Russia Develops Cyber Weapon That Can Disrupt Power Grids


Russia Develops Cyber Weapon

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CrashOverride malware is a Russian-linked ICS cyberweapon targeting power grids, SCADA systems, and utility networks; linked to Electrum/Sandworm, it threatens U.S. transmission and distribution with modular attacks and time-bomb payloads across critical infrastructure.

 

Key Points

A modular ICS malware linked to Russian actors that disrupts power grids via SCADA abuse and forced breaker outages.

✅ Targets breakers and substation devices to sustain outages

✅ Modular payloads adapt to ICS protocols and vendors

✅ Enables timed, multi-site attacks against transmission and distribution

 

Hackers allied with the Russian government have devised a cyberweapon that has the potential to be the most disruptive yet against electric systems that Americans depend on for daily life, according to U.S. researchers.

The malware, which researchers have dubbed CrashOverride, is known to have disrupted only one energy system — in Ukraine in December. In that incident, the hackers briefly shut down one-fifth of the electric power generated in Kiev.

But with modifications, it could be deployed against U.S. electric transmission and distribution systems to devastating effect, said Sergio Caltagirone, director of threat intelligence for Dragos, a cybersecurity firm that studied the malware and issued a recent report.

And Russian government hackers have shown their interest in targeting U.S. energy and other utility systems, with reports of suspected breaches at U.S. power plants in recent years, researchers said.

“It’s the culmination of over a decade of theory and attack scenarios,” Caltagirone warned. “It’s a game changer.”

The revelation comes as the U.S. government is investigating a wide-ranging, ambitious effort by the Russian government last year to disrupt the U.S. presidential election and influence its outcome, and has issued a condemnation of Russian power grid hacking as well. That campaign employed a variety of methods, including hacking hundreds of political and other organizations, and leveraging social media, U.S. officials said.

Dragos has named the group that created the new malware Electrum, and it has determined with high confidence that Electrum used the same computer systems as the hackers who attacked the Ukraine electric grid in 2015. That attack, which left 225,000 customers without power, was carried out by Russian government hackers, other U.S. researchers concluded. U.S. government officials have not officially attributed that attack to the Russian government, but some privately say they concur with the private-sector analysis.

“The same Russian group that targeted U.S. [industrial control] systems in 2014, including the Dragonfly campaign documented by Symantec, turned out the lights in Ukraine in 2015,” said John Hultquist, who analyzed both incidents while at iSight Partners, a cyber-intelligence firm now owned by FireEye, where he is director of intelligence analysis. Hultquist’s team had dubbed the group Sandworm.

“We believe that Sandworm is tied in some way to the Russian government — whether they’re contractors or actual government officials, we’re not sure,” he said. “We believe they are linked to the security services.”

Sandworm and Electrum may be the same group or two separate groups working within the same organization, but the forensic evidence shows they are related, said Robert M. Lee, chief executive of Dragos.

The Department of Homeland Security, which works with the owners of the nation’s critical infrastructure systems, did not respond to a request for comment Sunday.

Energy-sector experts said that the new malware is cause for concern, but that the industry is seeking to develop ways to disrupt attackers who breach their systems, including documented access to U.S. utility control rooms in prior incidents.

“U.S. utilities have been enhancing their cybersecurity, but attacker tools like this one pose a very real risk to reliable operation of power systems,” said Michael J. Assante, who worked at Idaho National Labs and is a former chief security officer of the North American Electric Reliability Corporation, where he oversaw the rollout of industry cybersecurity standards.

CrashOverride is only the second instance of malware specifically tailored to disrupt or destroy industrial control systems. Stuxnet, the worm created by the United States and Israel to disrupt Iran’s nuclear capability, was an advanced military-grade weapon designed to affect centrifuges that enrich uranium.

In 2015, the Russians used malware to gain access to the power supply network in western Ukraine, but it was hackers at the keyboards who remotely manipulated the control systems to cause the blackout — not the malware itself, Hultquist said.

With CrashOverride, “what is particularly alarming . . . is that it is all part of a larger framework,” said Dan Gunter, a senior threat hunter for Dragos.

The malware is like a Swiss Army knife, where you flip open the tool you need and where different tools can be added to achieve different effects, Gunter said.

Theoretically, the malware can be modified to attack different types of industrial control systems, such as water and gas. However, the adversary has not demonstrated that level of sophistication, Lee said.

Still, the attackers probably had experts and resources available not only to develop the framework but also to test it, Gunter said. “This speaks to a larger effort often associated with nation-state or highly funded team operations.”

One of the most insidious tools in CrashOverride manipulates the settings on electric power control systems. It scans for critical components that operate circuit breakers and opens the circuit breakers, which stops the flow of electricity. It continues to keep them open even if a grid operator tries to close them, creating a sustained power outage.

The malware also has a “wiper” component that erases the software on the computer system that controls the circuit breakers, forcing the grid operator to revert to manual operations, which means driving to the substation to restore power.

With this malware, the attacker can target multiple locations with a “time bomb” functionality and set the malware to trigger simultaneously, Lee said. That could create outages in different areas at the same time.

The outages would last a few hours and probably not more than a couple of days, Lee said. That is because the U.S. electric industry has trained its operators to handle disruptions caused by large storms, alongside a renewed focus on protecting the grid in response to recent alerts. “They’re used to having to restore power with manual operations,” he said.

So although the malware is “a significant leap forward in tradecraft, it’s also not a doomsday scenario,” he said.

The malware samples were first obtained by ESET, a Slovakian research firm, which shared some of them with Dragos. ESET has dubbed the malware Industroyer.

 

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UPS pre-orders 125 Tesla electric semi-trucks

UPS Tesla Electric Semi Order marks the largest pre-order of all-electric Class-8 big rigs, advancing sustainable freight logistics with lower total cost of ownership, expanded charging infrastructure support, and competitive range versus diesel trucks.

 

Key Points

UPS's purchase of 125 Tesla all-electric Class-8 semis to cut costs, emissions, and modernize long-haul freight.

✅ Largest public pre-order: 125 electric Class-8 trucks

✅ Aims lower total cost of ownership vs diesel

✅ Includes charging infrastructure consulting by Tesla

 

United Parcel Service Inc. said on Tuesday it is buying 125 Tesla Inc. all-electric semi-trucks, the largest order for the big rig so far, as the package delivery company expands its fleet of alternative-fuel vehicles, including options like the all-electric Transit cargo van now entering the market.

Tesla is trying to convince the trucking community it can build an affordable electric big rig with the range and cargo capacity to compete with relatively low-cost, time-tested diesel trucks. This is the largest public order of the big rig so far, Tesla said.

The Tesla trucks will cost around $200,000 each for a total order of about $25 million. UPS expects the semi-trucks, the big rigs that haul freight along America's highways, will have a lower total cost of ownership than conventional vehicles, which run about $120,000.

Tesla has received pre-orders from such major companies as Wal-Mart, fleet operator J.B. Hunt Transport Services Inc. and food service distributor Sysco Corp.

Prior to UPS, the largest single pre-order came from PepsiCo Inc, for 100 trucks. 

UPS said it has provided Tesla with real-world routing information as part of its evaluation of the vehicle's expected performance.

"As with any introductory technology for our fleet, we want to make sure it's in a position to succeed," Scott Phillippi, UPS senior director for automotive maintenance and engineering for international operations, told Reuters.

Phillippi said the 125 trucks will allow UPS to conduct a proper test of their abilities. He said the company was still determining their routes, but the semis will "primarily be in the United States." Tesla will provide consultation and support on charging infrastructure, as electric truck fleets will need a lot of power to operate at scale.

"We have high expectations and are very optimistic that this will be a good product and it will have firm support from Tesla to make it work," Phillippi said.

The UPS alternative fuel fleet already includes trucks propelled by electricity, natural gas, propane and other non-traditional fuels, and interest in electric mail trucks underscores how delivery fleets are evolving.

About 260,000 semis, or heavy-duty Class-8 trucks, are produced in North America annually, according to FTR, an industry economics research firm.

Including the UPS order, Tesla has at least 410 pre-orders in hand, according to a Reuters tally.

Navistar International Corp. and Volkswagen AG hope to launch a smaller, electric medium-duty truck by late 2019, while rival Daimler AG has delivered the first of a smaller range of electric trucks to customers in New York, and Volvo Trucks planned a complete range of electric trucks in Europe by 2021.

Tesla unveiled its semi last month, following earlier plans to reveal the truck in October, and expects the truck to be in production by 2019.

 

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Sparking change: what Tesla's Model 3 could mean for electric utilities

EV Opportunity for Utilities spans EV charging infrastructure, grid modernization, demand response, time-of-use rates, and customer engagement, enabling predictable load growth, flexible charging, and stronger utility branding amid electrification and resilience challenges.

 

Key Points

It is the strategy to leverage EV adoption for load growth, grid flexibility, and branded charging services.

✅ Monetizes EV load via TOU rates, managed charging, and V2G.

✅ Uses rate-based infrastructure to expand equitable charging access.

✅ Enhances resilience and DER integration through smart grid upgrades.

 

Tesla recently announced delivery of the first 30 production units of its Model 3 electric vehicle (EV). EV technology has generated plenty of buzz in the electric utility industry over the past decade and, with last week’s announcement, it would appear that projections of a significant market presence for EVs could give way to rapid growth.

Tesla’s announcement could not have come at a more critical time for utilities, which face unprecedented challenges. For the past 15 years, utilities have been grappling with increasingly frequent “100-year storms,” including hurricanes, snowstorms and windstorms, underscoring the reality that the grid’s aging infrastructure is not fit to withstand increasingly extreme weather, along with other threats, such as cyber attacks.

Coupled with flat or declining load growth, changing regulations, increasing customer demand, and new technology penetration, these challenges have given the electric utility industry good reason to describe its future as “threatened.” These trends, each exacerbating the others, mean essentially that utilities can no longer rely on traditional ways of doing business.

EVs have significant potential to help relieve the industry’s pessimistic outlook. This article will explore what EV growth could mean for utilities and how they can begin establishing critical foundations today to help ensure their ability to exploit this opportunity.

 

The opportunity

At the Bloomberg New Energy Finance (BNEF) Global Summit 2017, BNEF Advisory Board Chairman Michael Liebreich announced the group’s prediction that electric vehicles will comprise 35-47 percent of new vehicle sales globally by 2040.

U.S. utilities have good reason to be optimistic about this potential new revenue source, as EV-driven demand growth could be substantial according to federal lab analyses. If all 236 million gas-powered cars in the U.S. — average miles driven per year: 12,000 — were replaced with electric vehicles, which travel an average of 100 miles on 34 kWh, they would require 956 billion kWh each year. At a national average cost of $0.12 / kWh, the incremental energy sold by utilities in the U.S. would bring in around $115 billion per year in new revenues. A variety of factors could increase or decrease this number, but it still represents an attractive opportunity for the utility sector.

Capturing this burgeoning market is not simply a matter of increased demand; it will also require utilities to be predictable, adaptable and brandable. Moreover, while the aggregate increase in demand might be only 3-4 percent, demand can come as a flexible and adaptable load through targeted programming. Also, if utilities target the appropriate customer groups, they can brand themselves as the providers of choice for EV charging. The power of stronger branding, in a sector that’s experiencing significant third-party encroachment, could be critical to the ongoing financial health of U.S. utilities.

Many utilities are already keenly aware of the EV opportunity and are speeding down this road (no pun intended) as part of their plans for utility business model reinvention. Following are several questions to be asked when evaluating the EV opportunity.

 

Is the EV opportunity feasible with today’s existing grid?

According to a study conducted by the U.S. Department of Energy’s Pacific Northwest National Laboratory, the grid is already capable of supporting more than 150 million pure electric vehicles, even as electric cars could challenge state grids in the years ahead, a number equal to at least 63 percent of all gas-powered cars on the road today. This is significant, considering that a single EV plugged into a Level 2 charger can double a home’s peak electricity demand. Assuming all 236 million car owners eventually convert to EVs, utilities will need to increase grid capacity. However, today’s grid already has the capacity to accommodate the most optimistic prediction of 35-47 percent EV penetration by 2040, which is great news.

 

Should the EV opportunity be owned by utilities?

There’s significant ongoing debate among regulators and consumer advocacy groups as to whether utilities should own the EV charging infrastructure, with fights for control over charging reflecting broader market concerns today. Those who are opposed to this believe that the utilities will have an unfair pricing advantage that will inhibit competition. Similarly, if the infrastructure is incorporated into the rate base, those who do not own electric vehicles would be subsidizing the cost for those who do.

If the country is going to meet the future demands of electric cars, the charging infrastructure and power grid will need help, and electric utilities are in the best position to address the problem, as states like California explore EVs for grid stability through utility-led initiatives that can scale. By rate basing the charging infrastructure, utilities can provide charging services to a wider range of customers. This would not favor one economic group over another, which many fear would happen if the private sector were to control the EV charging market.

 

If you build it, will they come?

At this point, we can conclude that growth in EV market penetration is a tremendous opportunity for utilities, one that’s most advantageous to electricity customers if utilities own some, if not all, of the charging infrastructure. The question is, if you build it, will they come — and what are the consequences if they don’t?

With any new technology, there’s always a debate centered around adoption timing — in this case, whether to build the infrastructure ahead of demand for EV or wait for adoption to spike. Either choice could have disastrous consequences if not considered properly. If utilities wait for the adoption to spike, their lack of EV charging infrastructure could stunt the growth of the EV sector and leave an opening for third-party providers. Moreover, waiting too long will inhibit GHG emissions reduction efforts and generally complicate EV technology adoption. On the other hand, building too soon could lead to costly stranded assets. Both problems are rooted in the inability to control adoption timing, and, until recently, utilities didn’t have the means or the savvy to influence adoption directly.

 

How should utilities prepare for the EV?

Beyond the challenges of developing the hardware, partnerships and operational programs to accommodate EV, including leveraging energy storage and mobile chargers for added flexibility, influencing the adoption of the infrastructure will be a large part of the challenge. A compelling solution to this problem is to develop an engaged customer base.

A more engaged customer base will enable utilities to brand themselves as preferred EV infrastructure providers and, similarly, empower them to influence the adoption rate. There are five key factors in any sector that influence innovation adoption:

  1. Relative advantage – how improved an innovation is over the previous generation.

  2. Compatibility – the level of compatibility an innovation has with an individual’s life.

  3. Complexity – if the innovation is to difficult to use, individuals will not likely adopt it.

  4. Trialability – how easily an innovation can be experimented with as it’s being adopted.

  5. Observability – the extent that an innovation is visible to others.

Although much of EV adoption will depend on the private vehicle sector influencing these five factors, there’s a huge opportunity for utilities to control the compatibility, complexity and observability of the EV. According to  “The New Energy Consumer: Unleashing Business Value in a Digital World,” utilities can influence customers’ EV adoption through digital customer engagement. Studies show that digitally engaged customers:

  • have stronger interest and greater likelihood to be early EV adopters;

  • are 16 percent more likely to purchase home-based electric vehicle charging stations and installation services;

  • are 17 percent more likely to sign up for financing for home-based electric vehicle charging stations; and

  • increase the adoption of consumer-focused programs.

These findings suggest that if utilities are going to seize the full potential of the EV opportunity, they must start engaging customers now so they can appropriately influence the timing and branding of EV charging assets.

 

How can utilities engage consumers in preparation?

If utilities establish the groundwork to engage customers effectively, they can reduce the risks of waiting for an adoption spike and of building and investing in the asset too soon. To improve customer engagement, utilities need to:

  1. Change their customer conversations from bills, kWh, and outages, to personalized, interesting topics, communicated at appropriate intervals and via appropriate communication channels, to gain customers’ attention.

  2. Establish their roles as trusted advisors by presenting useful, personalized recommendations that benefit customers. These tips should change dynamically with changing customer behavior, or they risk becoming stagnant and redundant, thereby causing customers to lose interest.

  3. Convert the perception of the utility as a monopolistic, inflexible entity to a desirable, consumer-oriented brand through appropriate EV marketing.

It’s critical to understand that this type of engagement strategy doesn’t even have to provide EV-specific messaging at first. It can start by engaging customers through topics that are relevant and unique, through established or evolving customer-facing programs, such as EE, BDR, TOU, HER.

As lines of communication open up between utility and users, utilities can begin to understand their customers’ energy habits on a more granular level. This intelligence can be used by business analysts to help educate program developers on the optimal EV program timing. For example, as customers become interested in services in which EV owners typically enlist, utilities can target them for EV program marketing. As the number of these customers grows, the window for program development opens, and their levels of interest can be used to inform program and marketing timelines.

While all this may seem like an added nuisance to an EV asset development strategy, there’s significant risk of losing this new asset to third-party providers. This is a much greater burden to utilities than spending the time to properly own the EV opportunity.

 

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St. Albert touts green goals with three new electric buses

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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Coal comeback unlikely after Paris climate pact withdrawal, says utility CEO

US Shift From Coal to Renewables accelerates as natural gas, solar, and wind power gain market share, driven by the Paris climate agreement, clean energy mandates, smart grid upgrades, and energy efficiency.

 

Key Points

An industry trend where power producers replace coal with natural gas, solar, and wind to meet clean energy goals.

✅ Shareholders and customers demand cleaner power portfolios

✅ Natural gas, solar, and wind outcompete coal on cost and risk

✅ Smart grid and efficiency investments reduce emissions further

 

President Trump once again promised to revive the U.S. coal industry when he announced his intention to withdraw the U.S. from the Paris climate agreement.

But that reversal seems as unlikely as ever as electric power producers, the biggest consumers of coal in the U.S., continue to shift to natural gas and renewable energy sources like solar and wind power. In 2016, natural gas became the leading fuel for U.S. electricity generation for the first time, responsible for 33.8% of the output, compared with 30.4% for coal, according to the U.S. Energy Information Administration, even as coal-fired generation was projected to rise in 2021 in the short term.

Nick Akins, the CEO of American Electric Power, one of the largest utilities in the U.S., says the preference for gas, renewables and energy efficiency, will only grow in response to increasing demands from shareholders and customers for cleaner energy, regardless of changes in national energy policy.

With 5.4 million customers in 11 states, AEP plans to spend $1.5 billion on renewable energy from 2017 through 2019, and $13 billion on transmission and distribution improvements, including new “smart” technologies that will make the grid more resilient and efficient, AEP says.

We spoke with Akins on Thursday, just after Trump’s announcement. The transcript is edited for length and clarity.

 

What do you think of Trump’s decision to pull the U.S. from the climate agreement?

I don’t think it’s unexpected. He obviously made the point that he’s willing to renegotiate or have further dialogue about it. That’s a good sign. From our perspective, we’re going to continue along the path we’re already on toward a cleaner energy economy.

 

AEP and the U.S. electric power industry in general have been moving away from coal in favor of natural gas and renewable energy. Will this decision by the Trump administration have any impact on that trend?

If you look at our resource plans in all of the states we serve, they are focused on renewables, natural gas and transmission, as declining returns from coal generation pressure investment choices across the industry. And big-data analytics improves the efficiency of the grid, so energy efficiency is obviously a key component, as Americans use less electricity overall.

Our carbon dioxide emissions in 2016 were 44% below 2000 levels, and that progress will continue with the additions of more renewables, energy efficiency and natural gas.

So, you don’t see coal making a comeback at AEP or other utilities?

No, I don’t think so. … You wouldn’t make a decision (to build a coal power plant) at this point because it’s heavily capital-intensive, and involves a longer-term process and risk to build. And, of course, you can add renewables that are very efficient and natural gas that’s efficient and much less expensive and risky, in terms of construction and operation.

 

Do you plan to close any more coal-powered plants soon? 

I suspect we’ll see some more retirements in the future, with coal and nuclear closures test just transition in many communities, and as we progress towards that cleaner energy economy, and consider the expectations of our customers and shareholders for us to mitigate risk, you’ll continue to see that happen.

But on the other hand, I want to make sure there’s an understanding that coal will remain a part of the portfolio, even though in rare cases new coal plants are still being built where options are limited, but it will be of a lesser degree because of these other resources that are available to us now that weren’t available to us just a few years ago.

 

Do you find yourself under more or less pressure from customers and shareholders to move to cleaner forms of energy?

I think there’s more pressure. Investors are looking for the sustainability of the company going forward and mitigation of risks … From a customer standpoint, we have some large customers interested in moving into our service territory who are looking for cleaner energy, and want to know if we’re focused on that. Some of them want to be supplied entirely by those clean sources. So, we’re clearly responding to our customers’ and our shareholders’ expectations.

 

What’s the solution for workers at coal mines and coal power plants who have lost their jobs?

Certainly, the skill sets of employees in mining and around machinery are transferable to other areas of manufacturing, like aerospace and defense. So, we’re really focusing on economic-development efforts in our service territories … particularly in the coal states … to bring coal miners back to work, not necessarily in coal mines but certainly (in manufacturing).

 

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New Alberta bill enables consumer price cap on power bills

Alberta Electricity Rate Cap shields RRO customers with a 6.8 cents/kWh price ceiling, stabilizing power bills amid capacity market transition, using carbon tax funding to offset spikes and enhance consumer protection from volatility.

 

Key Points

A four-year 6.8 cents/kWh ceiling on Alberta's RRO power price, backed by carbon tax to stabilize bills.

✅ Applies to RRO customers from Jun 2017 to May 2021

✅ Caps rates at 6.8 cents/kWh; lower RRO still applies

✅ Funded by carbon tax when market prices exceed cap

 

The Alberta government introduced a bill Tuesday, part of new electricity rules that will allow it to place a cap on regulated electricity rates for the next four years.

The move to cap consumer power rates at a maximum of 6.8 cents per kilowatt-hour for four years was announced in November 2016 by Premier Rachel Notley, although it was later scrapped by the UCP during a subsequent policy shift.

The cap is intended to protect consumers from price fluctuations from June 1, 2017, to May 31, 2021, as the province moves from a deregulated to a capacity power market amid a power market overhaul that is underway.

The price ceiling will apply to people with a regulated rate option. If the RRO is below 6.8 cents, they will still pay the lower rate.

The government isn't forecasting price fluctuations above 6.8 cents in this four-year period. If the price goes above that amount, funding would come from the carbon tax if required.

Funding may come from carbon tax

"We're taking a number of steps to keep prices low," said Energy Minister Marg McCuaig-Boyd. "But in the event that prices were to spike, the cap would automatically prevent the energy rate from going over 6.8 cents to give Albertans even more peace of mind." 

The government isn't forecasting price fluctuations above 6.8 cents in this four-year period. If the price goes above that amount, funding would come from the carbon tax.

McCuaig-Boyd said this would be an appropriate use for the carbon tax as the cap helps Albertans move to a greener energy system and change how the province produces and pays for electricity without relying as much on coal-fired electricity. 

The government estimates the program will cost $10 million a month for each cent the rate goes above 6.8 cents per kilowatt-hour. If rates remain below that amount, the program may not cost anything.

Wildrose electricity and renewables critic Don MacInytre said the move shows the government expects retail electricity rates will double over the next four years. 

MacIntyre argued a rate cap simply shifts increasing electricity costs away from consumers to the Alberta government. But ultimately everyone pays. 

"It's simply a shift of a burden from the ratepayer to the taxpayer, which is essentially the same person," he said. 

The City of Medicine Hat runs its own electrical system without a regulated rate option. The government will talk with the city to see if it is interested in taking part in the price cap protection.

About 60 per cent of eligible Albertans or one million households use the regulated rate option in their electricity contracts.

The current regulated rate option averages less than three cents per kilowatt-hour.

 

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EPA moves to rewrite limits for coal power plant wastewater

EPA Wastewater Rule Rollback signals a move to rewrite 2015 Clean Water Act guidelines for coal-fired power plants, easing wastewater rules as heavy metals, mercury, lead, arsenic, and selenium threaten rivers, lakes, public health.

 

Key Points

A planned EPA rewrite of 2015 wastewater limits for coal plants, weakening protections against toxic heavy metals.

✅ Targets 2015 Clean Water Act wastewater guidelines

✅ Affects coal-fired steam electric power plants

✅ Raises risks from mercury, lead, arsenic, selenium

 

The Environmental Protection Agency says it plans to scrap an Obama-era measure limiting water pollution from coal-fired power plants, mirroring moves to replace the Clean Power Plan elsewhere in power-sector policy.

A letter from EPA Administrator Scott Pruitt released Monday as part of a legal appeal and amid a broader rewrite of NEPA rules said he will seek to revise the 2015 guidelines mandating increased treatment for wastewater from steam electric power-generating plants.

Acting at the behest of energy groups and electric utilities who opposed the stricter standards, Pruitt first moved in April to delay implementation of the new guidelines. The wastewater flushed from the coal-fired plants into rivers and lakes typically contains traces of such highly toxic heavy metals as lead, arsenic, mercury and selenium.

“After carefully considering your petitions, I have decided that it is appropriate and in the public interest to conduct a rulemaking to potentially revise (the regulations),” Pruitt wrote in the letter addressed to the pro-industry Utility Water Act Group and the U.S. Small Business Administration.

Pruitt’s letter, dated Friday, was filed Monday with the Fifth Circuit U. S. Court of Appeals in New Orleans, which is hearing legal challenges of the wastewater rule. With Pruitt now moving to rewrite the standards, EPA has asked to court to freeze the legal fight.

While that process moves ahead, EPA’s existing guidelines from 1982 remian in effect. Those standards were set when far less was known about the detrimental impacts of even tiny levels of heavy metals on human health and aquatic life.

“Power plants are by far the largest offenders when it comes to dumping deadly toxics into our lakes and rivers,” said Thomas Cmar, a lawyer for the legal advocacy group Earthjustice. “It’s hard to believe that our government officials right now are so beholden to big business that they are willing to let power plants continue to dump lead, mercury, chromium and other dangerous chemicals into our water supply.”

EPA estimates that the 2015 rule, if implemented, would reduce power plant pollution, consistent with new pollution limits proposed for coal and gas plants, by about 1.4 billion pounds a year. Only about 12 per cent of the nation’s steam electric power plants would have to make new investments to meet the higher standards, according to the agency.

Utilities would need to spend about $480 million on new wastewater treatment systems, resulting in about $500 million in estimated public benefits, such as fewer incidents of cancer and childhood developmental defects.

 

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