Weak grid hampers Chinese wind integration

EV Grid Capacity Management shows how smart charging, load balancing, and off-peak pricing align with utility demand response, DC fast charging networks, and renewable integration to keep national electricity infrastructure reliable as EV adoption scales

Key Points

EV Grid Capacity Management schedules charging and balances load to keep EV demand within utility capacity.

✅ Off-peak pricing and time-of-use tariffs shift charging demand.

✅ Smart chargers enable demand response and local load balancing.

✅ Gradual EV adoption allows utilities to plan upgrades efficiently.

One of the most frequent concerns you will see from electric vehicle haters is that the electricity grid can’t possibly cope with all cars becoming EVs, or that EVs will crash the grid entirely. However, they haven’t done the math properly. The grids in most developed nations will be just fine, so long as the demand is properly management. Here’s how.

The biggest mistake the social media keyboard warriors make is the very strange assumption that all cars could be charging at once. In the UK, there are currently 32,697,408 cars according to the UK Department of Transport. The UK national grid had a capacity of 75.8GW in 2020. If all the cars in the UK were EVs and charging at the same time at 7kW (the typical home charger rate), they would need 229GW – three times the UK grid capacity. If they were all charging at 50kW (a common public DC charger rate), they would need 1.6TW – 21.5 times the UK grid capacity. That sounds unworkable, and this is usually the kind of thinking behind those who claim the UK grid can't cope with EVs.

What they don’t seem to realize is that the chances of every single car charging all at once are infinitesimally low. Their arguments seem to assume that nobody ever drives their car, and just charges it all the time. If you look at averages, the absurdity of this position becomes particularly clear. The distance each UK car travels per year has been slowly dropping, and was 7,400 miles on average in 2019, again according to the UK Department of Transport. An EV will do somewhere between 2.5 and 4.5 miles per kWh on average, so let’s go in the middle and say 3.5 miles. In other words, each car will consume an average of 2,114kWh per year. Multiply that by the number of cars, and you get 69.1TWh. But the UK national grid produced 323TWh of power in 2019, so that is only 21.4% of the energy it produced for the year. Before you argue that’s still a problem, the UK grid produced 402TWh in 2005, which is more than the 2019 figure plus charging all the EVs in the UK put together. The capacity is there, and energy storage can help manage EV-driven peaks as well.

Let’s do the same calculation for the USA, where an EV boom is about to begin and planning matters. In 2020, there were 286.9 million cars registered in America. In 2020, while the US grid had 1,117.5TW of utility electricity capacity and 27.7GW of solar, according to the US Energy Information Administration. If all the cars were EVs charging at 7kW, they would need 2,008.3TW – nearly twice the grid capacity. If they charged at 50kW, they would need 14,345TW – 12.8 times the capacity.

However, in 2020, the US grid generated 4,007TWh of electricity. Americans drive further on average than Brits – 13,500 miles per year, according to the US Department of Transport’s Federal Highway Administration. That means an American car, if it were an EV, would need 3,857kWh per year, assuming the average efficiency figures above. If all US cars were EVs, they would need a total of 1,106.6TWh, which is 27.6% of what the American grid produced in 2020. US electricity consumption hasn’t shrunk in the same way since 2005 as it has in the UK, but it is clearly not unfeasible for all American cars to be EVs. The US grid could cope too, even as state power grids face challenges during the transition.

After all, the transition to electric isn’t going to happen overnight. The sales of EVs are growing fast, with for example more plug-ins sold in the UK in 2021 so far than the whole of the previous decade (2010-19) put together. Battery-electric vehicles are closing in on 10% of the market in the UK, and they were already 77.5% of new cars sold in Norway in September 2021. But that is new cars, leaving the vast majority of cars on the road fossil fuel powered. A gradual introduction is essential, too, because an overnight switchover would require a massive ramp up in charge point installation, particularly devices for people who don’t have the luxury of home charging. This will require considerable investment, but could be served by lots of chargers on street lamps, which allegedly only cost £1,000 ($1,300) each to install, usually with no need for extra wiring.

This would be a perfectly viable way to provide charging for most people. For example, as I write this article, my own EV is attached to a lamppost down the street from my house. It is receiving 5.5kW costing 24p (32 cents) per kWh through SimpleSocket, a service run by Ubitricity (now owned by Shell) and installed by my local London council, Barnet. I plugged in at 11am and by 7.30pm, my car (which was on about 28% when I started) will have around 275 miles of range – enough for a couple more weeks. It will have cost me around £12 ($16) – way less than a tank of fossil fuel. It was a super-easy process involving the scanning of a QR code and entering of a credit card, very similar to many parking systems nowadays. If most lampposts had one of these charging plugs, not having off-street parking would be no problem at all for owning an EV.

With most EVs having a range of at least 200 miles these days, and the average mileage per day being 20 miles in the UK (the 7,400-mile annual figure divided by 365 days) or 37 miles in the USA, EVs won’t need charging more than once a week or even every week or two. On average, therefore, the grids in most developed nations will be fine. The important consideration is to balance the load, because if too many EVs are charging at once, there could be a problem, and some regions like California are looking to EVs for grid stability as part of the solution. This will be a matter of incentivizing charging during off-peak times such as at night, or making peak charging more expensive. It might also be necessary to have the option to reduce charging power rates locally, while providing the ability to prioritize where necessary – such as emergency services workers. But the problem is one of logistics, not impossibility.

There will be grids around the world that are not in such a good place for an EV revolution, at least not yet, and some critics argue that policies like Canada's 2035 EV mandate are unrealistic. But to argue that widespread EV adoption will be an insurmountable catastrophe for electricity supply in developed nations is just plain wrong. So long as the supply is managed correctly to make use of spare capacity when it’s available as much as possible, the grids will cope just fine.

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TEP Undergrounding Policy prioritizes selective underground power lines to manage wildfire risk, engineering costs, and ratepayer impacts, balancing transmission and distribution reliability with right-of-way, safety, and vegetation management per Arizona regulators.

Key Points

A selective TEP approach to bury lines where safety, engineering, and cost justify undergrounding.

✅ Selective undergrounding for feeders near substations

✅ Balances wildfire mitigation, reliability, and ratepayer costs

✅ Follows ACC rules, BLM and USFS vegetation management

Though wildfires in California caused by power lines have prompted calls for more underground lines, Tucson Electric Power Co. plans to keep to its policy of burying lines selectively for safety.

Like many other utilities, TEP typically doesn’t install its long-range, high-voltage transmission lines, such as the TransWest Express project, and distribution equipment underground because of higher costs that would be passed on to ratepayers, TEP spokesman Joe Barrios said.

But the company will sometimes bury lower-voltage lines and equipment where it is cost-effective or needed for safety as utilities adapt to climate change across North America, or if customers or developers are willing to pay the higher installation costs

Underground installations generally include additional engineering expenses, right-of-way acquisition for projects like the New England Clean Power Link in other regions, and added labor and materials, Barrios said.

“This practice avoids passing along unnecessary costs to customers through their rates, so that all customers are not asked to subsidize a discretionary expenditure that primarily benefits residents or property owners in one small area of our service territory,” he said, adding that the Arizona Corporation Commission has supported the company’s policy.

Even so, TEP will place equipment underground in some circumstances if engineering or safety concerns, including electrical safety tips that utilities promote during storm season, justify the additional cost of underground installation, Barrios said.

In fact, lower-voltage “feeder” lines emerging from distribution substations are typically installed underground until the lines reach a point where they can be safely brought above ground, he added.

While in California PG&E has shut off power during windy weather to avoid wildfires in forested areas traversed by its power lines after events like the Drum Fire last June, TEP doesn’t face the same kind of wildfire risk, Barrios said.

Most of TEP’s 5,000 miles of transmission and distribution lines aren’t located in heavily forested areas that would raise fire concerns, though large urban systems have seen outages after station fires in Los Angeles, he said.

However, TEP has an active program of monitoring transmission lines and trimming vegetation to maintain a fire-safety buffer zone and address risks from vandalism such as copper theft where applicable, in compliance with federal regulations and in cooperation with the U.S. Bureau of Land Management and the U.S. Forest Service.

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Goreway Power Station Overbilling exposed by Ontario Energy Board shows IESO oversight failures, GCG gaming, and $100M in inappropriate payments at the Brampton natural gas plant, penalized with fines and repayments impacting Ontario ratepayers.

Key Points

Goreway exploited IESO GCG flaws, causing about $100M in improper payouts and fines.

✅ OEB probe flagged $89M in ineligible start-up O&M charges

✅ IESO fined Goreway $10M; majority of excess costs recovered

✅ Audit found $200M in overbilling across nine generators

Hydro customers shelled out about $100 million in "inappropriate" payments to a natural gas plant that exploited flaws in how Ontario manages its private electricity generators, according to the Ontario Energy Board.

The company operating the Goreway Power Station in Brampton "gamed" the system for at least three years, according to an investigation by the provincial energy regulator. 

The investigation also delivers stinging criticism of the provincial government's Independent Electricity System Operator (IESO), slamming it for a lack of oversight. The probe by the Ontario Energy Board's market surveillance panel was completed nearly a year ago, but was only made public in November because it was buried on its website without a news release. CBC News is the first media outlet to report on the investigation.  

The excess payments to Goreway Power Station included:

• $89 million in ineligible expenses billed as the costs of firing up power production. 
• $5.6 million paid in three months from a flaw in how IESO calculated top-ups for the company committing to generate power a day in advance.   
• Of $11.2 million paid to compensate the company for IESO ordering it to start or stop generating power, the investigation concluded "a substantial portion ... was the result of gaming."  

Most privately-owned natural gas-fired plants in the province do not generate electricity constantly, but start and stop production in response to fluctuating market demand, even as the energy minister has requested an halt to natural gas generation across the grid.  IESO pays them a premium for the costs of firing up production, through what it calls "generation cost guarantee" programs. 

But the investigation found IESO did little checking into the details of Goreway Power Station's billings. 

Goreway Power Station, located near Highway 407 in Brampton, Ont., is an 875 megawatt natural gas power plant. (Goreway)

"Conservatively, at least $89 million of Goreway's submissions were clearly ineligible by any reasonable measure," concludes the report.

"Goreway routinely submitted what were obviously inappropriate expenses to be reimbursed by the IESO, and ultimately borne by Ontario ratepayers,"

The investigation panel found an "extraordinary pattern" to these billings by Goreway Power Station, suggesting the IESO should have caught on sooner. The company submitted more than $100 million in start-up operating and maintenance costs during the three-year period investigated — more than all other gas-fired generators in the province combined. The company's costs per start-up were more than double the next most expensive power generator. 

"Goreway repeatedly exploited defects in the GCG (generation cost guarantee) program, and in doing so received at least $89 million in gamed GCG payments." 

Company fined $10M

The investigation covered a three-year period from when Goreway Power Station began generating power in June 2009. Investigators said that delays in releasing documents slowed down their probe, and they only obtained all the records they needed in April 2016.

The investigating panel does not have the power to impose penalties on companies it found broke the rules. 

The IESO fined Goreway Power Station $10 million. The company has also repaid IESO "a substantial portion" of the excess payments it received during its first six years of operating, but the exact figure is blacked out in the investigation report that was made public. 

The control room from which the provincial government's Independent Electricity System Operator manages Ontario's power supply. The agency is also responsible for managing contracts with private power producers.(IESO)

"Goreway does not agree with many of the draft report's findings and conclusions, including any suggestion that Goreway engaged in gaming or that it deliberately misled the IESO," writes lawyer George Vegh on behalf of the company in a response to the investigation report, dated Aug. 1.

"Goreway has implemented initiatives designed to ensure that compliance is a chief operating principle."     

The power station, located near Highway 407 in Brampton, is a joint venture between Toyota Tsusho Corp. and JERA Co. Inc. During the period under scrutiny, the project was run by Toyota Tsusho and Chubu Electric Power Inc., both headquartered in Japan. 

Investigators fear 'same situation' exists today

The report blames the provincially-controlled IESO for creating a system with defects that allowed the over-billing. 

"Goreway was able to — and repeatedly did — exploit these defects," says the investigation report. It goes on to explain the flaws "have created opportunities for exploitation, to the serious financial disadvantage of Ontario's ratepayers," even as greening Ontario's grid could entail massive costs.

The investigation suggests IESO hasn't made adequate changes to ensure it won't happen again, at a time when an analysis of a dirtier grid is raising concerns.   

"Goreway stands as a clear example of how generators are able to exploit the generation costs guarantee regime," says the report.

"The Panel is concerned that the same situation remains in place today." 

PC energy critic Todd Smith raised CBC News' report on the Goreway Power Station in Tuesday's question period. (Ontario Legislature)

After CBC News broke the story Tuesday, the provincial government was forced to respond in question period, amid a broader push for new gas plants to boost electricity production. 

"Here we have yet another gas plant scandal in Peel region that's costing electricity customers over $100 million," said PC energy critic Todd Smith. He slammed "the incompetence of a government that once again failed to look out for electricity customers." 

Economic Development Minister Brad Duguid said: "There is no excuse for any company in this province to ever game the system."

Nine companies overbilled $200M: audit 

The IESO found out about the overbilling "some time ago," said Duguid.

"They fully investigated, they've recovered most of the cost, they delivered a $10 million fine — the biggest fine on record."

The program that Goreway exploited became the subject of an audit that the IESO launched in 2011. The agency uncovered $200 million in ineligible billings by nine power producers, wrote the IESO vice president for policy Terry Young in an email to CBC News.

The IESO has recovered up to 85 per cent of those ineligible costs, Young noted.

Reforms to the design of the the program have removed the potential for overpayments and made it more efficient, he said, even as Ontario weighs embracing clean power more broadly. Last year, its total annual costs dropped to $23 million, down from $61 million in 2014.

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Enbridge Alberta CCS Project targets carbon capture and storage in Alberta, capturing emissions from industrial emitters to advance net-zero goals, leveraging carbon pricing, regulatory support, and a hub model despite a key partner's exit.

Key Points

A proposed Alberta carbon capture hub by Enbridge to store industrial emissions and support net-zero targets.

✅ Seeks emitters across power, oil and gas, and heavy industry

✅ Backed by carbon pricing, regulation, and net-zero mandates

✅ Faces high capex, storage risk, and anchor-tenant uncertainty

Enbridge Inc., a Canadian energy giant, is digging its heels in on its proposed carbon capture and storage (CCS) project in Alberta. This comes despite the recent withdrawal of Capital Power, a major potential emitter that was expected to utilize the CCS technology. Enbridge maintains the project remains viable, but questions linger about its future viability without a cornerstone anchor.

The CCS project, envisioned as a major carbon capture hub in Alberta, aimed to capture emissions from industrial facilities and permanently store them underground. This technology has the potential to play a significant role in reducing greenhouse gas emissions and mitigating the effects of climate change, alongside grid solutions like bridging the Alberta-B.C. electricity gap that can complement decarbonization efforts.

Capital Power's decision to shelve its $2.4 billion Genesee Generating Station project, which was designed to integrate with the CCS hub, threw a wrench into Enbridge's plans. The Genesee project was expected to be a key source of emissions for capture and storage, and its status is being weighed as Ottawa advances the federal coal plan to phase out unabated coal.

Enbridge, however, remains optimistic. The company cites ongoing discussions with other potential emitters interested in utilizing the CCS technology, amid new funding signals such as the U.S. DOE's $110M for CCUS that highlight momentum. They believe the project holds significant value despite Capital Power's departure.

"We are confident in the long-term viability of the project and continue to actively engage with potential customers," said Enbridge spokesperson Rachel Giroux. "Carbon capture and storage is a critical technology for achieving net-zero emissions, and we believe there is a strong business case for our CCS project."

Enbridge's confidence hinges on several factors. Firstly, they believe there is a growing appetite for CCS technology amongst industrial facilities facing increasing pressure to reduce their carbon footprint. Regulations and carbon pricing mechanisms, including new U.S. EPA power plant rules that test CCS readiness, could further incentivize companies to adopt CCS solutions.

Secondly, Enbridge highlights the potential for capturing emissions from not just power plants but also from other industrial sectors like oil and gas production and clean hydrogen projects in Canada, where reforming processes can generate CO2. This broader application could significantly increase the captured carbon volume and strengthen the project's economic viability.

However, skepticism remains. Critics point to the high upfront costs associated with CCS development and the nascent stage of the technology. They argue that without a guaranteed stream of captured emissions, the project might not be financially sound. Additionally, the long-term safety and effectiveness of large-scale carbon storage solutions remain under scrutiny.

The success of Enbridge's CCS project hinges on attracting new emitters. Replacing Capital Power's contribution will be a significant challenge. Enbridge will need to demonstrate the project's economic viability and navigate the complex regulatory landscape surrounding CCS technology.

The Alberta government's position on CCS is crucial. While the government has expressed support for the technology, the level of financial and regulatory incentives offered will significantly impact investor confidence, especially as the IEA net-zero outlook underscores Canada's need for much more electricity. A clear and stable policy framework will be essential for attracting emitters to the project.

The future of Enbridge's CCS project remains uncertain. Capital Power's withdrawal is a setback, but Enbridge's continued commitment suggests they believe the technology holds promise. Whether they can find enough emitters to justify the project's development will be a critical test. The outcome will have significant implications for the future of CCS technology in Alberta and Canada's broader efforts to achieve net-zero emissions, including Canada-Germany clean energy cooperation that seeks to scale low-carbon fuels.

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BC Hydro Clean Energy Champions highlights Vancouver's Bloedel Conservatory electrification with a massive heat pump, clean electricity, LED lighting, deep energy efficiency, and 90% greenhouse gas reductions advancing climate action across buildings and industry.

Key Points

A BC Hydro program honoring clean electricity adoption in homes, transport, and industry to replace fossil fuels.

✅ Vancouver's Bloedel Conservatory cut GHGs by 90% with a heat pump

✅ LEDs and electrification boost efficiency, comfort, and reliability

✅ Nominations open for residents, businesses, and Indigenous groups

The City of Vancouver has been selected as BC Hydro’s first Clean Energy Champion for energy efficient upgrades made at the Bloedel Conservatory that cut greenhouse gas emissions by 90 per cent, a meaningful step given concerns about 2050 greenhouse gas targets in B.C.

BC Hydro’s Clean Energy Champions program is officially being launched today to recognize residents, businesses, municipalities, Indigenous and community groups across B.C. that have made the choice to switch from using fossil fuels to using clean electricity in three primary areas: homes and buildings, transportation, and industry, even as drought challenges power generation in B.C. The City of Vancouver is being recognized as the first champion for demonstrating its commitment to using clean energy, including power from projects like Site C's electricity, to fight climate change at its landmark Bloedel Conservatory.

Earlier this year, the City of Vancouver installed a large air source heat pump at Bloedel Conservatory – more than 50 times the size of a heat pump used in a typical B.C. home – that uses electricity instead of natural gas to heat and cool the dome's interior, which is home to more than 500 exotic plants and flowers, and 100 exotic birds, aligning with citywide debates such as Vancouver’s reversal on gas appliances policy. It is the biggest heat pump the City of Vancouver has ever installed, with 210 tonnes of cooling capacity.

A heat pump that provides cooling in the summer and heating in the winter, helping reduce reliance on wasteful air conditioning that can drive up energy bills, is ideal for the conservatory, as its dome is completely made of glass, which can be challenging for temperature regulation. While the dome experiences a lot of heat loss in the colder months, its need for cooling in warmer weather is even greater to ensure the safety of the wildlife and plants that call it home.

The clean energy upgrades do not end there though. All lighting in the building has been upgraded to energy-efficient LEDs, reflecting conservation themes highlighted by 2018 Earth Hour electricity use discussions, and outside colour-changing LEDs now surround the perimeter and light up the dome at night.

BC Hydro is calling for nominations from B.C. residents, businesses, municipalities or Indigenous and community groups that have taken steps to lower their carbon footprint and adopt new clean energy technologies, and continues to support customers through programs like its winter payment plan during colder months. If you or someone you know is a Clean Energy Champion, nominate them at bchydro.com/cleanenergychampions.

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Three Mile Island Nuclear Debate spotlights subsidies, carbon pricing, wholesale power markets, grid reliability, and zero-emissions goals as Pennsylvania weighs keeping Exelon's reactor open amid natural gas competition and flat electricity demand.

Key Points

Debate over subsidies, carbon pricing, and grid reliability shaping Three Mile Island's zero-emissions future.

✅ Zero emissions credits vs market integrity

✅ Carbon pricing to value clean baseload power

✅ Closure risks jobs, tax revenue, and reliability

Three Mile Island is at the center of a new conversation about the future of nuclear energy in the United States nearly 40 years after a partial meltdown at the Central Pennsylvania plant sparked a national debate about the safety of nuclear power.

The site is slated to close in just two years, a closure plan Exelon has signaled, unless Pennsylvania or a regional power transmission operator delivers some form of financial relief, says Exelon, the Chicago-based power company that operates the plant.

That has drawn the Keystone State into a growing debate: whether to let struggling nuclear plants shut down if they cannot compete in the regional wholesale markets where energy is bought and sold, or adopt measures to keep them in the business of generating power without greenhouse gas emissions.

""The old compromise — that in order to have a reliable, affordable electric system you had to deal with a significant amount of air pollution — is a compromise our new customers today don't want to hear about.""
-Joseph Dominguez, Exelon executive vice president
Nuclear power plants produce about two-thirds of the country's zero-emissions electricity, a role many view as essential to net-zero emissions goals for the grid.

The debate is playing out as some regions consider putting a price on planet-warming carbon emissions produced by some power generators, which would raise their costs and make nuclear plants like Three Mile Island more viable, and developments such as Europe's nuclear losses highlight broader energy security concerns.

States that allow nuclear facilities to close need to think carefully because once a reactor is powered down, there's no turning back, said Jake Smeltz, chief of staff for Pennsylvania State Sen. Ryan Aument, who chairs the state's Nuclear Energy Caucus.

"If we wave goodbye to a nuclear station, it's a permanent goodbye because we don't mothball them. We decommission them," he told CNBC.

Three Mile Island's closure would eliminate more than 800 megawatts of electricity output. That's roughly 10 percent of Pennsylvania's zero-emissions energy generation, by Exelon's calculation. Replacing that with fossil fuel-fired power would be like putting roughly 10 million cars on the road, it estimates.

A closure would also shed about 650 well-paying jobs, putting the just transition challenge in focus for local workers and communities, tied to about $60 million in wages per year. Dauphin County and Londonderry Township, a rural area on the Susquehanna River where the plant is based, stand to lose $1 million in annual tax revenue that funds schools and municipalities. The 1,000 to 1,500 workers who pack local hotels, stores and restaurants every two years for plant maintenance would stop visiting.

Pennsylvanians and lawmakers must now decide whether these considerations warrant throwing Exelon a lifeline. It's a tough sell in the nation's second-largest natural gas-producing state, which already generates more energy than it uses. And time is running out to reach a short-term solution.

"What's meaningful to us is something where we could see the results before we turn in the keys, and we turn in the keys the third quarter of '19," said Joseph Dominguez, Exelon's executive vice president for governmental and regulatory affairs and public policy.

The end of the nuclear age?

The problem for Three Mile Island is the same one facing many of the nation's 60 nuclear plants: They are too expensive to operate.

Financial pressure on these facilities is mounting as power demand remains stagnant due to improved energy efficiency, prices remain low for natural gas-fired generation and costs continue to fall for wind and solar power.

Three Mile Island is something of a special case: The 1979 incident left only one of its two reactors operational, but it still employs about as many people as a plant with two reactors, making it less efficient. In the last three regional auctions, when power generators lock in buyers for their future energy generation, no one bought power from Three Mile Island.

But even dual-reactor plants are facing existential threats. FirstEnergy Corp's Beaver Valley will sell or close its nuclear plant near the Pennsylvania-Ohio border next year as it exits the competitive power-generation business, and facilities like Ohio's Davis-Besse illustrate what's at stake for the region.

Five nuclear power plants have shuttered across the country since 2013. Another six have plans to shut down, and four of those would close well ahead of schedule. An analysis by energy research firm Bloomberg New Energy Finance found that more than half the nation's nuclear plants are facing some form of financial stress.

Today's regional energy markets, engineered to produce energy at the lowest cost to consumers, do not take into account that nuclear power generates so much zero-emission electricity. But Dominguez, the Exelon vice president, said that's out of step with a world increasingly concerned about climate change.

"What we see is increasingly our customers are interested in getting electricity from zero air pollution sources," Dominguez said. "The old compromise — that in order to have a reliable, affordable electric system you had to deal with a significant amount of air pollution — is a compromise our new customers today don't want to hear about."

Strange bedfellows

Faced with the prospect of nuclear plant closures, Chicago and New York have both allowed nuclear reactors to qualify for subsidies called zero emissions credits. Exelon lobbied for the credits, which will benefit some of its nuclear plants in those states.

Even though the plants produce nuclear waste, some environmental groups like the Natural Resources Defense Council supported these plans. That's because they were part of broader packages that promote wind and solar power, and the credits for nuclear are not open-ended. They essentially provide a bridge that keeps zero-emissions power from nuclear reactors on the grid as renewable energy becomes more viable.

Lawmakers in Pennsylvania, Ohio and Connecticut are currently exploring similar options. Jake Smeltz, chief of staff to state Sen. Aument, said legislation could surface in Pennsylvania as soon as this fall. The challenge is to get people to consider the attributes of the sources of their electricity beyond just cost, according to Smeltz.

"Are the plants worth essentially saving? That's a social choice. Do they provide us with something that has benefits beyond the electrons they make? That's the debate that's been happening in other states, and those states say yes," he said.

Subsidies face opposition from anti-nuclear energy groups like Three Mile Island Alert, as well as natural gas trade groups and power producers who compete against Exelon by operating coal and natural gas plants.

"Where we disagree is to have an out-of-market subsidy for one specific company, for a technology that is now proven and mature in our view, at the expense of consumers and the integrity of competitive markets," NRG Energy Mauricio Gutierrez told analysts during a conference call this month.

Smeltz notes that power producers like NRG would fill in the void left by nuclear plants as they continue to shut down.

"The question that I think folks need to answer is are these programs a bailout or is the opposition to the program a payout? Because at the end of the day someone is going to make money. The question is who and how much?" Smeltz said.

Changing the market

Another critic is PJM Interconnection, the regional transmission organization that operates the grid for 13 states, including Pennsylvania, and Washington, D.C.

The subsidies distort price formation and inject uncertainty into the markets, says Stu Bresler, senior vice president in charge of operations and markets at PJM.

The danger PJM sees is that each new subsidy creates a precedent for government intervention. The uncertainty makes it harder for investors to determine what sort of power generation is a sound investment in the region, Bresler explained. Those investors could simply decide to put their capital to work in other energy markets where the regulatory outlook is more stable, ultimately leading to underinvestment in places where government intervenes, he added.

Three Mile Island nuclear power plant, Londonderry Township, Pennsylvania
PJM believes longer-term, regional approaches are more appropriate. It has produced research that outlines how coal plants and nuclear energy, which provide the type of stable energy that is still necessary for reliable power supply, could play a larger role in setting prices. It is also preparing to release a report on how to put a price on carbon emissions in all or parts of the regional grid.

"If carbon emissions are the concern and that is the public policy issue with which policymakers are concerned, the simple be-all answer from a market perspective is putting a price on carbon," Bresler said.

Three Mile Island could be viable if natural gas prices rose from below $3 per million British thermal units to about $5 per mmBtu and if a "reasonable" price were applied to carbon, according to Exelon's Dominguez. He is encouraged by the fact that conversations around new pricing models and carbon pricing are gaining traction.

"The great part about this is everybody understands we have a major problem. We're losing some of the lowest-cost, cleanest and most reliable resources in America," Dominguez said.

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