EPA moves to rewrite limits for coal power plant wastewater

St. Albert electric buses debut as zero-emission, quiet public transit, featuring BYD technology, long-range batteries, and charging stations, serving Edmonton routes while advancing sustainable transportation goals and a future fleet expansion.

Key Points

They are zero-emission BYD transit buses that cut noise and air pollution, with long-range batteries and city charging.

✅ Up to 250-280 km range per charge

✅ Quiet, zero-emission operations reduce urban pollution

✅ Backed by provincial GreenTRIP funding and BYD tech

The city of St. Albert is going green — both literally and esthetically — with three electric buses on routes in and around the city this week.

"They're virtually silent," Wes Brodhead, chair of the Capital Region Board transit committee and a St. Albert city councillor, said. "This, as opposed to the diesel buses and the roar that accompanies them as they drive down the street."

You may not hear them coming but you'll definitely see them, as electric school buses in B.C. hit the road as well.

The 35-foot electric buses are painted bright green to represent the city's goal of adopting sustainable transportation.

"There's no noise pollution, there's no air pollution, and it just kind of fit with the whole theme of the city," said St. Albert Transit director Kevin Bamber.

'The conversation around the conference was not if but when the industry will fully embrace electrification,' - Wes Brodhead, St. Albert city councillor

The buses cost about $970,000 each. Adding in the required infrastructure, including charging stations, the project cost a total of $3.1 million, with two-thirds of the funding coming from the provincial government's Green Transit Incentives Program. 

The electric buses are estimated to go between 250 and 280 kilometres on a single charge.

"That would mean any of the routes that we currently have through St. Albert or into Edmonton, an electric bus could do the morning route, come back, park in the afternoon and go back out and do the afternoon route without a charge," Bamber said. 

St. Albert councillor Wes Brodhead envisions having a full fleet of 60 electric buses in years to come, a scale informed by examples like the TTC's electric bus fleet operating in North America. (Supplied)

Brodhead went to an international transit conference in Montreal, where STM electric buses have begun rolling out and he said manufacturers presented various electric bus designs. 

"The conversation around the conference was not if but when the industry will fully embrace electrification," Brodhead said.

The vehicles were built in California by BYD Ltd., one of only two companies making the long-endurance electric buses.

The city has ordered four more of the buses and hopes to be running all seven by the end of the year, as battery-electric buses in Metro Vancouver continue to hit the roads nationwide.

Eventually, Brodhead envisions having a full fleet of 60 electric buses in St. Albert.

Edmonton is expected to operate as many as 40 electric buses, and while city staff are still in the planning stages, Edmonton's first electric bus has already hit city streets.

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California Natural Gas Plant Rethink signals a shift toward clean energy, renewables, distributed solar, battery storage, and grid modernization as LADWP and regulators pause repowering plans amid an electricity oversupply and rising ratepayer costs.

Key Points

California pauses new gas plants to assess renewables, storage, and grid solutions for reliability.

✅ LADWP delays $2.2B gas repowers to study clean alternatives

✅ CEC weighs halting Oxnard plant amid grid oversupply

✅ Distributed solar, batteries, demand response boost reliability

California energy officials are, for the first time, rethinking plans to build expensive natural gas power plants in the face of an electricity glut and growing use of cleaner and cheaper energy alternatives.

The Los Angeles Department of Water and Power announced Tuesday that it has put a hold on a $2.2-billion plan to rebuild several old natural gas power plants while it studies clean energy alternatives to meet electricity demands. And the California Energy Commission may decide as early as Thursday to halt a natural gas project in Ventura County.

The scrutiny comes after an investigation found that the state is operating with an oversupply of electricity, driven largely by the construction of gas-fueled generating plants, leading to higher rates as regulators consider a rate overhaul to clean the grid. The state’s power plants are on track to be able to produce at least 21% more electricity than needed by 2020, according to the Times report.

Californians are footing a $40-billion annual bill while using less electricity, paying $6.8 billion more than they did in 2008 when power use in the state was at its all-time high. Electricity consumption has since fallen and remained largely flat.

Utilities in California have been on a years-long building binge, adding new natural gas plants even as the nation’s electricity system has undergone significant change, including consumer choice reforms that are reshaping the market.

Where utilities once delivered all electrical services from huge power plants along miles of transmission lines, the industry now must consider power delivered to the electric grid not only from its own sources, but also from solar systems and batteries at homes and businesses.

At the same time, utilities have been aggressively upgrading or rebuilding their aging natural gas plants — a move critics have said is unnecessary because consumers are using less power and clean energy technology is making those plants obsolete.

The DWP and energy commission moves involve as many as seven natural gas plant projects proposed for Southern California, despite warnings about a looming shortage if capacity is retired too fast, from Oxnard to Carlsbad, at a cost of more than $6 billion.

Reiko Kerr, the DWP’s senior assistant general manager of power systems, said given the changes in the energy world, the assessment is necessary to protect ratepayer dollars and the environment.

“The whole utility paradigm has shifted,” Kerr said in an interview. “We really are doing our ratepayers a disservice by not considering all viable options.

“We’re just looking at everything,” she said. “What can help us solve this reliability, renewable and greenhouse gas challenge that we all have?”

State and local governments have felt a heightened sense of urgency to deal with climate change after President Trump decided last week to withdraw the United States from the Paris climate accord.

California already has mandated that at least 50% of the state’s electricity come from clean energy sources by 2030. Senate leader Kevin de León (D-Los Angeles) wants to increase that to 100% by 2045.

Building or overhauling natural gas plants throughout Southern California, environmentalists argue, isn’t helping achieve those goals, even as some contend the state can't keep the lights on without gas during the transition.

The DWP’s move to delay plans for the fossil fuel plants, which seemed all but set to be built, came as a surprise to clean-energy advocates, who hailed the decision.

“This is a great first step toward smart energy investments that save customers money, ensure the lights stay on and protect our health and environment,” Graciela Geyer of the Sierra Club said.

The environmental group said that if the utility had moved ahead with the $2.2-billion investment in repowering natural gas plants, it “would have blown an irreparable hole in the city and the state’s hopes to achieve 100% generation” from clean energy sources.

Angela Johnson Meszaros, attorney at EarthJustice, said in a statement: "As our city struggles with the worst smog we’ve seen in years, we appreciate that LADWP is taking some much-needed time to reassess its plans to build fossil fuel power plants. We look forward to the day that LADWP announces that we are going to power our city with 100% clean energy.”

The gas-fired generating units slated for demolition and rebuilding are at the Scattergood, Haynes and Harbor electricity plants, which range from 34 to 67 years old.

As a group, the three plants have generated less than 20% of their combined capacity since 2001. The Harbor facility has operated on the low end at just 7%, while Haynes ran on the high end at 22%.

“The old model, the old legacy clunkers, won’t get us into the future we want,” DWP’s Kerr said.

DWP staff members told the utility’s’ commissioners Tuesday that their analysis of possible alternatives would be completed no later than early 2018.

Separately, the California Energy Commission this week is evaluating whether to halt a natural gas project in Ventura County after the state’s electric grid operator offered to conduct a study of clean energy alternatives to the roughly $250-million project on Mandalay Bay in Oxnard.

An energy commission committee has been deliberating since a hearing Monday during which Southern California Edison and the project’s developer, NRG Energy, argued that a study is simply a delay tactic that probably would kill a project needed to ensure reliable electric service and to avoid blackouts during peak demand.

The California Independent System Operator, which runs the state’s electric grid, told the energy commission that it would take three to four weeks to conduct its study on alternatives to the Oxnard natural gas project.

“Here we have an actual offer by the ISO to do such an analysis,” Ellison Folk, a lawyer representing the city of Oxnard, told the energy commission as she pushed for the study. “Its view that this is an analysis worth doing is something worth taking seriously.”

Energy commission members reviewing the study proposal are scheduled to meet again Thursday to consider the offer.

The board of governors for the California Independent System Operator made the unusual offer at its May 1 meeting to conduct a eleventh-hour study of clean-energy alternatives to building a new natural gas plant.

“If we’re going to be moving forward with a gas plant at this time, in this juncture, in the context of everything that’s going on, not evaluating other alternatives that are viable, noncombustion alternatives, is a missed opportunity,” Angelina Galetiva. a commission board member, said during the May 1 meeting.

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Electric Vehicle Market Growth accelerated as EV adoption hit 2 million in 2016, per IEA, led by China, Tesla momentum, policy incentives, charging infrastructure buildout, and diesel decline under Paris Agreement goals.

Key Points

EV adoption rose to 2 million in 2016, driven by policy, China, and charging buildout, yet still only 0.2% of cars.

✅ 2M EVs on roads in 2016; 60% YoY growth

✅ China led with >40% of global EV sales

✅ Policies target 30% share by 2030 via EVI

The number of electric vehicles on the road rocketed to 2 million in 2016 as the age of electric cars accelerates after being virtually non-existent just five years ago, according to the International Energy Agency.

Registered plug-in and battery-powered vehicles on roads worldwide rose 60% from the year before, according to the Global EV Outlook 2017 report from the Paris-based IEA. Despite the rapid growth, electric vehicles still represent just 0.2% of total light-duty vehicles even as U.S. EV sales continue to soar into 2024, suggesting a turning point.

“China was by far the largest electric car market, accounting for more than 40% of the electric cars sold in the world and more than double the amount sold in the United States,” the IEA wrote in the report published Wednesday. “It is undeniable that the current electric car market uptake is largely influenced by the policy environment.”

A multi government program called the Electric Vehicle Initiative on Thursday will set a goal for 30% market share for battery power cars, buses, trucks and vans by 2030, aligning with projections that driving electric cars within a decade could become commonplace, according to IEA. The 10 governments in the initiative include China, France, Germany, the UK and US.

India, which isn’t part of the group, said last month that it plans to sell only electric cars by the end of the next decade. Countries and cities are looking to electric vehicles to help tackle their air pollution problems.

In order to limit global warming to below 2 degrees Celsius (3.6 degrees Fahrenheit), the target set by the landmark Paris Agreement on climate change, the world will need 600 million electric vehicles by 2040, according to the IEA.

After struggling for consumer acceptance, Tesla Inc. has made electric vehicles cool and trendy, and is pushing into the mass market as the United States approaches a tipping point for mass adoption with the new Model 3 sedan.

Consumer interest and charging infrastructure, as well as declining demand for diesel cars in the wake of Volkswagen’s emissions scandal, has spurred massive investments in plug-in cars, and across Europe the share of electric cars grew during virus lockdown months, reinforcing this momentum. An electrical vehicle “cool factor” could spur sales to 450 million by 2035, according to BP chief economist Spencer Dale.

Volkswagen, the world’s largest automaker, plans to roll out four affordable electric vehicles in the coming years as part of a goal to sell more than 2 million battery-powered vehicles a year by 2025. Mercedes-Benz accelerated the introduction of ten new electric vehicles by three years to 2022 to take on Tesla as the dominance of the combustion engine gradually fades. 

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Vancouver 100% EV-Ready Policy mandates EV charging in new multi-unit residential buildings, expands DC fast charging, and supports zero-emission vehicles, reducing carbon pollution and improving air quality with BC Hydro and citywide infrastructure upgrades.

Key Points

A city rule making new multi-unit homes EV-ready and expanding DC fast charging to accelerate zero-emission adoption.

✅ 100% EV-ready stalls in all new multi-unit residential builds

✅ Citywide DC fast charging within 10 minutes by 2021

✅ Preferential parking policies for zero-emission vehicles

Vancouver is now one of the first cities in North America to adopt a 100 per cent Electric Vehicle (EV)-ready policy for all new multi-unit residential buildings, aligning with B.C.'s EV expansion efforts across the province.

Vancouver City Council approved the recommendations made in the EV Ecosystem Program Update last week. The previous requirement of 20 per cent EV parking spots meant a limited number of residents had access to an outlet, reflecting charging challenges in MURBs across Canada. The actions will help reduce carbon pollution and improve air quality by increasing opportunities for residents to move away from fossil fuel vehicles.

Vancouver is also expanding charging station infrastructure across the city, and developing a preferential parking policy for zero emissions vehicles, while residents can tap EV charger rebates to support home and workplace charging. Plans are to add more DC fast charging points, which can provide up to 200 kilometres of range in an hour. The goal is to put all Vancouver residents within a 10 minute drive of a DC fast-charging station by 2021.

#google#

A DC fast charger will be installed at Science World, and the number of DC fast chargers available at Empire Fields in east Vancouver will be expanded. BC Hydro will also add DC fast chargers at their head office and in Kerrisdale, as part of a faster charging rollout across the network.

The cost of adding charging infrastructure in the construction phase of a building is much lower than retrofitting a building later on, and EV owners can access home and workplace charging rebates to offset costs, which will save residents up to $3,300 and avoid the more complex process of increasing electrical capacity in the future. Since 2014, the existing requirements have resulted in approximately 20,000 EV-ready stalls in buildings.

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Kemper County power plant costs and delays highlight lignite coal gasification, syngas production, carbon capture targets, and looming rate plans as Mississippi Power navigates Public Service Commission oversight and shareholder-ratepayer risk.

Key Points

Costs exceed $7.5B with repeated delays; rate impacts loom as syngas, lignite, and carbon capture systems mature.

✅ Estimate tops $7.5B; customers could fund about $4.3B

✅ Carbon capture target: 65% CO2 via syngas from lignite

✅ Rate plans pending before the Public Service Commission

A Mississippi utility on Monday delayed making proposals for how its customers should pay for an ever-more-expensive power plant, even as the estimated cost of the facility crossed $7.5 billion.

The Kemper County power plant will be tasked with mining lignite coal a few hundred yards away from the plant. That coal is moved through a process that will convert it to syngas. The syngas is then used to drive the energy output of the plant, and the resulting electricity is then moved into the grid, where transmission projects influence regional reliability and capacity.

Thomas Fanning, CEO of parent Southern Co., told shareholders in May that Mississippi Power would file rate plans for its Kemper County power plant this month. But still unable to operate the plant steadily enough to declare it finished, Mississippi Power punted, instead asking to hold rates level for 11 months to pay off costs that have already been approved by regulators.

Mississippi Power says it now hopes to reach commercial operation in June. The plant is more than three years behind schedule, with 10 delays announced in the past 18 months. It was originally supposed to cost $2.9 billion.

The company also said monday that it will have to replace troublesome parts of the facility much sooner than expected, including units that cool the synthetic gas produced from soft lignite coal by two gasifier units, plus ash handling systems in the gasifiers.

Kemper is designed to take synthetic gas, pipe it through a chemical plant to remove carbon dioxide and other chemicals, and then burn the gas in turbines to generate electricity. It’s designed to capture 65 percent of carbon dioxide from the coal, releasing only as much of the climate-warming gas as a typical natural gas plant. It’s a key effort nationally to maintain coal as a viable fuel source, even as coal unit retirements proceed in other states.

Mississippi Power raised its estimate of Kemper’s cost by $209.4 million, with shareholders absorbing $185.9 million, while ratepayers could be asked to pay $23.5 million. Overall, customers could be asked to pay $4.3 billion. Southern shareholders have agreed to absorb $3.1 billion, which has risen by $500 million since November.

The elected three-member Public Service Commission in 2015 allowed the company to raise rates on its 188,000 customers by $126 million a year. That paid for $840 million in Kemper work, which began generating electricity in 2014 using piped-in natural gas. Some items covered by that 15 percent rate increase will be paid off in coming months, but Mississippi Power now proposes to repay costs from regulatory proceedings earlier than originally projected.

In testimony filed with the Public Service Commission, Mississippi Power Chief Financial Officer Moses Fagin said that keeping rates level would reduce whiplash to customers when rates rise later to pay for Kemper, would pay off accumulated costs more quickly and would help the company wean itself off financial support from Southern Co. while maintaining credit ratings and positioning for a possible bond rating upgrade over time.

“Cash flow is important to the company in maintaining its current ratings and beginning to rebuild its credit strength on a more independent basis apart from the extraordinary parental support that has been required in recent years to maintain financial integrity,” Fagin testified.

Spokesman Jeff Shepard said Mississippi Power is still drawing up two rate plans — one requiring a sharp, immediate rate increase, and a “rate mitigation plan” that might cushion increases amid declining returns in coal markets. He said the company isn’t sure when it will file them. Fagin suggested the Public Service Commission set a new deadline of March 2, 2018.

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Renewable Energy Market Reform aligns solar and wind with modern grid pricing, tackling intermittency via batteries and demand response, stabilizing wholesale power prices, and enabling capacity markets to finance flexible supply for deep decarbonization.

Key Points

A market overhaul that integrates variable renewables, funds flexibility, and stabilizes grids as solar and wind grow.

✅ Dynamic pricing rewards flexibility and demand response

✅ Capacity markets finance reliability during intermittency

✅ Smart grids, storage, HV lines balance variable supply

ALMOST 150 years after photovoltaic cells and wind turbines were invented, they still generate only 7% of the world’s electricity. Yet something remarkable is happening. From being peripheral to the energy system just over a decade ago, they are now growing faster than any other energy source and their falling costs are making them competitive with fossil fuels. BP, an oil firm, expects renewables to account for half of the growth in global energy supply over the next 20 years. It is no longer far-fetched to think that the world is entering an era of clean, unlimited and cheap, abundant electricity for all. About time, too. 

There is a $20trn hitch, though. To get from here to there requires huge amounts of investment over the next few decades, to replace old smog-belching power plants and to upgrade the pylons and wires that bring electricity to consumers. Normally investors like putting their money into electricity because it offers reliable returns. Yet green energy has a dirty secret. The more it is deployed, the more it lowers the price of power from any source. That makes it hard to manage the transition to a carbon-free future, during which many generating technologies, clean and dirty, need to remain profitable if the lights are to stay on. Unless the market is fixed, subsidies to the industry will only grow.

Policymakers are already seeing this inconvenient truth as a reason to put the brakes on renewable energy. In parts of Europe and China, investment in renewables is slowing as subsidies are cut back, even as Europe’s electricity demand continues to rise. However, the solution is not less wind and solar. It is to rethink how the world prices clean energy in order to make better use of it.

Shock to the system

At its heart, the problem is that government-supported renewable energy has been imposed on a market designed in a different era. For much of the 20th century, electricity was made and moved by vertically integrated, state-controlled monopolies. From the 1980s onwards, many of these were broken up, privatised and liberalised, so that market forces could determine where best to invest. Today only about 6% of electricity users get their power from monopolies. Yet everywhere the pressure to decarbonise power supply has brought the state creeping back into markets. This is disruptive for three reasons. The first is the subsidy system itself. The other two are inherent to the nature of wind and solar: their intermittency and their very low running costs. All three help explain why power prices are low and public subsidies are addictive.

First, the splurge of public subsidy, of about $800bn since 2008, has distorted the market. It came about for noble reasons—to counter climate change and prime the pump for new, costly technologies, including wind turbines and solar panels. But subsidies hit just as electricity consumption in the rich world was stagnating because of growing energy efficiency and the financial crisis. The result was a glut of power-generating capacity that has slashed the revenues utilities earn from wholesale power markets and hence deterred investment.

Second, green power is intermittent. The vagaries of wind and sun—especially in countries without favourable weather—mean that turbines and solar panels generate electricity only part of the time. To keep power flowing, the system relies on conventional power plants, such as coal, gas or nuclear, to kick in when renewables falter. But because they are idle for long periods, they find it harder to attract private investors. So, to keep the lights on, they require public funds.

Everyone is affected by a third factor: renewable energy has negligible or zero marginal running costs—because the wind and the sun are free. In a market that prefers energy produced at the lowest short-term cost, wind and solar take business from providers that are more expensive to run, such as coal plants, depressing wholesale electricity prices, and hence revenues for all.

Get smart

The higher the penetration of renewables, the worse these problems get—especially in saturated markets. In Europe, which was first to feel the effects, utilities have suffered a “lost decade” of falling returns, stranded assets and corporate disruption. Last year, Germany’s two biggest electricity providers, E.ON and RWE, both split in two. In renewable-rich parts of America, power providers struggle to find investors for new plants, reflecting U.S. grid challenges that slow a full transition. Places with an abundance of wind, such as China, are curtailing wind farms to keep coal plants in business.

The corollary is that the electricity system is being re-regulated as investment goes chiefly to areas that benefit from public support. Paradoxically, that means the more states support renewables, the more they pay for conventional power plants, too, using “capacity payments” to alleviate intermittency. In effect, politicians rather than markets are once again deciding how to avoid blackouts. They often make mistakes: Germany’s support for cheap, dirty lignite caused emissions to rise, notwithstanding huge subsidies for renewables. Without a new approach the renewables revolution will stall.

The good news is that new technology can help fix the problem.  Digitalisation, smart meters and batteries are enabling companies and households to smooth out their demand—by doing some energy-intensive work at night, for example. This helps to cope with intermittent supply. Small, modular power plants, which are easy to flex up or down, are becoming more popular, as are high-voltage grids that can move excess power around the network more efficiently, aligning with common goals for electricity networks worldwide.

The bigger task is to redesign power markets to reflect the new need for flexible supply and demand. They should adjust prices more frequently, to reflect the fluctuations of the weather. At times of extreme scarcity, a high fixed price could kick in to prevent blackouts. Markets should reward those willing to use less electricity to balance the grid, just as they reward those who generate more of it. Bills could be structured to be higher or lower depending how strongly a customer wanted guaranteed power all the time—a bit like an insurance policy. In short, policymakers should be clear they have a problem and that the cause is not renewable energy, but the out-of-date system of electricity pricing. Then they should fix it.

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