Florida utility unveils grid enhancements and storm preparations

Ermineskin First Nation Solar Project delivers a 1 MW distributed generation array with 3,500 panels, selling power to Alberta's grid, driving renewable energy revenue, jobs, and regional economic development with partner SkyFire Energy.

Key Points

A 1 MW, 3,500-panel distributed generation plant selling power to Alberta's grid to support revenue and jobs.

✅ 1 MW array, 3,500 panels; grid-tied distributed generation

✅ Annual revenue projected at $80k-$150k, scalable

✅ Built with SkyFire Energy; expansion planned next summer

The switch will soon be flipped on a solar energy project that will generate tens of thousands of dollars for Ermineskin First Nation, while energizing economic development across Alberta, where selling renewables is emerging as a promising opportunity.

Built on six acres, the one-megawatt generator and its 3,500 solar panels will produce power to be sold into the province’s electrical grid, providing annual revenues for the band of $80,000 to $150,000, depending on energy demand and pricing.

The project cost $2.7 million, including connection costs and background studies, said Sam Minde, chief executive officer of the band-owned Neyaskweyahk Group of Companies Inc.

It was paid for with grants from the Western Economic Diversification Fund and the province’s Climate Leadership Plan, and, amid Ottawa’s green electricity contracting push, is expected to be connected to the grid by mid-December.

“It’s going to be the biggest distributed generation in Alberta,” he said.

Called the Sundancer generator, it was built and will be operated through a partnership with SkyFire Energy, reflecting how renewable power developers design better projects by combining diverse resources.

Minde said the project’s benefits extend beyond Ermineskin First Nation, one of four First Nations at Maskwacis, 20 km north of Ponoka, in a province where renewable energy surge could power thousands of jobs.

“Our nation is looking to do the best it can in business. It’s competitive, but at the same time, what is good for us is good for the region.

“If we’re creating jobs, we’re going to be building up our economy. And if you look at our region right now, we need to continue to create opportunities and jobs.”

Electricity prices are rock bottom right now, in the six to nine cents per kilowatt hour range, with recent Alberta solar contracts coming in below natural gas on cost. During the oilsands boom, when power demand was skyrocketing, the price was in the 16 to 18 cent range.

That means there is a lot of room for bigger returns for Ermineskin in the future, especially if pipelines such as TransMountain get going or the oilsands pick up again, and as Alberta solar growth accelerates in the years ahead.

The band is so confident that Sundancer will prove a success that there are plans to double it in size, a strategy echoed by community-scale efforts such as the Summerside solar project that demonstrate scalability. By next summer, a $1.5-million to $1.7-million project funded by the band will be built on another six acres nearby.

Minde said the project is an example of the community’s connection with the environment being used to create opportunities and embracing technologies that will likely figure large in the world’s energy future.

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Alberta Electricity Market faces energy-only vs capacity debate as transmission, distribution, and administration fees surge; rural rates rise amid a regulated duopoly of investor-owned utilities, prompting calls for competition, innovation, and lower bills.

Key Points

Alberta's electricity market is an energy-only system with rising delivery charges and limited rural competition.

✅ Energy-only design; capacity market scrapped

✅ Delivery charges outpace energy on monthly bills

✅ Rural duopoly limits competition and raises rates

Last week, Alberta’s new Energy Minister Sonya Savage announced the government, through its new electricity rules, would be scrapping plans to shift Alberta’s electricity to a capacity market and would instead be “restoring certainty in the electricity system.”

The proposed transition from energy only to a capacity market is a contentious subject as a market reshuffle unfolds across the province that many Albertans probably don’t know much about. Our electricity market is not a particularly glamorous subject. It’s complicated and confusing and what matters most to ordinary Albertans is how it affects their monthly bills.

What they may not realize is that the cost of their actual electricity used is often just a small fraction of their bill amid rising electricity prices across the province. The majority on an average electricity bill is actually the cost of delivering that electricity from the generator to your house. Charges for transmission, distribution and franchise and administration fees are quickly pushing many Alberta households to the limit with soaring bills.

According to data from Alberta’s Utilities Consumer Advocate (UCA), and alongside policy changes, in 2004 the average monthly transmission costs for residential regulated-rate customers was below $2. In 2018 that cost was averaging nearly $27 a month. The increase is equally dramatic in distribution rates which have more than doubled across the province and range wildly, averaging from as low as $10 a month in 2004 to over $80 a month for some residential regulated-rate customers in 2018.

Where you live determines who delivers your electricity. In Alberta’s biggest cities and a handful of others the distribution systems are municipally owned and operated. Outside those select municipalities most of Alberta’s electricity is delivered by two private companies which operate as a regulated duopoly. In fact, two investor-owned utilities deliver power to over 95 per cent of rural Alberta and they continue to increase their share by purchasing the few rural electricity co-ops that remained their only competition in the market. The cost of buying out their competition is then passed on to the customers, driving rates even higher.

As the CEO of Alberta’s largest remaining electricity co-op, I know very well that as the price of materials, equipment and skilled labour increase, the cost of operating follows. If it costs more to build and maintain an electricity distribution system there will inevitably be a cost increase passed on to the consumer. The question Albertans should be asking is how much is too much and where is all that money going with these private- investor-owned utilities, as the sector faces profound change under provincial leadership?

The reforms to Alberta’s electricity system brought in by Premier Klein in the late 1900s and early 2000s contributed to a surge in investment in the sector and led to an explosion of competition in both electricity generation and retail. 

More players entered the field which put downward pressure on electricity rates, encouraged innovation and gave consumers a competitive choice, even as a Calgary electricity retailer urged the government to scrap the overhaul. But the legislation and regulations that govern rural electricity distribution in Alberta continue to facilitate and even encourage the concentration of ownership among two players which is certainly not in the interests of rural Albertans.

It is also not in the spirit of the United Conservative Party platform commitment to a “market-based” system. A market-based system suggests more competition. Instead, what we have is something approaching a monopoly for many Albertans. The UCP promised a review of the transition to a capacity market that would determine which market would be best for Alberta, and through proposed electricity market changes has decided that we will remain an energy-only market.
Consumers in rural Alberta need electricity to produce the goods that power our biggest industries. Instead of regulating and approving continued rate increases from private multinational corporations, we need to drive competition and innovation that can push rates down and encourage growth and investment in rural-based industries and communities.

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Energy Transition Grid Reforms address transmission capacity, interconnection, congestion management, and flexibility markets, enabling renewable integration and grid stability while optimizing network charges and access in Australia, Ireland, and Great Britain.

Key Points

Measures to expand transmission, boost flexibility, and manage congestion for reliable, low-carbon electricity systems.

✅ Transmission upgrades and interconnectors ease congestion

✅ Flexible markets, DER, and storage bolster grid stability

✅ Evolving network charges and access incentivize siting

Electricity networks globally are experiencing significant increases in the volume of renewable capacity as countries seek to decarbonise their power sectors, even as clean energy's 'dirty secret' highlights integration trade-offs, without impacting the security of supply. The scale of this change is creating new challenges for power networks and those responsible for keeping the lights on.

The latest insight paper from Cornwall Insight – Market design amidst global energy transition – looks into this issue. It examines the outlook for transmission networks, and how legacy design and policies are supporting decarbonisation, aligning with IRENA findings on renewables and shaping the system. The paper focuses on three key markets; Australia, Ireland and Great Britain (GB).

Australia's main priority is to enhance transmission capacity and network efficiency; as concerns over excess solar risking blackouts grow in distribution networks, without this, the transmission system will be a barrier to growth for decentralised flexibility and renewables. In contrast, GB and Ireland benefit from interconnection with other national markets. This provides them with additional levers that can be pulled to manage system security and supply. However, they are still trying to hone and optimise network flexibility in light of steepening decarbonisation objectives.

Unsurprisingly, renewable energy resources have been growing in all three markets, with Ireland regarded as a leader in grid integration, with this expected to continue for the foreseeable future. Many of these projects are often located in places where network infrastructure is not as well developed, creating pressure on system operation as a result.

In all three markets, unit charges are rising, driven by a reduced charging base as decentralised energy grows quickly. This combination of changes is leading to network congestion, a challenge mirrored by the US grid overhaul for renewables underway, as transmission network development struggles to keep up, and flexibility markets are being optimised and changed.

In summary, reforms are on-going in each jurisdiction to accommodate the rapid physical transformation of the generation mix. Each has its objectives and tensions which are reflective of wider global reform programmes being undertaken in most developed, liberalised and decarbonising energy markets.

Gareth Miller, CEO of Cornwall Insight, said: “Despite differences in market design and characteristics, all three markets are grappling with similar issues, that comes from committing to deep decarbonisation. This includes the most appropriate methods for charging for networks, managing access to them and dealing with issues such as network congestion and constraint.

“In all three countries, renewable projects are often placed in isolated locations, as seen in Scotland where more pylons are needed to keep the lights on, away from the traditional infrastructure that is closer to demand. However, as renewable growth is set to continue, the networks will need to transition from being demand-centric to more supply orientated.

“Both system operators and stakeholders will need to continually evaluate their market structures and designs to alleviate issues surrounding locational congestion and grid stability. Each market is at very different stages in the process in trying to improve any problems implementing solutions to allow for higher efficiencies in renewable energy integration.

“It is uncertain whether any of the proposed changes will fundamentally resolve the issues that come with increased renewables on the system. However, despite marked differences, they certainly could all learn from each other and elements of their network arrangements, as well as from US decarbonisation strategies research.”

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COVID-19 Impact on Electricity Demand, per IEA data, shows 15% global load drop from lockdowns, with residential use up, industrial and service sectors down; fossil fuel generation fell as renewables and photovoltaics gained share.

Key Points

An overview of how lockdowns cut global power demand, boosted residential use, and increased the renewable share.

✅ IEA review shows at least 15% dip in daily global electricity load

✅ Lockdowns cut commercial and industrial demand; homes used more

✅ Fossil fuels fell as renewables and PV generation gained share

The daily demand for electricity dipped at least 15 per cent across the globe, according to Global Energy Review 2020: The impacts of the COVID-19 crisis on global energy demand and CO2 emissions, a report published by the International Energy Agency (IEA) in April 2020, even as global power demand surged above pre-pandemic levels.

The report collated data from 30 countries, including India and China, that showed partial and full lockdown measures adopted by them were responsible for this decrease.

Full lockdowns in countries — including France, Italy, India, Spain, the United Kingdom where daily demand fell about 10% and the midwest region of the United States (US) — reduced this demand for electricity.

Reduction in electricity demand after lockdown measures (weather corrected)

Source: Global Energy Review 2020: The impacts of the COVID-19 crisis on global energy demand and CO2 emissions, IEA

Drivers of the fall

There was, however, a spike in residential demand for electricity as a result of people staying and working from home. This increase in residential demand, though, was not enough to compensate for reduced demand from industrial and commercial operations.

The extent of reduction depended not only on the duration and stringency of the lockdown, but also on the nature of the economy of the countries — predominantly service- or industry-based — the IEA report said.

A higher decline in electricity demand was noted in countries where the service sector — including retail, hospitality, education, tourism — was dominant, compared to countries that had industrial economies.

The US, for example — where industry forms only 20 per cent of the economy — saw larger reductions in electricity demand, compared to China, where power demand dropped as the industry accounts for more than 60 per cent of the economy.

Italy — the worst-affected country from COVID-19 — saw a decline greater than 25 per cent when compared to figures from last year, even as power demand held firm in parts of Europe during later lockdowns.

The report said the shutting down of the hospitality and tourism sectors in the country — major components of the Italian economy — were said to have had a higher impact, than any other factor, for this fall.

Reduced fossil fuel dependency

Almost all of the reduction in demand was reportedly because of the shutting down of fossil fuel-based power generation, according to the report. Instead, the share of electricity supply from renewables in the entire portfolio of energy sources, increased during the pandemic, reflecting low-carbon electricity lessons observed during COVID-19.

This was due to a natural increase in wind and photovoltaic power generation compared to 2019 along with a drop in overall electricity demand that forced electricity producers from non-renewable sources to decrease their supplies, before surging electricity demand began to strain power systems worldwide.

The Power System Operation Corporation of India also reported that electricity production from coal — India’s primary source of electricity — fell by 32.2 per cent to 1.91 billion units (kilowatt-hours) per day, in line with India's electricity demand decline reported during the pandemic, compared to the 2019 levels.

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Nord Stream Pipeline Sabotage triggers Baltic Sea gas leaks as Norway and Denmark tighten energy infrastructure security, offshore surveillance, and exclusion zones, after drone sightings near platforms and explosions reported by experts.

Key Points

An alleged attack causing Baltic gas leaks and heightened energy security measures in Norway and Denmark.

✅ Norway boosts offshore and onshore site security

✅ Denmark enforces 5 nm exclusion zone near leaks

✅ Drones spotted; police probe sabotage and safety breaches

Norway and Denmark will increase security and surveillance around their energy infrastructure sites after the alleged sabotage of Russia's Nord Stream gas pipeline in the Baltic Sea, as the EU pursues a plan to dump Russian energy to safeguard supplies. 

Major leaks struck two underwater natural gas pipelines running from Russia to Germany, which has moved to a 200 billion-euro energy shield amid surging prices, with experts reporting that explosions rattled the Baltic Sea beforehand.

Norway -- an oil-rich nation and Europe's biggest supplier of gas -- will strengthen security at its land and offshore installations, even as it weighs curbing electricity exports to avoid shortages, the country's energy minister said.

The Scandinavian country's Petroleum Safety Authority also urged vigilance on Monday after unidentified drones were seen flying near Norway's offshore oil and gas platforms.

"The PSA has received a number of warnings/notifications from operator companies on the Norwegian Continental Shelf concerning the observation of unidentified drones/aircraft close to offshore facilities" the agency said in a statement.

"Cases where drones have infringed the safety zone around facilities are now being investigated by the Norwegian police."

Meanwhile Denmark will increase security across its energy sector after the Nord Stream incident, as wider market strains, including Germany's struggling local utilities, ripple across Europe, a spokesperson for gas transmission operator Energinet told Upstream.

The Danish Maritime Agency has also imposed an exclusion zone for five nautical miles around the leaks, warning ships of a danger they could lose buoyancy, and stating there is a risk of the escaping gas igniting "above the water and in the air," even as Europe weighs emergency electricity measures to limit prices.

Denmark's defence minister said there was no cause for security concerns in the Baltic Sea region.

"Russia has a significant military presence in the Baltic Sea region and we expect them to continue their sabre-rattling," Morten Bodskov said in a statement.

Video taken by a Danish military plane on Tuesday afternoon showed the extent of one of gas pipeline leaks, with the surface of the Baltic bubbling up as gas escapes, highlighting Europe's energy crisis for global audiences:

Meanwhile police in Sweden have opened a criminal investigation into "gross sabotage" of the Nord Stream 1 and Nord Stream 2 pipelines, and Sweden's crisis management unit was activated to monitor the situation. The unit brings together representatives from different government agencies. 

Swedish Foreign Minister Ann Linde had a call with her Danish counterpart Jeppe Kofod on Tuesday evening, and the pair also spoke with Norwegian Foreign Minister Anniken Huitfeldt on Wednesday, as the bloc debates gas price cap strategies to address the crisis, with Kofod saying there should be a "clear and unambiguous EU statement about the explosions in the Baltic Sea." 

"Focus now on uncovering exactly what has happened - and why. Any sabotage against European energy infrastructure will be met with a robust and coordinated response," said Kofod. 

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Texas PUC Electricity Market Reforms aim to boost grid reliability, support ERCOT resilience, pay standby generators, require capacity procurement, and mitigate blackout risk, though analysts warn higher consumer bills and winter reserve margin deficits.

Key Points

PUC proposals to bolster ERCOT reliability via standby capacity, capacity procurement, and measures to reduce blackout risk.

✅ Pays generators for standby capacity during grid stress

✅ Requires capacity procurement to meet forecast demand

✅ Could raise consumer bills despite reliability gains

The Public Utility Commission of Texas is discussing major reforms to the state’s electricity market with the purpose to avoid a repeat of the power failures and blackouts during the February 2021 winter storm, which led to the death of more than 100 people and left over 11 million residents without electricity for days.

The regulator is discussing at a meeting on Thursday around a dozen proposals to make the grid more stable and reliable in case of emergencies. Proposals include paying power generators that are on standby when the grid needs backup, and requiring companies to pre-emptively buy capacity to meet future demand.

It is not clear yet how many and which of the proposals for electricity market reforms PUC will endorse today, while Texans vote on funding to modernize electricity generation later this year.

Analysts and consumer protection bodies warn that the measures will raise the energy bills for consumers, as some electricity market bailout ideas shift costs to ratepayers as well.

“Customers will be paying for more, but will they be getting more reliability?” Michael Jewell, an attorney with Jewell & Associates PLLC who represents clients at PUC proceedings, told Bloomberg.

“This is going to take us further down a path that’s going to increase cost to consumers, we better be darn sure these are the right choices,” Tim Morstad, Associate State Director, AARP Texas, told FOX 4 NEWS.

Last month, a report by the North American Electric Reliability Corp warned that the Texas power grid remained vulnerable to blackouts in case of a repeat of this year’s February Freeze.

Beyond Texas, electricity blackout risks have been identified across the U.S., underscoring the stakes for grid planning.

According to the 2021-2022 Winter Reliability Assessment report, Texas risks a 37-percent reserve margin deficit in case of a harsh winter, with ERCOT moving to procure capacity to address winter concerns, NERC said.

A reserve margin is the reserve of power generation capacity comparative to demand. The expected reserve margin for Texas for this winter, according to NERC, is 41.9 percent. Yet if another cold spell hits the state, it would affect this spare capacity, pushing the margin deeply into negative territory.

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