Duke Energy fights rising pollution bill

By Knight Ridder Tribune


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Duke Energy is fighting proposed global-warming legislation it says would cost Carolinas customers millions of dollars in higher rates.

The bill, sponsored by Sens. Joe Lieberman of Connecticut, an independent, and John Warner of Virginia, a Republican, would place a national cap on carbon dioxide emissions from coal-fired plants, believed by many to be a major cause of global warming. It would also create a complex system for buying and selling pollution credits - special permission from the government for companies to pollute.

But it doesn't give enough exemptions to Duke and other utilities that rely heavily on coal, the company says. That's a deal breaker for Duke, which says the measure could send average power rates up 32 percent by 2020.

Chief executive Jim Rogers said the bill amounted to an unfair tax on producing power from coal. "They are, in my judgment, not being straightforward," he said. "They are using Washington-speak to describe what is really a carbon tax."

The bill would hit sectors of the economy that cover about 70 percent of the nation's carbon dioxide output, mainly from industry and other sources, such as cars. Exempted would be agriculture and residential emissions, which largely come from home heating with natural gas. The bill would set up a national cap-and-trade system for carbon dioxide, which would allow companies that pollute less and beat the cap to sell credits to those that exceed it.

Over time, the cap, initially based on carbon dioxide output from 2005, would be lowered and tougher to beat. The credits, traded on a national exchange, would become more rare and more expensive. Such systems are designed to make it more expensive over time to pollute, forcing companies to develop and pay for pollution-control technology.

There currently isn't a reliable way to reduce carbon dioxide emissions from coal-fired plants, short of shutting them down, Rogers said. So the industry needs exemptions for several years while it figures out the technology, and it shouldn't be taxed in the process, he said.

The Charlotte utility is among the nation's most prolific carbon dioxide emitters, the third largest user of coal. Duke relies on the fuel for 52 percent of its power generation in the Carolinas and 98 percent in its three Midwest territories - Indiana Kentucky and Ohio.

Several global warming bills are floating around Congress that would give utilities the allowances Duke is after. But the Lieberman bill was approved by a subcommittee November 1, and it appears to have some traction. The public criticism from Duke is a different tactic for Rogers, who has sought to be in the vanguard in setting carbon-regulation legislation.

He was among the first executives to call for carbon dioxide regulations and to blame the gas as cause of global warming. He knows his way around Capitol Hill as a former regulatory lawyer and has spent weeks since taking over as CEO early last year testifying before Congress and lobbying lawmakers on the issue.

David McIntosh, a Lieberman aide, said Duke's estimate of an up-to-32-percent increase for rates is inflated and that the bill follows guidelines by USCAP, a group of industry executives. Rogers was among those executives in January as they called for a national cap-and-trade system.

"That's not just any old interest group," McIntosh said. Rogers was successful in lobbying Congress for similar exemptions when it set up a cap and pollution credit system in the late 1980s to reduce sulfur dioxide emissions, a chief ingredient of acid rain. That program has been successful, Rogers pointed out.

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'Transformative change': Wind-generated electricity starting to outpace coal in Alberta

Alberta wind power surpasses coal as AESO reports record renewable energy feeding the grid, with natural gas conversions, solar growth, energy storage, and decarbonization momentum lowering carbon intensity across Alberta's electricity system.

 

Key Points

AESO data shows wind surpassing coal in Alberta, driven by coal retirements, gas conversions, and growing renewables.

✅ AESO reports wind output above coal several times this week

✅ Coal units retire or convert to natural gas, boosting renewables

✅ Carbon intensity falls; storage and solar improve grid reliability

 

Marking a significant shift in Alberta energy history, wind generation trends provided more power to the province's energy grid than coal several times this week.

According to data from the Alberta Energy System Operator (AESO) released this week, wind generation units contributed more energy to the grid than coal at times for several days. On Friday afternoon, wind farms contributed more than 1,700 megawatts of power to the grid, compared to around 1,260 megawatts from coal stations.

"The grid is going through a period of transformative change when we look at the generation fleet, specifically as it relates to the coal assets in the province," Mike Deising, AESO spokesperson, told CTV News in an interview.

The shift in electricity generation comes as more coal plants come offline in Alberta, or transition to cleaner energy through natural gas generation, including the last of TransAlta's units at the Keephills Plant west of Edmonton.

Only three coal generation stations remain online in the province, at the Genesee plant southwest of Edmonton, as the coal phase-out timeline advances. Less available coal power, means renewable energy like wind and solar make up a greater portion of the grid.

 

EVOLUTION OF THE GRID
"Our grid is changing, and it's evolving," Deising said, adding that more units have converted to natural gas and companies are making significant investments into solar and wind energy.

For energy analyst Kevin Birn with IHS Markit, that trend is only going to continue.

"What we've seen for the last 24 to 36 months is a dramatic acceleration in ambition, policy, and projects globally around cleaner forms of energy or lower carbon forms of energy," Birn said.

Birn, who is also chief analyst of Canadian Oil Markets, added that not only has the public appetite for cleaner energy helped fuel the shift, but technological advancements have made renewables like wind and solar more cost-efficient.

"Alberta was traditionally heavily coal-reliant," he said. "(Now) western Canada has quite a diverse energy base."


LESS CARBON-INTENSIVE
According to Birn, the shift in energy production marks a significant reduction in carbon emissions as Alberta progresses toward its last coal plant closure milestone.

Ten years ago, IHS Markit estimates that Alberta's grid contributed about 900 kilograms of carbon dioxide equivalent per megawatt-hour of energy generation.

"That (figure is) really representing the dominance and role of coal in that grid," Birn said.

Current estimates show that figure is closer to 600 kilograms of CO2 equivalent.

"That means the power you and I are using is less carbon-intensive," Birn said, adding that figure will continue to fall over the next couple of years.


RENEWABLES HERE TO STAY
While many debate whether Alberta's energy is getting clean enough fast enough, Birn believes change is coming.

"It's been a half-decade of incredible price volatility in the oil market which had really dominated this sector and region," the analyst said.

"When I think of the future, I see the power sector building on large-scale renewables, which means decarbonization, and that provides an opportunity for those tech companies looking for clean energy places to land facilities."

Coal and natural gas are considered baseline assets by the AESO, where generation capacity does not shift dramatically, though some utilities report declining coal returns in other markets.

"Wind is a variable resource. It will generate when the wind is blowing, and it obviously won't when the wind is not," Deising said. "Wind and solar can ramp quickly, but they can drop off quite quickly, and we have to be prepared.

"We factor that into our daily planning and assessments," he added. "We follow those trends and know where the renewables are going to show up on the system, how many renewables are going to show up."

Deising says one wind plant in Alberta currently has an energy storage capacity to preserve renewably generated electricity during summer demand records and peak hours as needed. As the technology becomes more affordable, he expects more plants to follow suit.

"As a system operator, our job is to make sure as (the grid) is evolving we can continue to provide reliable power to Albertans at every moment every day," Deising said. "We just have to watch the system more carefully." 

 

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Power customers in British Columbia, Quebec have faced fees for refusing the installation of smart meters

NB Power Smart Meter Opt-Out Fees reflect cost causation principles set before the Energy and Utilities Board, covering meter reading charges, transmitter-disable options, rollout targets, and education plans across New Brunswick's smart metering program.

 

Key Points

Fees NB Power may apply to customers opting out of smart meters, reflecting cost causation and meter-reading costs.

✅ Based on cost causation and meter reading expenses

✅ BC and Quebec charge monthly opt-out surcharges

✅ Policy finalized during rollout after EUB review

 

NB Power customers who do not want a smart meter installed on their home could be facing a stiff fee for that decision, but so far the utility is not saying how much it might be.  

"It will be based on the principles of cost causation, but we have not gotten into the detail of what that fee would be at this point," said NB Power Senior Vice President of Operations Lori Clark at Energy and Utilities Board hearings on Friday.

In other jurisdictions that have already adopted smart meters, customers not wanting to participate have faced hundreds of dollars in extra charges, while Texas utilities' pullback from smart-home networks shows approaches can differ.

In British Columbia, power customers are charged a meter reading fee of $32.40 per month if they refuse a smart meter, or $20 per month if they accept a smart meter but insist its radio transmitter be turned off. That's a cost of between $240 and $388.80 per year for customers to opt out.

In Quebec, smart meters were installed beginning in 2012. Customers who refused the devices were initially charged $98 to opt out plus a meter reading fee of $17 per month. That was eventually cut by Quebec's energy board in 2014 to a $15 refusal fee and a $5 per month meter reading surcharge.

NB Power said it may be a year or more before it settles on its own fee.

"The opt out policy will be developed and implemented as part of the roll out.  It will be one of the last things we do," said Clark.

 

Customers need to be on board

NB Power is in front of the New Brunswick Energy and Utilities Board seeking permission to spend $122.7 million to install 350,000 smart meters province wide, as neighboring markets grapple with major rate increases that heighten affordability concerns.  

The meters are capable of transmitting consumption data of customers back to NB Power in real time, which the utility said will allow for a number of innovations in pricing and service, and help address old meter inaccuracies that affected some households.

The meters require near universal adoption by customers to maximize their financial benefit — like eliminating more than $20 million a year NB Power currently spends to read meters manually. The utility has said the switch will not succeed if too many customers opt out.

"We certainly wouldn't be looking at making an investment of this size without having the customer with us," said Clark.

On Thursday, Kent County resident Daniel LeBlanc, who along with Roger Richard, is opposing the introduction of smart meters for health reasons, predicted a cool reception for the technology in many parts of the province, given concerns that include health effects and billing disputes in Nova Scotia reported elsewhere.

"If one were to ask most of the people in the rural areas, I'm not sure you would get a lot of takers for this infrastructure," said LeBlanc, who is concerned with the long-term effect microwave frequencies used by the meters to transmit data may have on human health.

That issue is before the EUB next week.

 

Haven't tested the waters

NB Power acknowledged it has not measured public opinion on adopting smart meters but is confident it can convince customers it is a good idea for them and the utility, even as seasonal rate proposals in New Brunswick have prompted consumer backlash.

"People don't understand what the smart meter is," said Clark. "We need to educate our customers first to allow them to make an informed decision so that will be part of the roll out plan."

Clark noted that smart meters, helped by stiff opting out penalties, were eventually accepted by 98 per cent of customers in British Columbia and by 97.4 per cent of customers in Quebec.

"We will check and adjust along the way if there are issues with customer uptake," said Clark.

 

"This is very similar to what has been done in other jurisdictions and they haven't had those challenges."

 

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California's Next Electricity Headache Is a Looming Shortage

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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Senate Committee Advised by WIRES Counsel That Electric Transmission Still Faces Barriers to Development

U.S. Transmission Grid Modernization underscores FERC policy certainty, high-voltage infrastructure upgrades, renewables integration, electrification, and grid resilience to cut congestion and enable distributed energy resources, safeguarding against extreme weather, cyber threats, and market volatility.

 

Key Points

A plan to expand, upgrade, and secure high-voltage networks for renewables integration, electrification, reliability.

✅ Replace aging lines to cut congestion and customer costs

✅ Integrate renewables and distributed energy resources at scale

✅ Enhance resilience to weather, cyber, and physical threats

 

Today, in a high-visibility hearing on U.S. energy delivery infrastructure before the United States Senate Committee on Energy and Natural Resources, WIRES Executive Director and Former FERC Chairman Jim Hoecker addressed the challenges and opportunities that confront the modern high-voltage grid as the industry strives to upgrade and expand it to meet the demands of consumers and the economy.

In prepared testimony and responses to Senators' questions, Hoecker urged the Committee to support industry efforts to expand and upgrade the transmission network and to help regulators, especially the Federal Energy Regulatory Commission (FERC action on aggregated DERs), promote certainty and predictability in energy policy and regulation. 

 

His testimony stressed these points:

Significant transmission investment is needed now to replace aging infrastructure like the aging grid risks to clean energy, reduce congestion costs, and deliver widespread benefits to customers.

Increasingly, the role of the transmission grid is to integrate new distributed resources and renewable energy into the electric system and make them available to the market.

The changing electric generation mix, including needed nuclear innovation, and the coming electrification of transportation, heating, and other segments of the American economy in the next quarter century will depend on a strong and adaptable electric system. A robust transmission grid will be the linchpin that will enable us to meet those demands.

"Transmission is the common element that will support all future electricity needs and provide a hedge against uncertainties and potential costly outcomes. The time is now to be proactive in encouraging additional investments in our nation's most crucial infrastructure: the electric transmission system," Hoecker said. 

Hoecker's testimony also emphasized that transmission investment will contribute to the overall resilience of the electric system by bringing multiple resources and technologies to bear on threats to the power system, including extreme weather and proposals like a wildfire-resilient grid bill, cyber or physical attacks, or other events. Visit WIRES website for recently filed comments on the subject (supported by a Brattle Group study). 

"Transmission gives us the optionality to adapt to whatever the future holds, and a modern and resilient transmission system, informed by Texas reliability improvements, will be the most valuable energy asset we have," says Nina Plaushin, president of WIRES and vice president of federal affairs, regulatory and communications for ITC Holdings Corp. 

Hoecker closed his testimony by emphasizing that the "electrification" scenario that is being discussed across multiple industries demands action now in order to ensure policy and regulatory certainty that will support needed transmission investment. More studies need to be conducted to better understand and define how this delivery network must be configured and planned in anticipation of this potential transformation in how we use electrical energy. A full copy of the WIRES testimony can be found here.

 

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B.C. government freezes provincial electricity rates

BC Hydro Rate Freeze delivers immediate relief on electricity rates in British Columbia, reversing a planned 3% hike, as BCUC oversight, a utility review, and Site C project debates shape provincial energy policy.

 

Key Points

A one-year provincial policy halting BC Hydro electricity rate hikes while a utility review finds cost savings.

✅ Freeze replaces planned 3% hike approved by BCUC.

✅ Government to conduct comprehensive BC Hydro review.

✅ Critics warn $150M revenue loss impacts capital projects.

 

British Columbia's NDP government has announced it will freeze BC Hydro rates effective immediately, fulfilling a key election promise.

Energy, Mines and Petroleum Resources Minister Michelle Mungall says hydro rates have gone up by more than 24 per cent in the last four years and by more than 70 per cent since 2001, reflecting proposals such as a 3.75% increase over two years announced previously.

"After years of escalating electricity costs, British Columbians deserve a break on their bills," Mungall said in a news release.

BC Hydro had been approved by the B.C. Utilities Commission to increase the rate by three per cent next year, but Mungall said it will pull back its request in order to comply with the freeze.

In the meantime, the government says it will undertake a comprehensive review of the utility meant to identify cost-savings measures for customers often asked to pay an extra $2 a month on electricity bills.

The Liberal critic, Tracy Redies, says the one year rate freeze is going to cost BC Hydro, calling it a distraction from the bigger issue of the future of the Site C project and the oversight of a BC Hydro fund surplus as well.

"A one year rate freeze costs Hydro $150 million," Redies said. "That means there's $150 million less to invest in capital projects and other investments that the utility needs to make."

"This is putting off decisions that should be made today to the future."

Recommendations from the review — including possible new rates — will be implemented starting in April 2019.

 

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Ontario announces SMR plans to four reactors at Darlington

Ontario Darlington SMR Expansion advances four GE Hitachi BWRX-300 reactors with OPG, adding 1,200 MW of baseload nuclear power to support electrification, grid reliability, and clean energy growth across Ontario and Saskatchewan.

 

Key Points

Plan to build four BWRX-300 SMRs at Darlington, delivering 1,200 MW of clean, reliable baseload power under OPG.

✅ Four GE Hitachi BWRX-300 units, 1,200 MW total

✅ Shared infrastructure cuts costs and timelines

✅ Supports electrification, grid reliability, net zero

 

The day after Ontario announced it would be building an additional 4,800 megawatts of nuclear reactors at Bruce Nuclear Generating Station, the province announced it would be dramatically expanding its planned rollout of small modular reactors at its Darlington Nuclear Generating Station, and confirmed plans to refurbish Pickering B as part of its broader strategy.

Ontario Power Generation OPG was always going to be the first to build the GE-Hitachi BWRX-300 small modular reactor SMR, with the U.S.’s Tennessee Valley Authority among others like SaskPower and several European nations following suit. But the OPG was originally going to build just one. On July 7, OPG and the Province of Ontario announced they would be bumping that up to four units of the BWRX-300.

The Ontario government is working with Ontario Power Generation (OPG) to commence planning and licensing for three additional small modular reactors (SMRs), for a total of four SMRs at the Darlington nuclear site. Once deployed, these four units would produce a total 1,200 megawatts (MW) of electricity, equivalent to powering 1.2 million homes, helping to meet increasing demand from electrification and fuel the province’s strong economic growth, the Ontario Ministry of Energy said in a release.

“Our government’s open for business approach has led to unprecedented investments across the province — from electric vehicles and battery manufacturing to critical minerals to green steel,” said Todd Smith, Minister of Energy. “Expanding Ontario’s world-leading SMR program will ensure we have the reliable, affordable and clean electricity we need to power the next major international investment, the new homes we are building and industries as they grow and electrify.”

For the first time since 2005, Ontario’s electricity demand is rising. While the government has implemented its plan to meet rising electricity demand this decade, the experts at Ontario’s Independent Electricity System Operator have recommended the province advance new nuclear generation and pursue life-extension at Pickering NGS to provide reliable, baseload power to meet increasing electricity needs in the 2030s and beyond.

Subject to Ontario Government and Canadian Nuclear Safety Commission (CNSC) regulatory approvals on construction, the additional SMRs could come online between 2034 and 2036. That is the same timeframe that SaskPower is looking at for its first, and possibly second, units.

The initial unit is expected to go online in 2028 following Ontario’s first SMR groundbreaking at Darlington.

The Darlington site, which already hosts four reactors, was originally considered for an expansion of “large nuclear,” which is why OPG was already well on its way for site approvals of additional nuclear power generation. The plan changed to one, singular, SMR. Now that has been updated to four.

The announcement has significant impact on Saskatchewan, and its plans to build four of its own SMRs. The timing would allow Ontario Power Generation to apply learnings from the construction of the first unit to deliver cost savings on subsequent units. This is also the strategy SaskPower is following – allow Ontario to build the first, then learn from that experience.

Building multiple units will also allow common infrastructure such as cooling water intake, transmission connection and control room to be utilized by all four units instead of just one, reducing costs even further, the Ministry said.

“A fleet of SMRs at the Darlington New Nuclear Site is key to meeting growing electricity demands and net zero goals,” said Ken Hartwick, OPG President and CEO. “OPG has proven its large nuclear project expertise through the on-time, on budget Darlington Refurbishment project. By taking a similar approach to building a fleet of SMRs, we will deliver cost and schedule savings, and power 1.2 million homes from this site by the mid-2030s.”

The Darlington SMR project is situated on the traditional and treaty territories of the seven Williams Treaties First Nations and is also located within the traditional territory of the Huron Wendat peoples. OPG is actively engaging and consulting with potentially impacted Indigenous communities, including exploring economic opportunities in the Darlington SMR project such as commercial participation and employment.

The Ministry noted, “Ontario’s robust nuclear supply chain is uniquely positioned to support SMR development and deployment in Ontario, Canada and globally. Building additional SMRs at Darlington would provide more opportunities for Ontario companies and broader economic benefits as suppliers of nuclear equipment, components, and services to make further investments to expand their operation to serve the growing SMR market both domestically and abroad.”

Supporting new SMR development and investing in nuclear power is part of the Ontario government’s larger plan, aligned with a Canadian interprovincial nuclear initiative that brings provinces together, to prepare for electricity demand in the 2030s and 2040s that will build on Ontario’s clean electricity advantage and ensure the province has the power to maintain it’s position as leader in job creation and a magnet for the industries of the future, the Ministry said.

In February, World Nuclear News (WNN) reported that Poland was considering up to 79 small modular reactors of the same design as OPG and SaskPower. And on June 5, it reported, “Canada’s Ontario Power Generation will provide operator services to Poland’s Orlen Synthos Green Energy under a letter of intent signed between the partners, extending their existing cooperation on the deployment of small modular reactors.”

WNN added, “The letter of intent is aimed at concluding future agreements under which OPG and its subsidiaries could provide operator services for SMR reactors to OSGE in connection with the deployment of SMRs in Poland and other European countries. The partnership would include a number of SMR-related activities including: development and deployment; operations and maintenance; operator training; commissioning; and regulatory support.”

 

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