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Newfoundland and Labrador electricity rate hike examines a proposed 18.6% increase under the PUB's Rate Stabilization Plan, driven by oil prices at Holyrood, with Consumer Advocate concerns over rate shock and use of RSP balances.

Key Points

A proposed 18.6% July 2017 increase under the RSP, driven by oil prices, now under PUB review for potential mitigation.

✅ PUB flags potential rate shock from proposed adjustment

✅ RSP balances cited to offset increases without depleting fund

✅ Oil-fired Holyrood volatility drives fuel cost uncertainty

How much of a rate hike is reasonable for users of electricity in Newfoundland and Labrador?

That's a question before the Public Utilities Board (PUB) as it examines an application by Newfoundland and Labrador Hydro, which could see consumers pay up to 18.6 per cent more as of July 1, reflecting regional pressures seen in Nova Scotia, where regulators approved a 14% rate hike earlier this year.

"The estimated rate increase for July 2017 is such a significant increase that it may be argued that it would cause rate shock," said the PUB, asking the company to revise its application.

NL Hydro said the price adjustment is part of what happens every year through the Rate Stabilization Plan (RSP), which is used to offset the ups and downs of oil prices.

"The cost of fuel is volatile and as long as we rely on oil-fired generation at Holyrood, customers will continue to be impacted by this electricity price uncertainty," said the company in a statement to CBC News.

It noted that customers received a break from RSP adjustments in 2015 and 2016, even as costs from the Muskrat Falls project begin to be reflected.

The PUB noted that under the rate stabilization plan, prices have gone up or down by about 10 per cent in the past.

The regulatory board said the impact of the latest request would be a 27.6 per cent hike to Newfoundland Power, with "an estimated average end customer impact of 18.6 per cent."

Hydro's estimates are based on an average price for oil of $81.40 per barrel from July 2017 to June 2018, according to the PUB.

'Unacceptable' burden: Consumer Advocate

"To burden ratepayers with an 18 per cent rate increase is unacceptable," said Consumer Advocate Dennis Browne, echoing pushback in Nova Scotia, where the premier urged regulators to reject a 14% hike at the time.

Browne is arguing that there is money in the RSP to reduce the proposed increase, including the possibility of a lump-sum bill credit for customers.

"These ratepayer balances — which, according to NL Power, totals $77.4 million — are not the property of Hydro," he wrote in a letter to the PUB.

"No utility has the right to squirrel away ratepayers' money to be used by that utility for some future purpose. The Board has jurisdiction over those balances," Browne said.

Browne also wants the RSP overhauled so that it can be applied to price fluctuations every quarter, as opposed to annually.

Hydro has expressed concern that depleting the rate stabilization fund would lead to other, more significant, rate increases in the future.

It said several alternatives to mitigate high rates have been provided to the PUB, which has final say, similar to how Manitoba Hydro scaled back a planned increase in the next year.

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Hinkley Point C dome lift marks a nuclear reactor milestone in Somerset, as EDF used Big Carl crane to place a 245-tonne steel roof, enabling 2027 startup amid costs, delays, and precision indoor welding.

Key Points

A 245-tonne dome lifted onto Hinkley Point C's first reactor, finishing the roof and enabling fit-out for a 2027 startup.

✅ 245-tonne steel dome lifted by Big Carl onto 44m-high reactor

✅ Indoor welding avoided weather defects seen at Flamanville

✅ Cost now £33bn; first power targeted by end of 2027

Engineers have lifted a steel roof onto a building which will house the first of two nuclear reactors at Hinkley Point in Somerset.

Hundreds of people helped with the delicate operation to get the 245-tonne steel dome into position.

It means the first reactor can be installed next year, ready to be switched on in June 2027.

Engineers at EDF said the "challenging job" was completed in just over an hour.

They first broke the ground on the new nuclear station in March 2017. Now, some 10,000 people work on what is Europe's largest building site.

Yet many analysts note that Europe is losing nuclear power even as demand for reliable energy grows.

They have faced delays from Covid restrictions and other recent setbacks, and the budget has doubled to £33bn, so getting the roof on the first of the two reactor buildings is a big deal.

EDF's nuclear island director Simon Parsons said it was a "fantastic night".

"Lifting the dome into place is a celebration of all the work done by a fantastic team. The smiles on people's faces this morning were something else.

"Now we can get on with the fitting of equipment, pipes and cables, including the first reactor which is on site and ready to be installed next year."

Nuclear minister Andrew Bowie hailed the "major milestone" in the building project, citing its role in the UK's green industrial revolution ambitions.

He said: "This is a key part of the UK Government's plans to revitalise nuclear."

But many still question whether Hinkley Point C will be worth all the money, especially after Hitachi's project freeze in Britain, with Roy Pumfrey of the Stop Hinkley campaign describing the project as "shockingly bad value".

Why lift the roof on?

The steel dome is bigger than the one on St Paul's Cathedral in London.

To lift it onto the 44-metre-high reactor building, they needed the world's largest land-based crane, dubbed Big Carl by engineers.

So why not just build the roof on top of the building?

The answer lies in a remote corner of Normandy in France, near a village called Flamanville.

EDF has been building a nuclear reactor there since 2007, ten years before they started in west Somerset.

The project is now a decade behind schedule and has still not been approved by French regulators.

Why? Because of cracks found in the precision welding on the roof of the reactor building.

In nuclear-powered France, they built the roof in situ, out in the open. 

Engineers have decided welding outside, exposed to wind and rain, compromised the high standards needed for a nuclear reactor.

So in Somerset they built a temporary workshop, which looks like a fair sized building itself. All the welding has been done inside, and then the completed roof was lifted into place.

Is it on time or on budget?

No, neither. When Hinkley C was first approved a decade ago, EDF said it would cost £14bn.

Four years later, in 2017, they finally started construction. By now the cost had risen to £19.5bn, and EDF said the plant would be finished by the end of 2025.

Today, the cost has risen to £33bn, and it is now hoped Hinkley C will produce electricity by the end of 2027.

"Nobody believes it will be done by 2027," said campaigner Roy Pumfrey.

"The costs keep rising, and the price of Hinkley's electricity will only get dearer," they added.

On the other hand, the increase in costs is not a problem for British energy bill payers, or the UK government.

EDF agreed to pay the full cost of construction, including any increases.

When I met Grant Shapps, then the UK Energy Secretary, at the site in April, he shrugged off the cost increases.

He said: "I think we should all be rather pleased it is not the British tax payer - it is France and EDF who are paying."

In return, the UK government agreed a set rate for Hinkley's power, called the Strike Price, back in 2013. The idea was this would guarantee the income from Hinkley Point for 35 years, allowing investors to get their money back.

Will it be worth the money?

Back in 2013, the Strike Price was set at £92.50 for each megawatt hour of power. At the time, the wholesale price of electricity was around £50/MWh, so Hinkley C looked expensive.

But since then, global shocks like the war in Ukraine have increased the cost of power substantially, and advocates argue next-gen nuclear could deliver smaller, cheaper, safer designs.

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Alberta Coal Phase-Out signals a clean energy transition, replacing coal with natural gas and renewables, cutting greenhouse gas emissions, leveraging a carbon levy, and supporting workers in Alberta's evolving electricity market.

Key Points

Alberta Coal Phase-Out moves power from coal to lower-emission natural gas and renewables to reduce grid emissions.

✅ Last coal plant closed: Genesee Generating Station, Sept 30, 2023

✅ Shift to natural gas and renewables lowers emissions

✅ Carbon levy and incentives accelerated clean power build-out

The closure of the Genesee Generating Station on September 30, 2023, marked a significant milestone in Alberta's energy history, as the province moved to retire coal power by 2023 ahead of its 2030 provincial deadline. The Genesee, located near Calgary, was the province's last remaining coal-fired power plant. Its closure represents the culmination of a multi-year effort to transition Alberta's electricity sector away from coal and towards cleaner sources of energy.

For decades, coal was the backbone of Alberta's electricity grid. Coal-fired plants were reliable and relatively inexpensive to operate. However, coal also has a significant environmental impact. The burning of coal releases greenhouse gases, including carbon dioxide, a major contributor to climate change. Coal plants also produce air pollutants such as sulfur dioxide and nitrogen oxide, which can cause respiratory problems and acid rain, and in some regions electricity is projected to get dirtier as gas use expands.

In recognition of these environmental concerns, the Alberta government began to develop plans to phase out coal-fired power generation in the early 2000s. The government implemented a number of policies to encourage the shift from coal to cleaner energy such as natural gas and renewable energy. These policies included providing financial incentives for the construction of new natural gas plants and renewable energy facilities, as well as imposing a carbon levy on coal-fired generation.

The phase-out of coal was also driven by economic factors. The cost of natural gas has declined significantly in recent years, making it a more competitive fuel source for electricity generation as producers switch to gas under evolving market conditions. Additionally, the Alberta government faced increasing pressure from the federal government to reduce greenhouse gas emissions.

The transition away from coal has not been without its challenges. Coal mining and coal-fired power generation have long been important parts of Alberta's economy. The closure of coal plants has resulted in job losses in the affected communities. The government has implemented programs to help workers transition to new jobs in the clean energy sector.

Despite these challenges, the closure of the Genesee Generating Station is a positive development for Alberta's environment and climate. Coal-fired power generation is one of the largest sources of greenhouse gas emissions in Alberta, and recent wind generation outpacing coal underscores the sector's transformation. The closure of the Genesee is expected to result in a significant reduction in emissions, helping Alberta to meet its climate change targets.

The transition away from coal also presents opportunities for Alberta. The province has vast natural gas resources, which can be used to generate electricity with lower emissions than coal. Alberta is also well-positioned to develop renewable energy sources, such as wind power and solar power. These renewable energy sources can help to further reduce emissions and create new jobs in the clean energy sector.

The closure of the Genesee Generating Station is a significant milestone in Alberta's energy history. It represents the end of an era for coal-fired power generation in the province, a shift mirrored by the UK's last coal station going offline earlier this year. However, it also marks the beginning of a new era for Alberta's energy sector. By transitioning to cleaner sources of energy, Alberta can reduce its environmental impact and create a more sustainable energy future.

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Wind And Solar Energy Growth is reshaping the global power mix, accelerating grid decarbonization as coal declines; boosted by pandemic demand drops, renewables now supply near 10% of electricity, advancing climate targets toward net-zero trajectories.

Key Points

It is the rise in wind and solar's share of electricity, driving decarbonization and displacing coal globally.

✅ Share doubled in five years across 83% of global electricity

✅ Coal's share fell; renewables neared 10% in H1 2020

✅ Growth still insufficient for 1.5 C; needs ~13% coal cuts yearly

Wind and solar energy doubled its share of the global power mix over the last five years, with renewable power records underscoring the trend, moving the world closer to a path that would limit the worst effects of global warming.

The sources of renewable energy made up nearly 10% of power in most parts of the world in the first half of this year, according to analysis from U.K. environmental group Ember, while globally over 30% of electricity is renewable in broader assessments.

That decarbonization of the power grid was boosted this year as shutdowns to contain the coronavirus reduced demand overall, leaving renewables to pick up the slack.

Ember analyzed generation in 48 countries that represent 83% of global electricity. The data showed wind and solar power increased 14% in the first half of 2020 compared with the same period last year while global demand fell 3% because of the impact of the coronavirus.

At the same time that wind turbines and solar panels have proliferated, coal’s share of the mix has fallen around the world. In some, mainly western European countries, where renewables surpassed fossil fuels, coal has been all but eliminated from electricity generation.

China relied on the dirtiest fossil fuel for 68% of its power five years ago, and solar PV growth in China has accelerated since then. That share dipped to 62% this year and renewables made up 10% of all electricity generated.

Still, the growth of renewables may not be going fast enough for the world to hit its climate goals, even as the U.S. is projected to have one-fourth of electricity from renewables soon, and coal is still being burnt for power in many parts of the world.

Coal use needs to fall by about 79% by 2030 from last year’s levels - a fall of 13% every year throughout the decade to come, and in the U.S. renewable electricity surpassed coal in 2022, Ember said.

New installations of wind farms are set to hold more or less steady in the next five years, according to data from BloombergNEF on deployment trends. That will make it difficult to realize a sustained pace of doubling renewable power every five years.

“If your expectations are that we need to be on target for 1.5 degrees, clearly we’re not going fast enough,” said Dave Jones, an analyst at Ember. “We’re not on a trajectory where we’re reducing coal emissions fast enough.”

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Atlantic Canada Energy Regulatory Reform accelerates smart grids, renewables, hydrogen, and small modular reactors to meet climate targets, enabling interprovincial transmission, EV charging, and decarbonization toward a net-zero grid by 2035 with agile, collaborative policies.

Key Points

A policy shift enabling smart grids, clean energy, and transmission upgrades to decarbonize Atlantic Canada by 2035.

✅ Agile rules for smart grids, EV load, and peak demand balancing

✅ Interprovincial transmission: Maritime Link, NB-PEI, Atlantic Loop

✅ Supports hydrogen, SMRs, and renewables to cut GHG emissions

Atlantica Centre for Energy Senior Policy Consultant Neil Jacobsen says the future of Atlantic Canada’s electricity grid depends on agile regulations, supported by targeted research such as the $2M Atlantic grid study, that match the pace at which renewable technologies are being developed in the race to meet Canada’s climate goals.

In an interview, Jacobsen stressed the need for a more modernized energy regulatory framework, so the Atlantic Provinces can collaborate to quickly develop and adopt cleaner energy.

To this end, Atlantica released a paper that makes the case for responsive smart grid technology, the adaptation of alternative forms of clean energy, the adaptation of hydrogen as an energy source, petroleum price regulation in Atlantic Canada and small modular reactors.

Jacobsen said regulations need to match Canada’s urgency around reducing greenhouse gas emissions by 40 to 45 percent by 2030, achieving a net-neutral national power grid by 2035 and ultimately a net-zero grid by 2050 in Canada – and the goal that 50 percent of Canadian vehicle sales being electric by 2030.

“It’s an evolution of policy and regulations to adapt to a very aggressive timeline of aggressive climate change and decarbonization targets,” said Jacobsen.

“These are transformational energy and environmental commitments, so the path forward really requires the ability to introduce and adapt and move forward with new clean renewable energy technologies.”

Jacobsen said Atlantica’s recommendations are not a criticism of existing regulations– but an acknowledgment that they need to evolve.

He noted newer, clearer regulations will make way for new energy sources – particularly a region that has the countries highest rates of dependency on fossil fuels and growing climate risks, with Atlantic grids under threat from more intense storms.

“We have a long way to go, but at the same time, we have a lot to celebrate. Atlantic Canada is leading the country in reducing greenhouse gas emissions,” said Jacobsen.

“There are new ways of producing energy that requires us to be able to be much more responsive and this is an opportunity to create a higher level of alignment here, in Atlantic Canada.”

Jacobsen said Atlantica is looking to aid interprovincial cooperation in providing power, echoing calls for a western Canadian grid elsewhere, through projects like the 500-megawatt, 170-kilometre Maritime Link that transports power from the Muskrat Falls hydroelectric dam in Labrador, through Newfoundland and across the Cabot Strait, to Nova Scotia – or NB Power’s export of electricity to P.E.I., via sub-sea cables crossing the Northumberland Strait.

He noted streamlined regulations may allow for more potential wider-scale partnerships, like the proposed Atlantic Loop project, aligning with macrogrid investments that would involve upgrading transmission capacity on the East Coast to allow hydroelectric power from Labrador and Quebec to displace coal use in the region.

Atlantic Canada has led the way with adaption new renewable technologies, noted Jacobsen, referring to nuclear startups Moltex Energy and ARC Nuclear Canada’s efforts to develop small modular nuclear reactor technology in New Brunswick, as well as the potential of adopting hydrogen fuel technology and Nova Scotia’s strides in developing offshore renewable energy.

“I don’t think we have any choice other than to be forceful and aggressive in driving forward a renewable energy agenda.”

Jacobsen said cooperation between the Atlantic provinces is crucial because of how challenging it is to meet energy demand with heavy seasonal and daily variations in energy demand in the region – something smart grid technology could address.

Smart Grid Atlantic is a four-year research and demonstration program testing technologies that provide cleaner local power, support a smarter electricity infrastructure across the region, more renewable power, more information and control over power use and more reliable electricity.

“It can be challenging for utilities to meet those cyclical demands, especially as grids are increasingly exposed to harsh weather across Canada. Smart girds add knowledge of the flow of electrons in a way that can help even out those electricity demands – and quite frankly, those demands will only increase when you look at the electrification of the transportation sector,” he said.

Jacobsen said Atlantica’s paper and call for modernized regulations are only the beginning of a conversation.

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US energy mix shows how the electric grid blends renewables, fossil fuels, nuclear, and hydro, varying by ISO/RTO markets, utilities, and state policies, affecting carbon emissions, pricing, reliability, and access.

Key Points

The US energy mix is the grid's source breakdown by region: fossil fuels, renewables, nuclear, and hydro.

✅ Check ISO or RTO dashboards for real-time generation by fuel source.

✅ Utilities may offer green power plans or RECs at modest premiums.

✅ Energy mix shifts with policy, pricing, and grid reliability needs.

There are few resources more important than energy. Sure, you may die if you don't eat for days. But your phone will die if you go too long without charging it. Energy feeds tech, the internet, city infrastructure, refrigerators, lights, and has evolved throughout U.S. history in profound ways. You get the idea. Yet unlike our other common needs, such as food, energy sources aren't exactly front of mind for most people. 

"I think a lot of people don't put a lot of bandwidth into thinking about this part of their lives," said Richard McMahon, the SVP of energy supply and finance at Edison Electric Institute, a trade group that represents investor-owned electric companies in the US. 

It makes sense. For most Americans, electricity is always there, and in many locations, there's not much of a choice involved, even as electricity demand is flat across the U.S. today. You sign up with a utility when you move into a new residence and pay your bills when they're due. 

But there's an important reality that indifference eschews: In 2018, a third of the energy-related carbon-dioxide emissions in the US came from the electric power sector, according to the US Energy Information Administration (EIA). 

A good chunk of that is from the residential sector, which consistently uses more energy than commercial customers, per EIA data.

Just as many people exercise choice when they eat, you typically also have a choice when it comes to your energy supply. That's not to say your current offering isn't what you want, or that switching will be easy or affordable, but "if you're a customer and want power with a certain attribute," McMahon said, "you can pretty much get it wherever you are." 

But first, you need to know the energy mix you have right now. As it turns out, it's not so straightforward. At all.

This brief guide may help. 

For some utility providers, you can find out if it publishes the energy mix online. Dominion Energy, which serves Idaho, North Carolina, Ohio, South Carolina, Utah, Virginia, West Virginia, and Wyoming, provides this information in a colored graphic. 

"Once you figure out who your utility is you can figure out what mix of resources they use," said Heidi Ratz, an electricity markets researcher at the World Resources Institute.

But not all utilities publish this information.

It has to do with their role in the grid and reflects utility industry trends in structure and markets. Some utility companies are vertically integrated; they generate power through nuclear plants or wind farms and distribute those electrons directly to their customers. Other utilities just distribute the power that different companies produce. 

Consider Consolidated Edison, or Con Ed, which distributes energy to parts of New York City. While reporting this story, Business Insider could not find information about the utility's energy mix online. When reached for comment, a spokesperson said, "we're indifferent to where it comes from."

That's because, in New York, distribution utilities like Con Ed often buy energy through a wholesale marketplace.

Take a look at this map. If you live in one of the colored regions, your electricity is sold on a wholesale market regulated by an organization called a regional transmission organization (RTO) or independent system operator (ISO). Distribution utilities like Con Ed often buy their energy through these markets, based on availability and cost, while raising questions about future utility revenue models as prices shift. 

Still, it's pretty easy to figure out where your energy comes from. Just look up the ISO or RTO website (such as NYISO or CAISO). Usually, these organizations will provide energy supply information in near-real time. 

That's exactly what Con Edison (which buys energy on the NYISO marketplace) suggested. As of Friday morning, roughly 40% of the energy on the market place was natural gas or other fossil fuels, 34% was nuclear, and about 22% was hydro. 

If you live in another region governed by an ISO or RTO, such as in most of California, you can do the same thing. Like NYISO, CAISO has a dashboard that shows (again, as of Friday morning) about 36% of the energy on the market comes from natural gas and more than 20% comes from renewables. 

In the map linked above, you'll notice that some of the ISOs and RTOs like MISO encompass enormous regions. That means that even if you figure out where the energy in your market comes from, it's not going to be geographically specific. But there are a couple of ways to drill down even further. 

The Environmental Protection Agency has a straightforward tool called Power Profiler. You can enter your zip code to see the fuel mix in your area. But it's not perfect. The data are from 2016 and, in some regions of the country like the upper Midwest, they aren't much more localized, and some import dirty electricity due to regional trading. 

The World Resources Institute also has a tool that allows you to see the electricity mix by state, based on 2017 data from EIA. These numbers represent power generation, not the electricity actually flowing into your sockets, but they offer a rough idea of what energy resources are operating in your state. 

One option is to check with your utility to see if it has a "green power" offering. Over 600 utilities across the country have one, according to the Climate Reality Project, though they often come at a slightly higher cost. It's typically on the scale of just a few more cents per kilowatt-hour. 

There are also independent, consumer-facing companies like Arcadia and Green Mountain Energy that allow you to source renewable energy, by virtually connecting you to community solar projects or purchasing Renewable Energy Certificates, or RECs, on your behalf, as America goes electric and more options emerge. 

"RECs measure an investment in a clean energy resource," Ratz said, in an email. "The goal of putting that resource on the grid is to push out the need for dirtier resources."

The good news: Even if you do nothing, your energy mix will get cleaner. Coal production has fallen to lows not seen since the 1980s, amid disruptions in coal and nuclear sectors that affect reliability and costs, while renewable electricity generation has doubled since 2008. So whether you like it or not, you'll be roped into the clean energy boom one way or another. 

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