New York fund would make energy-saving home loans

U.S. Power Grid Supply Shortages strain reliability as heat waves, hurricanes, and drought drive peak demand; transformer scarcity, gas constraints, and renewable delays raise outage risks across ERCOT and MISO, prompting FERC warnings.

Key Points

They are equipment and fuel constraints that, amid extreme weather and peak demand, elevate outage risks.

✅ Transformer shortages delay storm recovery and repairs.

✅ Record gas burn, low hydro tighten generation capacity.

✅ ERCOT and MISO warn of rolling outages in heat waves.

U.S. power companies are facing supply crunches amid the U.S. energy crisis that may hamper their ability to keep the lights on as the nation heads into the heat of summer and the peak hurricane season.

Extreme weather events such as storms, wildfires and drought are becoming more common in the United States. Consumer power use is expected to hit all-time highs this summer, reflecting unprecedented electricity demand across the Eastern U.S., which could strain electric grids at a time when federal agencies are warning the weather could pose reliability issues.

Utilities are warning of supply constraints for equipment, which could hamper efforts to restore power during outages. They are also having a tougher time rebuilding natural gas stockpiles for next winter, after the Texas power system failure highlighted cold-weather vulnerabilities, as power generators burn record amounts of gas following the shutdown of dozens of coal plants in recent years and extreme drought cuts hydropower supplies in many Western states.

"Increasingly frequent cold snaps, heat waves, drought and major storms continue to challenge the ability of our nation’s electric infrastructure to deliver reliable affordable energy to consumers," Richard Glick, chairman of the U.S. Federal Energy Regulatory Commission (FERC), said earlier this month.

Federal agencies responsible for power reliability like FERC have warned that grids in the western half of the country could face reliability issues this summer as consumers crank up air conditioners to escape the heat, with nationwide blackout risks not limited to Texas. read more

Some utilities have already experienced problems due to the heat. Texas' grid operator, the Electric Reliability Council of Texas (ERCOT), was forced to urge customers to conserve energy as the Texas power grid faced another crisis after several plants shut unexpectedly during an early heat wave in mid-May. read more

In mid-June, Ohio-based American Electric Power Co (AEP.O) imposed rolling outages during a heat wave after a storm damaged transmission lines and knocked out power to over 200,000 homes and businesses.

The U.S. Midwest faces the most severe risk because demand is rising while nuclear and coal power supplies have declined. read more

The Midcontinent Independent System Operator (MISO), which operates the grid from Minnesota to Louisiana, warned that parts of its coverage area are at increased risk of temporary outages to preserve the integrity of the grid.

Supply-chain issues have already delayed the construction of renewable energy projects across the country, and the aging U.S. grid is threatening progress on renewables and EVs. Those renewable delays coupled with tight power in the Midwest prompted Wisconsin's WEC Energy Group Inc (WEC.N) and Indiana's NiSource Inc (NI.N) to delay planned coal plant shutdowns in recent months.

BRACING FOR SUPPLY SHORTAGES
Utility operators are conserving their inventory of parts and equipment as they plan to prevent summer power outages during severe storms. Over the last several months, that means operators have been getting creative.

"We’re doing a lot more splicing, putting cables together, instead of laying new cable because we're trying to maintain our new cable for inventory when we need it," Nick Akins, chief executive of AEP, said at the CERAWeek energy conference in March.

Transformers, which often sit on top of electrical poles and convert high-voltage energy to the power used in homes, are in short supply.

New Jersey-based Public Service Enterprise Group Inc (PSEG) (PEG.N) Chief Executive Ralph Izzo told Reuters the company has had to look at alternate supply options for low voltage transformers.

"You don’t want to deplete your inventory because you don't know when that storm is coming, but you know it's coming," Izzo said.

Some utilities are facing waiting times of more than a year for transformer parts, the National Rural Electric Cooperative Association and the American Public Power Association told U.S. Energy Secretary Jennifer Granholm in a May letter.

Summer is just starting, but U.S. weather so far this year has already been about 21% warmer than the 30-year norm, according to data provider Refinitiv.

"If we have successive days of 100-degree-heat, those pole top transformers, they start popping like Rice Krispies, and we would not have the supply stack to replace them," Izzo said.

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Alberta Energy-Only Electricity Market faces capacity market debate, AESO price cap review, and coal-to-gas shifts by TransAlta and Capital Power, balancing reliability with volatility as investment signals evolve across Alberta's grid.

Key Points

An energy market paying generators only for electricity sold, with AESO oversight and a price cap guiding new capacity.

✅ AESO reviewing $999 per MW-h wholesale price cap.

✅ UCP retained energy-only; capacity market plan cancelled.

✅ TransAlta and Capital Power shift to coal-to-gas.

The Kenney government’s decision to cancel the redesign of Alberta’s electricity system to a capacity market won’t side-track two of the province’s largest power generators from converting coal-fired facilities to burn natural gas as part of Alberta’s shift from coal to cleaner energy overall.

But other changes could be coming to the province’s existing energy-only electricity market — including the alteration of the $999 per megawatt-hour (MW-h) wholesale price cap in Alberta.

The heads of TransAlta Corp. and Capital Power Corp. are proceeding with strategies to convert existing coal-fired power generating facilities to use natural gas in the coming years.

Calgary-based TransAlta first announced in 2017 that it would make the switch, as the NDP government was in the midst of overhauling the electricity sector and wind generation began to outpace coal in the province.

At the time, the Notley government planned to phase out coal-fired power by 2030, even as Alberta moved to retire coal by 2023 in practice, and shift Alberta into an electricity capacity market in 2021.

Such a move, made on the recommendation of the Alberta Electric System Operator (AESO), was intended to reduce price volatility and ensure system reliability.

Under the energy-only market, generators receive payments for electricity produced and sold into the grid. In a capacity market, generators are also paid for having power available on demand, regardless of how often they sell energy into the provincial grid.

The UCP government decided last month to ditch plans for a capacity market after consulting with the sector, saying it would be better for consumers.

On a conference call, TransAlta CEO Dawn Farrell said the company will convert coal-fired generating plants to burn gas, although it may alter the mix between simple conversions and switching to so-called “hybrid” plants.

(A hybrid conversion is a larger and more-expensive switch, as it includes installing a new gas turbine and heat-recovery steam generator, but it creates a highly efficient combined cycle unit.)

“Our view is fundamentally that carbon will be priced over the next 20 years no matter what,” she said Friday.

“We cannot get off coal fast enough in this company, and gas right now in Alberta is extremely inexpensive…

“So our coal-to-gas strategy is completely predicated on our belief that it’s not smart to be in carbon-intensive fuels for the future.”

Elsewhere in Canada, the Stop the Shock campaign has advocated for reviving coal power, underscoring ongoing policy debates.

The company said it’s planning the coal-to-gas conversion and re-powering of some or all of the units at its Keephills and Sundance facilities to gas-fired generation sometime between 2020 and 2023.

Similarly, Capital Power CEO Brian Vaasjo said the Edmonton-based company is moving ahead with a project that will allow it to burn both coal and natural gas at its Genesee generating station, even as Ontario’s energy minister sought to explore a halt to natural gas generation elsewhere.

In June, the company announced it would spend an estimated $50 million between 2019 and 2021 to allow it to use gas at the facility.

“What we’re doing is going to be dual fuel, so we will be able to operate 100 per cent natural gas or 100 per cent coal and everything in between,” Vaasjo said in an interview.

“You can expect to see we will be burning coal in the winter when natural gas prices are high, and we will be burning natural gas in summer when gas prices are real low.”

The transition comes as the government’s decision to stick with the energy-only market has been welcomed by players in the industry, and as Alberta's electricity future increasingly leans on wind resources.

A study by electricity consultancy EDC Associates found the capacity market would result in consumers paying an extra $1.4 billion in direct costs in 2021-22, as it required more generation to come online earlier than expected.

These additional costs would have accumulated to $10 billion by 2030, said EDC chief executive Duane-Reid Carlson.

For Capital Power, the decision to stick with the current system makes the province more investable in the future. Vaasjo said there was great uncertainty about the transition to a capacity market, and the possibility of rules shifting further.

Officials with Enmax Corp. said the city-owned utility would not have invested in future generation under the proposed capacity market.

“There is no short-term need (today) for new generation, so we’re just looking at the market and saying, ‘OK, as it evolves, we will see what happens,’” said Enmax vice-president Tim Boston.

Sticking with the energy-only market doesn’t mean Alberta will keep the existing rules.

In a July 25 letter, Alberta Energy Minister Sonya Savage directed AESO chair Will Bridge to examine if changes to the existing market are needed and report back by July 2020.

AESO, which manages the power grid, has been asked to investigate whether the current price cap of $999 per megawatt-hour (MW-h) should be changed.

The price ceiling hasn’t been altered since the energy-only market was implemented by the Klein government about two decades ago.

While allowing prices to go higher would increase volatility, reflecting lessons from Europe’s power crisis about scarcity pricing, during periods of rising demand and limited supply, it would send a signal to generators when investment in new generation is required, said Kent Fellows, a research associate at the University of Calgary’s School of Public Policy.

“Keeping the price (cap) too low could end up costing us more in the long run,” he said.

In a 2016 report, AESO said the province examined raising the price cap to $5,000 per MW-h, but “determined that it was unlikely to be successful in attracting investment due to increased price volatility.”

However, the amount of future generation that will be required in Alberta has been scaled back by the province.

In the United States, the Electricity Reliability Council of Texas (ERCOT) allows wholesale power prices in the state to climb to a cap of $9,000 per megawatt hours as demand rises — as it did Tuesday in the midst of a heat wave, according to Bloomberg.

Jim Wachowich, legal counsel for the Consumers’ Coalition of Alberta, said while few players are exposed to spot electricity prices, he has yet to be convinced raising the cap would be good for Albertans.

“Someone has to show me the evidence, and I suspect that’s what the minister has asked the AESO to do,” he said.

Generators say they believe some tinkering is needed to the energy-only market to ensure new generation is built when it’s required.

“The No. 1 change that the government has to … think about is in pricing,” added Farrell.

“If you don’t have enough of a price signal in an energy-only market to attract new capital, you won’t get new capital — and you’ll run up against the wall.”

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Shenao Power Plant Controversy intensifies as the EPA, Taipower, and New Taipei officials clash over EIA findings, a marine conservation area, fisheries, public health risks, and protests against a coal-fired plant in Rueifang.

Key Points

Dispute over coal plant EIA, marine overlap, and health risks, pitting EPA and Taipower against New Taipei and residents.

✅ EPA approved EIA changes; city cites marine conservation conflict

✅ Rueifang residents protest; 400+ signatures, wardens oppose

✅ Debate centers on fisheries, public health, and coal plant impacts

The controversy over the Shenao Power Plant heated up yesterday as Environmental Protection Administration (EPA) and New Taipei City Government officials quibbled over the project’s potential impact on a fisheries conservation area and other issues, mirroring New Hampshire hydropower clashes seen elsewhere.

State-run Taiwan Power Co (Taipower) wants to build a coal-fired plant on the site of the old Shenao plant, which was near Rueifang District’s (瑞芳) Shenao Harbor.

The company’s original plan to build a new plant on the site passed an environmental impact assessment (EIA) in 2006, similar to how NEPA rules function in the US, and the EPA on March 14 approved the firm’s environmental impact difference analysis report covering proposed changes to the project.

#google#

That decision triggered widespread controversy and protests by local residents, environmental groups and lawmakers, echoing enforcement disputes such as renewable energy pollution cases reported in Maryland.

The controversy reached a new peak after New Taipei City Mayor Eric Chu on Tuesday last week posted on Facebook that construction of wave breakers for the project would overlap with a marine conservation area that was established in November 2014.

The EPA and Taipower chose to ignore the demarcation lines of the conservation area, Chu wrote.

Dozens of residents from Rueifang and other New Taipei City districts yesterday launched a protest at 9am in front of the Legislative Yuan in Taipei, amid debates similar to the Maine power line proposal in the US, where the Health, Environment and Labor Committee was scheduled to review government reports on the project.

More than 400 Rueifang residents have signed a petition against the project, including 17 of the district’s 34 borough wardens, Anti-Shenao Plant Self-Help Group director Chen Chih-chiang said.

Ruifang residents have limited access to information, and many only became aware of the construction project after the EPA’s March 14 decision attracted widespread media coverage, Chen said,

Most residents do not support the project, despite Taipower’s claims to the contrary, Chen said.

New Power Party Executive Chairman Huang Kuo-chang, who represents Rueifang and adjacent districts, said the EPA has shown an “arrogance of power” by neglecting the potential impact on public health and the local ecology of a new coal-fired power plant, even as it moves to revise coal wastewater limits elsewhere.

Huang urged residents in Taipei, Keelung, Taoyaun and Yilan County to reject the project.

If the New Taipei City Government was really concerned about the marine conservation area, it should have spoken up at earlier EIA meetings, rather than criticizing the EIA decision after it was passed, Environmental Protection Administration Deputy Minister Chan Shun-kuei told lawmakers at yesterday’s meeting.

Chan said he wondered if Chu was using the Shenao project for political gain.

However, New Taipei City Environmental Protection Department specialist Sun Chung-wei  told lawmakers that the Fisheries Agency and other experts voiced concerns about the conservation area during the first EIA committee meeting on the proposed changes to the Shenao project on June 15 last year.

Sun was invited to speak to the legislative committee by Chinese Nationalist Party (KMT) Legislator Arthur Chen.

While the New Taipei City Fisheries and Fishing Port Affairs Management Office did not present a “new” opinion during later EIA committee meetings, that did not mean it agreed to the project, Sun said.

However, Chan said that Sun was using a fallacious argument and trying to evade responsibility, as the conservation area had been demarcated by the city government.

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Germany's Joint Onshore Wind and Solar Tender invites 200 MW bids in an EEG auction, with PV and onshore wind competing on price per MWh, including grid integration costs and network fees under BNA rules.

Key Points

A BNA-run 200 MW EEG auction where PV and onshore wind compete on price per MWh, including grid integration costs.

✅ 200 MW cap; minimum project size 750 kW

✅ Max subsidy 87.50 per MWh; bids include network costs

✅ Solar capped at 10-20 MW; wind requires prior approval

Germany's Federal Network Agency (BNA) has launched its second joint onshore wind and solar photovoltaic (PV) tender, with a total capacity of 200 MW.

A maximum guaranteed subsidy payment has been set at 87.50 per MWh for both energy sources, which BNA says will have to compete against each other for the lowest price of electricity. According to auction rules, all projects must have a minimum of 750 kW.

The auction is due to be completed on 2 November.

The network regulator has capped solar projects at 10 MW, though this has been extended to 20 MW in some districts, amid calls to remove barriers to PV at the federal level. Onshore wind projects did not receive any such restrictions, though they require approval from Federal Immission Control three weeks prior to the bid date of 11 Octobe

Bids also require network and system integration costs to be included, and similar solicitations have been heavily subscribed, as an over-subscribed Duke Energy solar solicitation in the US market illustrates.

According to Germanys Renewable Energy Act (EEG), two joint onshore wind and solar auctions must take place each year between 2018 and 2021. After this, the government will review the scheme and decide whether to continue it beyond 2021.

The first tender, conducted in April, saw the entire 200 MW capacity given to solar PV projects, reflecting a broader solar power boost in Germany during the energy crisis. Of the 32 contracts awarded, value varied from 39.60 per MWh to 57.60 per MWh. Among the winning bids were five projects in agricultural and grassland sites in Bavaria, totalling 31 MW, and three in Baden-Wrttemberg at 17 MW.

According to the Agency, the joint tender scheme was initiated in an attempt to determine the financial support requirements for wind and solar in technology-specific auctions, however, solar powers sole win in the April auction meant it was met with criticism, even as clean energy accounts for 50% of Germany's electricity today.

The heads of the Federal Solar Industry Association (BSW-Solar) and German Wind Energy Association (BWE) saying the joint tender scheme is unsuitable for the build-out of the two technologies.

A BWE spokesman previously stressed the companys rejection of competition between wind and solar, saying: It is not clear how this could contribute to an economically meaningful balanced energy mix,

Technologies that are in various stages of development must not enter into direct competition with each other. Otherwise, innovation and development potential will be compromised.

Similarly, BSW-Solar president Carsten Krnig said: We are happy for the many solar winners, but consider the experiment a failure. The auction results prove the excellent price-performance ratio of new solar power plants, as solar-plus-storage is cheaper than conventional power in Germany, but not the suitability of joint tenders.

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BC Hydro Electricity Imports shape CleanBC claims as Powerex trades cross-border electricity, blending hydro with coal and gas supplies, affecting emissions, grid carbon intensity, and how electric vehicles and households assess "clean" power.

Key Points

Powerex buys power for BC Hydro, mixing hydro with coal and gas, shifting emissions and affecting CleanBC targets.

✅ Powerex trades optimize price, not carbon intensity

✅ Imports can include coal- and gas-fired generation

✅ Emissions affect EV and CleanBC decarbonization claims

British Columbians naturally assume they’re using clean power when they fire up holiday lights, juice up a cell phone or plug in a shiny new electric car. 

That’s the message conveyed in advertisements for the CleanBC initiative launched by the NDP government, amid indications that residents are split on going nuclear according to a survey, which has spent $3.17 million on a CleanBC “information campaign,” including almost $570,000 for focus group testing and telephone town halls, according to the B.C. finance ministry.

“We’ll reduce air pollution by shifting to clean B.C. energy,” say the CleanBC ads, which feature scenic photos of hydro reservoirs. “CleanBC: Our Nature. Our Power. Our Future.” 

Yet despite all the bumph, British Columbians have no way of knowing if the electricity they use comes from a coal-fired plant in Alberta or Wyoming, a nuclear plant in Washington, a gas-fired plant in California or a hydro dam in B.C. 

Here’s why. 

BC Hydro’s wholly-owned corporate subsidiary, Powerex Corp., exports B.C. power when prices are high and imports power from other jurisdictions when prices are low. 

In 2018, for instance, B.C. imported more electricity than it exported — not because B.C. has a power shortage (it has a growing surplus due to the recent spate of mill closures and the commissioning of two new generating stations in B.C.) but because Powerex reaps bigger profits when BC Hydro slows down generators to import cheaper power, especially at night.

“B.C. buys its power from outside B.C., which we would argue is not clean,” says Martin Mullany, interim executive director for Clean Energy BC. 

“A good chunk of the electricity we use is imported,” Mullany says. “In reality we are trading for brown power” — meaning power generated from conventional ‘dirty’ sources such as coal and gas. 

Wyoming, which generates almost 90 per cent of its power from coal, was among the 12 U.S. states that exported power to B.C. last year. (Notably, B.C. did not export any electricity to Wyoming in 2018.)

Utah, where coal-fired power plants produce 70 per cent of the state’s energy amid debate over the costs of scrapping coal-fired electricity, and Montana, which derives about 55 per cent of its power from coal, also exported power to B.C. last year. 

So did Nebraska, which gets 63 per cent of its power from coal, 15 per cent from nuclear plants, 14 per cent from wind and three per cent from natural gas.   

Coal is responsible for about 23 per cent of the power generated in Arizona, another exporter to B.C., while gas produces about 44 per cent of the electricity in that state.  

In 2017, the latest year for which statistics are available, electricity imports to B.C. totalled just over 1.2 million tonnes of carbon dioxide emissions, according to the B.C. environment ministry — roughly the equivalent of putting 255,000 new cars on the road, using the U.S. Environmental Protection Agency’s calculation of 4.71 tonnes of annual carbon emissions for a standard passenger vehicle. 

These figures far outstrip the estimated local and upstream emissions from the contested Woodfibre LNG plant in Squamish that is expected to release annual emissions equivalent to 170,000 new cars on the road.

Import emissions cast a new light on B.C.’s latest “milestone” announcement that 30,000 electric cars are now among 3.7 million registered vehicles in the province.

BC Electric Vehicles Announcement Horgan Heyman Mungall Weaver
In November of 2018 the province announced a new target to have all new light-duty cars and trucks sold to be zero-emission vehicles by the year 2040. Photo: Province of B.C. / Flickr

“Making sure more of the vehicles driven in the province are powered by BC Hydro’s clean electricity is one of the most important steps to reduce [carbon] pollution,” said the November 28 release from the energy ministry, noting that electrification has prompted a first call for power in 15 years from BC Hydro.

Mullany points out that Powerex’s priority is to make money for the province and not to reduce emissions.

“It’s not there for the cleanest outcome,” he said. “At some time we have to step up to say it’s either the money or the clean power, which is more important to us?”

Electricity bought and sold by little-known, unregulated Powerex
These transactions are money-makers for Powerex, an opaque entity that is exempt from B.C.’s freedom of information laws. 

Little detailed information is available to the public about the dealings of Powerex, which is overseen by a board of directors comprised of BC Hydro board members and BC Hydro CEO and president Chris O’Reilly. 

According to BC Hydro’s annual service plan, Powerex’s net income ranged from $59 million to $436 million from 2014 to 2018. 

“We will never know the true picture. It’s a black box.” 

Powerex’s CEO Tom Bechard — the highest paid public servant in the province — took home $939,000 in pay and benefits last year, earning $430,000 of his executive compensation through a bonus and holdback based on his individual and company performance.  

“The problem is that all of the trade goes on at Powerex and Powerex is an unregulated entity,” Mullany says. 

“We will never know the true picture. It’s a black box.” 

In 2018, Powerex exported 8.7 million megawatt hours of electricity to the U.S. for a total value of almost $570 million, according to data from the Canada Energy Regulator. That same year, Powerex imported 9.6 million megawatt hours of electricity from the U.S. for almost $360 million. 

Powerex sold B.C.’s publicly subsidized power for an average of $87 per megawatt hour in 2018, according to the Canada Energy Regulator. It imported electricity for an average of $58 per megawatt hour that year. 

In an emailed statement in response to questions from The Narwhal, BC Hydro said “there can be a need to import some power to meet our electricity needs” due to dam reservoir fluctuations during the year and from year to year.

‘Impossible’ to determine if electricity is from coal or wind power
Emissions associated with electricity imports are on average “significantly lower than the emissions of a natural gas generating plant because we mostly import electricity from hydro generation and, increasingly, power produced from wind and solar,” BC Hydro claimed in its statement. 

But U.S. energy economist Robert McCullough says there’s no way to distinguish gas and coal-fired U.S. power exports to B.C. from wind or hydro power, noting that “electrons lack labels.” 

Similarly, when B.C. imports power from Alberta, where generators are shifting to gas and 48.5 per cent of electricity production is coal-fired and 38 per cent comes from natural gas, there’s no way to tell if the electricity is from coal, wind or gas, McCullough says.

“It really is impossible to make that determination.” 

Wyoming Gilette coal pits NASA
The Gillette coal pits in Wyoming, one of the largest coal-producers in the U.S. Photo: NASA Earth Observatory

Neither the Canada Energy Regulator nor Statistics Canada could provide annual data on electricity imports and exports between B.C. and Alberta. 

But you can watch imports and exports in real time on this handy Alberta website, which also lists Alberta’s power sources. 

In 2018, California, Washington and Oregon supplied considerably more power to B.C. than other states, according to data from Canada Energy Regulator. 

Washington, where about one-quarter of generated power comes from fossil fuels, led the pack, with more than $339 million in electricity exports to B.C. 

California, which still gets more than half of its power from gas-fired plants even though it leads the U.S. in renewable energy with substantial investments in wind, solar and geothermal, was in second place, selling about $18.4 million worth of power to B.C. 

And Oregon, which produces about 43 per cent of its power from natural gas and six per cent from coal, exported about $6.2 million worth of electricity to B.C. last year. 

By comparison, Nebraska’s power exports to B.C. totalled about $1.6 million, Montana’s added up to $1.3 million,  Nevada’s were about $706,000 and Wyoming’s were about $346,000.

Clean electrons or dirty electrons?
Dan Woynillowicz, deputy director of Clean Energy Canada, which co-chaired the B.C. government’s Climate Solutions and Clean Growth Advisory Council, says B.C. typically exports power to other jurisdictions during peak demand. 

Gas-fired plants and hydro power can generate electricity quickly, while coal-fired power plants take longer to ramp up and wind power is variable, Woynillowicz notes. 

“When you need power fast and there aren’t many sources that can supply it you’re willing to pay more for it.”

Woynillowicz says “the odds are high” that B.C. power exports are displacing dirty power.

Elsewhere in Canada, analysts warn that Ontario's electricity could get dirtier as policies change, raising similar concerns.

“As a consumer you never know whether you’re getting a clean electron or a dirty electron. You’re just getting an electron.” 

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California Community Choice Aggregators are reshaping electricity markets with renewable energy, solar and wind sourcing, competitive rates, and customer choice, challenging PG&E, SDG&E, and Southern California Edison while advancing California's clean power goals.

Key Points

Local governments that buy power, often cleaner and cheaper, while utilities handle delivery and billing.

✅ Offer higher renewable mix than utilities at competitive rates

✅ Utilities retain transmission and billing responsibilities

✅ Rapid expansion threatens IOU market share across California

Nearly 2 million electricity customers in California may not know it, but they’re part of a revolution. That many residents and businesses are getting their power not from traditional utilities, but via new government-affiliated entities known as community choice aggregators. The CCAs promise to deliver electricity more from renewable sources, such as solar and wind, even as California exports its energy policies across Western states, and for a lower price than the big utilities charge.

The customers may not be fully aware they’re served by a CCA because they’re still billed by their local utility. But with more than 1.8 million accounts now served by the new system and more being added every month, the changes in the state’s energy system already are massive.

Faced for the first time with real competition, the state’s big three utilities have suddenly become havens of innovation. They’re offering customers flexible options on the portion of their power coming from renewable energy, amid a broader review to revamp electricity rates aimed at cleaning the grid, and they’re on pace to increase the share of power they get from solar and wind power to the point where they are 10 years ahead of their deadline in meeting a state mandate.

#google#

But that may not stem the flight of customers. Some estimates project that by late this year, more than 3 million customers will be served by 20 CCAs, and that over a longer period, Pacific Gas & Electric, Southern California Edison, and San Diego Gas & Electric could lose 80% of their customers to the new providers.

Two big customer bases are currently in play: In Los Angeles and Ventura counties, a recently launched CCA called the Clean Power Alliance is hoping by the end of 2019 to serve nearly 1 million customers. Unincorporated portions of both counties and 29 municipalities have agreed in principle to join up.

Meanwhile, the city of San Diego is weighing two options to meet its goal of 100% clean power by 2035, as exit fees are being revised by the utilities commission: a plan to be submitted by SDG&E, or the creation of a CCA. A vote by the City Council is expected by the end of this year. A city CCA would cover 1.4 million San Diegans, accounting for half SDG&E’s customer demand, according to Cody Hooven, the city’s chief sustainability officer.

Don’t expect the big companies to give up their customers without a fight. Indeed, battle lines already are being drawn at the state Public Utilities Commission, where a recent CPUC ruling sided with a community energy program over SDG&E, and local communities.

“SDG&E is in an all-out campaign to prevent choice from happening, so that they maintain their monopoly,” says Nicole Capretz, who wrote San Diego’s climate action plan as a city employee and now serves as executive director of the Climate Action Campaign, which supports creation of the CCA.

California is one of seven states that have legalized the CCA concept, even as regulators weigh whether the state needs more power plants to ensure reliability. (The others are New York, New Jersey, Massachusetts, Ohio, Illinois and Rhode Island.) But the scale of its experiment is likely to be the largest in the country, because of the state’s size and the ambition of its clean-power goal, which is for 50% of its electricity to be generated from renewable sources by 2030.

California created its system via legislative action in 2002. Assembly Bill 117 enabled municipalities and regional governments to establish CCAs anywhere that municipal power agencies weren’t already operating. Electric customers in the CCA zones were automatically signed up, though they could opt out and stay with their existing power provider. The big utilities would retain responsibility for transmission and distribution lines.

The first CCA, Marin Clean Energy, began operating in 2010 and now serves 470,000 customers in Marin and three nearby counties.

The new entities were destined to come into conflict with the state’s three big investor-owned utilities. Their market share already has fallen to about 70%, from 78% as recently as 2010, and it seems destined to keep falling. In part that’s because the CCAs have so far held their promise: They’ve been delivering relatively clean power and charging less.

The high point of the utilities’ hostility to CCAs was the Proposition 16 campaign in 2009. The ballot measure was dubbed the “Taxpayers Right to Vote Act,” but was transparently an effort to smother CCAs in the cradle. PG&E drafted the measure, got it on the ballot, and contributed all of the $46.5 million spent in the unsuccessful campaign to pass it.

As recently as last year, PG&E and SDG&E were lobbying in the legislature for a bill that would place a moratorium on CCAs. The effort failed, and hasn’t been revived this year.

Rhetoric similar to that used by PG&E against Marin’s venture has surfaced in San Diego, where a local group dubbed “Clear the Air” is fighting the CCA concept by suggesting that it could be financially risky for local taxpayers and questioning whether it will be successful in providing cleaner electricity. Whether Clear the Air is truly independent of SDG&E’s parent, Sempra Energy, is questionable, as at least two of its co-chairs are veteran lobbyists for the company.

SDG&E spokeswoman Helen Gao says the utility supports “customers’ right to choose an energy provider that best meets their needs” and expects to maintain a “cooperative relationship” with any provider chosen by the city.

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