To many communities, trash-to-energy means burning garbage. But a handful of companies say they are close to bringing cleaner technology to market for making electricity or ethanol from waste.
At a panel discussion on waste-to-energy at the AlwaysOn GoingGreen East conference, representatives from four companies detailed their plans to use gasification to convert waste products to usable energy. Some products are ready to be deployed more widely while others are still in the pilot testing phase.
The promise of using municipal solid trash or other waste products for useful energy is tantalizing: it's a renewable resource and reduces the need for methane-emitting landfills or incineration.
But making the technology less expensive, along with resistance from communities over environmental concerns, remain formidable barriers.
"It's a bit of minefield. We all run companies where 40 companies have failed before us," said Bill Davis, the CEO of Ze-Gen, a start-up which has a pilot facility for turning construction debris into electricity.
Representatives from the four companies — Ze-Gen, IST Energy, Enerkem, and Plasco Energy Group — took pains to point out that gasification is different and cleaner than combustion.
In a gasifier, a feedstock like municipal trash is heated at high temperatures and pressure, which breaks down the material into a synthetic gas, which contains hydrogen and carbon monoxide. That synthetic gas, or syngas, can be burned in a commercial turbine to make electricity or heat.
Plasco Energy Group appeared to be furthest along in terms of commercializing the technology. It has a facility in Ottawa, Canada, that handles 100 tons a day of municipal garbage left over after recyclable items have been removed. The company plans to open a manufacturing facility this summer to produce more of these 100-ton modules and is in discussion with communities in California, British Columbia, France and the U.K., according to CEO Rod Bryden.
Bryden hopes to replicate the model in Ottawa where the waste-to-energy facility is sited in the city and the community holds the company to high environmental standards for air quality and waste water disposal.
After creating a syngas, its equipment can separate residual materials and turn them into products, so that 99 percent of the input is used. Leftover solids, for example, can be mixed to make asphalt or other construction equipment, Bryden said.
"One of the things about garbage (as a feedstock) is that it's where the people are and that's where the energy is used," he said. Wind and solar, by contrast need to have transmissions constructed. "The first barrier to overcome is environmental (such as air quality). If you can't get by that, you won't be able to get into business."
Enerkem uses a gasification process as well, but makes ethanol rather than electricity. Last year it signed a contract with Edmonton in Canada to supply 25 years worth of telephone poles which will be converted into ethanol.
It plans to open a facility in Montreal, which took only four months to be permitted. By contrast, the last incinerator in the U.S. was built in 1996, according to Vincent Chornet, the CEO of Enerkem.
The company will announce plans for another waste-to-ethanol facility in Mississippi, he said.
Permitting, however, remains a formidable barrier, said Stu Haber, the CEO of IST Energy, which has developed a waste-treatment machine that can fit onto a flatbed truck. It's aimed at hospitals, prisons, and other buildings that generate at least two tons of trash a day.
Regulations for waste-to-energy were not written for gasification technology, which means that state agencies don't know how to deal with IST Energy's product, which the company intends to start manufacturing this summer.
"If we can't (get through) restrictions in government agencies, we'll have to go out business and it will make it harder for the industry," Haber said.
Also, within communities there's opposition from people who associate waste-to-energy with incineration, noted Ze-Gen's Davis.
On a technical level, making sure that a gasification can produce enough energy to be a replacement for fossil fuels, such as natural gas, still remains a challenge. Ze-Gen's business model, for example, is to get a high-quality fuel that can replace natural gas at a power plant facility. But with falling fossil fuel prices, the target is harder.
"Our competitor effectively is landfill most of the time so the biggest long-term issue is economics," said Ze-Gen's Davis.
Muskrat Falls financial impact highlights a hydro megaproject's cost overruns, rate mitigation challenges, and inquiry findings in Newfoundland and Labrador, with power exports, Churchill River generation, and subsea cables shaping long-term viability.
Key Points
It refers to the project's burden on provincial finances, driven by cost overruns, rate hikes, and debt risks.
✅ Costs rose to $12.7B from $6.2B; inquiry cites suppressed risks.
✅ Rate mitigation needed to offset power bill shocks.
✅ Exports via subsea cables may improve long-term viability.
Newfoundland and Labrador's premier says the Muskrat Falls hydro megaproject is currently too much of a massive financial burden for him to be optimistic about its long-term potential.
"I am probably one of the most optimistic people in this room," Liberal Premier Dwight Ball told the inquiry into the project's runaway cost and scheduling issues, echoing challenges at Manitoba Hydro that have raised similar concerns.
"I believe the future is optimistic for Newfoundland Labrador, of course I do. But I'm not going to sit here today and say we have an optimistic future because of the Muskrat Falls project."
Ball, who was re-elected on May 16, has been critical of the project since he was opposition leader around the time it was sanctioned by the former Tory government.
He said Friday that despite his criticism of the Labrador dam, which has seen costs essentially double to more than $12.7 billion, he didn't set out to celebrate a failed project.
He said he still wants to see Muskrat Falls succeed someday through power sales outside the province, but there are immediate challenges -- including mitigating power-rate hikes once the dam starts providing full power and addressing winter reliability risks for households.
"We were told the project would be $6.2 billion, we're at $12.7 (billion). We were never told this project would be nearly 30 per cent of the net debt of this province just six, seven years later," the premier said.
"I wanted this to be successful, and in the long term I still want it to be successful. But we have to deal with the next 10 years."
The nearly complete dam will harness Labrador's lower Churchill River to provide electricity to the province as well as Nova Scotia and potentially beyond through subsea cables, while the legacy of Churchill Falls continues to shape regional power arrangements.
Ball's testimony wraps up a crucial phase of hearings in the extensive public inquiry.
The inquiry has heard from dozens of witnesses, with current and former politicians, bureaucrats, executives and consultants, amid debates over Quebec's electricity ambitions in the region, shedding long-demanded light on what went on behind closed doors that made the project go sideways.
Some witnesses have suggested that estimates were intentionally suppressed, and many high-ranking officials, including former premiers, have denied seeing key information about risk.
On Thursday, Ball testified to his shock when he began to understand the true financial state of the project after he was elected premier in 2015.
On Friday, Ball said he has more faith in future of the offshore oil and gas industry, and emerging options like small nuclear reactors, for example, than a mismanaged project that has put immense pressure on residents already struggling to make ends meet.
After his testimony, Ball said he takes some responsibility for a missed opportunity to mitigate methylmercury risks downstream from the dam through capping the reservoir, in parallel with debates over biomass power in electricity generation, something he had committed to doing before it is fully flooded this summer.
Still to come is a third phase of hearings on future best practices for issues like managing large-scale projects and independent electricity planning, two public feedback sessions and closing submissions from lawyers.
The final report from the inquiry is due before Dec. 31.
ERCOT Winter Capacity RFP seeks up to 3,000 MW through generation and demand response to bolster Texas grid reliability during peak load, leveraging Reliability Must-Run, incentive factors, and EEA risk mitigation for the 2023-24 season.
Key Points
An ERCOT initiative to procure 3,000 MW of generation and demand response to reduce EEA risk and improve reliability.
✅ Targets 3,000 MW from generation and demand response
✅ Uses RMR-style contracts with flexible incentive factors
✅ Aims to lower EEA probability below 10% this winter
The Electric Reliability Council of Texas (ERCOT) issued a request for proposals to stakeholders to procure up to 3,000 MW of generation or demand response capacity to meet load and reserve requirements during the winter 2023-24 peak load season (Dec. 1, 2023, through Feb. 29, 2024), amid ongoing Texas power grid challenges across the region.
ERCOT cited “several factors, including significant peak load growth since last winter, recent and proposed retirements of dispatchable Generation Resources, and recent extreme winter weather events, including Winter Storm Elliott in December 2022, Winter Storm Uri in February 2021, and the 2018 and 2011 winter storms, each of which resulted in abnormally high demand during winter weather.” It now seeks additional capacity under its “authority to prevent an anticipated Emergency Condition,” reflecting nationwide blackout risks identified by grid experts.
In its notice regarding the RFP, ERCOT identified a number of mothballed and recently decommissioned generation resources that may be eligible to offer capacity under the RFP. It further stated that offers must comport with the format of its “Reliability Must-Run” agreement but could include a proposed “Incentive Factor” that reflects the revenues the unit owners determine would be necessary to bring the unit back to operation. It added that the Incentive Factor is not necessarily limited to 10%. Providers of eligible demand response can submit offers based on similar principles that are not necessarily constrained by cost. The notice identifies potential acceptable sources of demand response, describes certain parameters for the kinds of demand response that are permitted to respond to the RFP, and outlines the time periods during which ERCOT must be able to deploy the demand response resources to improve electricity reliability across the system.
To meet the Dec. 1, 2023, service start date, ERCOT developed an aggressive timeline to solicit and evaluate proposals through the RFP. Responses to the RFP are due Nov. 6, 2023. ERCOT’s schedule provides that it will notify market participants that obtain awards on Nov. 23, 2023. Expect contracts to be executed by Nov. 30, 2023.
Unlike Regional Transmission Organizations in the Northeastern United States, ERCOT does not have a capacity market. Instead, ERCOT relies on a high price cap of $5,000 per MWh for its energy market (decreased from the $9,000 per MWh cap in effect during Winter Storm Uri) and an Operating Reserve Demand Curve adder that pays additional funds to generators supplying power and ancillary services, an area recently scrutinized for improper payments when supply conditions are tight. In the wake of Winter Storm Uri, some calls were made to have ERCOT adopt a capacity market for reliability reasons, and a number of legal battles continue to play out in the wake of Winter Storm Uri. (See recent McGuireWoods legal alert “Winter Storm Uri Power Dispute Reaches the Supreme Court of Texas.”) Though a capacity market was not adopted, the Texas Legislature approved a $7.2 billion loan program, widely described as an electricity market bailout for generators, to build up to 10,000 MW of dispatchable generation. The legislature also approved a version of the Public Utility Commission of Texas’ proposal to establish a “Performance Credit Mechanism,” but with a cost cap of $1 billion.
The loss of life and economic impacts of Winter Storm Uri in 2021, along with the energy crunches and calls for conservation this past summer, are driving changes to ERCOT’s “energy-only” market, including electricity market reforms under consideration. Texas policymakers are providing multiple financial incentives to promote investment in dispatchable on-demand generation, and voters will consider funding to modernize generation measures this year to make the Texas grid more reliable and able to deal with power demand from a growing economy and increased demand for electricity driven by weather. In the meantime, ERCOT’s plan to procure 3,000 MW through this RFP process is a stopgap measure intended to bolster reliability for the upcoming winter season and lower the probability of load shed in the event of severe winter weather.
European Power Demand During Second Lockdowns remains resilient as winter heating offsets commercial losses; electricity consumption tracks seasonal norms, with weather sensitivity, industrial activity, natural gas shielding, and coal decline shaping dynamics under COVID-19 restrictions.
Key Points
It is expected to remain near seasonal norms, driven by heating, industry activity, and weather sensitive consumption.
✅ Winter heating offsets retail and hospitality closures
✅ Demand sensitivity rises with colder weather in France
✅ Gas generation shielded; coal likely to curtail first
European power demand is likely to hold up in the second round of national lockdown restrictions, with fluctuations most likely driven by changes in the weather.
Traders and analysts expect normal consumption this time around as home heating during the chilly season replaces commercial demand.
Last week electricity consumption in France, Germany and the U.K. was close to business-as-usual levels for the time of year, according to BloombergNEF data. By contrast, power demand had dropped 16% in the first seven days of the springtime lockdown, as reflected by the U.K.’s 10% daily decline reported then.
How power demand performs has significance outside the sector. It’s often seen as a proxy for economic growth and during lockdowns earlier this year, electricity use slumped along with GDP, and stunted hydro and nuclear output could further hobble recovery. For Western Europe, annual demand is expected to be 5% lower than the previous year, a bigger decline than after the global financial crisis in 2008, according to S&P Global Platts.
The Covid-19 limits are lighter than those from earlier in the year “with an explicit drive to preserve economic activity, particularly at the more energy-intensive industrial end of the spectrum,” said Glenn Rickson, head of European power analysis at S&P Global Platts.
Higher levels of working from home will offset some of the losses from shop and hospitality closures, “but also increase the temperature sensitivity of overall gas and power demand, as heat-driven demand records have shown in recent summers,” he said.
The latest wave of national lockdowns began in France, Germany, Spain, Italy and Britain, with Spain having seen April demand plummet earlier in the year, as coronavirus cases surged and officials struggled to keep the spread of the virus under control.
Much of the manufacturing industry remains working for now despite additional restrictions to contain the coronavirus. With the peak of the second wave yet to be reached, “it seems almost inevitable that the fourth quarter will prove economically challenging,” analysts at Alfa Energy said.
There will initially be significantly less of an impact on demand compared with this spring when global daily demand dipped about 15% and electricity consumption in Europe was down 30%, Johan Sigvardsson, power price analyst at Swedish utility Bixia AB said.
The prevalence of electric heating systems in France means that power demand is particularly sensitive to cold weather. A cold spell would significantly boost demand and drive record electricity prices in tight markets.
Similar to the last round of shutdowns, it’s use of coal that will probably be hit first if power demand sags, as transition-focused responses gather pace, leaving natural gas mostly shielded from fluctuations in the market.
“We expect that another drop in power demand would again impact coal-fired generation and shield gas power to some extent,” said Carlos Torres Diaz, an analyst at Rystad Energy.
Boeing 787 More-Electric Architecture replaces pneumatics with bleedless pressurization, VFSG starter-generators, electric brakes, and heated wing anti-ice, leveraging APU, RAT, batteries, and airport ground power for efficient, redundant electrical power distribution.
Key Points
An integrated, bleedless electrical system powering start, pressurization, brakes, and anti-ice via VFSGs, APU and RAT.
✅ VFSGs start engines, then generate 235Vac variable-frequency power
✅ Bleedless pressurization, electric anti-ice improve fuel efficiency
✅ Electric brakes cut hydraulic weight and simplify maintenance
The 787 Dreamliner is different to most commercial aircraft flying the skies today. On the surface it may seem pretty similar to the likes of the 777 and A350, but get under the skin and it’s a whole different aircraft.
When Boeing designed the 787, in order to make it as fuel efficient as possible, it had to completely shake up the way some of the normal aircraft systems operated. Traditionally, systems such as the pressurization, engine start and wing anti-ice were powered by pneumatics. The wheel brakes were powered by the hydraulics. These essential systems required a lot of physical architecture and with that comes weight and maintenance. This got engineers thinking.
What if the brakes didn’t need the hydraulics? What if the engines could be started without the pneumatic system? What if the pressurisation system didn’t need bleed air from the engines? Imagine if all these systems could be powered electrically… so that’s what they did.
Power sources
The 787 uses a lot of electricity. Therefore, to keep up with the demand, it has a number of sources of power, much as grid operators track supply on the GB energy dashboard to balance loads. Depending on whether the aircraft is on the ground with its engines off or in the air with both engines running, different combinations of the power sources are used.
Engine starter/generators
The main source of power comes from four 235Vac variable frequency engine starter/generators (VFSGs). There are two of these in each engine. These function as electrically powered starter motors for the engine start, and once the engine is running, then act as engine driven generators.
The generators in the left engine are designated as L1 and L2, the two in the right engine are R1 and R2. They are connected to their respective engine gearbox to generate electrical power directly proportional to the engine speed. With the engines running, the generators provide electrical power to all the aircraft systems.
APU starter/generators
In the tail of most commercial aircraft sits a small engine, the Auxiliary Power Unit (APU). While this does not provide any power for aircraft propulsion, it does provide electrics for when the engines are not running.
The APU of the 787 has the same generators as each of the engines — two 235Vac VFSGs, designated L and R. They act as starter motors to get the APU going and once running, then act as generators. The power generated is once again directly proportional to the APU speed.
The APU not only provides power to the aircraft on the ground when the engines are switched off, but it can also provide power in flight should there be a problem with one of the engine generators.
Battery power
The aircraft has one main battery and one APU battery. The latter is quite basic, providing power to start the APU and for some of the external aircraft lighting.
The main battery is there to power the aircraft up when everything has been switched off and also in cases of extreme electrical failure in flight, and in the grid context, alternatives such as gravity power storage are being explored for long-duration resilience. It provides power to start the APU, acts as a back-up for the brakes and also feeds the captain’s flight instruments until the Ram Air Turbine deploys.
Ram air turbine (RAT) generator
When you need this, you’re really not having a great day. The RAT is a small propeller which automatically drops out of the underside of the aircraft in the event of a double engine failure (or when all three hydraulics system pressures are low). It can also be deployed manually by pressing a switch in the flight deck.
Once deployed into the airflow, the RAT spins up and turns the RAT generator. This provides enough electrical power to operate the captain’s flight instruments and other essentials items for communication, navigation and flight controls.
External power
Using the APU on the ground for electrics is fine, but they do tend to be quite noisy. Not great for airports wishing to keep their noise footprint down. To enable aircraft to be powered without the APU, most big airports will have a ground power system drawing from national grids, including output from facilities such as Barakah Unit 1 as part of the mix. Large cables from the airport power supply connect 115Vac to the aircraft and allow pilots to shut down the APU. This not only keeps the noise down but also saves on the fuel which the APU would use.
The 787 has three external power inputs — two at the front and one at the rear. The forward system is used to power systems required for ground operations such as lighting, cargo door operation and some cabin systems. If only one forward power source is connected, only very limited functions will be available.
The aft external power is only used when the ground power is required for engine start.
Circuit breakers
Most flight decks you visit will have the back wall covered in circuit breakers — CBs. If there is a problem with a system, the circuit breaker may “pop” to preserve the aircraft electrical system. If a particular system is not working, part of the engineers procedure may require them to pull and “collar” a CB — placing a small ring around the CB to stop it from being pushed back in. However, on the 787 there are no physical circuit breakers. You’ve guessed it, they’re electric.
Within the Multi Function Display screen is the Circuit Breaker Indication and Control (CBIC). From here, engineers and pilots are able to access all the “CBs” which would normally be on the back wall of the flight deck. If an operational procedure requires it, engineers are able to electrically pull and collar a CB giving the same result as a conventional CB.
Not only does this mean that the there are no physical CBs which may need replacing, it also creates space behind the flight deck which can be utilised for the galley area and cabin.
A normal flight
While it’s useful to have all these systems, they are never all used at the same time, and, as the power sector’s COVID-19 mitigation strategies showed, resilience planning matters across operations. Depending on the stage of the flight, different power sources will be used, sometimes in conjunction with others, to supply the required power.
On the ground
When we arrive at the aircraft, more often than not the aircraft is plugged into the external power with the APU off. Electricity is the blood of the 787 and it doesn’t like to be without a good supply constantly pumping through its system, and, as seen in NYC electric rhythms during COVID-19, demand patterns can shift quickly. Ground staff will connect two forward external power sources, as this enables us to operate the maximum number of systems as we prepare the aircraft for departure.
Whilst connected to the external source, there is not enough power to run the air conditioning system. As a result, whilst the APU is off, air conditioning is provided by Preconditioned Air (PCA) units on the ground. These connect to the aircraft by a pipe and pump cool air into the cabin to keep the temperature at a comfortable level.
APU start
As we near departure time, we need to start making some changes to the configuration of the electrical system. Before we can push back , the external power needs to be disconnected — the airports don’t take too kindly to us taking their cables with us — and since that supply ultimately comes from the grid, projects like the Bruce Power upgrade increase available capacity during peaks, but we need to generate our own power before we start the engines so to do this, we use the APU.
The APU, like any engine, takes a little time to start up, around 90 seconds or so. If you remember from before, the external power only supplies 115Vac whereas the two VFSGs in the APU each provide 235Vac. As a result, as soon as the APU is running, it automatically takes over the running of the electrical systems. The ground staff are then clear to disconnect the ground power.
If you read my article on how the 787 is pressurised, you’ll know that it’s powered by the electrical system. As soon as the APU is supplying the electricity, there is enough power to run the aircraft air conditioning. The PCA can then be removed.
Engine start
Once all doors and hatches are closed, external cables and pipes have been removed and the APU is running, we’re ready to push back from the gate and start our engines. Both engines are normally started at the same time, unless the outside air temperature is below 5°C.
On other aircraft types, the engines require high pressure air from the APU to turn the starter in the engine. This requires a lot of power from the APU and is also quite noisy. On the 787, the engine start is entirely electrical.
Power is drawn from the APU and feeds the VFSGs in the engines. If you remember from earlier, these fist act as starter motors. The starter motor starts the turn the turbines in the middle of the engine. These in turn start to turn the forward stages of the engine. Once there is enough airflow through the engine, and the fuel is igniting, there is enough energy to continue running itself.
After start
Once the engine is running, the VFSGs stop acting as starter motors and revert to acting as generators. As these generators are the preferred power source, they automatically take over the running of the electrical systems from the APU, which can then be switched off. The aircraft is now in the desired configuration for flight, with the 4 VFSGs in both engines providing all the power the aircraft needs.
As the aircraft moves away towards the runway, another electrically powered system is used — the brakes. On other aircraft types, the brakes are powered by the hydraulics system. This requires extra pipe work and the associated weight that goes with that. Hydraulically powered brake units can also be time consuming to replace.
By having electric brakes, the 787 is able to reduce the weight of the hydraulics system and it also makes it easier to change brake units. “Plug in and play” brakes are far quicker to change, keeping maintenance costs down and reducing flight delays.
In-flight
Another system which is powered electrically on the 787 is the anti-ice system. As aircraft fly though clouds in cold temperatures, ice can build up along the leading edge of the wing. As this reduces the efficiency of the the wing, we need to get rid of this.
Other aircraft types use hot air from the engines to melt it. On the 787, we have electrically powered pads along the leading edge which heat up to melt the ice.
Not only does this keep more power in the engines, but it also reduces the drag created as the hot air leaves the structure of the wing. A double win for fuel savings.
Once on the ground at the destination, it’s time to start thinking about the electrical configuration again. As we make our way to the gate, we start the APU in preparation for the engine shut down. However, because the engine generators have a high priority than the APU generators, the APU does not automatically take over. Instead, an indication on the EICAS shows APU RUNNING, to inform us that the APU is ready to take the electrical load.
Shutdown
With the park brake set, it’s time to shut the engines down. A final check that the APU is indeed running is made before moving the engine control switches to shut off. Plunging the cabin into darkness isn’t a smooth move. As the engines are shut down, the APU automatically takes over the power supply for the aircraft. Once the ground staff have connected the external power, we then have the option to also shut down the APU.
However, before doing this, we consider the cabin environment. If there is no PCA available and it’s hot outside, without the APU the cabin temperature will rise pretty quickly. In situations like this we’ll wait until all the passengers are off the aircraft until we shut down the APU.
Once on external power, the full flight cycle is complete. The aircraft can now be cleaned and catered, ready for the next crew to take over.
Bottom line
Electricity is a fundamental part of operating the 787. Even when there are no passengers on board, some power is required to keep the systems running, ready for the arrival of the next crew. As we prepare the aircraft for departure and start the engines, various methods of powering the aircraft are used.
The aircraft has six electrical generators, of which only four are used in normal flights. Should one fail, there are back-ups available. Should these back-ups fail, there are back-ups for the back-ups in the form of the battery. Should this back-up fail, there is yet another layer of contingency in the form of the RAT. A highly unlikely event.
The 787 was built around improving efficiency and lowering carbon emissions whilst ensuring unrivalled levels safety, and, in the wider energy landscape, perspectives like nuclear beyond electricity highlight complementary paths to decarbonization — a mission it’s able to achieve on hundreds of flights every single day.
Washington County solar farm incentives aim to steer projects to industrial sites with tax breaks, underground grid connections, decommissioning bonds, and wildlife corridors, balancing zoning, historic preservation, and Maryland renewable energy mandates.
Key Points
Policies steer solar to industrial sites with tax breaks, buried lines, and bonds, aligning with zoning and state goals.
✅ Tax breaks to favor rooftops and parking canopies
✅ Bury new grid lines to shift projects to industrial parks
✅ Require decommissioning bonds and wildlife corridors
Incentives for establishing solar farms at industrial spaces instead of on prime farmland are among the ideas the Washington County Planning Commission is recommending for the county to update its policies regarding solar farms.
Potential incentives would include tax breaks on solar equipment and requiring developers to put power-grid connections and line extensions underground, a move tied to grid upgrade cost debates in other regions, Planning Commission members said during a Monday meeting.
The tax break could make it more attractive for a developer to put a solar farm on a roof or over a parking lot, similar to California's building-solar requirement policies that favor rooftop generation, which could cost more than putting it on farmland, said Commission member Dave Kline, who works for FirstEnergy.
Requiring a company to bury new transmission lines could steer them to industrial or business parks where, theoretically, transmission lines are more readily available, Kline said Wednesday in a phone interview.
Chairman Clint Wiley suggested talking to industrial property owners to create a list of industrial sites that make sense for a solar site, which could generate extra income for the property owner.
Commission members also talked about requiring a wildlife corridor. Anne Arundel County requires such a corridor if a solar site is over 15 acres, according to Jill Baker, deputy director of planning and zoning. The solar site is broken into sections so animals such as deer can get through, she said.
However, that means the solar farm would take up more agricultural land, Commission member Jeremiah Weddle said. Weddle, a farmer, has repeatedly voiced concerns about solar farms using prime farmland.
County zoning law already states solar farms are prohibited in Rural Legacy Areas, Priority Preservation Areas, and within Antietam Overlay zones that preserve the Antietam National Battlefield viewshed. They also cannot be built on land with permanent preservation easements, Baker said.
However, a big reason county officials are looking to strengthen county policies for solar generating systems, or solar farms, is a recent court decision that ruled the Maryland Public Service Commission can preempt county zoning law when it comes to large solar farms.
County zoning law defines a solar energy generating system as a solar facility, with multiple solar arrays, tied into the power grid and whose primary purpose is to generate power to distribute and/or sell into the public utility grid rather than consuming that power on site.
The Maryland Court of Appeals ruled in July that the Public Service Commission can preempt local zoning regarding solar farms larger than 2 megawatts. But the ruling also stated local government is a "significant participant in the process" and the state commission must give "due consideration" to local zoning laws.
County officials are looking at recommendations for solar farms, whether they are over 2 megawatts or not.
Solar farms are a popular issue statewide, especially with Maryland solar subscriptions expanding, and were discussed at a recent Maryland Association of Counties meeting for planners, Planning and Zoning Director Stephen Goodrich said.
The thinking is the best way for counties to express their opinions about a solar project is to participate in the state commission's local public hearings, where issues like how solar owners are paid often arise, Goodrich said. Another popular idea is for the county to continue to follow its process, which requires a public hearing for a special exception to establish a solar farm. That will help the county form an opinion, on individual cases, to offer the state commission, he said.
Recommendations discussed by the Planning Commission include:
A break on personal property taxes, which is on equipment, including affordable battery storage that can firm output, to steer developers away from areas where the county doesn't want solar farms. The Board of County Commissioners have been split on tax-break agreements for solar farms, with a majority recently granting a few.
Protecting valuable historic sites.
Requiring a decommissioning bond for removing the equipment at the end of the solar farm's life. The bond is protection in case the company goes bankrupt. The county commissioners have been making such a bond a requirement when granting recent tax breaks.
Looking at allowing solar farms in stormwater-management areas.
Other counties, particularly in Western Maryland and on the Eastern Shore, are having issues with solar farms even as research to improve solar and wind advances, because land is cheaper and there are wide-open spaces, Goodrich said.
Many solar projects are being developed or proposed because state lawmakers passed legislation requiring 50% of electricity produced in the state to come from renewable sources by 2030, and a federal plan to expand solar is also shaping expectations. Of that 50%, 14.5% is to come from solar energy.
In Maryland, the average number of homes that can be powered by 1 megawatt of solar energy is about 110, according to the Solar Energy Industries Association's website.
Eletrobras Privatization Strike sparks a 72-hour CNE walkout by Brazil's electricity workers, opposing asset sell-offs and grid privatization while pledging essential services; unions target President Wilson Ferreira Jr. over energy-sector reforms.
Key Points
A 72-hour CNE walkout by Brazil's electricity workers opposing Eletrobras sell-offs, while keeping essential services.
✅ 72-hour strike led by CNE unions and federations
✅ Targets privatization plans and leadership at Eletrobras
✅ Essential services maintained to avoid consumer impact
Brazil's national electricity workers' collective (CNE) has called for a 72-hour strike to protest the privatization of state-run electric company Eletrobras and its subsidiaries.
The CNE, which gathers the electricity workers' confederation, federations, unions and associations, said the strike is to begin at Monday midnight (0300 GMT) and last through midnight Wednesday, even as some utilities elsewhere have considered asking staff to live on site to maintain operations.
Workers are demanding the ouster of Eletrobras President Wilson Ferreira Jr., who they say is the leading promoter of the privatization move.
Some 24,000 workers are expected to take part in the strike. However, the CNE said it will not affect consumers by ensuring essential services, a pledge echoed by utilities managing costs elsewhere such as Manitoba Hydro's unpaid days off during the pandemic.
#google#
Eletrobras accounts for 32 percent of Brazil's installed energy generation capacity, mainly via hydroelectric plants. Besides, it also operates nuclear and thermonuclear plants, and solar and wind farms, reflecting trends captured by young Canadians' interest in electricity jobs in recent years.
The company distributes electricity in six northern and northeastern states, and handles 47 percent of the nation's electricity transmission lines, even as a U.S. grid pandemic warning has highlighted reliability risks.
The government owns a 63-percent stake in the company, a reminder that public policy shapes the sector, similar to Canada's future-of-work investment initiatives announced recently.
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instruction, our electrical training courses can be
tailored to meet your company's specific requirements
and delivered to your employees in one location or at
various locations.
