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FERC Grid Resiliency Pricing Opposition underscores industry groups, RTOs, and ISOs rejecting DOE's NOPR, warning against out-of-market subsidies for coal and nuclear, favoring competitive markets, reliability, and true grid resilience.

Key Points

Coalition urging FERC to reject DOE's NOPR subsidies, protecting reliability and competitive power markets.

✅ Industry groups, RTOs, ISOs oppose DOE NOPR

✅ PJM reports sufficient reliability and resilience

✅ Reject out-of-market aid to coal, nuclear

A diverse group of a dozen energy industry associations representing oil, natural gas, wind, solar, efficiency, and other energy technologies today submitted reply comments to the Federal Energy Regulatory Commission (FERC) continuing their opposition to the Department of Energy's (DOE) proposed rulemaking on grid resiliency pricing and electricity pricing changes within competitive markets, in the next step in this FERC proceeding.

Action by FERC, as lawmakers urge movement on aggregated DERs to modernize markets, is expected by December 11.

In these comments, this broad group of energy industry associations notes that most of the comments submitted initially by an unprecedented volume of filers, including grid operators whose markets would be impacted by the proposed rule, urged FERC not to adopt DOE'sproposed rule to provide out-of-market financial support to uneconomic coal and nuclear power plants in the wholesale electricity markets overseen by FERC.

Just a small set of interests - those that would benefit financially from discriminatory pricing that favors coal and nuclear plants - argued in favor of the rule put forward by DOE in its Notice of Proposed Rulemaking, or NOPR, as did coal and business interests in related regulatory debates. But even those interests - termed 'NOPR Beneficiaries' by the energy associations - failed to provide adequate justification for FERC to approve the rule, and their specific alternative proposals for implementing the bailout of these plants were just as flawed as the DOE plan, according to the energy industry associations.

'The joint comments filed today with partners across the energy spectrum reflect the overwhelming majority view that this proposed rulemaking by FERC is unprecedented and unwarranted, said Todd Foley, Senior Vice President, Policy & Government Affairs, American Council on Renewable Energy.

We're hopeful that FERC will rule against an anti-competitive distortion of the electricity marketplace and avoid new unnecessary initiatives that increase power prices for American consumers and businesses.'

In the new reply comments submitted in response to the initial comments filed by hundreds of stakeholders on or before October 23 - the energy industry associations made the following points: Despite hundreds of comments filed, no new information was brought forth to validate the assertion - by DOE or the NOPR Beneficiaries - that an emergency exists that requires accelerated action to prop up certain power plants that are failing in competitive electricity markets: 'The record in this proceeding, including the initial comments, does not support the discriminatory payments proposed' by DOE, state the industry groups.

Nearly all of the initial comments filed in the matter take issue with the DOE NOPR and its claim of imminent threats to the reliability and resilience of the electric power system, despite reports of coal and nuclear disruptions cited by some advocates: 'Of the hundreds of comments filed in response to the DOE NOPR, only a handful purported to provide substantive evidence in support of the proposal. In contrast, an overwhelming majority of initial comments agree that the DOE NOPR fails to substantiate its assertions of an immediate reliability or resiliency need related to the retirement of merchant coal-fired and nuclear generation.'

Grid operators filed comments refuting claims that the potential retirement of coal and nuclear plants which could not compete for economically present immediate or near-term challenges to grid management, even as a coal CEO criticism targeted federal decisions: 'Even the RTOs and ISOs themselves filed comments opposing the DOE NOPR, noting that the proposed cost-of-service payments to preferred generation would disrupt the competitive markets and are neither warranted nor justified.... Most notably, this includes PJM Interconnection, ... the RTO in which most of the units potentially eligible for payments under the DOE NOPR are located. PJM states that its region 'unquestionably is reliable, and its competitive markets have for years secured commitments from capacity resources that well exceed the target reserve margin established to meet [North American Electric Reliability Corp.] requirements.' And PJM analysis has confirmed that the region's generation portfolio is not only reliable, but also resilient.'

The need for NOPR Beneficiaries to offer alternative proposals reflects the weakness of DOE'srule as drafted, but their options for propping up uneconomic power plants are no better, practically or legally: 'Plans put forward by supporters of the power plant bailout 'acknowledge, at least implicitly, that the preferential payment structure proposed in the DOE NOPR is unclear, unworkable, or both. However, the alternatives offered by the NOPR Beneficiaries, are equally flawed both substantively and procedurally, extending well beyond the scope of the DOE NOPR.'

Citing one example, the energy groups note that the detailed plan put forward by utility FirstEnergy Service Co. would provide preferential payments far more costly than those now provided to individual power plants needed for immediate reasons (and given a 'reliability must run' contract, or RMR): 'Compensation provided under [FirstEnergy's proposal] would be significantly expanded beyond RMR precedent, going so far as to include bailing [a qualifying] unit out of debt based on an unsupported assertion that revenues are needed to ensure long-term operation.'

Calling the action FERC would be required to take in adopting the DOE proposal 'unprecedented,' the energy industry associations reiterate their opposition: 'While the undersigned support the goals of a reliable and resilient grid, adoption of ill-considered discriminatory payments contemplated in the DOE NOPR is not supportable - or even appropriate - from a legal or policy perspective.

About ACORE

The American Council on Renewable Energy (ACORE) is a national non-profit organization leading the transition to a renewable energy economy. With hundreds of member companies from across the spectrum of renewable energy technologies, consumers and investors, ACORE is uniquely positioned to promote the policies and financial structures essential to growth in the renewable energy sector. Our annual forums in Washington, D.C., New York and San Franciscoset the industry standard in providing important venues for key leaders to meet, discuss recent developments, and hear the latest from senior government officials and seasoned experts.

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

Key Points

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

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

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

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

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

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

Georgia Power's 2018 financial results.

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

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

Fuel rate lowered 17.2 percent

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

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

February bill credit due to tax law savings

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

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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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Brazil Energy Emergency Loan Package aims to bolster utilities via BNDES as coronavirus curbs electricity demand. Aneel and the Mines and Energy Ministry weigh measures while Eletrobras privatization and auctions face delays.

Key Points

An emergency plan supporting Brazilian utilities via BNDES and banks during coronavirus demand slumps and payment risks.

✅ Modeled on 2014-2015 sector loans via BNDES and private banks

✅ Addresses cash flow from lower demand and bill nonpayment

✅ Auctions and Eletrobras privatization delayed amid outbreak

Brazil’s government is considering an emergency loan package for energy distributors struggling with lower energy use and facing lost revenues because of the coronavirus outbreak, echoing strains seen elsewhere such as Germany's utility troubles during the energy crisis, an industry group told Reuters.

Marcos Madureira, president of Brazilian energy distributors association Abradee, said the package being negotiated by companies and the government could involve loans from state development bank BNDES or a pool of banks, but that the value of the loans and other details was not yet settled.

Also, Brazil’s Mines and Energy Ministry is indefinitely postponing projects to auction off energy transmission and generation assets planned for this year because of the coronavirus, even as the need for electricity during COVID-19 remained critical, it said in the Official Gazette.

The coronavirus outbreak will also delay the privatization of state-owned utility Eletrobras, its chief executive officer said on Monday.

The potential loan package under discussion would resemble a similar measure in 2014 and 2015 that offered about 22 billion reais ($4.2 billion) in loans to the sector as Brazil was entering its deepest recession on record, and drawing comparisons to a proposed Texas market bailout after a winter storm, Madureira said.

Public and private banks including BNDES, Caixa Economica Federal, Itau Unibanco and Banco Bradesco participated in those loans.

Three sources involved in the discussions said on condition of anonymity that the Mines and Energy Ministry and energy regulator Aneel were considering the matter.

Aneel declined to comment. The Mines and Energy Ministry and BNDES did not immediately respond to requests for comment.

Energy distributors worry that reduced electricity demand during COVID-19 could result in deep revenue losses.

The coronavirus has led to widespread lockdowns of non-essential businesses in Brazil, while citizens are being told to stay home. That is causing lost income for many hourly and informal workers in Brazil, who could be unable to pay their electricity bills, raising risks of pandemic power shut-offs for vulnerable households.

The government sees a loan package as a way to stave off a potential chain of defaults in the sector, a move discussed alongside measures such as a Brazil tax strategy on energy prices, one of the sources said.

On a conference call with investors about the company’s latest earnings, Eletrobras CEO Wilson Ferreira Jr. said privatization would be delayed, without giving any more details on the projected time scale.

The largest investors in Brazil’s energy distribution sector include Italy’s Enel, Spain’s Iberdrola via its subsidiary Neoenergia and China’s State Grid via CPFL Energia, with Chinese interest also evidenced by CTG's bid for EDP, as well as local players Energisa e Equatorial Energia. 

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EU Clean Energy Transition underscores the shift from fossil fuels to renewable energy, decarbonization, and hydrogen, as soaring gas prices and electricity volatility spur resilience, storage, and joint procurement across the single market.

Key Points

EU Clean Energy Transition shifts from fossil fuels to renewables, enhancing resilience and reducing price volatility.

✅ Cuts reliance on Russian gas and fossil imports

✅ Scales renewables, hydrogen, and energy storage

✅ Stabilizes electricity prices via market resilience

Soaring energy prices, described as Europe's energy nightmare, are a stark reminder of how dependent Europe is on fossil fuels and should serve to accelerate the shift towards renewable forms of energy.

"This experience today of the rising energy prices is a clear wake up call... that we should accelerate the transition to clean energy, wean ourselves off the fossil fuel dependency," a senior EU official told reporters as the European Commission unveiled a series of emergency electricity measures aimed at tackling the crisis.

The European Union is facing a sharp spike in energy prices, driven by increased global demand as the world recovers from the pandemic and lower-than-expected natural gas deliveries from Russia. Wholesale electricity prices have increased by 200% compared to the 2019 average, underscoring why rolling back electricity prices is tougher than it appears, according to the European Commission.

"Winter is coming and for many electricity costs are larger than they have been for a decade," Energy Commissioner Kadri Simson told reporters on Wednesday.

80 million European households struggle to stay warm
Wholesale gas prices — which have surged to record highs in France, Spain, Germany and Italy, amid reports of Germany's local utilities crying for help — are expected to remain high through the winter.

Prices are expected to fall in the spring, but remain higher than the average of past years, according to the Commission. Most EU countries rely on gas-fired power stations to meet electricity demand, and about 40% of that gas comes from Russia, with the EU outlining a plan to dump Russian energy to reduce this reliance, according to Eurostat.

Simson said that the Commission's initial assessment indicates that Russia's Gazprom has been fulfilling its long-term contracts "while providing little or no additional supply."
Kremlin spokesman Dmitry Peskov told journalists on Wednesday that Russia has increased gas supplies to Europe to the maximum possible level under existing contracts, but could not exceed those thresholds. "We can say that Russia is flawlessly fulfilling all contractual obligations," he said.

Measures EU states can take to help consumers and businesses cope with soaring electricity costs include emergency income support to households to help them pay their energy bills, alongside potential gas price cap strategies, state aid for companies, and targeted tax reductions. Member states can also temporarily delay bill payments and put in place processes to ensure that no one is disconnected from the grid.

Green energy the solution
The Commission also published a series of longer term measures the bloc should consider to reduce its dependence on fossil fuels and tackle energy price volatility, despite opposition from nine countries to electricity market reforms.

"Our immediate priority is to protect Europe's consumers, especially the most vulnerable," Simson said. "Second, we want to make our energy system better prepared and more resilient, so we don't have to face a similar situation in the future," she added.

Energy crisis could force more UK factories to close
This would require speeding up the green energy transition rather than slowing it down, Simson said. "We are not facing an energy price surge because of our climate policy or because renewable energy is expensive. We are facing it because the fossil fuel prices are spiking," she continued.

"The only long term remedy against demand shocks and price volatility is a transition to a green energy system."

Simson said she will propose to EU leaders a package of measures to decarbonize Europe's gas and hydrogen markets by 2050. Other measures to improve energy market stability could include increasing gas storage capacity and buying gas jointly at an EU level.

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Texas Electricity Prices are shifting as deregulation matures, with competitive market shopping lowering residential rates, narrowing gaps with regulated areas, and EIA data showing long term declines versus national averages across most Texans.

Key Points

Texas Electricity Prices are average residential rates in deregulated and regulated markets across the state.

✅ Deregulated areas saw 17.4% residential price declines since 2006

✅ Regulated zones experienced a 5.5% increase over the same period

✅ Competitive shopping narrowed the gap; Texas averaged below US

Shopping for electricity is becoming cheaper for most Texans, according to a new study from the Texas Coalition for Affordable Power. But for those who live in an area with only one electricity provider, prices have increased in a recent 10-year period, the study says.

About 85 percent of Texans can purchase electricity from a number of providers in a deregulated marketplace, while the remaining 15 percent must buy power from a single provider, often an electric cooperative, in their area.

The report from the Texas Coalition for Affordable Power, which advocates for cities and local governments and negotiates their power contracts, pulls information from the U.S. Energy Information Administration to compare prices for Texans in the two models. Most Texans could begin choosing their electricity provider in 2002.

Buying power tends to be more expensive for Texans who live in a part of the state with a deregulated electricity market. But that gap is continuing to shrink as Texans become more willing to shop for power, even as electricity complaints have periodically risen. In 2015, the gap “was the smallest since the beginning of deregulation,” according to the report.

Between 2006 and 2015, the last year for which data is available, average residential electric prices for Texans in a competitive market decreased by 17.4 percent, while average prices increased by 5.5 percent in the regulated areas, even as the Texas power grid has periodically faced stress.

“These residential price declines are promising, and show the retail electric market is maturing,” Jay Doegey, executive director for the Texas Coalition for Affordable Power, said in a statement. “We’re encouraged by the price declines, but more progress is needed.”

The study attributes the decline to the prevalence of “low-priced individual deals” in the competitive areas, while policymakers consider market reforms to bolster reliability.

Overall, the average price of electricity in Texas (which produces and consumes the most electricity in the U.S.) — including the price in the deregulated marketplace, for the third time in four years — was below the national average in 2015.

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