Electricity News in June 2019
Why electric buses haven't taken over the world—yet
Electric Buses reduce urban emissions and noise, but require charging infrastructure, grid upgrades, and depot redesigns; they offer lower operating costs and simpler maintenance, with range limits influencing routes, schedules, and on-route fast charging.
Key Points
Battery-electric buses cut emissions and noise while lowering operating and maintenance costs for transit agencies.
✅ Lower emissions, noise; improved rider experience
✅ Requires charging, grid upgrades, depot redesigns
✅ Range limits affect routes; on-route fast charging helps
In lots of ways, the electric bus feels like a technology whose time has come. Transportation is responsible for about a quarter of global emissions, and those emissions are growing faster than in any other sector. While buses are just a small slice of the worldwide vehicle fleet, they have an outsize effect on the environment. That’s partly because they’re so dirty—one Bogotá bus fleet made up just 5 percent of the city’s total vehicles, but a quarter of its CO2, 40 percent of nitrogen oxide, and more than half of all its particulate matter vehicle emissions. And because buses operate exactly where the people are concentrated, we feel the effects that much more acutely.
Enter the electric bus. Depending on the “cleanliness” of the electric grid into which they’re plugged, e-buses are much better for the environment. They’re also just straight up nicer to be around: less vibration, less noise, zero exhaust. Plus, in the long term, e-buses have lower operating costs, and related efforts like US school bus electrification are gathering pace too.
So it makes sense that global e-bus sales increased by 32 percent last year, according to a report from Bloomberg New Energy Finance, as the age of electric cars accelerates across markets worldwide. “You look across the electrification of cars, trucks—it’s buses that are leading this revolution,” says David Warren, the director of sustainable transportation at bus manufacturer New Flyer.
Today, about 17 percent of the world’s buses are electric—425,000 in total. But 99 percent of them are in China, where a national mandate promotes all sorts of electric vehicles. In North America, a few cities have bought a few electric buses, or at least run limited pilots, to test the concept out, and early deployments like Edmonton's first e-bus offer useful lessons as systems ramp up. California has even mandated that by 2029 all buses purchased by its mass transit agencies be zero-emission.
But given all the benefits of e-buses, why aren’t there more? And why aren’t they everywhere?
“We want to be responsive, we want to be innovative, we want to pilot new technologies and we’re committed to doing so as an agency,” says Becky Collins, the manager of corporate initiative at the Southeastern Pennsylvania Transportation Authority, which is currently on its second e-bus pilot program. “But if the diesel bus was a first-generation car phone, we’re verging on smartphone territory right now. It’s not as simple as just flipping a switch.”
One reason is trepidation about the actual electric vehicle. Some of the major bus manufacturers are still getting over their skis, production-wise. During early tests in places like Belo Horizonte, Brazil, e-buses had trouble getting over steep hills with full passenger loads. Albuquerque, New Mexico, canceled a 15-bus deal with the Chinese manufacturer BYD after finding equipment problems during testing. (The city also sued). Today’s buses get around 225 miles per charge, depending on topography and weather conditions, which means they have to re-up about once a day on a shorter route in a dense city. That’s an issue in a lot of places.
If you want to buy an electric bus, you need to buy into an entire electric bus system. The vehicle is just the start.
The number one thing people seem to forget about electric buses is that they need to get charged, and emerging projects such as a bus depot charging hub illustrate how infrastructure can scale. “We talk to many different organizations that get so fixated on the vehicles,” says Camron Gorguinpour, the global senior manager for the electric vehicles at the World Resources Institute, a research organization, which last month released twin reports on electric bus adoption. “The actual charging stations get lost in the mix.”
But charging stations are expensive—about $50,000 for your standard depot-based one. On-route charging stations, an appealing option for longer bus routes, can be two or three times that. And that’s not even counting construction costs. Or the cost of new land: In densely packed urban centers, movements inside bus depots can be tightly orchestrated to accommodate parking and fueling. New electric bus infrastructure means rethinking limited space, and operators can look to Toronto's TTC e-bus fleet for practical lessons on depot design. And it’s a particular pain when agencies are transitioning between diesel and electric buses. “The big issue is just maintaining two sets of fueling infrastructure,” says Hanjiro Ambrose, a doctoral student at UC Davis who studies transportation technology and policy.
“We talk to many different organizations that get so fixated on the vehicles. The actual charging stations get lost in the mix as the American EV boom gathers pace across sectors.”
Then agencies also have to get the actual electricity to their charging stations. This involves lengthy conversations with utilities about grid upgrades, rethinking how systems are wired, occasionally building new substations, and, sometimes, cutting deals on electric output, since electric truck fleets will also strain power systems in parallel. Because an entirely electrified bus fleet? It’s a lot to charge. Warren, the New Flyer executive, estimates it could take 150 megawatt-hours of electricity to keep a 300-bus depot charged up throughout the day. Your typical American household, by contrast, consumes 7 percent of that—per year. “That’s a lot of work by the utility company,” says Warren.
For cities outside of China—many of them still testing out electric buses and figuring out how they fit into their larger fleets—learning about what it takes to run one is part of the process. This, of course, takes money. It also takes time. Optimists say e-buses are more of a question of when than if. Bloomberg New Energy Finance projects that just under 60 percent of all fleet buses will be electric by 2040, compared to under 40 percent of commercial vans and 30 percent of passenger vehicles.
Which means, of course, that the work has just started. “With new technology, it always feels great when it shows up,” says Ambrose. “You really hope that first mile is beautiful, because the shine will come off. That’s always true.”
Related News
Duke Energy Florida to build its largest battery storage projects yet
Duke Energy Florida battery storage will add 22 MW across Trenton, Cape San Blas and Jennings, improving grid reliability, outage resilience, enabling peak shaving and deferring distribution upgrades to increase efficiency and customer value.
Key Points
Three lithium battery projects totaling 22 MW to improve Florida grid reliability, outage resilience and efficiency.
✅ 22 MW across Trenton, Cape San Blas and Jennings sites
✅ Enhances outage resilience and grid reliability
✅ Defers costly distribution upgrades and improves efficiency
Duke Energy Florida (DEF) has announced three battery energy storage projects, totaling 22 megawatts, that will improve overall reliability and support critical services during power outages.
Duke Energy, the nation's largest electric utility, unveils its new logo. (PRNewsFoto/Duke Energy) (PRNewsfoto/Duke Energy)
Collectively, the storage facilities will enhance grid operations, increase efficiencies and improve overall reliability for surrounding communities, with virtual power plant programs offering a model for coordinating distributed resources.
They will also provide important backup generation during power outages, a service that is becoming increasingly important with the number and intensity of storms that have recently impacted the state.
As the grid manager and operator, DEF can maximize the versatility of battery energy storage systems (BESS) to include multiple customer and electric system benefits such as balancing energy demand, managing intermittent resources, increasing energy security and deferring traditional power grid upgrades.
These benefits help reduce costs for customers and increase operational efficiencies.
The 11-megawatt (MW) Trenton lithium-based battery facility will be located 30 miles west of Gainesville in Gilchrist County. The energy storage project will continue to improve power reliability using newer technologies.
The 5.5-MW Cape San Blas lithium-based battery facility will be located approximately 40 miles southeast of Panama City in Gulf County. The project will provide additional power capacity to meet our customers' rising energy demand in the area. This project is an economical alternative to replacing distribution equipment necessary to accommodate local load growth.
The 5.5-MW Jennings lithium-based battery facility will be located 1.5 miles south of the Florida-Georgia border in Hamilton County. The project will continue to improve power reliability through energy storage as an alternative solution to installing new and more costly distribution equipment.
Currently the company plans to complete all three projects by the end of 2020.
"These battery projects provide electric system benefits that will help improve local reliability for our customers and provide significant energy services to the power grid," said Catherine Stempien, Duke Energy Florida state president. "Duke Energy Florida will continue to identify opportunities in battery storage technology which will deliver efficiency improvements to our customers."
Additional renewables projects
As part of DEF's commitment to renewables, the company is investing an estimated $1 billion to construct or acquire a total of 700 MW of cost-effective solar power facilities and 50 MW of battery storage through 2022.
Duke Energy is leading the industry deployment of battery technology, with SDG&E's Emerald Storage project underscoring broader adoption across the sector today. Last fall, the company and University of South Florida St. Petersburg unveiled a Tesla battery storage system that is connected to a 100-kilowatt (kW) solar array – the first of its kind in Florida.
This solar-battery microgrid system manages the energy captured by the solar array, situated on top of the university's parking garage, and similar low-income housing microgrid financing efforts are expanding access. The solar array was constructed three years ago through a $1 million grant from Duke Energy. The microgrid provides a backup power source during a power outage for the parking garage elevator, lights and electric vehicle charging stations. Click here to learn more.
In addition to expanding its battery storage technology and solar investments, DEF is investing in transportation electrification to support the growing U.S. adoption of electric vehicles (EV), including EV charging infrastructure, 530 EV charging stations and a modernized power grid to deliver the diverse and reliable energy solutions customers want and need.
Related News
Duke Energy installing high-tech meters for customers
Duke Energy Smart Meters enable remote meter reading, daily energy usage data, and two-way outage detection via AMI, with encrypted data, faster restoration, and remote connect/disconnect for Indiana customers in Howard County.
Key Points
Advanced meters that support remote readings, daily usage insights, two-way outage detection, and secure, encrypted data.
✅ Daily energy usage available online the next day
✅ Two-way communications speed outage detection and restoration
✅ Remote connect/disconnect; manual reads optional with opt-out fee
Say goodbye to your neighborhood meter reader. Say hello to your new smart meter.
Over the next three months, Duke Energy will install nearly 43,000 new high-tech electric meters for Howard County customers that will allow the utility company to remotely access meters via the digital grid instead of sending out employees to a homeowner's property for walk-by readings.
That means there's no need to estimate bills when meters can't be easily accessed, such as during severe weather or winter storms.
Other counties serviced by Duke Energy slated to receive the meters include Miami, Tipton, Cass and Carroll counties.
Angeline Protogere, Duke Energy's lead communication consultant, said besides saving the company money and manpower, the new smart meters come with a host of benefits for customers enabled by smart grid solutions today.
The meters are capable of capturing daily energy usage data, which is available online the next day. Having this information available on a daily basis can help customers make smarter energy decisions and support customer analytics that avoid billing surprises at the end of the month, she said.
"The real advantage is for the consumer, because they can track their energy usage and adjust their usage before the bills come," Protogere said.
When it comes to power outages, the meters are capable of two-way communications. That allows the company to know more about an outage through synchrophasor monitoring, which can help speed up restoration. However, customers will still need to notify Duke Energy if their power goes out.
If a customer is moving, they don't have to wait for a Duke Energy representative to come to the premises to connect or disconnect the energy service because requests can be performed remotely.
Protogere said when it comes to installing the meters, the changeover takes less than 5 minutes to complete. Customers should receive advance notices from the company, but the technician also will knock on the door to let the customer know they are there.
If no one is available and the meter is safely accessible, the technician will go ahead and change out the meter, Protogere said. There will be a momentary outage between the time the old meter is removed and the new meter is installed.
Kokomo and the surrounding areas are one of the last parts of the state to receive Duke Energy's new, high-tech meters, which are commonly used by other utility companies and in smart city initiatives across the U.S.
Protogere said statewide, the company started installing smart meters in August 2016 as utilities deploy digital transformer stations to modernize the grid. To date, they have installed 694,000 of the 854,000 they have planned for the state.
The company says the information stored and transmitted on the smart meters is safe, protected and confidential. Duke Energy said on its website that it does not share data with anyone without customers' authorization. The information coming from the meters is encrypted and protected from the moment it is collected until the moment it is purged, the company said.
Digital smart meter technology uses radio frequency bands that have been used for many years in devices such as baby monitors and medical monitors. The radio signals are far below the levels emitted by common household appliances and electronics, including cellphones and microwave ovens.
According to the World Health Organization, FCC, U.S. Food and Drug Administration and Electric Power Research Institute, no adverse health effects have been shown to occur from the radio frequency signals produced by smart meters or other such wireless networks.
However, customers can still opt-out of getting a smart meter and continue to have their meter manually read.
Those who choose not to get a smart meter must pay a $75 initial opt-out fee and an additional $17.50 monthly meter reading charge per account.
If smart meters have not yet been installed, Duke Energy will waive the $75 initial opt-out fee if customers notify the company they want to opt out within 21 days of receiving the installation postcard notice.
Related News
Advocates call for change after $2.9 million surplus revealed for BC Hydro fund
BC Hydro Customer Crisis Fund Surplus highlights unused grants, pilot program imbalance, and calls to reduce fees or expand eligibility. Ratepayers, regulators, and social agencies urge awareness, rebates, and aid for overdue electricity bills.
Key Points
A funding carryover from BC Hydro's crisis grants, sparking debate over fee reductions or more aid eligibility.
✅ $2.9M surplus from 25-cent monthly customer fee
✅ Only 2,250 grants issued; awareness and eligibility questioned
✅ Regulator may refund balance or adjust program design
BC Hydro is sitting on a surplus of about $2.9 million in its customer crisis fund, even as BC Hydro rates rise 3% across the province, leading to calls for the utility to reduce its take from the average customer or provide more money to those in need.
B.C. Liberal Energy Critic Greg Kyllo said if the imbalance continues in the year-old pilot program, amid a provincial rate freeze announced by the province, it’s time to cut the monthly 25 cent fee in half.
"If the grant requirement or the need in the province is going to remain where it is, they should look at rolling back the contribution level in the fund," he told CTV News Vancouver from Salmon Arm.
But social agencies who were part of the consultation around the fund in the beginning said it’s more likely that people in need don’t know about the fund and more time is necessary to get the word out.
"If they collect the money, then the program’s got to change to make sure more people are able to be helped," said Gudrun Langolf of the Council of Senior Citizens Organizations of BC.
The customer crisis fund was started in spring 2018 to give people short-term relief when they can’t pay their electricity bills, especially as a $2 monthly hike pressures household budgets. Customers can apply to get a grant of up to $500 to keep the lights on, and up to $600 if electricity heats their homes.
The public utility took in about 25 cents per customer per month which added up to a revenue of $4.5 million in the year since the program started, BC Hydro confirmed to CTV News.
But the agency only gave out 2,250 grants totalling $850,000.
Administration costs added up around $750,000 – leaving the $2.9 million remaining.
The news will come as a welcome relief to those who suddenly struggle to pay their hydro bills, particularly as Alberta ratepayers are on the hook under a utility deferral program elsewhere in Canada.
Some people who come into Disability Alliance B.C. are often anxious and emotional when they’re suddenly unable to pay their bills, said Shar Saremi, an advocate there.
"I’ve had people crying. I’ve had people who have experienced a loss in the family," she said. "A lot of the time people are stressed out, anxious, really upset. They are looking for assistance, and they aren’t sure what is available for them."
She said people are only eligible if their bills are under $1,000, which could be cutting out the people who are most in need. And because the program is in its first year, it could be undersubscribed, she said.
"A lot of people don’t know about the program, don’t know how to apply, or what kind of assistance is out there," Saremi said.
The fund was established thanks to an order from the B.C. Utilities Commission, the utilities regulator in the province.
The pilot program is going to be examined by the regulator at the end of its first year.
"Any remaining balance in the account at the end of the pilot would be returned to residential ratepayers," says a BCUC fact sheet, as BC Hydro rates are set to rise 3.75% over two years. The decision on exactly what to do with the money hasn’t yet been made.
In Manitoba, a similar program is by donation, and in Newfoundland and Labrador a lump-sum credit was offered to bill payers in a separate initiative. That program raised about $200,000 from customers and $60,000 in other income. It spent $199,000 on grants to applicants, but lost about $20,000 a year.
In Ontario, private utilities are expected to raise 0.12 per cent of their revenue, and Hydro One reconnections have highlighted the stakes for nonpayment there. Across the province, those utilities gave out about $7.3 million in grants. Any unused funds in one year are rolled over to the following year.
Related News
Nonstop Records For U.S. Natural-Gas-Based Electricity
U.S. Natural Gas Power Demand is surging for electricity generation amid summer heat, with ERCOT, Texas grid reserves tight, EIA reporting coal and nuclear retirements, renewables intermittency, and pipeline expansions supporting combined-cycle capacity and prices.
Key Points
It is rising use of natural gas for power, driven by summer heat, plant retirements, and new combined-cycle capacity.
✅ ERCOT reserve margin 9%, below 14% target in Texas
✅ Gas share of U.S. power near 40-43% this summer
✅ Coal and nuclear retirements shift capacity to combined cycle
As the hot months linger, it will be natural gas that is leaned on most to supply the electricity that we need to run our air conditioning loads on the grid and keep us cool.
And this is surely a great and important thing: "Heat causes most weather-related deaths, National Weather Service says."
Generally, U.S. gas demand for power in summer is 35-40% higher than what it was five years ago, with so much more coming (see Figure).
The good news is regions across the country are expected to have plenty of reserves to keep up with power demand.
The only exception is ERCOT, covering 90% of the electric load in Texas, where a 9% reserve margin is expected, below the desired 14%.
Last summer, however, ERCOT’s reserve margin also was below the desired level, yet the grid operator maintained system reliability with no load curtailments.
Simply put, other states are very lucky that Texas has been able to maintain gas at 50% of its generation, despite being more than justified to drastically increase that.
At about 1,600 Bcf per year, the flatness of gas for power demand in Texas since 2000 has been truly remarkable, especially since Lone Star State production is up 50% since then.
Increasingly, other U.S. states (and even countries) are wanting to import huge amounts of gas from Texas, a state that yields over 25% of all U.S. output.
Yet if Texas justifiably ever wants to utilize more of its own gas, others would be significantly impacted.
At ~480 TWh per year, if Texas was a country, it would be 9th globally for power use, even ahead of Brazil, a fast growing economy with 212 million people, and France, a developed economy with 68 million people.
In the near-term, this explains why a sweltering prolonged heat wave in July in Texas, with a hot Houston summer setting new electricity records, is the critical factor that could push up still very low gas prices.
But for California, our second highest gas using state, above-average snowpack should provide a stronger hydropower for this summer season relative to 2018.
Combined, Texas and California consume about 25% of U.S. gas, with Texas' use double that of California.
Across the U.S., gas could supply a record 40-43% of U.S. electricity this summer even as the EIA expects solar and wind to be larger sources of generation across the mix
Our gas used for power has increased 35-40% over the past five years, and January power generation also jumped on the year, highlighting broad momentum.
Our gas used for power has increased 35-40% over the past five years. DATA SOURCE: EIA; JTC
Indeed, U.S. natural gas for electricity has continued to soar, even as overall electricity consumption has trended lower in some years, at nearly 10,700 Bcf last year, a 16% rise from 2017 and easily the highest ever.
Gas is expected to supply 37% of U.S. power this year, even as coal-fired generation saw a brief uptick in 2021 in EIA data, versus 27% just five years ago (see Figure).
Capacity wise, gas is sure to continue to surge its share 45% share of the U.S. power system.
"More than 60% of electric generating capacity installed in 2018 was fueled by natural gas."
We know that natural gas will continue to be the go-to power source: coal and nuclear plants are retiring, and while growing, wind and solar are too intermittent, geography limited, and transmission short to compensate like natural gas can.
"U.S. coal power capacity has fallen by a third since 2010," and last year "16 gigawatts (16,000 MW) of U.S. coal-fired power plants retired."
This year, some 2,000 MW of coal was retired in February alone, with 7,420 MW expected to be closed in 2019.
Ditto for nuclear.
Nuclear retirements this year include Pilgrim, Massachusetts’s only nuclear plant, and Three Mile Island in Pennsylvania.
This will take a combined ~1,600 MW of nuclear capacity offline.
Another 2,500 MW and 4,300 MW of nuclear are expected to be leaving the U.S. power system in 2020 and 2021, respectively.
As more nuclear plants close, EIA projects that net electricity generation from U.S. nuclear power reactors will fall by 17% by 2025.
From 2019-2025 alone, EIA expects U.S. coal capacity to plummet nearly 25% to 176,000 MW, with nuclear falling 15% to 83,000 MW.
In contrast, new combined cycle gas plants will grow capacity almost 30% to around 310,000 MW.
Lower and lower projected commodity prices for gas encourage this immense gas build-out, not to mention non-stop increases in efficiency for gas-based units.
Remember that these are official U.S. Department of Energy estimates, not coming from the industry itself.
In other words, our Department of Energy concludes that gas is the future.
Our hotter and hotter summers are therefore more and more becoming: "summers for natural gas"
Ultimately, this shows why the anti-pipeline movement is so dangerous.
"Affordable Energy Coalition Highlights Ripple Effect of Natural Gas Moratorium."
In April, President Trump signed two executive orders to promote energy infrastructure by directing federal agencies to remove bottlenecks for gas transport into the Northeast in particular, where New England oil-fired generation has spiked, and to streamline federal reviews of border-crossing pipelines and other infrastructure.
Builders, however, are not relying on outside help: all they know is that more U.S. gas demand is a constant, so more infrastructure is mandatory.
They are moving forward diligently: for example, there are now some 27 pipelines worth $33 billion already in the works in Appalachia.
Related News
Growing pot sucks up electricity and pumps out an astounding amount of carbon dioxide — it doesn't have to
Sustainable Cannabis Cultivation leverages greenhouse design, renewable energy, automation, and water recapture to cut electricity use, emissions, and pesticides, delivering premium yields with natural light, smart sensors, and efficient HVAC and irrigation control.
Key Points
A data-driven, low-impact method that cuts energy, water, and chemicals while preserving premium yields.
✅ 70-90% less electricity vs. conventional indoor grows
✅ Natural light, solar, and rainwater recapture reduce footprint
✅ Automation, sensors, and HVAC stabilize microclimates
In the seven months since the Trudeau government legalized recreational marijuana use, licensed producers across the country have been locked in a frenetic race to grow mass quantities of cannabis for the new market.
But amid the rush for scale, questions of sustainability have often taken a back seat, and in Canada, solar adoption has lagged in key sectors.
According to EQ Research LLC, a U.S.-based clean-energy consulting firm, cannabis facilities can need up to 150 kilowatt-hours of electricity per year per square foot. Such input is on par with data centres, which are themselves 50 to 200 times more energy-intensive than a typical office building, and achieving zero-emission electricity by 2035 would help mitigate the associated footprint.
At the Lawrence Berkley National Laboratory in California, a senior scientist estimated that one per cent of U.S. electricity use came from grow ops. The same research — published in 2012 — also found that the procedures for refining a kilogram of weed emit around 4,600 kilograms of carbon dioxide to the atmosphere, equivalent to operating three million cars for a year, though a shift to zero-emissions electricity by 2035 could substantially cut those emissions.
“All factors considered, a very large expenditure of energy and consequent ‘environmental imprint’ is associated with the indoor cultivation of marijuana,” wrote Ernie Small, a principal research scientist for Agriculture and Agri-Food Canada, in the 2018 edition of the Biodiversity Journal.
Those issues have left some turning to technology to try to reduce the industry’s footprint — and the economic costs that come with it — even as more energy sources make better projects for forward-looking developers.
“The core drawback of most greenhouse environments is that you’re just getting large rooms, which are harder to control,” says Dan Sutton, the chief executive officer of Tantalus Labs., a B.C.-based cannabis producer. “What we did was build a system specifically for cannabis.”
Sutton is referring to SunLab, the culmination of four years of construction, and at present the main site where his company nurtures rows of the flowering plant. The 120,000-square foot structure was engineered for one purpose: to prove the merits of a sustainable approach.
“We’re actually taking time-series data on 30 different environmental parameters — really simple ones like temperature and humidity — all the way down to pH of the soil and water flow,” says Sutton. “So if the temperature gets a little too cold, the system recognizes that and kicks on heaters, and if the system senses that the environment is too hot in the summertime, then it automatically vents.”
A lot is achieved without requiring much human intervention, he adds. Unlike conventional indoor operations, SunLab demands up to 90 per cent less electricity, avoids using pesticides, and draws from natural light and recaptured rainwater to feed its crops.
The liquid passes through a triple-filtration process before it is pumped into drip irrigation tubing. “That allows us to deliver a purity of water input that is cleaner than bottled water,” says Sutton.
As transpiration occurs, a state-of-the-art, high-capacity airflow suspended below the ceiling cycles air at seven-minute intervals, repeatedly cooling the air and preventing outbreaks of mould, while genetically modified “guardian” insects swoop in to eliminate predatory pests.
“When we first started, people never believed we would cultivate premium quality cannabis or cannabis that belongs on the top shelf, shoulder to shoulder with the best in the world and the best of indoor,” says Sutton.
Challenges still exist, but they pale in comparison to the obstacles that American companies with an interest in adopting greener solutions persistently face, and in provinces like Alberta, an Alberta renewable energy surge is reshaping the opportunity set.
Although cannabis is legal in a number of states, it remains illegal federally, which means access to capital and regulatory clarity south of the border can be difficult to come by.
“Right now getting a new project built is expensive to do because you can’t get traditional bank loans,” says Canndescent CEO Adrian Sedlin, speaking by phone from California.
In retrofitting the company’s farm to accommodate a sizeable solar field, he struggled to secure investors, even as a solar-powered cannabis facility in Edmonton showcased similar potential.
“We spent over a year and a half trying to get it financed,” says Sedlin. “Finding someone was the hard part.”
Decriminalizing the drug would ultimately increase the supply of capital and lower the costs for innovative designs, something Sedlin says would help incentivize producers to switch to more effective and ecologically sound techniques.
Some analysts argue that selling renewable energy in Alberta could become a major growth avenue that benefits energy-intensive industries like cannabis cultivation.
Canndescent, however, is already there.
“We’re now harnessing the sun to reduce our reliance on fossil fuels and going to sustainable, or replenishable, energy sources, while leveraging the best and most efficient water practices,” says Sedlin. “It’s the right thing to do.”
Related News
Costa Rica hits record electricity generation from 99% renewable sources
Costa Rica Renewable Energy Record highlights 99.99% clean power in May 2019, driven by hydropower, wind, solar, geothermal, and biomass, enabling ICE REM electricity exports and reduced rates from optimized generation totaling 984.19 GWh.
Key Points
May 2019 benchmark: Costa Rica generated 99.99% of 984.19 GWh from renewables, shifting from imports to regional exports.
✅ 99.99% renewable share across hydro, wind, solar, geothermal, biomass
✅ 984.19 GWh generated; ICE suspended imports and exported via REM
✅ Geothermal output increased to offset dry-season hydropower variability
During the whole month of May 2019, Costa Rica generated a total of 984.19 gigawatt hours of electricity, the highest in the country’s history. What makes this feat even more impressive is the fact that 99.99% of this energy came from a portfolio of renewable sources such as hydropower, wind, biomass, solar, and geothermal.
With such a high generation rate, the state power company Instituto Costariccense de Electricidad (ICE) were able to suspend energy imports from the first week of May and shifted to exports, while U.S. renewable electricity surpassed coal in 2022 domestically. To date, the power company continues to sell electricity to the Regional Electricity Market (REM) which generates revenues and is likely to reduce local electricity rates, a trend echoed in places like Idaho where a vast majority of electricity comes from renewables.
The record-breaking power generation was made possible by optimization of the country’s renewable sources, much as U.S. wind capacity surpassed hydro capacity at the end of 2016 to reshape portfolios. As the period coincided with the tail end of the dry season, the geothermal quota had to be increased.
Costa Rica remains a leader in renewable power generation, whereas U.S. wind generation has become the most-used renewable source in recent years. In 2015, more than 98% of the country’s electrical generation came from renewable sources, while U.S. renewables hit a record 28% in April in one recent benchmark. Through the years, this figure has remained fairly constant despite dry bouts caused by the El Niño phenomenon, and U.S. solar generation also continued to rise.
Related News
Flowing with current, Frisco, Colorado wants 100% clean electricity
Frisco 100% Renewable Electricity Goal outlines decarbonization via Xcel Energy, wind, solar, and battery storage, enabling beneficial electrification and a smarter grid for 100% municipal power by 2025 and community-wide clean electricity by 2035.
Key Points
Frisco targets 100% renewable electricity: municipal by 2025, community by 2035, via Xcel decarbonization.
✅ Municipal operations to reach 100% renewable electricity by 2025
✅ Community-wide electricity to be 100% carbon-free by 2035
✅ Partnerships: Xcel Energy, wind, solar, storage, grid markets
Frisco has now set a goal of 100-per-cent renewable energy, joining communities on the road to 100% renewables across the country. But unlike some other resolutions adopted in the last decade, this one isn't purely aspirational. It's swimming with a strong current.
With the resolution adopted last week by the town council, Frisco joins 10 other Colorado towns and cities, plus Pueblo and Summit counties, a trend reflected in tracking progress on clean energy targets reports nationwide, in adopting 100-per-cent goals.
The goal is to get the municipality's electricity to 100-per-cent by 2025 and the community altogether by 2035, a timeline aligned with scenarios showing zero-emissions electricity by 2035 is possible in North America.
Decarbonizing electricity will be far easier than transportation, and transportation far easier than buildings. Many see carbon-free electricity as being crucial to both, a concept called "beneficial electrification," and point to ways to meet decarbonization goals that leverage electrified end uses.
Electricity for Frisco comes from Xcel Energy, an investor-owned utility that is making giant steps toward decarbonizing its power supply.
Xcel first announced plans to close its work-horse power plants early to take advantage of now-cheap wind and solar resources plus what will be the largest battery storage project east of the Rocky Mountains. All this will be accomplished by 2026 and will put Xcel at 55 per cent renewable generation in Colorado.
In December, a week after Frisco launched the process that produced the resolution, Xcel announced further steps, an 80 percent reduction in carbon dioxide emissions by 2030 as compared to 2050 levels. By 2050, the company vows to be 100 per cent "carbon-free" energy by 2050.
Frisco's non-binding goals were triggered by Fran Long, who is retired and living in Frisco. For eight years, though, he worked for Xcel in helping shape its response to the declining prices of renewables. In his retirement, he has also helped put together the aspirational goal adopted by Breckenridge for 100-per-cent renewables.
A task force that Long led identified a three-pronged approach. First, the city government must lead by example. The resolution calls for the town to spend $25,000 to $50,000 annually during the next several years to improve energy efficiency in its municipal facilities. Then, through an Xcel program called Renewable Connect, it can pay an added cost to allow it to say it uses 100-per-cent electricity from renewable sources.
Beyond that, Frisco wants to work with high-end businesses to encourage buying output from solar gardens or other devices that will allow them to proclaim 100-per-cent renewable energy. The task force also recommends a marketing program directed to homes and smaller businesses.
Goals of 100-per-cent renewable electricity are problematic, given why the grid isn't 100% renewable today for technical and economic reasons. Aspen Electric, which provides electricity for about two-thirds of the town, by 2015 had secured enough wind and hydro, mostly from distant locations, to allow it to proclaim 100 per cent renewables.
In fact, some of those electrons in Aspen almost certainly originate in coal or gas plants. That doesn't make Aspen's claim wrong. But the fact remains that nobody has figured out how, at least at affordable cost, to deliver 100-per-cent clean energy on a broad basis.
Xcel Energy, which supplies more than 60 per cent of electricity in Colorado, one of six states in which it operates, has a taller challenge. But it is a very different utility than it was in 2004, when it spent heavily in advertising to oppose a mandate that it would have to achieve 10 per cent of its electricity from renewable sources by 2020.
Once it lost the election, though, Xcel set out to comply. Integrating renewables proved far more easily than was feared. It has more than doubled the original mandate for 2020. Wind delivers 82 per cent of that generation, with another 18 per cent coming from community, rooftop, and utility-scale solar.
The company has become steadily more proficient at juggling different intermittent power supplies while ensuring lights and computers remain on. This is partly the result of practice but also of relatively minor technological wrinkles, such as improved weather forecasting, according to an Energy News Network story published in March.
For example, a Boulder company, Global Weather corporation, projects wind—and hence electrical production—from turbines for 10 days ahead. It updates its forecasts every 15 minutes.
Forecasts have become so good, said John T. Welch, director of power operations for Xcel in Colorado, that the utility uses 95 per cent to 98 per cent of the electricity generated by turbines. This has allowed the company to use its coal and natural gas plants less.M
Moreover, prices of wind and then solar declined slowly at first and then dramatically.
Xcel is now comfortable that existing technology will allow it to push from 55 per cent renewables in 2026 to an 80 per cent carbon reduction goal by 2030.
But when announcing their goal of emissions-free energy by mid-century in December, the company's Minneapolis-based chief executive, Ben Fowke, and Alice Jackson, the chief executive of the company's Colorado subsidiary, freely admitted they had no idea how they will achieve it. "I have a lot of confidence they will be developed," Fowke said of new technologies.
Everything is on the table, they said, including nuclear. But also including fossil fuels, if the carbon dioxide can be sequestered. So far, such technology has proven prohibitively expensive despite billions of dollars in federal support for research and deployment. They suggested it might involve new technology.
Xcel's Welch told Energy News Network that he believes solar must play a larger role, and he believes solar forecasting must improve.
Storage technology must also improve as batteries are transforming solar economics across markets. Batteries, such as produced by Tesla at its Gigafactory near Reno, can store electricity for hours, maybe even a few days. But batteries that can store large amounts of electricity for months will be needed in Colorado. Wind is plentiful in spring but not so much in summer, when air conditioners crank up.
Increased sharing of cheap renewable generation among utilities will also allow deeper penetration of carbon-free energy, a dynamic consistent with studies finding wind and solar could meet 80% of demand with improved transmission. Western US states and Canadian provinces are all on one grid, but the different parts are Balkanized. In other words, California is largely its own energy balancing authority, ensuring electricity supplies match electricity demands. Ditto for Colorado. The Pacific Northwest has its own balancing authority.
If they were all orchestrated as one in an expanded energy market across the West, however, electricity supplies and demands could more easily be matched. California's surplus of solar on summer afternoons, for example, might be moved to Colorado.
Colorado legislators in early May adopted a bill that requires the state's Public Utilities Commission to begin study by late this year of an energy imbalance market or regional transmission organization.
Related News
Electrifying Manitoba: How hydro power 'absolutely revolutionized' the province
Manitoba Electrification History charts arc lights, hydroelectric dams, Winnipeg utilities, transmission lines, rural electrification, and Manitoba Hydro to today's wind, solar, and EV transition across the provincial power grid, driving modernization and reliability.
Key Points
Manitoba's power evolution from arc lights to hydro and rural electrification, advancing wind and solar on a modern grid.
✅ 1873 Winnipeg arc light predates Edison and Bell.
✅ 1919 Act built transmission lines, rural electrification.
✅ Hydroelectric dams reshaped lands and affected First Nations.
The first electric light in Manitoba was turned on in Winnipeg in 1873, but it was a century ago this year that the switch was flipped on a decision that would bring power to the fingertips of people across the province.
On March 12, 1873, Robert Davis — who owned the Davis House hotel on Main Street, about a block from Portage Avenue — used an electric arc light to illuminate the front of his building, according to A History of Electric Power in Manitoba, published by Manitoba Hydro.
That type of light used an an inert gas in a glass container to create an electric arc between two metal electrodes.
"The lamp in front of the Davis Hotel is quite an institution," a Manitoba Free Press report from the day said. "It looks well and guides the weary traveller to a haven of rest, billiards and hot drinks."
A ladder crew from the Winnipeg Electric Street Railway Company working on an electric trolley line in 1905. (I.F. Allen/Manitoba Hydro archives)
The event took place six years before Thomas Edison's first incandescent lamp was invented and three years before the first complete sentence was spoken over the telephone by Alexander Graham Bell.
"Electrification probably had a bigger influence on the lives of Manitobans than virtually anything else," said Gordon Goldsborough, head researcher with the Manitoba Historical Society.
"It's one of the most significant changes in the lives of Manitobans ever, because basically it transformed so many aspects of their lives. It wasn't just one thing — it touched pretty much every aspect of life."
Winnipeg gets its 1st street lamps
In the pioneer days of lighting and street railway transportation in Winnipeg, multiple companies formed in an effort to take advantage of the new utility: Winnipeg Gas Company, Winnipeg General Power Company, Manitoba Electric and Gas Light Company, and The North West Electric Light and Power Company.
In October 1882, the first four street lamps, using electric arc lights, were turned on along Main Street from Broadway to the CPR crossing over the Assiniboine River.
They were installed privately by P.V. Carroll, who came from New York to establish the Manitoba Electric Light & Power Company and try to win a contract for illuminating the rest of the city's streets.
He didn't get it. Newspaper reports from the time noted many outages and other problems and general disappointment in the quality of the light.
Instead, the North West Electric Light and Power Company won that contract and in June 1883 it lit up the streets.
Workers erect a wooden hydro pole beside the Belmont Hotel in 1936. Belmont is a small community southeast of Brandon. (Manitoba Hydro archives)
Over the years, other companies would bring power to the city as it became more reliable, including the Winnipeg Electric Street Railway Company (WERCo), which built the streetcar system and sold electric heat, light and power.
But it was the Brandon Electric Light Company that first tapped into a new source of power — hydro. In 1900, a dam was built across the Minnedosa River (now known as the Little Saskatchewan River) in western Manitoba, and the province's first hydroelectric generating station was created.
The first transmission line was also built, connecting the station with Brandon.
By 1906, WERCo had taken over the Winnipeg General Power Company and the Manitoba Electric and Gas Light Company, and changed its name to the Winnipeg Electric Railway Company. Later, it became the Winnipeg Electric Company, or WECo.
It also took a cue from Brandon, building a hydroelectric plant to provide more power. The Pinawa dam site operated until 1951 and is now a provincial park.
The Minnedosa River plant was the first hydroelectric generating station in Manitoba. (Manitoba Hydro archives)
The City of Winnipeg Hydroelectric System was also formed in 1906 as a public utility to combat the growing power monopoly held by WECo, and to get cheaper power. The city had been buying its supply from the private company "and the City of Winnipeg didn't quite like that price," said Bruce Owen, spokesman for Manitoba Hydro.
So the city funded and built its own dam and generating station site on the Winnipeg River in Pointe du Bois — about 125 kilometres northeast of Winnipeg — which is still in operation today.
"All of a sudden, not only did we have street lights … businesses had lights, power was supplied to homes, people no longer had to cook on wood stoves or walk around with kerosene lanterns. This city took off," said Owen.
"It helped industry grow in the city of Winnipeg. Within a few short years, a second plant had to be built, at Slave Falls."
Lighting up rural Manitoba
While the province's two biggest cities enjoyed the luxury of electricity and the conveniences it brought, the patchwork of power suppliers had also created a jumble of contracts with differing rates and terms, spurring periodic calls for a western Canadian electricity grid to improve coordination.
Meanwhile, most of rural Manitoba remained in the dark.
The Pinawa Dam was built by the Winnipeg Electric Street Railway Company in 1906 and operated until 1951. (Manitoba Hydro archives)
The Pinawa Dam site now, looking like some old Roman ruins. (Darren Bernhardt/CBC)
That began to change in 1919 when the Manitoba government passed the Electric Power Transmission Act, with the aim of supplying rural Manitoba with electrical power. The act enabled the construction of transmission lines to carry electricity from the Winnipeg River generating stations to communities all over southern Manitoba.
It also created the Manitoba Power Commission, predecessor to today's Manitoba Hydro, to purchase power from the City of Winnipeg — and later WECo — to supply to those other communities.
The first transmission line, a 97-kilometre link between Winnipeg and Portage la Prairie, opened in late 1919, and modern interprovincial projects like Manitoba-Saskatchewan power line funding continue that legacy today. The power came from Pointe du Bois to a Winnipeg converter station that still stands at the corner of Stafford Street and Scotland Avenue, then went on to Portage la Prairie.
"That's the remarkable thing that started in 1919," said Goldsborough.
Every year after that, the list of towns connected to the power grid became longer "and gradually, over the early 20th century, the province became electrified," Goldsborough said.
"You'd see these maps that would spider out across the province showing the [lines] that connected each of these communities — a precursor to ideas like macrogrids — to each other, and it was really quite remarkable."
By 1928, 33 towns were connected to the Manitoba Power Commission grid. That rose to 44 by 1930 and 140 by 1939, according to the Manitoba Historical Society.
Power on the farm
Still, one group who could greatly use electricity for their operations — farmers — were still using lanterns, steam and coal for light, heat and power.
"The power that came to the [nearest] town didn't extend to them," said Goldsborough.
It was during the Second World War, as manual labour was hard to come by on farms, that the Manitoba Power Commission recognized the gap in its grid.
It met with farmers to explain the benefits electricity could bring and surveyed their interest. When the war ended in 1945, the farm electrification process got underway.
Employees, their spouses, and children pose for a photo outside of Great Falls generating station in 1923. (Manitoba Hydro archives)
Farmers were taught wiring techniques and about the use of motors for farm equipment, as well as about electric appliances and other devices to ease the burden of domestic life.
"The electrification of the 1940s and '50s absolutely revolutionized rural life," said Goldsborough.
"Farmers had to provide water for all those animals and in a lot of cases [prior to electrification] they would just use a hand pump, or sometimes they'd have a windmill. But these were devices that weren't especially reliable and they weren't high capacity."
Electric motors changed everything, from pumping water to handling grain, while electric heat provided comfort to both people and animals.
Workers build a hydro transmission line tower in an undated photo from Manitoba Hydro. (Manitoba Hydro archives)
"Now you could have heat lamps for your baby chickens. They would lose a lot of chickens normally, because they would simply be too cold," Goldsborough said.
Keeping things warm was important, but so too was refrigeration. In addition to being able to store meat in summer, it was "something to prolong the life of dairy products, eggs, anything," said Manitoba Hydro's Owen.
"It's all the things we take for granted — a flick of a switch to turn the lights on instead of walking around with a lantern, being able to have maybe a bit longer day to do routine work because you have light."
Agriculture was the backbone of the province but it was limited without electricity, said Owen.
Connecting it to the grid "brought it into the modern age and truly kick-started it to make it a viable part of our economy," he said. "And we still see that today."
In 1954, when the farm electrification program ended, Manitoba was the most wired of the western provinces, with 75 per cent of farms and 100,000 customers connected.
The success of the farm electrification program, combined with the post-war boom, brought new challenges, as the existing power generation could not support the new demand.
The three largest players — City Hydro, WECo and the Manitoba Power Commission, along with the provincial government — created the Manitoba Hydro-Electric Board in 1949 to co-ordinate generation and distribution of power.
A float in a Second World War victory parade represents a hydroelectric dam and the electricity it generates to power cities. (Manitoba Hydro archives)
More hydroelectric generating stations were built and more reorganizations took place. WECo was absorbed by the board and its assets split into separate companies — Greater Winnipeg Gas and Greater Winnipeg Transit.
Its electricity distribution properties were sold to City Hydro, which became the sole distributor in central Winnipeg. The Manitoba Power Commission became sole distributor of electricity in the suburbs and the rest of Manitoba.
Impacts on First Nations
Even as the lives of many people in the province were made easier by the supply of electricity, many others suffered from negative impacts in the rush of progress.
Many First Nations were displaced by hydro dams, which flooded their ancestral lands and destroyed their traditional ways of life.
"And we hear stories about the potential abuses that occurred," said Goldsborough. "So you know, there are there pluses but there are definitely minuses."
In the late 1950s, the Manitoba Power Commission continued to grow and expand its reach, this time moving into the north by buying up private utilities in The Pas and Cranberry Portage.
In 1961, the provincial government merged the commission with the Manitoba Hydro-Electric Board to create Manitoba Hydro.
In 1973, 100 years after the first light went on at that Main Street hotel, the last of the independent power utilities in the province — the Northern Manitoba Power Company Ltd. — was taken over by Hydro.
Winnipeg Hydro, previously called City Hydro, joined the fold in 2002.
Today, Manitoba Hydro operates 15 generating stations and serves 580,262 electric power customers in the province, as well as 281,990 natural gas customers.
New era
And now, as happened in 1919, a new era in electricity distribution is emerging as alternative sources of power — wind and solar — grow in popularity, and as communities like Fort Frances explore integrated microgrids for resilience.
"There's a bit of a clean energy shift happening," said Owen, adding use of biomass energy — energy production from plant or animal material — is also expanding.
"And there's a technological change going on and that's the electrification of vehicles. There are only really several hundred [electric vehicles] in Manitoba on the streets right now. But we know at some point, with affordability and reliability, there'll be a switch over and the gas-powered internal combustion engine will start to disappear."
'We're just a little behind here': Manitoba electric vehicle owners call for more charging stations
That means electrical utilities around the world are re-examining their capabilities, as climate change increasingly stresses grids, said Owen.
"It's coming [and we need to know], are we in a position to meet it? What will be the demands on the system on a path to a net-zero grid by 2050 nationwide?" he said.
"It may not come in my lifetime, but it is coming."
Related News
Tunisia moves ahead with smart electricity grid
Tunisia Smart Grid Project advances with an AFD loan as STEG deploys smart meters in Sfax, upgrades grid infrastructure, boosts energy efficiency, curbs losses, and integrates renewable energy through digitalization and advanced communication systems.
Key Points
A national program funded by an AFD $131.7M loan to modernize STEG, deploy smart meters, and integrate renewable energy.
✅ 430,000 smart meters in Sfax during phase one
✅ 20-year AFD loan with 7-year grace period
✅ Cuts losses, improves efficiency, enables renewables
The Tunisian parliament has approved taking a $131.7 million loan from the French Development Agency for the implementation of a smart grid project.
Parliament passed legislation regarding the 400 million dinar ($131.7 million) loan plus a grant of $1.1 million.
The loan, to be repaid over 20 years with a grace period of up to 7 years, is part of the Tunisian government’s efforts to establish a strategy of energy switching aimed at reducing costs and enhancing operational efficiency.
The move to the smart grid had been postponed after the Tunisian Company of Electricity and Gas (STEG) announced in March 2017 that implementation of the first phase of the project would begin in early 2018 and cover the entire country by 2023.
STEG was to have received funding some time ago. Last year at the Africa Smart Grid Summit in Tunis, the company said it would initiate an international tender during the first quarter of 2019 to start the project.
The French funding is to be allocated to implementation of the first phase only, which will involve development of control and communication stations and the improvement of infrastructure, where regulatory outcomes such as the Hydro One T&D rates decision can influence investment planning in comparable markets.
It includes installation of 430,000 “intelligent” metres over three years in Sfax governorate in southern Tunisia. The second phase of the project is planned to extend the programme to the rest of the country.
Smart metres to be installed in homes and businesses in Sfax account for about 10% of the total number of metres to be deployed in Tunisia.
At the beginning of 2017, the Industrial Company of Metallic Articles (SIAM), a Tunisian industrial electrical equipment and machinery company, signed an agreement with Huawei for the Chinese company to supply smart electricity metres. The value of the deal was not disclosed.
The smart grid is designed to reduce power waste, reduce the number of unpaid bills, prevent consumer fraud such as power theft in India across distribution networks, improve the ecosystem and increase competitiveness in the electricity sector.
Experts said the main difference between the traditional and smart grids is the adoption of advanced infrastructure for measuring electricity consumption and for communication between the power plant and consumers. The data exchange allows power plants to coordinate electricity production with actual demand.
STEG previously indicated that it had implemented measures to ensure the transition to the smart grid, especially since digitalisation is playing an important role in the energy sector.
The project, which translates Tunisia’s energy plans in the form of a partnership between the public and private sectors, aims at reaching 30% of the country’s electricity need from renewable sources by 2025, even as entities like the TVA face climate goals scrutiny that can affect electricity rates in other markets.
The development of the smart grid will allow STEG to monitor consumption patterns, detect abuses and remotely monitor the grid’s power supply, at a time when regulators have questioned UK network profits to spur efficiency, underscoring the value of transparency.
“The smart grid will change the face of the energy system towards the use of renewable energies,” said Tunisian Industry Minister Slim Feriani. At the forum on alternative energies, he pointed out that energy sector digitisation requires investments in technology and a change in the consumption mentality, as new entrants consider roles like Tesla electricity retailer plans in advanced markets.
Official data indicate that Tunisia’s energy deficit accounts for one-third of the country’s annual trade deficit, which reached record levels of more than $6 billion last year.
STEG, whose debts have reached $329 million over the past eight years, a situation resembling Manitoba Hydro debt pressures in Canada, has not disclosed when and how funding would be secured for the completion of the second phase. The company insists it is working to prevent further losses and to collect its unpaid bills.
STEG CEO Moncef Harrabi, earlier this year, said: “The current situation of the company has forced us to take immediate action to reduce the worsening of the crisis and stop the financial bleeding caused by losses.”
He said the company had repeatedly asked the government to pay subsidy instalments due to the company and to enact binding decisions to force government institutions and departments to pay electricity bills, while elsewhere measures like Thailand power bill cuts have been used to support consumers.
The Tunisian government has yet to disburse the subsidy instalments due STEG for 2018 and 2019, which amount to $658 million. STEG also imports natural gas from Algeria for its power plants at a cost of $1.1 billion a year.
Related News
Will Iraq have enough electricity for coming hot summer days?
Iraq Electricity Crisis intensifies as summer heat drives demand; households face power outages, reliance on private generators, distorted tariffs, and strained grid capacity despite government reforms, Siemens upgrades, and IEA warnings.
Key Points
A supply-demand gap causing outages, generator reliance, and grid inefficiencies across Iraq, worsened by summer peaks.
✅ Siemens deal to upgrade generation and grid
✅ Progressive tariffs to curb demand and waste
✅ Private generators fill gaps but raise costs
At a demonstration in June 2018, protesters in Basra loaded a black box resembling a coffin with the inscription “Electricity” onto the roof of a car. This was one demonstration of how much of a political issue electricity is in Iraq.
With what is likely to be another hot summer ahead, there is increasing pressure on the Baghdad government to improve access to electricity and water.
Many Iraqis blame the government for not providing adequate services despite the country’s oil wealth. Protests in southern Iraq last year turned violent, with demonstrators attacking governmental and political parties’ buildings; in neighboring Iran, blackouts also sparked protests over outages.
“It is very hard” to deal with the electricity issues, said Iraqi journalist Methaq al-Fayyadh, adding that the lack of reliable electricity was not a new problem and affects most parts of the country.
Dozens of people protested June 1 in Karbala against prices for new generators and demanded an improvement to the electricity situation.
In anticipation of high temperatures during Eid al-Fitr, the Electricity Ministry called on governorates to adhere to allocated quotas and told the public to ration electricity.
“Outages remain a daily occurrence for most households because increasing generating capacity has been outrun by increasing demand for electricity, as surging demand worldwide demonstrates,” noted the International Energy Agency (IAE) in April.
This is particularly the case, the authors said, as the hot summer months, when temperatures can top 50 degrees Celsius, drive up the use of air conditioning.
The Iraqi government has made improving the electricity supply one of its priorities, including nuclear power plans under consideration. The Electricity Ministry, headed by Luay al-Khatteeb, announced in May that national electricity production had reached 17 gigawatts.
Khatteeb presented comparative electricity data for May from 2018 and 2019, indicating production increases on every day of the month. IEA data indicate that available electricity supply has increased over the past five years and the gap between supply and demand has widened.
The government signed an agreement with German company Siemens this year to upgrade Iraq’s electricity grid, and in parallel deals with Iran to rehabilitate and develop the grid were finalized, according to Iranian officials. The agreement “includes the addition of new and highly efficient power generation capacity, rehabilitation and upgrade of existing plants and the expansion of transmission and distribution networks,” Siemens said.
The Iraqi prime minister’s office said the 4-year plan would be worth $15.7 billion. The first phase includes the installation of 13 transformer stations, cooling systems for power stations and building a 500-megawatt, gas-fired power plant south of Baghdad.
In an interview with Al-Monitor, Khatteeb said radical changes would happen in 2020, stating that the current situation was not “ideal” but “better” because of steps taken to create more energy, amid discussions on energy cooperation with Iran that could shape implementation.
Robert Tollast, of the Iraq Energy Institute, said the economics of the electricity system is distorted. Subsidies ensured that electricity provided by the national grid is almost free, he said. However, while the subsidies were designed to help the poor, the tariff system disadvantages them and does not create incentives to consume electricity more efficiently, he said.
A large part of families’ electricity expenditures goes to operators of privately owned generators, which run on fuel. These neighbourhood generators are used to close gaps in the electricity supply but are expensive, and regional fuel arrangements such as ENOC’s swap of Iraqi fuel have highlighted supply constraints. Generator operators have sometimes worked with armed groups to prevent upgrades to the grid that could hurt their business.
Until 1990, the Iraq electricity sector was considered among the best in the region. That legacy was destroyed by successive wars and international sanctions. With Iraq’s population growing at a rate of 1 million per year, peak demand is projected to double by 2030 if left unchecked, the IEA estimated.
Tollast said efforts to improve the distribution system and increase capacity are key but it is important “to tackle the problem from the demand side.” This entails implementing a progressive tariff scheme so users pay more if they consume more, he said. There is a “tremendous use of energy per capita in Iraq,” Tollast said.
In the current tariff structure, consumers pay a fixed price if they use more than 4,000-kilowatt hours per year, a relatively low amount, meaning the price per unit drops the more one consumes.
Any change to the tariff system must be accompanied by a “political campaign” to explain the changes, said Tollast, adding that more investment in the electricity sector and a “change in culture” of using electricity was needed. “The current system is unsustainable, even with high oil prices,” he said.
Fayyadh said people don’t expect the government will be able to fix the electricity issue before summer, having failed to do so in the past.
Tollast struck a more optimistic tone, saying it was unlikely that Iran, which supplies about 40% of Iraq’s power, would cut its export of electricity to Iraq this year as it did in 2018. He added that the water situation was better than last year when the country experienced drought. Iraq has also been processing more flare gas, which can be used to generate electricity.
“There is an expectation that this year might not be as bad as last year,” he concluded.
Related News
New rules give British households right to sell solar power back to energy firms
UK Smart Export Guarantee enables households to sell surplus solar energy to suppliers, with dynamic export tariffs, grid payments, and battery-friendly incentives, boosting local renewable generation, microgeneration uptake, and decarbonisation across Britain.
Key Points
UK Smart Export Guarantee pays homes for exporting surplus solar power to the grid via supplier tariffs.
✅ Suppliers must pay households for exported kWh.
✅ Dynamic tariffs incentivize daytime solar generation.
✅ Batteries boost self-consumption and grid flexibility.
Britain’s biggest energy companies will have to buy renewable energy from their own customers through community-generated green electricity models under new laws to be introduced this week.
Homeowners who install new rooftop solar panels from 1 January 2020 will be able to lower their bills as many seek to cut soaring bills by selling the energy they do not need to their supplier.
A record was set at noon on a Friday in May 2017, when solar energy supplied around a quarter of the UK’s electricity, and a recent award that adds 10 GW of renewables indicates further growth.
However, solar panel owners are not always at home on sunny days to reap the benefit. The new rules will allow them to make money if they generate electricity for the grid.
Some 800,000 householders with solar panels already benefit from payments under a previous scheme. However, the subsidies were controversially scrapped by the government in April, with similar reduced credits for solar owners seen in other regions, causing the number of new installations to fall by 94% in May from the month before.
Labour accused the government last week of “actively dismantling” the solar industry. The sector will still struggle this summer as the change does not come in for another seven months, so homeowners have no incentive to buy panels this year.
Chris Skidmore, the minister for energy and clean growth, said the government wanted to increase the number of small-scale generators without adding the cost of subsidies to energy bills. “The future of energy is local and the new smart export guarantee will ensure households that choose to become green energy generators will be guaranteed a payment for electricity supplied to the grid,” he said. The government also hopes to encourage homes with solar panels to install batteries to help manage excess solar power on networks.
Greg Jackson, the founder of Octopus Energy, said: “These smart export tariffs are game-changing when it comes to harnessing the power of citizens to tackle climate change”.
A few suppliers, including Octopus, already offer to buy solar power from their customers, often setting terms for how solar owners are paid that reflect market conditions.
“They mean homes and businesses can be paid for producing clean electricity just like traditional generators, replacing old dirty power stations and pumping more renewable energy into the grid. This will help bring down prices for everyone as we use cheaper power generated locally by our neighbours,” Jackson said.
Léonie Greene, a director at the Solar Trade Association, said it was “vital” that even “very small players” were paid a fair price. “We will be watching the market like a hawk to see if competitive offers come forward that properly value the power that smart solar homes can contribute to the decarbonising electricity grid,” she said.
Related News
PG&E restoring power after intentional shut-offs affect 20,500 customers
PG&E power restoration continues across Butte and Yuba counties after PSPS shut-offs from high winds and dry weather, with crews patrolling overhead lines, repairing damage, and reopening community resource centers near Lake Berryessa.
Key Points
PG&E power restoration safely re-energizes lines after PSPS, using inspections and repairs to restore service.
✅ Crews patrolled 800 miles of overhead lines for hazards
✅ Repairs followed wind damage; gradual re-energization
✅ Resource centers offered water, outlets, air conditioning
Pacific Gas and Electric Co. field crews have begun restoring power to approximately 20,500 customers in Butte and Yuba counties after the utility shut off electricity to reduce wildfire risk because of gusty winds and dry weather conditions.
More than half of the affected customers had electricity again as of 1:47 p.m. Sunday, according to PG&E, and by 4 p.m. all of Yuba County power had been restored.
The utility also cut electricity for about 1,600 customers in parts of Napa, Solano and Yolo counties, primarily in the Lake Berryessa area, in a PSPS event separate from statewide grid conservation alerts that can trigger rolling blackouts. Power to those areas was switched off at 6:15 a.m. Saturday but was restored by the evening.
As the danger subsided Sunday, utility workers, as part of PG&E's local response planning for winter storms, worked throughout Butte and Yuba counties to re-energize power lines. The shut-offs affected areas including eastern Chico, Oroville and fire-ravaged Paradise.
Technicians checked lines for damage or fire hazards, like vegetation that could interfere with live wires, Pasion said, as part of broader pandemic grid preparedness that informed utility protocols.
PG&E “patrolled approximately 800 miles of overhead power lines,” the company said in a statement. “Crews found instances of damage to de-energized equipment caused by the extreme weather event and are making necessary repairs.”
While the shut-offs inconvenienced businesses and homeowners, they also highlighted energy inequality across impacted neighborhoods, and some called 911 with emergencies and confusion.
A half hour into the shut-off Saturday night, Butte County sheriff’s dispatchers received a call from a person requesting a welfare check on an individual whose care required electricity, according to department call logs. Two calls overnight from the Magalia area requested medical assistance because residents had oxygen concerns for medically sensitive spouses.
One woman requested an ambulance because her “husband was running out of oxygen,” according to the logs.
Around 4:11 a.m. Sunday, a resident of Hidden Valley Mobile Home Park in Oroville called about a tree falling into a trailer, causing a power line to fall, but noted that the electricity was off.
In a comparable storm-related outage, Sudbury Hydro crews worked to reconnect service after severe weather in Ontario.
And there were multiple calls asking for information about the shut-off, including one caller around midnight who was “demanding PG&E turn his power back on.”
The calls led the Butte County Sheriff’s Office to tweet a reminder Sunday afternoon that 911 is reserved for emergencies and requests for information about the power shutdown should be done through PG&E.
The utility opened a community resource center at Harrison Stadium in Oroville (Butte County) on Sunday morning to provide restrooms, bottled water, power outlets and air conditioning to residents. About 40 people showed up at the center in the first few hours, officials said.
“It’s a small but steady stream,” Pasion said.
Power was being restored to parts of Oroville as of 11 a.m. Sunday.
PG&E officials said it could take up to 48 hours for power to be restored in some areas.
For perspective, during severe storms in Ontario, Hydro One crews restored power to more than 277,000 customers within days.
Related News
Canada's nationwide climate success — electricity
Canada Clean Electricity leads decarbonization, slashing power-sector emissions through coal phase-out, renewables like hydro, wind, and solar, and nuclear. Provinces cut carbon intensity, enabling electrification of transport and buildings toward net-zero goals.
Key Points
Canada Clean Electricity is the shift to low-emission power by phasing out coal and scaling renewables and nuclear.
✅ 38% cut in electricity emissions since 2005; 84% fossil-free power.
✅ Provinces lead coal phase-out; carbon intensity plummets.
✅ Enables EVs, heat pumps, and building electrification.
It's our country’s one big climate success so far.
"All across Canada, electricity generation has been getting much cleaner. It's our country’s one big climate success so far,"
To illustrate how quickly electric power is being cleaned up, what's still left to do, and the benefits it brings, I've dug into Canada's latest emissions inventory and created a series of charts below.
The sector that could
Climate pollution by Canadian economic sector, 2005 to 2017My first chart shows how Canada's economic sectors have changed their climate pollution since 2005.
While most sectors have increased their pollution or made little progress in the climate fight, our electricity sector has shined.
As the green line shows, Canadians have eliminated an impressive 38 per cent of the climate pollution from electricity generation in just over a decade.
To put these shifts into context, I've shown Canada's 2020 climate target on the chart as a gray star. This target was set by the Harper government as part of the global Copenhagen Accord. Specifically, Canada pledged to cut our climate pollution 17 per cent below 2005 levels under evolving Canadian climate policy frameworks of the time.
As you can see, the electricity sector is the only one to have done that so far. And it didn’t just hit the target — it cut more than twice as much.
Change in Canada's electricity generation, 2005 to 2017My next chart shows how the electricity mix changed. The big climate pollution cuts came primarily from reductions in coal burning, highlighting the broader implications of decarbonizing Canada's electricity grid for fuel choices.
The decline in coal-fired power was replaced (and then some) by increases in renewable electricity and other zero-emissions sources — hydro, wind, solar and nuclear.
As a result, Canada's overall electricity generation is now 84 per cent fossil free.
Every province making progress
A primary reason why electricity emissions fell so quickly is because every province worked to clean up Canada's electricity together.
Change in Canadian provincial electricity carbon intensity, 2005 to 2017
My next chart illustrates this rare example of Canada-wide climate progress. It shows how quickly the carbon-intensity of electricity generation has declined in different provinces.
(Note: carbon-intensity is the amount of climate pollution emitted per kilowatt-hour of electricity generated: gCO2e/kWh).
Ontario clearly led the way with an amazing 92 per cent reduction in climate pollution per kWh in just twelve years. Most of that came from ending the burning of coal in their power plants. But a big chunk also came from cutting in half the amount of natural gas they burn for electricity.
Manitoba, Quebec and B.C. also made huge improvements.
Even Alberta and Saskatchewan, which were otherwise busy increasing their overall climate pollution, made progress in cleaning up their electricity.
These real-world examples show that rapid and substantial climate progress can happen in Canada when a broad-spectrum of political parties and provinces decide to act.
Most Canadians now have superclean electricity
As a result of this rapid cleanup, most Canadians now have access to superclean energy.
Canadian provincial electricity carbon intensity in 2017
Who has it? And how clean is it?
The biggest climate story here is the superclean electricity generated by the four provinces shown on the left side — Quebec, Manitoba, B.C. and Ontario. Eighty per cent of Canadians live in these provinces and have access to this climate-safe energy source.
Those living in Alberta and Saskatchewan, however, still have fairly dirty electricity — as shown in orange on the right — and options like bridging the electricity gap between Alberta and B.C. could accelerate progress in the West.
A lot more cleanup must happen here before the families and businesses in these provinces have a climate-safe energy supply.
What's left to do?
Canada's electricity sector has two big climate tasks remaining: finishing the cleanup of existing power and generating even more clean energy to replace fossil fuels like the gasoline and natural gas used by vehicles, factories and other buildings.
Finishing the clean up
Climate pollution from Canadian provincial electricity 2005 and 2017
As we saw above, more than a third of the climate pollution from electricity has already been eliminated. That leaves nearly two-thirds still to clean up.
Back in 2005, Canada's total electricity emissions were 125 million tonnes (MtCO2).
Over the next twelve years, emissions fell by more than a third (-46 MtCO2). Ontario did most of the work by cutting 33 MtCO2. Alberta, New Brunswick and Nova Scotia made the next biggest cuts of around 4 MtCO2 each.
Now nearly eighty million tonnes of climate pollution remain.
As you can see, nearly all of that now comes from Alberta and Saskatchewan. As a result, continuing Canada's climate progress in the power sector now requires big cuts in the electricity emissions from these two provinces.
Generating more clean electricity
The second big climate task remaining for Canada's electricity is to generate more clean electricity to replace the fossil fuels burned in other sectors. My next chart lets you see how big a task this is.
Clean electricity generation by Canadian province, 2017
It shows how much climate-safe electricity is currently generated in major provinces. This includes zero-emissions renewables (blue bars) and nuclear power (pale blue).
Quebec tops the list with 191 terawatt-hours (TWh) per year. While impressive, it only accounts for around half of the energy Quebecers use. The other half still comes from climate-damaging fossil fuels and to replace those, Quebec will need to build out more clean energy.
The good news here is that electricity is more efficient for most tasks, so fossil fuels can be replaced with significantly less electric energy. In addition, other efficiency and reduction measures can further reduce the amount of new electricity needed.
Newfoundland and Labrador is in the best situation. They are the only province that already generates more climate-safe electricity than they would need to replace all the fossil fuels they burn. They currently export most of that clean electricity.
At the other extreme are Alberta and Saskatchewan. These provinces currently produce very little climate-safe energy. For example, Alberta's 7 TWh of climate-safe electricity is only enough to cover 1 per cent of the energy used in the province.
All told, Canadians currently burn fossil fuels for three-quarters of the energy we use. To preserve a safe-and-sane climate, most provinces will soon need lots more clean electricity in the race to net-zero to replace the fossil fuels we burn.
How soon will they need it?
According to the most recent report from the International Panel on Climate Change (IPCC), avoiding a full-blown climate crisis will require humanity to cut emissions by 45 per cent over the next decade.
Using electricity to clean up other sectors
Finally, let's look at how electricity can help clean up two of Canada’s other high-emission sectors — transportation and buildings.
Cleaning up transportation
Transportation is now the second biggest climate polluting sector in Canada (after the oil and gas industry). So, it’s a top priority to reduce the amount of gasoline we use.
Canadian provincial electricity carbon intensity in 2017, plus gasoline equivalent
Switching to electric vehicles (EVs) can reduce transportation emissions by a little, or a lot. It depends on how clean the electricity supply is.
To make it easy to compare gasoline to each province's electricity I've added a new grey-striped zone at the top of the carbon-intensity chart.
This new zone shows that burning gasoline in cars and trucks has a carbon-intensity equivalent to more than 1,000 gCO2e/kWh. (If you are interested in the details of this and other data points, see the geeky endnotes.)
The good news is that every province's electricity is now much cleaner than gasoline as a transportation fuel.
In fact, most Canadians have electricity that is at least 95 per cent less climate polluting than gasoline. Electrifying vehicles in these provinces virtually eliminates those transportation emissions.
Even in Alberta, which has the dirtiest electricity, it is 20 per cent cleaner than gasoline. That's a help, for sure. But it also means that Albertans must electrify many more vehicles to achieve the same emissions reductions as regions with cleaner electricity.
In addition to reducing climate pollution, switching transportation to electricity brings other big benefits:
It reduces air pollution in cities — a major health hazard.
It cuts the energy required for transportation by 75 per cent — because electric motors are so much more efficient.
It reduces fuel costs up to 80 per cent — saving tens of thousands of dollars.
And for gasoline-importing provinces, using local electricity keeps billions of fuel dollars inside their provincial economy.
As an extra bonus, it makes it hard for companies to manipulate the price or for outsiders to "turn off the taps.”
Cleaning up buildings
Canada's third biggest source of climate pollution is the buildings sector.
Burning natural gas for heating is the primary cause. So, reducing the amount of fossil gas burned in buildings is another top climate requirement.
Canadian provincial electricity carbon intensity in 2017, plus gasoline and nat gas heating equivalent
Heating with electricity is a common alternative. However, it's not always less climate polluting. It depends on how clean the electricity is.
To compare these two heating sources, look at the lower grey-striped zone I've added to the chart.
It shows that heating with natural gas has a carbon-intensity of 200 to 300 gCO2 per kWh of heat delivered. High-efficiency gas furnaces are at the lower end of this range.
As you can see, for most Canadians, electric heat is now the much cleaner choice — nearly eliminating emissions from buildings. But in Alberta and Saskatchewan, electricity is still too dirty to replace natural gas heat.
The climate benefits of electric heat can be improved further by using the newer high-efficiency air-source heat pump technologies like mini-splits. These can heat using one half to one third of the electricity of standard electric baseboard heaters. That means it is possible to use electricity that is a bit dirtier than natural gas and still deliver cleaner heating. As a bonus, heat pumps can free up a lot of existing electricity supply when used to replace existing electric baseboards.
Electrify everything
You’ve probably heard people say that to fight climate breakdown, we need to “electrify everything.” Of course, the electricity itself needs to be clean and what we’ve seen is that Canada is making important progress on that front. The electricity industry, and the politicians that prodded them, all deserve kudos for slashing emissions at more than twice the rate of any other sector.
We still need to finish the cleanup job, but we also need to turn our sights to the even bigger task ahead: requiring that everything fossil fuelled — every building, every factory, every vehicle — switches to clean Canadian power.
Related News
Alberta Carbon tax is gone, but consumer price cap on electricity will remain
Alberta Electricity Rate Cap stays despite carbon tax repeal, keeping the Regulated Rate Option at 6.8 cents/kWh. Levy funds cover market gaps as the UCP reviews NDP policies to maintain affordable utility bills.
Key Points
Program capping RRO power at 6.8 cents/kWh, using levy funds to offset market prices while the UCP reviews policy.
✅ RRO cap fixed at 6.8 cents/kWh for eligible customers
✅ Levy funds pay generators when market prices exceed the cap
✅ UCP reviewing NDP policies to ensure affordable rates
Alberta's carbon tax has been cancelled, but a consumer price cap on electricity — which the levy pays for — is staying in place for now.
June electricity rates are due out on Monday, about four days after the new UCP government did away with the carbon charge on natural gas and vehicle fuel.
Part of the levy's revenue was earmarked by the previous NDP government to keep power prices at or below 6.8 cents per kilowatt hour under new electricity rules set by the province.
"The Regulated Rate Option cap of 6.8 cents/kWh was implemented by the previous government and currently remains in effect. We are reviewing all policies put in place by the former government and will make decisions that ensure more affordable electricity rates for job-creators and Albertans," said a spokesperson for Alberta's energy ministry in an emailed statement.
Albertans with regulated rate contracts and all City of Medicine Hat utility customers only pay that amount or less, though some Alberta ratepayers have faced deferral-related arrears.
If the actual market price rises above that, the difference is paid to generators directly from levy funds, a buffer that matters as experts warn prices are set to soar later this year.
The government has paid more than $55 million to utilities over the past year ending in March 2019, due to that electricity price cap being in place.
Alberta Energy says the price gap program will continue, at least for the time being, amid electricity policy changes being considered.
