Forum News

• Energy Policy News

Fukushima Daiichi decommissioning delay highlights TEPCO's revised timeline, spent fuel removal at Units 1 and 2, safety enclosures, decontamination, fuel debris extraction by robot arm, and contaminated water management under stricter radiation control.

Key Points

A government revised schedule pushing back spent fuel removal and decommissioning milestones at Fukushima Daiichi.

✅ TEPCO delays spent fuel removal at Units 1 and 2 for safety.

✅ Enclosures, decontamination, and robotics mitigate radioactive risk.

✅ Contaminated water cut target: 170 tons/day to 100 by 2025.

The Japanese government decided Friday to delay the removal of spent fuel from the Fukushima Daiichi nuclear power plant's Nos. 1 and 2 reactors by as much as five years, casting doubt on whether it can stick to its timeframe for dismantling the crippled complex.

The process of removing the spent fuel from the units' pools had previously been scheduled to begin in the year through March 2024.

In its latest decommissioning plan, the government said the plant's operator, Tokyo Electric Power Company Holdings Inc., will not begin the roughly two-year process (a timeline comparable to major reactor refurbishment programs seen worldwide) at the No. 1 unit at least until the year through March 2028 and may wait until the year through March 2029.

Work at the No. 2 unit is now slated to start between the year through March 2025 and the year through March 2027, it said.

The delay is necessary to take further safety precautions such as the construction of an enclosure around the No. 1 unit to prevent the spread of radioactive dust, and decontamination of the No. 2 unit, even as authorities have begun reopening previously off-limits towns nearby, the government said. It is the fourth time it has revised its schedule for removing the spent fuel rods.

"It's a very difficult process and it's hard to know what to expect. The most important thing is the safety of the workers and the surrounding area," industry minister Hiroshi Kajiyama told a press conference.

The government set a new goal of finishing the removal of the 4,741 spent fuel rods across all six of the plant's reactors by the year through March 2032, amid ongoing debates about the consequences of early nuclear plant closures elsewhere.

Plant operator TEPCO has started the process at the No. 3 unit and already finished at the No. 4 unit, which was off-line for regular maintenance at the time of the disaster. A schedule has yet to be set for the Nos. 5 and 6 reactors.

While the government maintained its overarching timeframe of finishing the decommissioning of the plant 30 to 40 years from the 2011 crisis triggered by a magnitude 9.0 earthquake and tsunami, there may be further delays, even as milestones at other nuclear projects are being reached worldwide.

The government said it will begin removing fuel debris from the three reactors that experienced core meltdowns in the year through March 2022, starting with the No. 2 unit as part of broader reactor decommissioning efforts.

The process, considered the most difficult part of the decommissioning plan, will involve using a robot arm, reflecting progress in advanced reactors technologies, to initially remove small amounts of debris, moving up to larger amounts.

The government also said it will aim to reduce the pace at which contaminated water at the plant increases. Water for cooling the melted cores, mixed with underground water, amounts to around 170 tons a day. That number will be brought down to 100 tons by 2025, it said.

The water is being treated to remove the most radioactive materials and stored in tanks on the plant's grounds, but already more than 1 million tons has been collected and space is expected to run out by the summer of 2022.

Related News

• Electricity Forum News

• Power Generation News

Iran Combined-Cycle Power Plants drive energy efficiency, cut greenhouse gases, and expand megawatt capacity by converting thermal units; MAPNA-led upgrades boost grid reliability, reduce fuel use, and accelerate electricity generation growth nationwide.

Key Points

Upgraded thermal plants that reuse waste heat to boost efficiency, cut emissions, and add capacity to Iran's grid.

✅ 27 thermal plants converted; 160 more viable units identified

✅ Adds 12,600 MW capacity via heat recovery steam generators

✅ Combined-cycle share: 31.2% of 80.509 GW capacity

Iran has turned six percent of its thermal power plans into combined cycle plants in order to reduce greenhouse gases and save energy, with potential to lift thermal plants' PLF under rising demand, IRNA reported, quoting an energy official.

According to the MAPNA Group’s Managing Director Abbas Aliabadi, so far 27 thermal power plants have been converted to combined-cycle ones, aligning with Iran’s push to transmit power to Europe as a regional hub.

“The conversion of a thermal power plant to a combined cycle one takes about one to two years, however, it is possible for us to convert all the country’s thermal power plants into combined cycle plants over a five-year period.

Currently, a total of 478 thermal power plants are operating throughout Iran, of which 160 units could be turned into combined cycle plants. In doing so, 12,600 megawatts will be added to the country’s power capacity, supporting ongoing exports such as supplying a large share of Iraq's electricity under existing arrangements.

Related cross-border work includes deals to rehabilitate Iraq's power grid that support future exchanges.

As reported by IRNA on Wednesday, Iran’s Nominal electricity generation capacity has reached 80,509 megawatts (80.509 gigawatts), and it is deepening energy cooperation with Iraq to bolster regional reliability. The country increased its electricity generation capacity by 500 megawatts (MW) compared to the last year (ended on March 20).

Currently, with a total generation capacity of 25,083 MW (31.2 percent) combined cycle power plants account for the biggest share in the country’s total power generation capacity followed by gas power plants generating 29.9 percent, amid global trends where renewables are set to eclipse coal and regional moves such as Israel's coal reduction signal accelerating shifts. EF/MA

Related News

• Electricity Forum News

• Power Generation News

Saamis Solar Park advances Medicine Hat's renewable energy strategy, as DP Energy secures AUC approval for North America's largest urban solar, repurposing contaminated land; capacity phased from 325 MW toward an initial 75 MW.

Key Points

A 325 MW solar project in Medicine Hat, Alberta, repurposing contaminated land; phased to 75 MW under city ownership.

✅ City acquisition scales capacity to 75 MW in phased build

✅ AUC approval enables construction and grid integration

✅ Reuses phosphogypsum-impacted land near fertilizer plant

DP Energy, an Irish renewable energy developer, has finalized the sale of the Saamis Solar Park—a 325 megawatt (MW) solar project—to the City of Medicine Hat in Alberta, Canada. This transaction marks the development of North America's largest urban solar initiative, while mirroring other Canadian clean-energy deals such as Canadian Solar project sales that signal market depth.

Project Development and Approval

DP Energy secured development rights for the Saamis Solar Park in 2017 and obtained a development permit in 2021. In 2024, the Alberta Utilities Commission (AUC) granted approval for construction and operation, reflecting Alberta's solar growth trends in recent years, paving the way for the project's advancement.

Strategic Acquisition by Medicine Hat

The City of Medicine Hat's acquisition of the Saamis Solar Park aligns with its commitment to enhancing renewable energy infrastructure. Initially, the project was slated for a 325 MW capacity, which would significantly bolster the city's energy supply. However, the city has proposed scaling the project to a 75 MW capacity, focusing on a phased development approach, and doing so amid challenges with solar expansion in Alberta that influence siting and timing. This adjustment aims to align the project's scale with the city's current energy needs and strategic objectives.

Utilization of Contaminated Land

An innovative aspect of the Saamis Solar Park is its location on a 1,600-acre site previously affected by industrial activity. The land, near Medicine Hat's fertilizer plant, was previously compromised by phosphogypsum—a byproduct of fertilizer production. DP Energy's decision to develop the solar park on this site exemplifies a productive reuse of contaminated land, transforming it into a source of clean energy.

Benefits to Medicine Hat

The development of the Saamis Solar Park is poised to deliver multiple benefits to Medicine Hat:

• Energy Supply Enhancement: The project will augment the city's energy grid, much like municipal solar projects that provide local power, providing a substantial portion of its electricity needs.

• Economic Advantages: The city anticipates financial savings by reducing carbon tax liabilities, as lower-cost solar contracts have shown competitiveness, through the generation of renewable energy.

• Environmental Impact: By investing in renewable energy, Medicine Hat aims to reduce its carbon footprint and contribute to global sustainability efforts.

DP Energy's Ongoing Commitment

Despite the sale, DP Energy maintains a strong presence in Canada, where Indigenous-led generation is expanding, with a diverse portfolio of renewable energy projects, including solar, onshore wind, storage, and offshore wind initiatives. The company continues to focus on sustainable development practices, striving to minimize environmental impact while maximizing energy production efficiency.

The transfer of the Saamis Solar Park to the City of Medicine Hat represents a significant milestone in renewable energy development. It showcases effective land reutilization, strategic urban planning, and a shared commitment to sustainable energy solutions, aligning with federal green electricity procurement that reinforces market demand. This project not only enhances the city's energy infrastructure but also sets a precedent for integrating large-scale renewable energy projects within urban environments.

Related News

• Electricity Forum News

• Renewable Energy News