Iraq invites France back to build nuclear plant

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."

Related News

• Electricity Forum News

• Energy Policy News

Nova Scotia Integrated Resource Plan evaluates NSPI supply options, UARB oversight, Muskrat Falls imports, coal retirements, wind and biomass expansion, transmission upgrades, storage, and least-cost pathways to decarbonize the grid for ratepayers.

Key Points

A 25-year roadmap assessing supply, imports, costs, and emissions to guide least-cost decarbonization for Nova Scotia.

✅ Compares wind, biomass, gas, imports, and storage costs

✅ Addresses coal retirements, emissions caps, and reliability

✅ Recommends transmission upgrades and Muskrat Falls utilization

Maintaining a viable electricity network requires good long-term planning and, as a recent grid operations report notes, ongoing operational improvements. The existing stock of generating assets can become obsolete through aging, changes in fuel prices or environmental considerations. Future changes in demand must be anticipated.

Periodically, an integrated resource plan is created to predict how all this will add up during the ensuing 25 years. That process is currently underway and is led by Nova Scotia Power Inc. (NSPI) and will be submitted for approval to the Utilities and Review Board (UARB).

Coal-fired plants are still the largest single source of electricity in Nova Scotia. They need to be replaced with more environmentally friendly sources when they reach the end of their useful lives. Other sources include wind, hydroelectricity from rivers, biomass, as seen in increased biomass use by NS Power, natural gas and imports from other jurisdictions.

Imports are used sparingly today but will be an important source when the electricity from Muskrat Falls comes on stream. That project has big capacity. It can produce all the power needed in Newfoundland and Labrador (NL), where Quebec's power ambitions influence regional flows, plus the amount already committed to Nova Scotia, and still have a lot left over.

Some sources of electricity are more valuable than others. The daily amount of power from wind and solar cannot be controlled. Fuel-based sources and hydro can.

Utilities make their profits by providing the capital necessary to build infrastructure. Most of the money is borrowed but a portion, typically 30 per cent, usually comes from NSPI or a sister company. On that they receive a rate of return of nine per cent. Nova Scotia can borrow money today at less than two per cent.

The largest single investment of that type is the $1.577-billion Maritime Link connecting power from Newfoundland to Nova Scotia. It continues through to the New Brunswick border to facilitate exports to the United States. NSPI’s sister company, NSP Maritime Link Inc. (NSPML), is making nine per cent on $473 million of the cost.

There is little unexploited hydro capacity in Nova Scotia and there will not be any new coal-fired plants. Large-scale solar is not competitive in Nova Scotia’s climate. Nova Scotia’s needs would not accommodate the amount of nuclear capacity needed to be cost-effective, even as New Brunswick explores small reactors in its strategy.

So the candidates for future generating resources are wind, natural gas, biomass (though biomass criticism remains) and imports from other jurisdictions. Tidal is a promising opportunity but is still searching for a commercially viable technology. 

NSPI is commendably transparent about its process (irp.nspower.ca). At this stage there is little indication of the conclusions they are reaching but that will presumably appear in due course.

The mountains of detail might obscure the fact that NSPI is not an unbiased arbiter of choices for the future.

It is reported that they want to prematurely close the Trenton 5 coal plant in 2023-25. It is valued at $88.5 million. If it is closed early, ratepayers will still have to pay off the remaining value even though the plant will be idle. NSPI wants to plan a decommissioning of five of its other seven plants. There is a federal emissions constraint but retiring coal plants earlier than needed will cost ratepayers a lot.

Whenever those plants are closed, there will be a need for new sources of power. NSPI is proposing to plan for new investments in new transmission infrastructure to facilitate imports. Other possibilities would be additional wind farms, consistent with the shift to more wind and solar projects, thermal plants that burn natural gas or biomass, or storage for excess wind power that arrives before it can be used. The investment in storage could be anywhere from $20 million to $200 million.

These will add to the asset burden funded by ratepayers, even as industrial customers seek discounts while still paying for shuttered coal infrastructure.

External sources of new power will not provide NSPI the same opportunity: wind power by independent producers might be less expensive because they are willing to settle for less than nine per cent or because they are more efficient. Buying more power from Muskrat Falls will use transmission infrastructure we are already paying for. If a successful tidal technology is found, it will not be owned by NSPI or a sister company, which are no longer trying to perfect the technology.

This is not to suggest that NSPI would misrepresent the alternatives. But they can tilt the discussion in their favour. How tough will they be negotiating for additional Muskrat Falls power when it hurts their profits? Arguing for premature coal retirement on environmental grounds is fair game but whether the cost should be accepted is a political choice. 

NSPI is in a conflict of interest. We need a different process. An independent body should author the integrated resource plan. They should be fully informed about NSPI’s views.

They should communicate directly with Newfoundland and Labrador for Muskrat power, with independent wind producers, and with tidal power companies. The UARB cannot do any of these things.

The resulting plan should undergo the same UARB review that NSPI’s version would. This enhances the likelihood that Nova Scotians will get the least-cost alternative.

Related News

• Electricity Forum News

• Power Generation News

Hydro-Que9bec COVID-19 M&A Pause signals a halt to international expansion as falling electricity demand, weaker exports, and revenue pressure shift capital to the Quebec economy, prioritizing domestic investment, strategic plan revisions, and risk management.

Key Points

Hydro-Que9bec COVID-19 M&A Pause halts overseas deals, shifting investment to Quebec as demand, exports and revenue fall.

✅ International M&A on hold; capital reallocated to Quebec projects

✅ Lower electricity demand reduces exports and spot prices

✅ Strategic plan and 2020 guidance revised downward

COVID-19 is forcing Hydro-Québec to pull the plug on its global ambitions — for now, even as its electricity ambitions have reopened old wounds in Newfoundland and Labrador in recent years.

Quebec’s state-owned power generator and distributor has put international mergers and acquisitions on hold for the foreseeable future because of the COVID-19 crisis, chief financial officer Jean-Hugues Lafleur said Friday.

Former chief executive officer Éric Martel, who left last month, had made foreign expansion a key tenet of his growth strategy.

“We’re in revision mode” as pertains to acquisitions, Lafleur told reporters on a conference call, as the company pursues a long-term strategy to wean the province off fossil fuels at home as well. “I don’t see how Hydro-Québec could take $5 billion now and invest it in Chile because we have an investment opportunity there. Instead, the $5 billion will be invested here to support the Quebec economy. We’re going to make sure the Quebec economy recovers the right way before we go abroad.”

Lafleur spoke after Hydro-Québec reported a 14-per-cent drop in first-quarter profit and warned full-year results will fall short of expectations as COVID-19 weighs on power demand.

Net income in the three-month period ended March 31 was $1.53 billion, down from $1.77 billion a year ago, Hydro-Québec said in a statement. Revenue fell about six per cent to $4.37 billion.

“Due to the economic downturn resulting from the current crisis, we’re anticipating lower electricity sales in all of our markets,” Lafleur said. “Consequently, the financial outlook for 2020 set out in the strategic plan 2020–2024, which also reflects the province’s no-nuclear stance, will be revised downward.”

It’s still too early to determine the scope of the revision, the company said in its quarterly report. Hydro-Québec was targeting net income of between $2.8 billion and $3 billion in 2020, according to its strategic plan.

The first quarter was the utility’s last under Martel, who quit to take over at jetmaker Bombardier Inc. Quebec appointed former Énergir CEO Sophie Brochu to replace him, effective April 6.

First-quarter results “weren’t significantly affected” by the pandemic, Lafleur said on a conference call with reporters. Electricity sales generated $294 million less than a year ago due primarily to milder temperatures, he said.

Results will start to reflect COVID-19’s impact in the second quarter, though NB Power has signed three deals to bring more Quebec electricity into the province that could cushion some exports.

Electricity consumption in Quebec has fallen five per cent in the past two months, paced by an 11-per-cent plunge for commercial and institutional clients, and cities such as Ottawa saw a demand plunge during closures.

Industrial customers such as pulp and paper producers have also curbed power use, and it’s hard to see demand rebounding this year, Lafleur said.

“What we’ve lost since the start of the pandemic is not coming back,” he said.

Demand on export markets, meanwhile, has shrunk between six per cent and nine per cent since mid-March. The drop has been particularly steep in Ontario, reaching as much as 12 per cent, after the province chose not to renew its electricity deal with Quebec earlier this year, compared with declines of up to five per cent in New England and eight per cent in New York.

Spot prices in the U.S. have retreated in tandem, falling this week to as low as 1.5 U.S. cents per kilowatt-hour, Lafleur said. Hydro-Québec’s hedging strategy — which involves entering into fixed-price sales contracts about a year ahead of time — allowed the company to export power for an average of 4.9 U.S. cents per kilowatt-hour in the first quarter, compared with the 2.2 cents it would have otherwise made.

Investments will decline this year as construction activity proceeds at reduced speed, Lafleur said. Hydro-Québec was initially planning to invest about $4 billion in the province, he said, as it works to increase hydropower capacity to more than 37,000 MW across its fleet.

Physical distancing measures “are having an impact on productivity,” Lafleur said. “We can’t work the way we wanted, and project costs are going to be affected. Anytime we send workers north on a plane, we need to leave an empty seat beside them.”

Related News

• Electricity Forum News

• Energy Policy News

Texas power grid highlights ERCOT reliability strains from extreme heat, climate change, and low wind, as natural gas and renewables balance tight capacity amid EV charging growth, heat pumps, and blackout risk across the U.S.

Key Points

Texas power grid is ERCOT-run and isolated, balancing natural gas and wind amid extreme weather and electrification.

✅ Isolated from other U.S. grids, limited import support

✅ Vulnerable to extreme heat, winter storms, low wind

✅ Demand growth from EVs and heat pumps stresses capacity

Texas has a unique state-run power grid facing a Texas grid crisis that has raised concerns, but its issues with extreme weather, and balancing natural gas and wind, hold lessons for an entire U.S. at risk for power outages from climate change.

Grid operator the Electric Reliability Council of Texas, or ERCOT, which has drawn criticism from Elon Musk recently, called on consumers to voluntarily reduce power use on Monday when dangerous heat gripped America’s second-most populous state.

The action paid off as the Texas grid avoided blackouts — and a repeat of its winter crisis — despite record or near-record temperatures that depleted electric supplies amid a broader supply-chain crisis affecting utilities this summer, and risked lost power to more than 26 million customers. ERCOT later on Monday lifted the call for conservation.

For sure, it’s a unique situation, as the state-run power grid system runs outside the main U.S. grids. Still, all Americans can learn from Texas about the fragility of a national power grid that is expected to be challenged more frequently by hot and cold weather extremes brought on by climate change, including potential reliability improvements policymakers are weighing.

The grid will also be tested by increased demand to power electric vehicles (EVs) and conversions to electric heat pumps — all as part of a transition to a “greener” future.

Why is Texas different?
ERCOT, the main, but not only, Texas grid, is unique in its state-run, and not regional, format used by the rest of the country. Because it’s an energy-rich state, Texas has been able to set power prices below those seen in other parts of the country, and its independence gives it more pricing authority, while lawmakers consider market reforms to avoid blackouts. But during unusual strain on the system, such as more people blasting their air conditioners longer to combat a record heat wave, it also has no where else to turn.

A lethal winter power shortage in February 2021, during a Texas winter storm that left many without power and water, notoriously put the state and its independent utility in the spotlight when ERCOT failed to keep residents warm and pipes from bursting. Texas’s 2021 outage left more than 200 people dead and rang up $20 billion in damage. Fossil-fuel CL00, 0.80% backers pointed to the rising use of intermittent wind power, which generates 23% of Texas’s electricity. Others said natural-gas equipment was frozen under the extreme conditions.

This week, ERCOT is asking for voluntary conservation between 2 p.m. and 8 p.m. local time daily due to record high electricity demand from the projected heat wave, and also because of low wind. ERCOT said current projections show wind generation coming in at less than 10% of capacity. ERCOT stressed that no systemwide outages are expected, and Gov. Greg Abbott has touted grid readiness heading into fall, but it was acting preemptively.

A report late last year from the North American Electric Reliability Corp. (NERC) said the Texas system without upgrades could see a power shortfall of 37% in extreme winter conditions. NERC’s outlook suggested the state and ERCOT isn’t prepared for a repeat of weather extremes.

Related News

• Electricity Forum News

• Energy Policy News

Commercial Electric Tariffs explain utility rate structures, peak demand charges, kWh vs kW pricing, time-of-use periods, voltage, delivery, capacity ratchets, and riders, guiding facility managers in tariff analysis for accurate energy savings.

Key Points

Commercial electric tariffs define utility pricing for energy, demand, delivery, time-of-use periods, riders, and ratchet charges.

✅ Separate kWh charges from kW peak demand fees.

✅ Verify time-of-use windows and demand interval length.

✅ Review riders, capacity ratchets, and minimum demand clauses.

Especially during these tough economic times, as major changes to electric bills are debated in some states, facility executives who don’t understand how their power is priced have been disappointed when their energy projects failed to produce expected dollar savings. Here’s how not to be one of them.

Your electric rate is spelled out in a document called a “tariff” that can be downloaded from your utility’s web page. A tariff should clearly spell out the costs for each component that is part of your rate, reflecting cost allocation practices in your region. Don’t be surprised to learn that it contains a bunch of them. Unlike residential electric rates, commercial electric bills are not based solely on the quantity of kilowatt-hours (kWh) consumed in a billing period (in the United States, that’s a month). Instead, different rates may apply to how your power is supplied, how it is delivered via electricity delivery charges, when it was consumed, its voltage, how fast it was used (in kW), and other factors.

If a tariff’s lingo and word structure are too opaque, spend some time with a utility account rep to translate it. Many state utility commissions also have customer advocates that may assist as they explore new utility rate designs that affect customers. Alternatively, for a fee, facility managers can privately chat with an energy consultant.

Common mistakes

Many facility managers try to estimate savings based on an averaged electric rate, i.e., annual electric spend divided by annual kWh. However, in markets where electricity demand is flat, such a number may obscure the fastest rising cost component: monthly peak demand charges, measured in dollars per kW (or kilo-volt-amperes, kVA).

This charge is like a monthly speeding ticket, based solely on the highest speed you drove during that time. In some areas, peak demand charges now account for 30 to 60 percent of a facility’s annual electric spend. When projecting energy cost savings, failing to separately account for kW peak demand and kWh consumption may result in erroneous results, and a lot of questions from the C-suite.

How peak demand charges are calculated varies among utilities. Some base it on the highest average speed of use across one hour in a month, while others may use the highest average speed during a 15- or 30-minute period. Others may average several of the highest speeds within a defined time period (for example, 8 a.m. to 6 p.m. on weekdays). It is whatever your tariff says it is.

Because some power-consuming (or producing) devices, including those tied to smart home electricity networks, vary in their operation or abilities, they may save money on a few — but not all — of those rate components. If an equipment vendor calculates savings from its product by using an average electric rate, take pause. Tell the vendor to return after the proposal has been redone using tariff-based numbers.

When a vendor is the only person calculating potential savings from using a product, there’s also a built-in conflict of interest: The person profiting from an equipment sale should not also be the one calculating its expected financial return. Before signing any energy project contracts, it’s essential that someone independent of the deal reviews projected savings. That person (typically an energy or engineering consultant) should be quite familiar with your facility’s electric tariff, including any special provisions, riders, discounts, etc., that may pertain. When this doesn’t happen, savings often don’t occur as planned. 

For example, some utilities add another form of demand charge, based on the highest kW in a year. It has various names: capacity, contract demand, or the generic term “ratchet charge.” Some utilities also have a minimum ratchet charge which may be based on a percent of a facility’s annual kW peak. It ensures collection of sufficient utility revenue to cover the cost of installed transmission and distribution even when a customer significantly cuts its peak demand.

Related News

• Electricity Forum News

• Energy Policy News

Ukraine Electricity Exports resume as the EU grid links stabilize; ENTSO-E caps, megawatt capacity, renewables, and infrastructure repairs enable power flows to Moldova, Poland, Slovakia, and Romania despite ongoing Russian strikes.

Key Points

Resumed cross-border power sales showing grid stability under ENTSO-E limits and surplus generation.

✅ Exports restart to Moldova; Poland, Slovakia, Romania next.

✅ ENTSO-E cap limits to 400 MW; more capacity under negotiation.

✅ Revenues fund grid repairs after Russian strikes.

Ukraine began resuming electricity exports to European countries on Tuesday, its energy minister said, a dramatic turnaround from six months ago when fierce Russian bombardment of power stations plunged much of the country into darkness in a bid to demoralize the population.

The announcement by Energy Minister Herman Halushchenko that Ukraine was not only meeting domestic consumption demands but also ready to restart exports to its neighbors was a clear message that Moscow’s attempt to weaken Ukraine by targeting its infrastructure did not work.

Ukraine’s domestic energy demand is “100%” supplied, he told The Associated Press in an interview, and it has reserves to export due to the “titanic work” of its engineers and international partners.

Russia ramped up infrastructure attacks in September, when waves of missiles and exploding drones destroyed about half of Ukraine's energy system, even as it built lines to reactivate the Zaporizhzhia plant in occupied territory. Power cuts were common across the country as temperatures dropped below freezing and tens of millions struggled to keep warm.

Moscow said the strikes were aimed at weakening Ukraine’s ability to defend itself, and both sides have floated a possible agreement on power plant attacks amid mounting civilian harm, while Western officials said the blackouts that caused civilians to suffer amounted to war crimes. Ukrainians said the timing was designed to destroy their morale as the war marked its first anniversary.

Ukraine had to stop exporting electricity in October to meet domestic needs.

Engineers worked around the clock, often risking their lives to come into work at power plants and keep the electricity flowing. Kyiv’s allies also provided help. In December, U.S. Secretary of State Antony Blinken announced $53 million in bilateral aid to help the country acquire electricity grid equipment, on top of $55 million for energy sector support.

Much more work remains to be done, Halushchenko said. Ukraine needs funding to repair damaged generation and transmission lines, and revenue from electricity exports would be one way to do that.

The first country to receive Ukraine’s energy exports will be Moldova, he said.

Besides the heroic work by engineers and Western aid, warmer temperatures are enabling the resumption of exports by making domestic demand lower, and across Europe initiatives like virtual power plants for homes are helping balance grids. Nationwide consumption was already down at least 30% due to the war, Halushchenko said, with many industries having to operate with less power.

Renewables like solar and wind power also come into play as temperatures rise, taking some pressure off nuclear and coal-fired power plants.

But it’s unclear if Ukraine can keep up exports amid the constant threat of Russian bombardment.

“Unfortunately now a lot of things depend on the war,” Halushchenko said. “I would say we feel quite confident now until the next winter.”

Exports to Poland, Slovakia and Romania are also on schedule to resume, he said.

“Today we are starting with Moldova, and we are talking about Poland, we are talking about Slovakia and Romania,” Halushchenko added, noting that how much will depend on their needs.

“For Poland, we have only one line that allows us to export 200 megawatts, but I think this month we will finish another line which will increase this to an additional 400 MW, so these figures could change,” he said.

Export revenue will depend on fluctuating electricity prices in Europe, where stunted hydro and nuclear output may hobble recovery efforts. In 2022, while Ukraine was still able to export energy, Ukrainian companies averaged 40 million to 70 million euros a month depending on prices, Halushchenko said.

“Even if it’s 20 (million euros) it’s still good money. We need financial resources now to restore generation and transmission lines,” he said.

Ukraine has the ability to export more than the 400 megawatt capacity limit imposed by the European Network of Transmission System Operators for Electricity, or ENTSO-E, and rising EU wind and solar output is reshaping cross-border flows. “We are in negotiations to increase this cap because today we can export even more, we have the necessary reserves in the system,” the minister said.

The current capacity limit is in line with what Ukraine was exporting in September 2022 before Ukraine diverted resources to meet domestic needs amid the Russian onslaught.

Related News

• Electricity Forum News

• Power Generation News