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North Seattle Power Outage disrupts 13,000 in Ballard, Northgate, and Lake City as Seattle City Light crews repair equipment failures. Aging infrastructure, smart grid upgrades, microgrids, and emergency preparedness highlight resilience and reliability challenges.

Key Points

A major outage affecting 13,000 in North Seattle from equipment failures and aging grid, prompting repairs and planning.

✅ 13,000 customers in Ballard, Northgate, Lake City affected

✅ Cause: equipment failures and aging infrastructure

✅ Crews, smart grid upgrades, and preparedness improve resilience

On a recent Wednesday morning, a significant power outage struck a large area of North Seattle, affecting approximately 13,000 residents and businesses. This incident not only disrupted daily routines, as seen in a recent London outage, but also raised questions about infrastructure reliability and emergency preparedness in urban settings.

Overview of the Outage

The outage began around 9 a.m., with initial reports indicating that neighborhoods including Ballard, Northgate, and parts of Lake City were impacted. Utility company Seattle City Light quickly dispatched crews to identify the cause of the outage and restore power as soon as possible. By noon, the utility reported that repairs were underway, with crews working diligently to restore service to those affected.

Such outages can occur for various reasons, including severe weather, such as windstorm-related failures, equipment failure, or accidents involving utility poles. In this instance, the utility confirmed that a series of equipment failures contributed to the widespread disruption. The situation was exacerbated by the age of some infrastructure in the area, highlighting ongoing concerns about the need for modernization and upgrades.

Community Impact

The power outage caused significant disruptions for residents and local businesses. Many households faced challenges as their morning routines were interrupted—everything from preparing breakfast to working from home became more complicated without electricity. Schools in the affected areas also faced challenges, as some had to adjust their schedules and operations.

Local businesses, particularly those dependent on refrigeration and electronic payment systems, felt the immediate impact. Restaurants struggled to serve customers without power, while grocery stores dealt with potential food spoilage, leading to concerns about lost inventory and revenue. The outage underscored the vulnerability of businesses to infrastructure failures, as recent Toronto outages have shown, prompting discussions about contingency plans and backup systems.

Emergency Response

Seattle City Light’s swift response was crucial in minimizing the outage's impact. Utility crews worked through the day to restore power, and the company provided regular updates to the community, keeping residents informed about progress and estimated restoration times. This transparent communication was essential in alleviating some of the frustration among those affected, and contrasts with extended outages in Houston that heightened public concern.

Furthermore, the outage served as a reminder of the importance of emergency preparedness for both individuals and local governments, and of utility disaster planning that supports resilience. Many residents were left unprepared for an extended outage, prompting discussions about personal emergency kits, alternative power sources, and community resources available during such incidents. Local officials encouraged residents to stay informed about power outages and to have a plan in place for emergencies.

Broader Implications for Infrastructure

This incident highlights the broader challenges facing urban infrastructure. Many cities, including Seattle, are grappling with aging power grids that struggle to keep up with modern demands, and power failures can disrupt transit systems like the London Underground during peak hours. Experts suggest that regular assessments and updates to infrastructure are critical to ensuring reliability and resilience against both natural and human-made disruptions.

In response to increasing frequency and severity of power outages, including widespread windstorm outages in Quebec, there is a growing call for investment in modern technologies and infrastructure. Smart grid technology, for instance, can enhance monitoring and maintenance, allowing utilities to respond more effectively to outages. Additionally, renewable energy sources and microgrid systems could offer more resilience and reduce reliance on centralized power sources.

The recent power outage in North Seattle was a significant event that affected thousands of residents and businesses. While the immediate response by Seattle City Light was commendable, the incident raised important questions about infrastructure reliability and emergency preparedness. As cities continue to grow and evolve, the need for modernized power systems and improved contingency planning will be crucial to ensuring that communities can withstand future disruptions.

As residents reflect on this experience, it serves as a reminder of the interconnectedness of urban living and the critical importance of reliable infrastructure in maintaining daily life. With proactive measures, cities can work towards minimizing the impact of such outages and building a more resilient future for their communities.

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BC Hydro Time-of-Use Rates propose off-peak credits and peak surcharges, with 5 cent/kWh differentials, encouraging demand shifting, EV charging at night, and smart meter adoption, pending BC Utilities Commission review in an optional opt-in program.

Key Points

Optional pricing that credits 5 cents/kWh off-peak and adds 5 cents/kWh during 4-9 p.m. peak to encourage load shifting.

✅ Off-peak credit: 11 p.m.-7 a.m., 5 cents/kWh savings

✅ Peak surcharge: 4-9 p.m., additional 5 cents/kWh

✅ Opt-in only; BCUC review; suits EV charging and flexible loads

BC Hydro is looking to charge customers less for electricity during off peak hours and more during the busiest times of the day, reflecting holiday electricity demand as well.

The BC Utilities Commission is currently reviewing the application that if approved would see customers receive a credit of 5 cents per kilowatt hour for electricity used from 11 p.m. to 7 a.m.

Customers would be charged an additional 5 cents per kWh for electricity used during the on-peak period from 4 p.m. to 9 p.m., and in Ontario, there were no peak-rate cuts for self-isolating customers during early pandemic response.

There would be no credit or additional charge will be applied to usage during the off-peak period from 7 a.m. to 4 p.m. and 9 p.m. to 11 p.m.

“We know the way our customers are using power is changing and they want more options,” BC Hydro spokesperson Susie Rieder said.

“It is optional and we know it may not work for everyone.”

For example, if a customer has an electric vehicle it will be cheaper to plug the car in after 9 p.m., similar to Ontario's ultra-low overnight plan offerings, rather than immediately after returning home from a standard work day.

If approved, the time of use rates would only apply to customers who opt in to the program, whereas Ontario provided electricity relief during COVID-19.

During the pandemic, Ontario extended off-peak electricity rates to help households and small businesses.

The regulatory review process is expected to take about one year.

Other jurisdictions, including Ontario's ultra-low overnight pricing, currently offer off peak rates. One of the challenges is that consumers change in hopes of altering their behaviour, but in reality, end up paying more.

“The cheapest electrical grid system is one with consistent demand and the issue of course is our consumption is not flat,” energyrates.ca founder Joel MacDonald said.

“There is a 5 cent reduction in off peak times, there is a 5 cent increase in peak times, you would have to switch 50 per cent of your load.”

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Georgia Electricity Imports October 2017 surged as hydropower output fell and thermal power plants underperformed; ESCO balanced demand via low-cost imports, mainly from Azerbaijan, amid rising tariffs, kWh consumption growth, and a widening generation-consumption gap.

Key Points

They mark a record import surge due to costly local generation, lower hydropower, ESCO balancing costs, and rising demand.

✅ Imports rose 832% YoY to 157 mln kWh, mainly from Azerbaijan

✅ TPP output fell despite capacity; only low-tariff plants ran

✅ Balancing price 13.8 tetri/kWh signaled costly domestic PPAs

In October 2017, Georgian power plants generated 828 mln. KWh of electricity, marginally up (+0.79%) compared to September. Following the traditional seasonal pattern and amid European concerns over dispatchable power shortages affecting markets, the share of electricity produced by renewable sources declined to 71% of total generation (87% in September), while thermal power generation’s share increased, accounting for 29% of total generation (compared to 13% in September). When we compare last October’s total generation with the total generation of October 2016, however, we observe an 8.7% decrease in total generation (in October 2016, total generation was 907 mln. kWh). The overall decline in generation with respect to the previous year is due to a simultaneous decline in both thermal power and hydro power generation. 

Consumption of electricity on the local market in the same period was 949 mln. kWh (+7% compared to October 2016, and +3% with respect to September 2017), and reflected global trends such as India's electricity growth in recent years. The gap between consumption and generation increased to 121 mln. kWh (15% of the amount generated in October), up from 100 mln. kWh in September. Even more importantly, the situation was radically different with respect to the prior year, when generation exceeded consumption.

The import figure for October was by far the highest from the last 12 years (since ESCO was established), occurring as Ukraine electricity exports resumed regionally, highlighting wider cross-border dynamics. In October 2017, Georgia imported 157 mln. kWh of electricity (for 5.2 ¢/kWh – 13 tetri/kWh). This constituted an 832% increase compared to October 2016, and is about 50% larger than the second largest import figure (104.2 mln. kWh in October 2014). Most of the October 2017 imports (99.6%) came from Azerbaijan, with the remaining 0.04% coming from Russia.

The main question that comes to mind when observing these statistics is: why did Georgia import so much? One might argue that this is just the result of a bad year for hydropower generation and increased demand. This argument, however, is not fully convincing. While it is true that hydropower generation declined and demand increased, the country’s excess demand could have been easily satisfied by its existing thermal power plants, even as imported coal volumes rose in regional markets. Instead of increasing, however, the electricity coming from thermal power plants declined as well. Therefore, that cannot be the reason, and another must be found. The first that comes to mind is that importing electricity may have been cheaper than buying it from local TPPs, or from other generators selling electricity to ESCO under power purchase agreements (PPAs). We can test the first part of this hypothesis by comparing the average price of imported electricity to the price ceiling on the tariff that TPPs can charge for the electricity they sell. Looking at the trade statistics from Geostat, the average price for imported electricity in October 2017 remained stable with respect to the same month of the previous year, at 5.2 ¢ (13 tetri) per kWh. Only two thermal power plants (Gardabani and Mtkvari) had a price ceiling below 13 tetri per kWh. Observing the electricity balance of Georgia, we see that indeed more than 98% of the electricity generated by TPPs in October 2017 was generated by those two power plants.

What about other potential sources of electricity amid Central Asia's power shortages at the time? To answer this question, we can use the information derived from the weighted average price of balancing electricity. Why balancing electricity? Because it allows us to reconstruct the costs the market operator (ESCO) faced during the month of October to make sure demand and supply were balanced, and it allows us to gain an insight about the price of electricity sold through PPAs.

ESCO reports that the weighted average price of balancing electricity in October 2017 was 13.8 tetri/kWh, (25% higher than in October 2016, when it was below the average weighted cost of imports – 11 vs. 13 – and when the quantity of imported electricity was substantially smaller). Knowing that in October 2017, 61% of balancing electricity came from imports, while 39% came from hydropower and wind power plants selling electricity to ESCO under their PPAs, we can deduce that in this case, internal generation was (on average) also substantially more expensive than imports. Therefore, the high cost of internally generated electricity, rather than the technical impossibility of generating enough electricity to satisfy electricity demand, indeed appears to be one the main reasons why electricity imports spiked in October 2017.

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Germany Energy Demand Decline reflects economic stagnation, IEA forecasts, and the Energiewende, as industrial output slips and efficiency gains, renewables growth, and cost-cutting reduce fossil fuel use while reshaping sustainability and energy security.

Key Points

A projected 7% drop in German energy use driven by industrial slowdown, efficiency gains, and renewables expansion.

✅ IEA projects up to 7% demand drop in the next year

✅ Industrial slowdown and efficiency programs cut consumption

✅ Energiewende shifts mix to wind, solar, and less fossil fuel

Germany is on the verge of experiencing a significant decline in energy demand, with forecasts suggesting that usage could hit a record low as the country grapples with economic stagnation. This shift highlights not only the immediate impacts of sluggish economic growth but also broader trends in energy consumption, Europe's electricity markets, sustainability, and the transition to renewable resources.

Recent data indicate that Germany's economy is facing substantial challenges, including high inflation and reduced industrial output. As companies struggle to maintain profitability amid nearly doubled power prices and rising costs, many have begun to cut back on energy consumption. This retrenchment is particularly pronounced in energy-intensive sectors such as manufacturing and chemical production, which are crucial to Germany's export-driven economy.

The International Energy Agency (IEA) has projected that German energy demand could decline by as much as 7% in the coming year, a stark contrast to the trends seen in previous decades. This decline is primarily driven by a combination of factors, including reduced industrial activity, increased energy efficiency measures, and a shift toward alternative energy sources, as well as mounting pressures on local utilities to stay solvent. The current economic landscape has led businesses to prioritize cost-cutting measures, including energy efficiency initiatives aimed at reducing consumption.

In the context of these developments, Germany’s energy transition—known as the "Energiewende"—is becoming increasingly significant. The country has made substantial investments in renewable energy sources such as wind, solar, and biomass in recent years. As energy efficiency improves and the share of renewables in the energy mix rises, traditional fossil fuel consumption has begun to wane. This transition is seen as both a response to climate change and a strategy for energy independence, particularly in light of geopolitical tensions and Europe's wake-up call to ditch fossil fuels across the continent.

However, the current stagnation presents a paradox for the German energy sector. While lower energy demand may ease some pressures on supply and prices, it also raises concerns about the long-term viability of investments in renewable energy infrastructure, even as debates continue over electricity subsidies for industry to support competitiveness. The economic slowdown has the potential to derail progress made in reducing carbon emissions and achieving energy targets, particularly if it leads to decreased investment in green technologies.

Another layer to this issue is the potential impact on employment within the energy sector. As energy demand decreases, there may be a ripple effect on jobs tied to traditional energy production and even in renewable energy sectors if investment slows. Policymakers are now tasked with balancing the immediate need for economic recovery, illustrated by the 200 billion-euro energy price shield, with the longer-term goal of achieving sustainability and energy security.

The effects of the stagnation are also being felt in the residential sector. As households face increased living costs and rising heating and electricity costs, many are becoming more conscious of their energy consumption. Initiatives to improve home energy efficiency, such as better insulation and energy-efficient appliances, are gaining traction among consumers looking to reduce their utility bills. This shift toward energy conservation aligns with broader national goals of reducing overall energy consumption and carbon emissions.

Despite the challenges, there is a silver lining. The current situation offers an opportunity for Germany to reassess its energy strategies and invest in technologies that promote sustainability while also addressing economic concerns. This could include increasing support for research and development in green technologies, enhancing energy efficiency programs, and incentivizing businesses to adopt cleaner energy practices.

Furthermore, Germany’s experience may serve as a case study for other nations grappling with similar issues. As economies around the world face the dual pressures of recovery and sustainability, the lessons learned from Germany’s current energy landscape could inform strategies for balancing these often conflicting priorities.

In conclusion, Germany is poised to witness a historic decline in energy demand as economic stagnation takes hold. While this trend poses challenges for the energy sector and economic growth, it also highlights the importance of sustainability and energy efficiency in shaping the future. As the nation navigates this complex landscape, the focus will need to be on fostering innovation and investment that aligns with both immediate economic needs and long-term environmental goals. The path forward will require a careful balancing act, but with the right strategies, Germany can emerge as a leader in sustainable energy practices even in challenging times.

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Hong Kong Electricity Tariff Increase reflects a projected 1-2% rise as HK Electric and CLP Power shift to cleaner fuel and natural gas, expand gas-fired units and LNG terminals, and adjust the fuel clause charge.

Key Points

An expected 1-2% 2018 rise from cleaner fuel, natural gas projects, asset growth, and shrinking fuel cost surpluses.

✅ Expected 1-2% rise amid cleaner fuel and gas shift

✅ Fuel clause charge and asset expansion pressure prices

✅ HK Electric and CLP Power urged to use surpluses prudently

Hong Kong customers have been asked to expect higher electricity bills next year, as seen with BC Hydro rate increases in Canada, with a member of a government panel on energy policy anticipating an increase in tariffs of one or two per cent.

The environment minister, Wong Kam-sing, also hinted they should be prepared to dig deeper into their pockets for electricity, as debates over California electric bills illustrate, in the wake of power companies needing to use more expensive but cleaner fuel to generate power in the future.

HK Electric supplies power to Hong Kong Island, Lamma Island and Ap Lei Chau. Photo: David Wong

The city’s two power companies, HK Electric and CLP Power, are to brief lawmakers on their respective annual tariff adjustments for 2018, amid Ontario electricity price pressures drawing international attention, at a Legislative Council economic development panel meeting on Tuesday.

HK Electric supplies electricity to Hong Kong Island and neighbouring Lamma Island and Ap Lei Chau, while CLP Power serves Kowloon and the New Territories, including Lantau Island.

Wong said on Monday: “We have to appreciate that when we use cleaner fuel, there is a need for electricity tariffs to keep pace. I believe it is the hope of mainstream society to see a low-carbon and healthier environment.”

Secretary for the Environment Wong Kam-sing believes most people desire a low-carbon environment. Photo: Sam Tsang

But he declined to comment on how much the tariffs might rise.

World Green Organisation chief executive William Yu Yuen-ping, also a member of the Energy Advisory Committee, urged the companies to better use their “overflowing” surpluses in their fuel cost recovery accounts.

Tariffs are comprised of two components: a basic amount reflecting a company’s operating costs and investments, and the fuel clause charge, which is based on what the company projects it will pay for fuel for the year.

William Yu of World Green Organisation says the companies should use their surpluses more carefully. Photo: May Tse

Critics have claimed the local power suppliers routinely overestimate their fuel costs and amass huge surpluses.

In recent years, the two managed to freeze or cut their tariffs thanks to savings from lower fuel costs. Last year, HK Electric offered special rebates to its customers, which saw its tariff drop by 17.2 per cent. CLP Power froze its own charge for 2017.

Yu said the two companies should use the surpluses “more carefully” to stabilise tariffs.

Rise after fall in Hong Kong electricity use linked to subsidies

“We estimate a big share of the surplus has been used up and so the honeymoon period is over.”

Based on his group’s research, Yu believed the tariffs would increase by one or two per cent.

Economist and fellow committee member Billy Mak Sui-choi said the expansion of the power companies’ fixed asset bases, such as building new gas-fired units and offshore liquefied natural gas terminals, a pattern reflected in Nova Scotia's 14% rate hike recently approved by regulators, would also cause tariffs to rise.

To fight climate change and improve air quality, the government has pledged to cut carbon intensity by between 50 and 60 per cent by 2020. Officials set a target of boosting the use of natural gas for electricity generation to half the total fuel mix from 2020.

Both power companies are privately owned and monitored by the government through a mutually agreed scheme of control agreements, akin to oversight seen under the UK energy price cap in other jurisdictions. These require the firms to seek government approval for their development plans, including their projected basic tariff levels.

At present, the permitted rate of return on their net fixed assets is 9.99 per cent. The deals are due to expire late next year.

Earlier this year, officials reached a deal with the two companies on the post-2018 scheme, settling on a 15-year term. The new agreements slash their permitted rate of return to 8 per cent.

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Puerto Rico Microgrid Regulations outline renewable energy, CHP, and storage standards, enabling islanded systems, PREPA interconnection, excess energy sales, and IRP alignment to boost resilience, distributed resources, and community power across the recovering grid.

Key Points

Rules defining microgrids, requiring 75 percent renewables or CHP, and setting interconnection and PREPA fee frameworks.

✅ 75 percent renewables or CHP; hybrids allowed

✅ Registration, engineer inspection, and annual generation reports

✅ PREPA interconnection fees; excess energy sales permitted

The Puerto Rico Energy Commission unveiled 29 pages of proposed regulations last week for future microgrid installations on the island.

The regulations, which are now open for 30 days of public comment, synthesized pages of responses received after a November 10 call for recommendations. Commission chair José Román Morales said it’s the most interest the not-yet four-year-old commission has received during a public rulemaking process.

The goal was to sketch a clearer outline for a tricky-to-define concept -- the term "microgrid" can refer to many types of generation islanded from the central grid -- as climate pressures on the U.S. grid mount and more developers eye installations on the recovering island.

“There’s not a standard definition of what a microgrid is, not even on the mainland,” said Román Morales.

According to the commission's regulation, “a microgrid shall consist, at a minimum, of generation assets, loads and distribution infrastructure. Microgrids shall include sufficient generation, storage assets and advanced distribution technologies, including advanced inverters, to serve load under normal operating and usage conditions.”

All microgrids must be renewable (with at least 75 percent of power from clean energy), combined heat and power (CHP) or hybrid CHP-and-renewable systems. The regulation applies to microgrids controlled and owned by individuals, customer cooperatives, nonprofit and for-profit companies, and cities, but not those owned by the Puerto Rico Electric Power Authority (PREPA). Owners must submit a registration application for approval, including a certification of inspection from a licensed electric engineer, and an annual fuel, generation and sales report that details generation and fuel source, as well as any change in the number of customers served.

Microgrids, like the SDG&E microgrid in Ramona in California, can interconnect with the PREPA system, but if a microgrid will use PREPA infrastructure, owners will incur a monthly fee. That amounts to $25 per customer up to a cap of $250 per month for small cooperative microgrids. The cost for larger systems is calculated using a separate, more complex equation. Operators can also sell excess energy back to PREPA.

Big goals for the island's future grid

In total, 53 groups and companies, including Sunnova, AES, the Puerto Rico Solar Energy Industries Association (PR-SEIA), the Advanced Energy Management Alliance (AEMA), and the New York Smart Grid Consortium, submitted their thoughts about microgrids or, in many cases, broader goals for the island’s future energy system. It was a quick turnaround: The Puerto Rico Energy Commission offered a window of just 10 days to submit advice, although the commission continued to accept comments after the deadline.

“PREC wanted the input as fast as possible because of the urgency,” said AES CEO Chris Shelton.

AES’ plan includes a network of “mini-grids” that could range in size from several megawatts to one large enough to service the entire city of San Juan.

“The idea is, you connect those to each other with transmission so they can have a co-optimized portfolio effect and lower the overall cost,” said Shelton. “But they would be largely autonomous in a situation where the tie-lines between them were broken.”

According to estimates provided in AES’ filing, utility-scale solar installations over 50 megawatts on the island could cost between $40 and $50 per megawatt-hour. Those prices make solar located near load centers an economic alternative to the island’s fossil-fuel generating plants. The utility’s analysis showed that a 10,000-megawatt solar system could replace 12,000 gigawatt-hours of fossil generation, with 25 gigawatt-hours of battery storage leveling out load throughout the day. Puerto Rico’s peak load is 3,000 megawatts.

In other filings, PR-SEIA urged a restructuring of FEMA funds so they’re available for microgrid development. GridWise Alliance wrote that plans should consider cybersecurity, and AEMA recommended the commission develop an integrated resource plan (IRP) that includes distributed energy resources, microgrids and non-wires alternatives.

An air of optimism, though 1.5 million are still without power

After the commission completes the microgrid rulemaking, a new IRP is next on the commission’s to-do list. PREPA must file that plan in July, and regulators are working furiously to make sure it incorporates the recent flood of rebuilding recommendations from the energy industry.

Though the commission has the final say when it comes to approval of the plan, PREPA will lead the IRP process. The utility’s newly formed Transformation Advisory Council (TAC), a group of 11 energy experts, will contribute.

With that group, along with New York’s Resiliency Working Group, lessons from California's grid transition, the Energy Commission, the utility itself, and the dozens of other clean energy experts and entrepreneurs who want to offer their two cents, the energy planning process has a lot of moving parts. But according to Julia Hamm, CEO of the Smart Electric Power Alliance and a member of both the Energy Resiliency Working Group and the TAC, those working to establish standards for Puerto Rico’s future are hitting their stride.

“Certainly over the past three months, it has been a bit of a challenge to ensure that everybody has been coordinating efforts. Just over the past couple of weeks, we’ve seen some good progress on that front. We’re starting to see a lot more communication,” she said, adding that an air of optimism has settled on the process. “The key stakeholders all have a very common vision for Puerto Rico when it comes to the power sector.”

Nisha Desai, a PREPA board member who is liaising with the TAC, affirmed that collaborators are on the same page. “Everyone is violently in agreement that the future of Puerto Rico involves renewables, microgrids and distributed generation,” she said.

The TAC will hold its first in-person meeting in mid-January, and has already consulted with the utility on its formal fiscal plan submission, due January 10.

Though many taking part in the process feel the once-harried recovery is beginning to adopt a more organized approach, Desai acknowledges that “there are a lot of people in Puerto Rico who feel forgotten.”

Puerto Rico’s current generation sits at just 72.6 percent, in a nation facing longer, more frequent outages due to extreme weather. The government recently offered its first estimate that about half the island, 1.5 million residents, remains without power.

In late December and into January, 1,500 more crewmembers from 18 utilities in states as far flung as Minnesota, Missouri and Arizona will land on the island to aid further restoration through mutual aid agreements.

“The system is getting up to speed, getting to 100 percent, but there’s still some instability,” said Román Morales. “Right now it’s a matter of time.”

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