Renters are wary of meters

Northern Ireland No-Deal Power Contingency outlines Whitehall plans to deploy thousands of generators on barges in the Irish Sea, safeguard the electricity market, and avert blackouts if Brexit disrupts imports from the Republic of Ireland.

Key Points

A UK Whitehall plan to prevent NI blackouts by deploying generators and protecting cross-border electricity flows.

✅ Barges in Irish Sea to host temporary power generators

✅ Mitigates loss of EU market access in a no-deal Brexit

✅ Ensures NI supply if Republic cuts electricity exports

Such a scenario could see thousands of electricity generators being requisitioned at short notice and positioned on barges in the Irish Sea, even as Great Britain's generation mix shapes wider supply dynamics, to help keep the region going, a Whitehall document quoted by the Financial Times states.

An emergency operation could see equipment being brought back from places like Afghanistan, where the UK still has a military presence, the newspaper said.

The extreme situation could arise because Northern Ireland shares a single energy market with the Irish Republic, where Irish grid price spikes have heightened concern about stability.

The region relies on energy imports from the Republic because it does not have enough generating capacity itself, and the UK is aiming to negotiate a deal to allow that single electricity market on the island of Ireland to continue post-EU withdrawal, while virtual power plant proposals for UK homes are explored to avoid outages, the FT stated.

However, if no Brexit deal is agreed Whitehall fears suppliers in the Irish Republic could cut off power because the UK would no longer be part of the European electricity market, and a recent short supply warning from National Grid underscores the risk.

In a bid to prevent blackouts in Northern Ireland in a worse case situation the Government would need to put thousands of generators into place, even as an emergency energy plan has reportedly not gone ahead nationwide, according to the report.

And officials fear they may need to commandeer some generators from the military in such a scenario, the FT reports.

An official was quoted by the newspaper as saying the preparations were “gob-smacking”.

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Cold-Climate Heat Pumps deliver efficient heating and cooling for Northern B.C. Net Zero Ready homes, with air-source Mitsubishi H2i systems, triple-pane windows, blower door ACH 0.8, BC Hydro rebates, and CleanBC incentives.

Key Points

Electric air-source systems that heat and cool in subzero climates, cutting emissions and lowering energy costs.

✅ Net Zero Ready, Step Code 5, ACH 0.8 airtightness

✅ Operate efficiently to about -28 C with backup heat

✅ Eligible for BC Hydro and CleanBC rebates

Heat pump provides heating, cooling in northern B.C. home
It's a tradition at Vanderhoof-based Northern Homecraft that, on the day of the blower door test for a just-completed home, everyone who worked on the build gathers to watch it happen. And in the spring of 2021, on a dazzling piece of land overlooking the mouth of the Stuart River near Fort St. James, that day was a cause for celebration.

A new 3,400-square foot home subjected to the blower door test – a diagnostic tool to determine how much air is entering or escaping from a home – was rated as having just .8 air changes per hour (ACH). That helps make it a Net Zero Ready home, and BC Energy Code Step 5 compliant. That means it would take about a third of the amount of energy to heat the home compared to a typical similar-sized home in B.C. today.

From an energy-efficiency perspective, this is a home whose evident beauty is anything but skin deep.

"The home has lot of square footage of finished living space, and it also has a lot of glazing," says Northern Homecraft owner Shay Bulmer, referring to the home's large windows. "We had a lot of window space to deal with, as well as large vaulted open areas where you can only achieve so much additional insulation. There were a few things that the home had going against it as far as performance goes. There were challenges in keeping it comfortable year-round."

Well-insulated home ideal for heat pump option
Most homes in colder areas of B.C. lean on gas-fueled heating systems to deal with the often long, chilly winters. But with the arrival of cold climate heat pumps capable of providing heat efficiently when temperatures dip as low as -30°C, there's now a clean option for those homes, and using more electricity for heat is gaining support in the North as well.

Heat pumps are an increasingly popular option, both for new and existing homes, because they avoid carbon emissions associated with fossil use while also offering summer cooling, even as record-high electricity demand in Yukon underscores the need for efficient systems.

The Fort St. James home, which was built with premium insulation, airtightness and energy efficiency in mind, made the decision to opt for a heat pump even easier. Still, the heat pump option took the home's owners Dexter and Cheryl Hodder by surprise. While their focus was on designing a home that took full advantage of views down to the river, the couple was under the distinct impression that heat pumps couldn't cut it in the chilly north.

"I wasn't really considering a heat pump, which I thought was only a good solution in a moderate climate," says Dexter, who as director of research and education for the John Prince Research Forest, studies wildlife and forestry interactions in north central B.C. "The specs on the heat pump indicate it would work down to -28°C, and I was skeptical of that. But it worked exactly to spec. It almost seems ridiculous to generate heat from outside air at those low temperatures, but it does."

Getting it right with support and rebates
Northern Homecraft took advantage of BC Hydro's Mechanical System Design Pilot program to ensure proper heat pump system design, installation, and verification for the home were applied, and with BC Hydro's first call for power in 15 years driven by electrification, the team prioritized efficient load management.

Based on the home's specific location, size, and performance targets, they installed a ducted Mitsubishi H2I air-source heat pump system. Windows are triple pane, double coated, and a central feature of the home, while insulation specifications were R-40 deep frame insulation in the exterior walls, R-80 insulation in the attic, and R-40 insulation in the vaulted ceilings.

The combination of the year-round benefits of heat pumps, their role in reducing fossil fuel emissions, and the availability of rebates, is making the systems increasingly attractive in B.C., especially as two new BC generating stations were recently commissioned to expand clean supply.

BC Hydro offers home renovation rebates of up to $10,000 for energy-efficient upgrades to existing homes. Rebates are available for windows and doors, insulation, heat pumps, and heat pump hot water heaters. In partnership with CleanBC, rebates of up to $11,000 are also available – when combined with the federal Greener Homes program – for those switching from fossil fuel heating to an electric heat pump.

'Heat dome' pushes summer highs to 40°C
Cooling wasn't really a consideration for Dexter and Cheryl when they were living in a smaller bungalow shaded by trees. But they knew that with the big windows, vaulted ceiling in the living room, and an upstairs bedroom in the new home, there may come a time when they needed air conditioning.

That day arrived shortly after the home was built, as the infamous "heat dome" settled on B.C. and drove temperatures at Fort St. James to a dizzying 40°C.

"It was disgustingly hot, and I don't care if I never see that again here," says Hodder, with a laugh. "But the heat pump maintained the house really nicely throughout, at about 22 degrees. The whole house stayed cool. We just had to close the door to the upper bedroom so it wasn't really heating up during the day."

Hodder says he had to work with the heat pump manufacturer Mitsubishi a couple times over that first year to fix a few issues with the system's controls. But he's confident that the building's tight and well-insulated envelope, and the heat pump's backup electric heat that kicks in when temperatures dip below -28°C, will make it the system-for-all-seasons it was designed to be.

Even with the use of supplemental electric heating during the record chill of December-January, the home's energy costs weren't much higher than the mid-winter energy bills they used to pay in the couple's smaller bungalow that relied on a combination of gas-fired in-floor heating and electric baseboards, as gas-for-electricity swaps are being explored elsewhere.

Fort St. James is a former fur trading post located northwest of Prince George and a short drive north of Vanderhoof. Winters are cold and snowy, with average daily low temperatures in December and January of around -14°C.

"During the summer and into the fall, we were paying well less than $100 a month," says Hodder, looking back at electricity bills over the first year in the home. "And that's everything. We're only electric here, and we also had both of us working from home all last year."

Word of mouth making heat pumps popular in Fort St. James
While the size of the home presented new challenges for the builders, it's one of five Net Zero Ready or Net Zero homes – all equipped with some form of heat pump – that Northern Homecraft has built in Fort St. James, even as debates about going nuclear for electricity continue in B.C.

The smallest of the homes is a two-bedroom, one-bathroom home that's just under 900 square feet. Northern Homecraft may be based in Vanderhoof, but it's the much smaller town of Fort St. James where they're making their mark with super-efficient homes. Net Zero Ready homes are up to 80% more efficient than the standard building code, and become Net Zero once renewable energy generation – usually in the form of photovoltaic solar – is installed, and programs like switching 5,000 homes to geothermal show the broader momentum for clean heating.

"We were pretty proud that the first home we built in Fort St. James was the first single family Net Zero Ready home built in B.C.," says Northern Homecraft's Bulmer. "And I think it's kind of caught on in a smaller community where everyone talks to everyone."

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Power plant staff sequestration isolates essential operators on-site at plants and control centers, safeguarding critical infrastructure and grid reliability during the COVID-19 pandemic under DHS CISA guidance, with social distancing, offset shifts, and stockpiled supplies.

Key Points

A protocol isolating essential grid workers on-site to maintain operations at plants and control centers.

✅ Ensures grid reliability and continuity of critical infrastructure

✅ Implements social distancing, offset shifts, and isolation protocols

✅ Stockpiles food, beds, PPE, and sanitation for essential crews

The U.S. electric industry may ask essential staff to live on site at power plants and control centers to keep operations running if the coronavirus outbreak worsens, after a U.S. grid warning from the overseer, and has been stockpiling beds, blankets, and food for them, according to industry trade groups and electric cooperatives.

The contingency plans, if enacted, would mark an unprecedented step by power providers to keep their highly-skilled workers healthy as both private industry and governments scramble to minimize the impact of the global pandemic that has infected more than 227,000 people worldwide, with some utilities such as BC Hydro at Site C reporting COVID-19 updates as the situation evolves.

“The focus needs to be on things that keep the lights on and the gas flowing,” said Scott Aaronson, vice president of security and preparedness at the Edison Electric Institute (EEI), the nation’s biggest power industry association. He said that some “companies are already either sequestering a healthy group of their essential employees or are considering doing that and are identifying appropriate protocols to do that.”

Maria Korsnick, president of the Nuclear Energy Institute, said that some of the nation’s nearly 60 nuclear power plants are also “considering measures to isolate a core group to run the plant, stockpiling ready-to-eat meals and disposable tableware, laundry supplies and personal care items.”

Neither group identified specific companies, though nuclear worker concerns have been raised in some cases.

Electric power plants, oil and gas infrastructure and nuclear reactors are considered “critical infrastructure” by the federal government, and utilities continue to emphasize safety near downed lines even during emergencies. The U.S. Department of Homeland Security is charged with coordinating plans to keep them operational during an emergency.

A DHS spokesperson said that its Cybersecurity and Infrastructure Security Agency had issued guidance to local governments and businesses on Thursday asking them to implement policies to protect their critical staff from the virus, even as an EPA telework policy emerged during the pandemic.

“When continuous remote work is not possible, businesses should enlist strategies to reduce the likelihood of spreading the disease,” the guidance stated. “This includes, but is not necessarily limited to, separating staff by off-setting shift hours or days and/or social distancing.”

Public health officials have urged the public to practice social distancing as a preventative measure to slow the spread of the virus, and as more people work from home, rising residential electricity use is being observed alongside daily routines. If workers who are deemed essential still leave, go to work and return to their homes, it puts the people they live with at risk of exposure. 

California has imposed a statewide shutdown, asking all citizens who do not work in those critical infrastructure industries not to leave their homes, a shift that may raise household electricity bills for consumers. Similar actions have been put in place in cities across America.

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Vancouver Natural Gas Ban Reversal spotlights energy policy, electrification tradeoffs, heat pumps, emissions, grid reliability, and affordability, reshaping building codes and decarbonization pathways while inviting stakeholders to weigh practical constraints and climate goals.

Key Points

Vancouver ending its ban on natural gas in new homes to balance climate goals with reliability, costs, and technology.

✅ Balances emissions goals with reliability and affordability

✅ Impacts builders, homeowners, and energy infrastructure

✅ Spurs debate on electrification, heat pumps, and grid capacity

In a significant policy shift, Vancouver has decided to lift its ban on natural gas appliances in new homes, a move that marks a pivotal moment in the city's energy policy and environmental strategy. This decision, announced recently and following the city's Clean Energy Champion recognition for Bloedel upgrades, has sparked a broader conversation about the future of energy systems and the balance between environmental goals and practical energy needs. Stewart Muir, CEO of Resource Works, argues that this reversal should catalyze a necessary dialogue on energy choices, highlighting both the benefits and challenges of such a policy change.

Vancouver's original ban on natural gas appliances was part of a broader initiative aimed at reducing greenhouse gas emissions and promoting sustainability, including progress toward phasing out fossil fuels where feasible over time. The city had adopted stringent regulations to encourage the use of electric heat pumps and other low-carbon technologies in new residential buildings. This move was aligned with Vancouver’s ambitious climate goals, which include achieving carbon neutrality by 2050 and significantly cutting down on fossil fuel use.

However, the recent decision to reverse the ban reflects a growing recognition of the complexities involved in transitioning to entirely new energy systems. The city's administration acknowledged that while electric alternatives offer environmental benefits, they also come with challenges that can affect homeowners, builders, and the broader energy infrastructure, including options for bridging the electricity gap with Alberta to enhance regional reliability.

Stewart Muir argues that Vancouver’s policy shift is not just about natural gas appliances but represents a larger conversation about energy system choices and their implications. He suggests that the reversal of the ban provides an opportunity to address key issues related to energy reliability, affordability, and the practicalities of integrating new technologies, including electrified LNG options for industry within the province into existing systems.

One of the primary reasons behind the reversal is the recognition of the practical limitations and costs associated with transitioning to electric-only systems. For many homeowners and builders, natural gas appliances have long been a reliable and cost-effective option. The initial ban on these appliances led to concerns about increased construction costs and potential disruptions for homeowners who were accustomed to natural gas heating and cooking.

In addition to cost considerations, there are concerns about the reliability and efficiency of electric alternatives. Natural gas has been praised for its stable energy supply and efficient performance, especially in colder climates where electric heating systems might struggle to maintain consistent temperatures or fully utilize Site C's electricity under peak demand. By reversing the ban, Vancouver acknowledges that a one-size-fits-all approach may not be suitable for every situation, particularly when considering diverse housing needs and energy demands.

Muir emphasizes that the reversal of the ban should prompt a broader discussion about how to balance environmental goals with practical energy needs. He argues that rather than enforcing a blanket ban on specific technologies, it is crucial to explore a range of solutions that can effectively address climate objectives while accommodating the diverse requirements of different communities and households.

The debate also touches on the role of technological innovation in achieving sustainability goals. As energy technologies continue to evolve, renewable electricity is coming on strong and new solutions and advancements could potentially offer more efficient and environmentally friendly alternatives. The conversation should include exploring these innovations and considering how they can be integrated into existing energy systems to support long-term sustainability.

Moreover, Muir advocates for a more inclusive approach to energy policy that involves engaging various stakeholders, including residents, businesses, and energy experts. A collaborative approach can help identify practical solutions that address both environmental concerns and the realities of everyday energy use.

In the broader context, Vancouver’s decision reflects a growing trend in cities and regions grappling with energy transitions. Many urban centers are evaluating their energy policies and considering adjustments based on new information and emerging technologies. The key is to find a balance that supports climate goals such as 2050 greenhouse gas targets while ensuring that energy systems remain reliable, affordable, and adaptable to changing needs.

As Vancouver moves forward with its revised policy, it will be important to monitor the outcomes and assess the impacts on both the environment and the community. The reversal of the natural gas ban could serve as a case study for other cities facing similar challenges and could provide valuable insights into how to navigate the complexities of energy transitions.

In conclusion, Vancouver’s decision to reverse its ban on natural gas appliances in new homes is a significant development that opens the door for a critical dialogue about energy system choices. Stewart Muir’s call for a broader conversation emphasizes the need to balance environmental ambitions with practical considerations, such as cost, reliability, and technological advancements. As cities continue to navigate their energy futures, finding a pragmatic and inclusive approach will be essential in achieving both sustainability and functionality in energy systems.

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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.

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Great Northern Transmission Line delivers 250 MW of carbon-free hydropower from Manitoba Hydro, strengthening Midwest grid reliability, enabling wind storage balancing, and advancing Minnesota Power's EnergyForward strategy for cleaner, renewable energy across the region.

Key Points

A 500 kV cross-border line delivering 250 MW of carbon-free hydropower, strengthening reliability and enabling renewables.

✅ 500 kV, 224-mile line from Manitoba to Minnesota

✅ Delivers 250 MW hydropower via ALLETE-Minnesota Power

✅ Enables wind storage and grid balancing with Manitoba Hydro

Minnesota Power, a utility division of ALLETE Inc. (NYSE:ALE), has energized its Great Northern Transmission Line, bringing online an innovative delivery and storage system for renewable energy that spans two states and one Canadian province, similar to the Maritime Link project in Atlantic Canada.

The 500 kV line is now delivering 250 megawatts of carbon-free hydropower from Manitoba, Canada, to Minnesota Power customers.

Minnesota Power completed the Great Northern Transmission Line (GNTL) in February 2020, ahead of schedule and under budget. The 224-mile line runs from the Canadian border in Roseau County to a substation near Grand Rapids, Minnesota. It consists of 800 tower structures which were fabricated in the United States and used 10,000 tons of North American steel. About 2,200 miles of wire were required to install the line's conductors. The GNTL also is contributing significant property tax revenue to local communities along the route.

"This is such an incredible achievement for Minnesota Power, ALLETE, and our region, and is the culmination of a decade-long vision brought to life by our talented and dedicated employees," said ALLETE President and CEO Bethany Owen. "The GNTL will help Minnesota Power to provide our customers with 50 percent renewable energy less than a year from now. As part of our EnergyForward strategy, it also strengthens the grid across the Midwest and in Canada, enhancing reliability for all of our customers."

With the GNTL energized and connected to Manitoba Hydro's recently completed Manitoba-Minnesota Transmission Project at the border, the companies now have a unique "wind storage" mechanism that quickly balances energy supply and demand in Minnesota and Manitoba, and enables a larger role for renewables in the North American energy grid.

The GNTL and its delivery of carbon-free hydropower are important components of Minnesota Power's EnergyForward strategy to transition away from coal and add renewable power sources while maintaining reliable and affordable service for customers, echoing interties like the Maritime Link that facilitate regional power flows. It also is part of a broader ALLETE strategy to advance and invest in critical regional transmission and distribution infrastructure, such as the TransWest Express transmission project, to ensure grid integrity and enable cleaner energy to reduce carbon emissions.

"The seed for this renewable energy initiative was planted in 2008 when Minnesota Power proposed purchasing 250 megawatts of hydropower from Manitoba Hydro. Beyond the transmission line, it also included a creative asset swap to move wind power from North Dakota to Minnesota, innovative power purchase agreements, and a remarkable advocacy process to find an acceptable route for the GNTL," said ALLETE Executive Chairman Al Hodnik. "It marries wind and water in a unique connection that will help transform the energy landscape of North America and reduce carbon emissions related to the existential threat of climate change."

Minnesota Power and Manitoba Hydro, a provincial Crown Corporation, coordinated on the project from the beginning, navigating National Energy Board reviews along the way. It is based on the companies' shared values of integrity, environmental stewardship and community engagement.

"The completion of Minnesota Power's Great Northern Transmission Line and our Manitoba-Minnesota Transmission Project is a testament to the creativity, perseverance, cooperation and skills of hundreds of people over so many years on both sides of the border," said Jay Grewal, president and CEO of Manitoba Hydro. "Perhaps even more importantly, it is a testament to the wonderful, longstanding relationship between our two companies and two countries. It shows just how much we can accomplish when we all work together toward a common goal."

Minnesota Power engaged federal, state and local agencies; the sovereign Red Lake Nation and other tribes, reflecting First Nations involvement in major transmission planning; and landowners along the proposed routes beginning in 2012. Through 75 voluntary meetings and other outreach forums, a preferred route was selected with strong support from stakeholders that was approved by the Minnesota Public Utilities Commission in April 2016.

A four-year state and federal regulatory process culminated in late 2016 when the federal Department of Energy approved a Presidential Permit for the GNTL, similar to the New England Clean Power Link process, needed because of the international border crossing. Construction of the line began in early 2017.

"A robust stakeholder process is essential to the success of any project, but especially when building a project of this scope," Owen said. "We appreciated the early engagement and support from stakeholders, local communities and tribes, agencies and regulators through the many approval milestones to the completion of the GNTL."

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