Regulators may OK $10 monthly NV Energy rate hike

CPUC Exit Fee Increase for CCAs adjusts the PCIA, affecting utilities, San Diego ratepayers, renewable energy procurement, customer equity, and cost allocation, while providing regulatory certainty for Community Choice Aggregation programs and clean energy goals.

Key Points

A CPUC-approved change raising PCIA exit fees paid by CCAs to utilities, balancing cost shifts and customer equity.

✅ PCIA rises from about 2.5c to roughly 4.25c per kWh in San Diego

✅ Aims to reduce cost shifts and protect non-CCA customers

✅ Offers regulatory certainty for CCA launches and clean energy goals

The California Public Utilities Commission approved an increase on the exit fees charged to customers who take part in Community Choice Aggregation -- government-run alternatives to traditional utilities like San Diego Gas & Electric.

After reviewing two competing exit fee proposals, all five commissioners voted Thursday in favor of an adjustment that many CCA advocates predicted could hamper the growth of the community choice movement.

But minutes after the vote was announced, one of the leading voices in favor of the city San Diego establishing its own CCA said the decision was good news because it provides some regulatory certainty.

"For us in San Diego, it's a green light to move forward with community choice," said Nicole Capretz, executive director of the Climate Action Campaign. "For us, it's let's go, let's launch and let's give families a choice. We no longer have to wait."

Under the CCA model, utilities still maintain transmission and distribution lines (poles and wires, etc.) and handle customer billing. But officials in a given local government entity make the final decisions about what kind of power sources are purchased.

Once a CCA is formed, its customers must pay an exit fee -- called a Power Charge Indifference Adjustment -- to the legacy utility serving that particular region. The fee is included in customers' monthly bills.

The fee is required to offset the costs of the investments utilities made over the years for things like natural gas power plants, renewable energy facilities and other infrastructure.

Utilities argue if the exit fee is set too low, it does not fairly compensate them for their investments; if it's too high, CCAs complain it reduces the financial incentive for their potential customers.

The Public Utilities Commission chose to adopt a proposal that some said was more favorable to utilities, leading to complaints from CCA boosters.

"We see this will really throw sand in the gears in our ability to do things that can move us toward (climate change) goals," Jim Parks, staff member of Valley Clean Energy, a CCA based in Davis, said before the vote.

Commissioner Carla Peterman, who authored the proposal that passed, said she supports CCAs but stressed the commission has a "legal obligation" to make sure increased costs are not shouldered by "customers who do not, or cannot, join a CCA. Today's proposal ensures a more level playing field between customers."

As for what the vote means for the exit fee in San Diego, Peterman's office earlier in the week estimated the charge would rise from 2.5 cents a kilowatt-hour to about 4.25 cents.

The Clear the Air Coaltion, a San Diego County group critical of CCAs, said the newly established exit fee -- which goes into effect starting next year -- is "a step in the direction."

But the group, which includes the San Diego Regional Chamber of Commerce, the San Diego County Taxpayers Association and lobbyists for Sempra Energy (the parent company of SDG&E), repeated concerns it has brought up before.

"If the city of San Diego decides to get into the energy business this decision means ratepayers in National City, Chula Vista, Carlsbad, Imperial Beach, La Mesa, El Cajon and all other neighboring communities would see higher energy bills, and San Diego taxpayers would be faced with mounting debt," coalition spokesman Tony Manolatos said in an email.

CCA supporters say community choice is critical in ensuring San Diego meets the pledge made by Mayor Kevin Faulconer to adopt the city's Climate Action Plan, mandating 100 percent of the city's electricity needs must come from renewable sources by 2035.

Now attention turns to Faulconer, who promised to make a decision on bringing a CCA proposal to the San Diego City Council only after the utilities commission made its decision.

A Faulconer spokesman said Thursday afternoon that the vote "provides the clarity we've been waiting for to move forward" but did not offer a specific time table.

"We're on schedule to reach Mayor Faulconer's goal of choosing a pathway that achieves our renewable energy goals while also protecting ratepayers, and the mayor looks forward to making his recommendation in the next few weeks," said Craig Gustafson, a Faulconer spokesman, in an email.

A feasibility study released last year predicted a CCA in San Diego has the potential to deliver cheaper rates over time than SDG&E's current service, while providing as much as 50 percent renewable energy by 2023 and 80 percent by 2027.

"The city has already figured out we are still capable of launching a program, having competitive, affordable rates and finally offering families a choice as to who their energy provider is," said Capretz, who helped draft an initial blueprint of the climate plan as a city staffer.

SDG&E has come to the city with a counterproposal that offers 100 percent renewables by 2035.

Thus far, the utility has produced a rough outline for a "tariff" program that would charge ratepayers the cost of delivering more clean sources of energy over time.

Some council members have expressed frustration more specifics have not been sketched out.

SDG&E officials said they will take the new exit fee into account as they go forward with their counterproposal to the city council.

Speaking in general about the utility commission's decision, SDG&E spokeswoman Helen Gao called it "a victory for our customers, as it minimizes the cost shifts that they have been burdened with under the existing fee formula.

"As commissioners noted in rendering their decision, reforming the (exit fee) addresses a customer-to-customer equity issue and has nothing to do with increasing profits for investor-owned utilities," Gao said in an email.

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New Zealand Renewable Energy Strategy examines decarbonisation, GHG emissions, and net energy as electrification accelerates, expanding hydro, geothermal, wind, and solar PV while weighing intermittency, storage, materials, and energy security for a resilient power system.

Key Points

A plan to expand electricity generation, balancing decarbonisation, net energy limits, and energy security.

✅ Distinguishes decarbonisation targets from renewable capacity growth

✅ Highlights net energy limits, intermittency, and storage needs

✅ Addresses materials, GHG build-out costs, and energy security

The Electricity Authority has released a document outlining a plan to achieve the Government’s goal of more than doubling the amount of electricity generated in New Zealand over the next few decades.

This goal is seen as a way of both reducing our greenhouse gas (GHG) emissions overall, as everything becomes electrified, and ensuring we have a 100 percent renewable energy system at our disposal. Often these two goals are seen as being the same – to decarbonise we must transition to more renewable energy to power our society.

But they are quite different goals and should be clearly differentiated. GHG emissions could be controlled very effectively by rationing the use of a fossil fuel lockdown approach, with declining rations being available over a few years. Such a direct method of controlling emissions would ensure we do our bit to remain within a safe carbon budget.

If we took this dramatic step we could stop fretting about how to reduce emissions (that would be guaranteed by the rationing), and instead focus on how to adapt our lives to the absence of fossil fuels.

Again, these may seem like the same task, but they are not. Decarbonising is generally thought of in terms of replacing fossil fuels with some other energy source, signalling that a green recovery must address more than just wind capacity. Adapting our lives to the absence of fossil fuels pushes us to ask more fundamental questions about how much energy we actually need, what we need energy for, and the impact of that energy on our environment.

MBIE data indicate that between 1990 and 2020, New Zealand almost doubled the total amount of energy it produced from renewable energy sources - hydro, geothermal and some solar PV and wind turbines.

Over this same time period our GHG emissions increased by about 25 percent. The increase in renewables didn’t result in less GHG emissions because we increased our total energy use by almost 50 percent, mostly by using fossil fuels. The largest fossil fuel increases were used in transport, agriculture, forestry and fisheries (approximately 60 percent increases for each).

These data clearly demonstrate that increasing renewable energy sources do not necessarily result in reduced GHG emissions.

The same MBIE data indicate that over this same time period, the amount of Losses and Own Use category for energy use more than doubled. As of 2020 almost 30 percent of all energy consumed in New Zealand fell into this category.

These data indicate that more renewable energy sources are historically associated with less energy actually being available to do work in society.

While the category Losses and Own Use is not a net energy analysis, the large increase in this category makes the call for a system-wide net energy analysis all the more urgent.

Net energy is the amount of energy available after the energy inputs to produce and deliver the energy is subtracted. There is considerable data available indicating that solar PV and wind turbines have a much lower net energy surplus than fossil fuels.

And there is further evidence that when the intermittency and storage requirements are engineered into a total renewable energy system, the net energy of the entire system declines sharply. Could the Losses and Other Uses increase over this 30-year period be an indication of things to come?

Despite the importance of net energy analysis in designing a national energy system which is intended to provide energy security and resilience, there is not a single mention of net energy surplus in the EA reference document.

So over the last 30 years, New Zealand has doubled its renewable energy capacity, and at the same time increased its GHG emissions and reduced the overall efficiency of the national energy system.

And we are now planning to more than double our renewable energy system yet again over the next 30 years, even as zero-emissions electricity by 2035 is being debated elsewhere. We need to ask if this is a good idea.

How can we expand New Zealand’s solar PV and wind turbines without using fossil fuels? We can’t.

How could we expand our solar PV and wind turbines without mining rare minerals and the hidden costs of clean energy they entail, further contributing to ecological destruction and often increasing social injustices? We can't.

Even if we could construct, deliver, install and maintain solar PV and wind turbines without generating more GHG emissions and destroying ecosystems and poor communities, this “renewable” infrastructure would have to be replaced in a few decades. But there are at least two major problems with this assumed scenario.

The rare earth minerals required for this replacement will already be exhausted by the initial build out. Recycling will only provide a limited amount of replacements.

The other challenge is that a mostly “renewable” energy system will likely have a considerably lower net energy surplus. So where, in 2060, will the energy come from to either mine or recycle the raw materials, and to rebuild, reinstall and maintain the next iteration of a renewable energy system?

There is currently no plan for this replacement. It is a serious misnomer to call these energy technologies “renewable”. They are not as they rely on considerable raw material inputs and fossil energy for their production and never ending replacement.

New Zealand is, of course, blessed with an unusually high level of hydro electric and geothermal power. New Zealand currently uses over 170 GJ of total energy per capita, 40 percent of which is “renewable”. This provides approximately 70 GJ of “renewable” energy per capita with our current population.

This is the average global per capita energy level from all sources across all nations, as calls for 100% renewable energy globally emphasize. Several nations operate with roughly this amount of total energy per capita that New Zealand can generate just from “renewables”.

It is worth reflecting on the 170 GJ of total energy use we currently consume. Different studies give very different results regarding what levels are necessary for a good life.

For a complex industrial society such as ours, 100 GJ pc is said to be necessary for a high levels of wellbeing, determined both subjectively (life satisfaction/ happiness measures), and objectively (e.g. infant mortality levels, female morbidity as an index of population health, access to nutritious food and educational and health resources, etc). These studies do not take into account the large amount of energy that is wasted either through inefficient technologies, or frivolous use, which effective decarbonization strategies seek to reduce.

Other studies that consider the minimal energy needed for wellbeing suggest a much lower level of per capita energy consumption is required. These studies take a different approach and focus on ensuring basic wellbeing is maintained, but not necessarily with all the trappings of a complex industrial society. Their results indicate a level of approximately 20 GJ per capita is adequate.

In either case, we in New Zealand are wasting a lot of energy, both in terms of the efficiency of our technologies (see the Losses and Own Use info above), and also in our uses which do not contribute to wellbeing (think of the private vehicle travel that could be done by active or public transport – if we had good infrastructure in place).

We in New Zealand need a national dialogue about our future. And energy availability is only one aspect. We need to discuss what our carrying capacity is, what level of consumption is sustainable for our population, and whether we wish to make adjustments in either our per capita consumption or our population. Both together determine whether we are on the sustainable side of carrying capacity. Currently we are on the unsustainable side, meaning our way of life cannot endure. Not a good look for being a good ancestor.

The current trajectory of the Government and Electricity Authority appears to be grossly unsustainable. At the very least they should be able to answer the questions posed here about the GHG emissions from implementing a totally renewable energy system, the net energy of such a system, and the related environmental and social consequences.

Public dialogue is critical to collectively working out our future. Allowing the current profit-driven trajectory to unfold is a recipe for disasters for our children and grandchildren.

Being silent on these issues amounts to complicity in allowing short-term financial interests and an addiction to convenience jeopardise a genuinely secure and resilient future. Let’s get some answers from the Government and Electricity Authority to critical questions about energy security.

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Franco-German Nuclear Power Divide shapes EU energy policy, electricity market reform, and decarbonization strategies, as Paris backs reactors and state subsidies while Berlin prioritizes renewables, hydrogen, and energy security after Russian gas shocks.

Key Points

A policy rift over nuclear shaping EU market reform, subsidies, and the balance between reactors and renewables.

✅ Nuclear in EU targets vs. renewables-first strategy

✅ Market design disputes over long-term power prices

✅ Energy security after Russian gas; hydrogen definitions

Near the French village of Fessenheim, facing Germany across the Rhine, a nuclear power station stands dormant. The German protesters that once demanded the site’s closure have decamped, in a sign of Europe's nuclear decline, and the last watts were produced three years ago. 

But disagreements over how the plant from 1977 should be repurposed persist, speaking to a much deeper divide over nuclear power, which Eon chief's warning to Germany underscored, between the two countries on either side of the river’s banks.

German officials have disputed a proposal to turn it into a centre to treat metals exposed to low levels of radioactivity, Fessenheim’s mayor Claude Brender says. “They are not on board with anything that might in some way make the nuclear industry more acceptable,” he adds.

France and Germany’s split over nuclear power is a tale of diverging mindsets fashioned over decades, including since the Chernobyl disaster in USSR-era Ukraine. But it has now become a major faultline in a touchy relationship between Europe’s two biggest economies.

Their stand-off over how to treat nuclear in a series of EU reforms has consequences for how Europe plans to advance towards cleaner energy. It will also affect how the bloc secures power supplies as the region weans itself off Russian gas, even though nuclear would do little for the gas issue, and how it provides its industry with affordable energy to compete with the US and China. 

“There can be squabbles between partners. But we’re not in a retirement home today squabbling over trivial matters. Europe is in a serious situation,” says Eric-André Martin, a specialist in Franco-German relations at French think-tank IFRI. 

France, which produces two-thirds of its power from nuclear plants and has plans for more reactors, is fighting for the low-carbon technology to be factored into its targets for reducing emissions and for leeway to use state subsidies to fund the sector.

For Germany, which closed its last nuclear plants this year and, having turned its back on nuclear, has been particularly shaken by its former reliance on Russian gas, there’s concern that a nuclear drive will detract from renewable energy advances.

But there is also an economic subtext in a region still reeling from an energy crisis last year, reviving arguments for a needed nuclear option for climate in Germany, when prices spiked and laid bare how vulnerable households and manufacturers could become.

Berlin is wary that Paris would benefit more than its neighbours if it ends up being able to guarantee low power prices from its large nuclear output as a result of new EU rules on electricity markets, amid talk of a possible U-turn on the phaseout, people close to talks between the two countries say.

Ministers on both sides have acknowledged there is a problem. “The conflict is painful. It’s painful for the two governments as well as for our [EU] partners,” Sven Giegold, state secretary at the German economy and climate action ministry, where debates about whether a nuclear resurgence is possible persist, tells the Financial Times. 

Agnès Pannier-Runacher, France’s energy minister, says she wants to “get out of the realm of the emotional and move past the considerable misunderstandings that have accumulated in this discussion”.

In a joint appearance in Hamburg last week, German chancellor Olaf Scholz and French president Emmanuel Macron made encouraging noises over their ability to break the latest deadlock: a disagreement over the design of the EU’s electricity market. Ministers had been due to agree a plan in June but will now meet on October 17 to discuss the reform, aimed at stabilising long-term prices.

But the French and German impasse on nuclear has already slowed down debates on key EU policies such as rules on renewable energy and how hydrogen should be produced. Smaller member states are becoming impatient. The delay on the market design is “a big Franco-German show of incompetence again”, says an energy ministry official from another EU country who requested anonymity. 

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EU Electricity Market Reform advances two-way CfDs, PPAs, and fixed-price tariffs to cut volatility, support renewables and nuclear, stabilize investor revenues, and protect consumers from price spikes across wholesale power markets.

Key Points

An EU plan expanding two-way CfDs, PPAs, and fixed-price contracts to curb price swings and support low-carbon power.

✅ Two-way CfDs return excess revenues to consumers

✅ Boosts PPAs and fixed-price retail options

✅ Targets renewables, nuclear; limits fossil exposure

The European Union wants to expand the use of contracts that pay power plants a fixed price for electricity, a draft proposal showed, as part of an electricity market revamp to shield European consumers from big price swings.

The European Commission pledged last year to reform the EU's electricity market rules, after record-high gas prices, caused by cuts to Russian flows, sent power prices soaring, prompting debates over gas price cap strategies in response.

A draft of the EU executive's proposal, seen by Reuters on Tuesday and due to be published on Mar. 16, steered clear of the deep redesign of the electricity market that some member states have called for, even as nine EU countries opposed sweeping reforms as a fix earlier in the crisis, suggesting instead limited changes to nudge countries towards more predictable, fixed-price power contracts.

If EU countries want to support new investments in wind, solar, geothermal, hydropower and nuclear electricity, for example - a point over which France and Germany have wrestled - they should use a two-way contract for difference (CfD) or an equivalent contract, the draft said.

The aim is to provide a stable revenue stream to investors, and help make consumers' energy bills less volatile, even though rolling back electricity prices is tougher than it appears. Restricting this support to renewable and low-carbon electricity also aims to speed up Europe's shift away from fossil fuels.

Two-way CfDs offer generators a fixed "strike price" for their electricity, regardless of the price in short-term energy markets. If the market price is above the CfD strike price, then the extra revenue the generator receives should be handed out to final electricity consumers, the draft EU document said.

Countries should also make it easier for power buyers to sign power purchase agreements (PPA) - another type of long-term contract to directly buy electricity from a generator.

Governments should also make sure consumers have access to fixed-price electricity contracts - echoing France's new electricity pricing scheme to reassure Brussels - giving them the option to avoid a contract that would expose them to volatile prices swings in energy markets, the draft said.

If European energy prices were to spike to extreme levels again, the Commission suggested allowing national governments to temporarily intervene to fix prices while weighing emergency measures to limit prices where needed, and offer consumers and small businesses a share of their electricity at a lower price.

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Ontario CEAP Program provides one-time electricity bill relief for residential consumers via local utilities, supports low-income households, aligns with COVID-19 recovery rates, and complements time-of-use pricing options and the winter disconnection ban.

Key Points

A one-time electricity bill credit for eligible Ontario households affected by COVID-19, available via local utilities.

✅ Apply through your local distribution company or utility

✅ One-time credit for overdue electricity bills from COVID-19

✅ Complements TOU options, OER, and winter disconnection ban

Applications for the CEAP program for Ontario residential consumers has opened. Residential customers across the province can now apply for funding through their local distribution company/utility.

On June 1st, our government announced a suite of initiatives to support Ontario’s electricity consumers amid changes for electricity consumers during the pandemic, including a $9 million investment to support low-income Ontarians through the COVID-19 Energy Assistance Program (CEAP). CEAP will provide a one-time payment to Ontarians who are struggling to pay down overdue electricity bills incurred during the COVID-19 outbreak.

These initiatives include:

• $9 million for the COVID-19 Energy Assistance Program (CEAP) to support consumers struggling to pay their energy bills during the pandemic. CEAP will provide one-time payments to consumers to help pay down any electricity bill debt incurred over the COVID19 period. Applications will be available through local utilities in the upcoming months;
• $8 million for the COVID-19 Energy Assistance Program for Small Business (CEAP-SB) to provide support to businesses struggling with bill payments as a result of the outbreak; and
• An extension of the Ontario Energy Board’s winter disconnection ban until July 31, 2020 to ensure no one is disconnected from their natural gas or electricity service during these uncertain times.

More information about applications for the CEAP for Small Business will be coming later this summer, as electricity rates are about to change across Ontario for many customers.

In addition, the government recently announced that it will continue the suspension of time-of-use (TOU) electricity rates and, starting on June 1, 2020, customers will be billed based on a new fixed COVID-19 hydro rate of 12.8 cents per kilowatt hour. The COVID-19 Recovery Rate, which some warned in analysis could lead to higher hydro bills will be in place until October 31, 2020.

Later in the pandemic, Ontario set electricity rates at the off-peak price until February 7 to provide additional relief.

“Starting November 1, 2020, our government has announced Ontario electricity consumers will have the option to choose between time-of-use and tiered electricity pricing plan, following the Ontario Energy Board’s new rate plan prices and support thresholds announcement. We are proud to soon offer Ontarians the ability to choose an electricity plan that best suits for their lifestyle,” said Jim McDonell, MPP for Stormont–Dundas–South Glengarry.

The government will continue to subsidize electricity bills by 31.8 per cent through the Ontario Electricity Rebate.

The government is providing approximately $5.6 billion in 2020-21 as part of its existing electricity cost relief programs and conservation initiatives such as the Peak Perks program to help ensure more affordable electricity bills for eligible residential, farm and small business consumers.

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California Electricity Reserve Mandate requires 3.3 GW of new capacity to bolster grid reliability amid solar power volatility, peak demand, and wildfire-driven blackouts, as CPUC directs PG&E, Edison, and Sempra to procure resource adequacy.

Key Points

A CPUC order for utilities to add 3.3 GW of reserves, safeguarding grid reliability during variable renewables and peaks

✅ 3.3 GW procurement to meet resource adequacy targets

✅ Focus on grid reliability during peak evening demand

✅ Prioritizes renewables, storage; limits new fossil builds

As if California doesn’t have enough problems with its electric service, now state regulators warn the state may be short on power supplies by 2021 if utilities don’t start lining up new resources now.

In the hopes of heading off a shortfall as America goes electric, the California Public Utilities Commission has ordered the state’s electricity providers to secure 3.3 additional gigawatts of reserve supplies. That’s enough to power roughly 2.5 million homes. Half of it must be in place by 2021 and the rest by August 2023.

The move comes as California is already struggling to accommodate increasingly large amounts of solar power that regularly send electricity prices plunging below zero and force other generators offline so the region’s grid doesn’t overload. The state is also still reeling from a series of deliberate mass blackouts that utilities imposed last month to keep their power lines from sparking wildfires amid strong winds. And its largest power company, PG&E Corp., went bankrupt in January.

Now as natural gas-fired power plants retire under the state’s climate policies, officials are warning the state could run short on electricity on hot evenings, when solar production fades and commuters get home and crank up their air conditioners. “We have fewer resources that can be quickly turned on that can meet those peaks,” utilities commission member Liane Randolph said Thursday before the panel approved the order to beef up reserves.

The 3.3 gigawatts that utilities must line up is in addition to a state rule requiring them to sign contracts for 15% more electricity than they expect to need. Some critics question the need for added supplies, particularly after the state went on a plant-building boom in the 2000s.

But California’s grid managers say the risk of a shortfall is real and could be as high as 4.7 gigawatts, especially during heat waves that test the grid again. Mark Rothleder, with the California Independent System Operator, said the 15% cushion is a holdover from the days before big solar and wind farms made the grid more volatile. Now it may need to be increased, he said.

“We’re not in that world anymore,” said Rothleder, the operator’s vice president of state regulatory affairs. “The complexity of the system and the resources we have now are much different.”

The state’s three major utilities, PG&E, Edison International and Sempra Energy, will be largely responsible for securing new supplies. The commission banned fossil fuels from being used at any new power generators built to meet the requirement — though it left the door open for expansions at existing ones.

Some analysts argue California is exporting its energy policies to Western states, making electricity more costly and less reliable.

PG&E said in an emailed statement that it was pleased the commission didn’t adopt an earlier proposal to require 4 gigawatts of additional resources. Edison similarly said it was “supportive.” Sempra didn’t immediately respond with comment.

Extending Deadlines

The pending plant closures are being hastened by a 2020 deadline requiring California’s coastal generators to stop using aging seawater-cooling systems. Some gas-fired power plants have said they’ll simply close instead of installing costly new cooling systems. So the commission on Thursday also asked California water regulators to extend the deadline for five plants.

The Sierra Club, meanwhile, called on regulators to turn away from fossil fuels altogether, saying their decision Thursday “sets California back on its progress toward a clean energy future.”

The move to push back the deadline also faces opposition from neighboring towns. Redondo Beach Mayor Bill Brand, whose city is home to one of the plants in line for an extension, told the commission it wasn’t necessary, since California utilities already have plenty of electricity reserves.

“It’s just piling on to that reserve margin,” Brand said.

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