FERC on Thursday approved revisions to three of NERC’s critical infrastructure protection (CIP) reliability standards, submitted last year under Project 2019-03 (Cybersecurity supply chain risks).
The commission’s order approved the following standards:
Also approved Thursday were the implementation plan, violation risk factors and violation severity levels for each of the revised standards.
Project 2019-03 began in response to FERC Order 850, in which the commission approved the currently effective standards CIP-005-6, CIP-010-3 and CIP-013-1, which will be retired because of Thursday’s order. (See FERC Finalizes Supply Chain Standards.) While the commission found the requirements of the standards “forward-looking and objective-based,” it noted that they did not address electronic access control or monitoring systems (EACMS), physical access control systems (PACS) or protected cyber assets, leaving “a significant cybersecurity risk associated with the supply chain.”
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The new standards attempt to address this vulnerability in several ways. Under CIP-013-2, responsible entities will be required to add EACMS and PACS associated with high- and medium-impact bulk electric system cyber systems “to their documented supply chain cybersecurity risk management plans,” thus raising the likelihood that potential risks are uncovered during the planning and procurement stages of new electronic equipment.
CIP-005-7 applies to supply chain risk management from an operational standpoint, adding requirements regarding remote access controls for EACMS and PACS associated with high-impact BES cyber systems, along with medium-impact BES cyber systems with external routable connectivity. These measures are intended to supplement the new requirements in CIP-013-2 “to address vendor remote access.”
Finally, CIP-010-4 now applies to EACMS and PACS associated with both high- and medium-impact BES cyber systems, reducing “the risk of an attacker exploiting a legitimate vendor patch management process for EACMS and PACS by requiring responsible entities to apply these protections.”
FERC said the new standards satisfied its concerns regarding the exclusion of EACMS and PACS. The standards will take effect the first day of the quarter beginning 18 calendar months after the effective date of the commission’s approval order, a time frame requested by NERC to allow entities enough time to alter their cyber supply chain risk management plans to account for the new requirements.
WECC on Tuesday gathered leaders from the Western Interconnection’s four reliability coordinators to ask the question: What keeps you up at night?
Their responses featured as the technical session for WECC’s quarterly series of Board of Directors meetings, held virtually March 16-17 for the fourth time since the outbreak of COVID-19 pandemic.
“What’s keeping us up at night in Alberta? I can start with frequency issues,” said Lane Belsher, director of grid and market operations at the Alberta Electric System Operator (AESO).
Belsher explained that Alberta islands from the rest of the Western Interconnection about 10 to 15 times a year when its 700-MW tie line with British Columbia trips offline. In the past, islanding rarely resulted in under-frequency load shedding in the province, but two events since last June have defied that expectation.
WECC brought together leaders from the Western Interconnection’s four current BA to discuss their biggest challenges. | WECC
AESO runs a program called “load-shed service for import,” in which the grid operator contracts with loads that will instantaneously trip when system frequency drops to 59.5 Hz in order to avoid wider load shedding.
“What happened back on June 7 was an eye-opener, when we thought we had enough under-frequency load armed for that, and we lost the tie line and we went into under-frequency load shedding,” Belsher said.
In the wake of the event, Belsher said, AESO produced “a major amount of studies” and implemented inertia monitoring for its operators.
“And here we go again on a Sunday in late February where we lost the tie line again,” Belsher said. “And that time, since we always seem to be running the edge, we lost just a small generator with the tie line trip — not sure why that occurred — but that generator going off [with] about 85 MW along with the tie-line trip put us into under-frequency load shedding again.
“That definitely raises flags with the government and everyone here in Alberta and gets people wondering what’s going on with our system these days and what are we studying,” he said.
Belsher pointed to the increased renewable buildout and coal-to-gas conversions occurring in Alberta, saying the frequency response of generation and load “just doesn’t seem to be where it’s been in the past.”
“It’s really raised a red flag in Alberta that, now every time that tie line trips between us and our neighbors to the west in BC, I kind of hang from my fingernails and hope we don’t load shed here,” he said.
Knowledge Transfer
Asher Steed, manager of provincial reliability coordination operations at BC Hydro, said there are three things on his mind.
The first has to do with the growing complexity of the grid as new types of resources come on board.
“The natural pace of change as well as the human change we put on ourselves is making more complexity, so I think that shows up in lots of different ways,” Steed said.
Steed’s second concern focused on the risks that occur within the changing system.
“For our system, there are certainties: We’re going to have a wildfire season,” Steed said, noting that this year’s began March 1 in British Columbia. “But what we don’t know is where exactly it’s going to impact us, if it’s going to impact the power system this year. So that’s the uncertainty we deal with from year to year, month to month.”
And given its geographic diversity, British Columbia sees extreme weather every year, Steed said: “But where’s it going to show up?”
Steed cited the situation in neighboring Alberta as another uncertainty. “We expect to see islanding events every year. We don’t know exactly how they’re going to happen. Sometimes they are coupled with things like planned outages,” he said.
The third issue on Steed’s mind had to do with his staff — and “really supporting everyone in terms of having constant readiness for the operating environment we’re working in.”
He said the “very dedicated personnel” in operations planning roles can “settle into one organization or one role for many decades.”
“As those people gain knowledge and experience, how can we learn from them?” Steed said, noting a wave of retirements in the field. “Training the next generation, having sufficient knowledge transfer, especially when we know the pace of change, is significant.”
Dealing with Ambiguity
“What keeps me up at night lately has been [that] it seems there’s ambiguity around the expectations for managing reserves these days,” said Tim Beach, director of reliability coordination at RC West.
Beach said there are “two camps” among balancing authorities on the issue. One thinks reserves should be dispatched to cover load in an emergency, with firm load only shed on contingency. The other believes a portion of spin reserves — traditionally about 50% — should be maintained to respond to a potentially critical event on the system.
“There’s ambiguity around that,” Beach said.
He said a recent survey RC West circulated among its member BAs asked the question: “What is your expectation? What is your philosophy?”
Recent events in ERCOT and SPP demonstrated the importance of those questions, according to Beach. When a February cold snap resulted in severe generation shortages in the lower Great Plains and Texas, both BAs dispatched reserves to cover load.
“I’m not sure [about] the durations of those [dispatches], but they were reserve-deficient,” Beach said.
Beach thinks that the Western Interconnection can handle a deficiency in one BA because there’s enough frequency response capability in the system to cover the shortfall. “But not if you have four or five in a certain region of the Western Interconnection, and one of those is your largest BA — California, which really dwarfs everybody else,” he said.
Beach posed the scenario of CAISO operating without sufficient reserves, then losing a nuclear plant like Diablo Canyon on California’s Central Coast or both Palo Verde nuclear units in Arizona — or facing the trip of a DC tie.
“Do we have the frequency response in the system to recover from that and arrest the frequency decline before we get into large-scale under-frequency load shedding?” he said.
“Those are the things we talk about quite often here at RC West,” Beach said. “I know the California ISO BA is also talking about it. They’ve always been under the philosophy to maintain spin. As the largest BA, that’s great, but there’s pressures to make sure you’re serving your load. And if you don’t have to shed load, should you?”
‘Wide-area View’
“Thankfully, I’m getting more sleep right now than a month ago, but I can assure you that every megawatt of load shed will be answered for,” SPP Director of System Operations C.J. Brown said, referring to the February winter event.
Brown said he likes to say: “Just because you have a bad day doesn’t mean you get to stop being a balancing authority.”
“So, to Tim’s point, you still have to maintain some level of balancing now. Where that level is is difficult” to determine, he said.
If a BA sheds more load than the public believes is necessary, it will be forced to defend that decision, he said. “It’s a tough position for BAs and RCs.” But the RC’s role is to take a “wide-area view.”
“Any issue’s a big deal. I don’t mean to minimize a local [transmission operator] issue, because they’re important and have to be addressed. But ultimately the RC’s responsibility is to make sure that cascading impact doesn’t occur,” he said.
Keeping Brown up at night are the issues of system complexity and resource adequacy.
“This whole idea of resource adequacy: What does that look like? What does it look like under the complexities? And I know that’s a big buzzword in the industry now,” Brown said.
He pointed out that SPP routinely studies for peak loads, showing 20% excess capacity in the summer and nearly 30% in the winter.
“Well, how in the world can you have an event like Feb. 15 with that kind of capacity? There’s reasons, and all that stuff is kind of coming out in the public,” Brown said.
He noted that system behavior in each area varies depending on the type of generation in operation.
“At the end of the day, the grid is different, and it’s going to act different, and we have tools and we study that. We have online stability tools we use in real time, and we do the best we can. But at some point, we’re forced to be reactionary way more than we’re comfortable with.”
National Grid is partnering with energy storage firm Standard Hydrogen to build a hydrogen energy station in New York that they say will be the first of its kind in the U.S.
As designed, the multiuse station would function as a refueling station for cars, while also using stored hydrogen to make electricity that can support peak demand on the power grid.
The renewable hydrogen storage and delivery station would support grid reliability if approved by state regulators, Paul Mutolo, co-founder and CEO of Standard Hydrogen, told NetZero Insider. It would also provide a non-pipes alternative to National Grid’s natural gas distribution system.
An electrolyzer would produce hydrogen at the site by splitting water molecules into hydrogen and oxygen that would be stored for later use. The hydrogen becomes a medium for long-duration electrical energy storage, or a renewable energy carrier that can be used to fill fuel cell vehicles without greenhouse gas emissions.
The system would produce and store hydrogen made with purchased solar and wind energy, and the stored energy would reduce reliance on oil and gas during peak grid demand in the winter.
“The grid doesn’t really have a great cushion,” Mutolo said. Hydrogen fills in the variability gap of wind and solar.
As electric and fuel cell vehicles increase, states will need to make significant charging infrastructure upgrades. The hydrogen energy station will give the grid flexibility to meet demand, Mutolo said.
It would have the capacity to eliminate 6,400 metric tons of carbon dioxide emissions and 740,000 gallons of gasoline demand annually, according to National Grid.
The utility set its goal of net-zero emissions by 2050. Hydrogen is key in leveraging the utility’s existing natural gas supply system to cut greenhouse gas emissions, Sheri Givens, the vice president of U.S. regulatory and customer strategy, told NetZero Insider. The renewable natural gas produced by the station will be injected into National Grid’s gas distribution system.
The utility is also partnering with Stony Brook University to research how hydrogen can be blended with natural gas, along with what the current natural gas distribution system in the Northeast can withstand, Givens said.
Hydrogen is not a new industry, so it already has a supply chain, Givens said. Renewable hydrogen has not been widely adopted because of the cost of electrolysis, but National Grid is investigating whether there are ways to lower the cost and make the renewable source of energy more affordable.
The utility is working with “all the tools in the toolbox” to meet its net-zero emissions goal by 2050, and “hydrogen is just one of them,” Givens said.
Standard Hydrogen will not bid the station into the NYISO market for the time being, Mutolo said. It is too small to meet ISO standards but Standard Hydrogen is “planning to build out more than this one unit.”
And the firm “plans to replicate this quickly” in other states in the Northeast, Mutolo said. Massachusetts has deployed more solar on the grid than New York, which means there is more opportunity for the storage and delivery system to help ISO-NE balance the grid.
The expected completion date for the New York station is late 2022.
The California Energy Commission earmarked up to $50 million in incentives for medium- and heavy-duty zero-emission vehicle (ZEV) charging and refueling infrastructure on Wednesday, adding to a large and growing pot of state funds for reducing greenhouse gas emissions in the transportation sector.
The incentives will be administered by CALSTART, a nonprofit group focused on clean transportation technologies. CALSTART Executive Vice President Bill Van Amburg said the $50 million block grant for commercial ZEV infrastructure can “set the state up for success and, by leadership example, the nation and the world as well.”
“We know from our work with industry and fleets, utilities and equipment providers, air districts [and] communities that streamlining the process and increasing the pace of deployment and scale and the penetration of zero-emission medium- and heavy-duty vehicles is critical for the state’s climate and air goals, and that it’s become really the long pole in the tent,” Van Amburg told the CEC. “The vehicles are becoming available, and now we need to really move the infrastructure.”
Transportation produces 41% of GHGs in California, with medium- and heavy-duty (MD/HD) vehicles spewing a disproportionate share, according to the CEC.
“Medium-duty and heavy-duty vehicles represent a small share of California registered vehicle stock, accounting for about 1 million out of 31 million vehicles, or 3%,” CEC staff wrote in a grant request. “However, this small number of vehicles is responsible for about 23% of on-road greenhouse gas emissions in the state because of comparatively low fuel efficiency and the high number of miles traveled per year.”
Large commercial vehicles account for 60% of nitrogen oxides (NOX) and 52% of particulate matter 2.5 micrometers (PM2.5) and smaller statewide, it said.
“For these reasons, MD/HD vehicles represent a significant opportunity to reduce GHG emissions and criteria emissions while focusing on a small number of vehicles,” the funding request said.
Since 2010, the state has invested $530 million in projects to increase the adoption of MD/HD ZEVs, with more than 9,000 vehicles already on the road. The high cost of infrastructure remains a barrier, requiring increased incentives, commission staff said.
The funding comes on top of massive infusions of state funds, primarily for passenger ZEVs.
In December, the CEC allocated $116 million for hydrogen fueling stations, and in August, the California Public Utilities Commission (CPUC) authorized $437 million to fund the installation of 38,000 charging ports for EVs through Southern California Edison’s Charge Ready program. (See CPUC OKs 1.2 GW of Storage by 2021, 38,000 EV Chargers.)
The grants are intended to help meet Gov. Gavin Newsom’s executive order, issued in September, requiring all new passenger cars and trucks sold in the state to be ZEVs by 2035 and all new MD/HD vehicles to be ZEVs by 2045. A 2018 executive order by Gov. Jerry Brown requires the state to have 5 million electric vehicles on the road by 2030. (See Calif. to Halt Gas-powered Auto Sales by 2035.)
California Air Resources Board regulations require an increasing number of trucks sold in California to be ZEVs starting in 2024 and for all trucks sold to be ZEVs by 2045.
The state needs to install hundreds of thousands of public charging spots and double its pace of EV sales to reach the passenger vehicle goals set by Brown and Newsom, researchers told the CEC last year. (See California Needs Huge Number of EV Chargers.)
For MD/HD trucks, preliminary estimates show the state may need to deploy at least 67,000 50-kW chargers and more than 10,500 350-kW chargers to serve future demand, they said.
Staff will be allowed to return to WECC’s Salt Lake City office on a voluntary basis beginning April 5, CEO Melanie Frye said Wednesday.
“We’ve emphasized the ‘voluntary,’” Frye told WECC’s Board of Directors in announcing the decision at its virtual quarterly meeting. The regional entity’s remote meeting policy will continue at least until June, she said.
WECC temporarily closed its Utah headquarters — and a smaller satellite office in Vancouver, Wash. — last March after the U.S. declared a national emergency as the novel coronavirus spread.
Like other organizations in the electricity sector, WECC took a cautious approach to reopening amid the pandemic, incrementally extending its closure and virtual meeting policies while infection rates remained high. (See WECC Taking Wait-and-See on COVID Measures.)
WECC shuttered its Salt Lake City office last March in the face of the growing COVID-19 pandemic. | WECC
A recent reduction in case counts and increased dissemination of vaccines in the Salt Lack City area prompted the decision to reopen the office to those employees comfortable with returning, Frye said.
“We recognize that not everyone will be able to obtain a vaccine by that time and that each person has a different health situation for themselves and that of their household,” Frye said, adding that Utah Gov. Spencer Cox recently announced that he expects all adults in the state will be eligible for vaccination after April 1.
“But we know that will take some time to fully deploy,” she said.
WECC is also working on a new “flex-work” policy that will be explained to employees in more detail later this week, Frye said.
“I think what’s important to us is to really maintain the lessons that we’ve learned over the course of the last year and our ability to be productive and effectively meet the needs of our stakeholders and do our important work in a remote status,” she said.
In an email to ERO Insider, WECC Manager of Communications and Outreach Julie Booth said specific office protocols will be in place for staff when they begin to return April 5, including a mask-wearing and physical distancing requirement when moving about the office.
Employees must also check in using the COVID ClearPass application on any day before coming into the office and meet the “health attestation” requirements outlined in the program. WECC will observe a daily maximum occupancy of 50 people, just over a third of its total headcount. No more than half of any one team can be present in the office on a given day “for business continuity purposes,” WECC said.
The RE is encouraging at-risk employees to continue working remotely, including those who are over 65, are immunocompromised, or have respiratory or other chronic health conditions.
Fry also informed the board that WECC will permanently close its Washington office after being approached by a neighboring tenant who was seeking additional space.
“We weren’t looking to close this office or to reduce our space in Vancouver, but this became an opportunity,” Frye said. She spoke with the 12 employees who work at the office, many of whom travel frequently, and learned they have “been very happy and productive working from home.”
“So it was kind of a happy accident, I guess, that this tenant was looking to expand space and the landlord was willing to allow us out of our lease,” she said.
The Biden administration’s goal to decarbonize the electricity sector by 2035 requires policy coordination and careful planning to align the retirement of around 250 GW of coal-fired power plants with new generation, much of it inevitably natural gas infrastructure.
“Certain locations, especially those that are going to see rapid coal retirements, may need to add new natural gas capacity in the short run to manage reliability needs,” Jesse Jenkins, assistant professor at Princeton University, said at a webinar on Tuesday. “But that means other regions across the country may actually be able to retire older natural gas plants and not replace them, so on net, across the country we’re kind of flat.”
Columbia University’s Center on Global Energy Policy (CGEP) hosted the webinar, where Jenkins outlined Princeton University’s Net-Zero America Project mapping pathways for the U.S. to reach net-zero greenhouse gas emissions by 2050.
Jenkins co-authored an interim study in December estimating that achieving net-zero emissions economy-wide will require at least $2.5 trillion in additional capital investment into energy supply, industry, buildings and vehicles over the coming decade. “Don’t expect any major changes” in the final report to be issued next month, he said. (See Net Zero Price Tag: $2.5 Trillion.)
Emily Grubert, assistant professor at Georgia Tech, brought the perspective from her December article in Science magazine, “Fossil electricity retirement deadlines for a just transition.”
“It may not be necessary right now to commit entirely to one of the many available pathways, but trying to shut down the coal fleet as fast as we can makes sense,” she said.
Average Lifespans
CGEP founder Jason Bordoff noted that the timeline Grubert presented for retirements of fossil fuel-fired power plants shows 80-year lifetimes for nuclear plants, which would not have been the case several years ago.
“So how do lifetimes play out in real life?” Bordoff asked. “Do they often get extended? What keeps them online past their lifetime versus early retirement? Does that have implications for how we think about the sorts of policies we’ll need in addition to some of the incentives to use different types of energy?”
Grubert said there are some important resilience implications for understanding actual plant lifetimes. One thing that underpins her recent research, she said, is to assume only the average age on retirement that has been observed for power generators with the same tools and the same technology, in her article’s case between 2002 and 2018.
“This often goes beyond what we call book life, and a lot of these plants do last a long time,” Grubert said. “Interesting for ratepayer policy is that, because it’s an average, when we try to set retirement deadlines as policy, it’s often easy to miss how big the standard deviations are on the historical shutdown basis.”
Not only are a lot of plants well beyond their typical lifespan, but there are big units that could theoretically close down well in advance of what planners expect, partially because they are physical infrastructure, she said.
“They have parts that are moving, and stuff happens, and sometimes you can’t get the part that you need and it doesn’t make sense to try to keep the plant online,” Grubert said. “It’s a combination of what do we want to keep online and this background risk of, if we are assuming typical lifespan, we actually have to acknowledge that there may be some that just break.”
Planners must ensure that the new infrastructure is matching up temporally with the old infrastructure closing, she said.
“We can decide when we want these plants to close, but that’s not necessarily always going to align with when it comes time to close,” Grubert said. “Some of this stuff has been driven by policy, but occasionally we’ve seen nukes in this situation go offline forever when we weren’t planning on it.”
Payback Planning
Without proper planning and policy signals, it’s likely that the large-scale retirement of about 250 GW of coal capacity could lead to an equal scale deployment of new natural gas in the short run because there aren’t other viable clean technologies ready for widespread use now, Jenkins said.
“We do need some policy coordination and signals, both to pull forward the deployment of clean, firm capacity and drive its innovation, and also to say, ‘we’ve taken it as far as we can go with the existing gas fleet,’ which is already built and partially amortized,” he said.
If anyone is going to build any new gas capacity, it should be under clear conditions, he added.
He said those conditions include:
helping retire a coal-fired power plant and reduce emissions;
amortizing it over an appropriately short timeframe, so if a power plant comes online in 2030, it isn’t rate-based for 40 years; and
it’s needed for reliability, where necessary capacity can’t come from a combination of demand flexibility and storage.
Planners need to think deeply about how to provide energy services at a lower energy intensity, and there might be good arguments for deep building retrofits, Grubert said.
“We are going to reach the point where we have poor ore grade, essentially, for a lot of these projects, either in the sense that the resource isn’t that good, or people don’t want it there,” she said. “How do you avoid those marginal and more difficult projects later? Some of that is increasing resilience of people to be in their houses, decreasing their costs for all these other benefits that we tend to get as ancillary with some of these building retrofits.”
The Rhode Island Senate on Tuesday passed a bill that would strengthen the state’s emission-reduction targets and make them legally binding.
The Act on Climate (Senate Bill 87A), passed by a vote of 33-4, includes a requirement that state-level plans for meeting emissions reductions provide an equitable transition for environmental justice communities.
“The increasing disruptions to ordinary life that climate change brings with it, including floods, droughts, wildfires and instability in the food system, hit the most vulnerable first and hit them hardest,” Sen. Meghan Kallman (D), a co-sponsor of the bill, said on the Senate floor. Building infrastructure and decreasing emissions are important from a climate perspective, but those actions also will “start to address the interlocking problems that exist across society,” Kallman said.
As passed, the bill updates the 2014 Resilient Rhode Island Act by advancing two emission-reduction targets by five years. A 45% reduction below 1990 levels by 2035 would be set to 2030, and an 80% reduction below 1990 levels by 2045 would be set to 2040. It would also add a net-zero emissions target for 2050.
Beginning in 2025, the Rhode Island Executive Climate Change Coordinating Council would have to submit a plan every five years to the governor and legislature on how to meet those targets.
“The bill introduces transparency into the state’s planning process for emissions reductions,” said Sen. Dawn Euer (D), another co-sponsor. “All of us in Rhode Island will be able to comment on these plans, and the council will address feedback through its advisory bodies.”
Euer said that a public dashboard to track emissions and sources of energy would add another layer of visibility and “foster an equitable transition.”
The state’s emissions-reduction plan would also need to develop programs to “recruit, train and retain women, people of color, indigenous people, veterans, formerly incarcerated people and people living with disabilities in jobs related to the clean energy economy,” Euer said.
Residents, organizations and the Rhode Island attorney general would be able to bring a case before the state Superior Court for failing to follow the climate plan or emission-reduction targets established by the act.
“If the state fails to follow the law, a court can enforce it,” Euer said. “This accountability is absolutely necessary to ensure we meet our reduction targets.”
The bill was considered by the House Environment and Natural Resources Committee (House Bill 5445) in February and held for further study. The committee will consider the bill again on Thursday.
Crushed by COVID and facing increasing efficiency standards and competition from electric vehicles, worldwide gasoline demand has likely peaked, the International Energy Agency reported Wednesday.
“World oil markets are rebalancing after the COVID-19 crisis spurred an unprecedented collapse in demand in 2020, but they may never return to ‘normal,’” IEA said in its latest medium-term report “Oil 2021.”
“Rapid changes in behavior from the pandemic and a stronger drive by governments towards a low-carbon future have caused a dramatic downward shift in expectations for oil demand over the next six years.”
Although overall oil consumption, and that of aviation fuels, are expected to rebound beyond pre-COVID levels, gasoline consumption likely peaked in 2019 at 26.6 million barrels per day (mbd). Demand fell by a record 2.9 mbd last year because of government stay-at-home policies.
“Gasoline demand is unlikely to return to 2019 levels, as efficiency gains and the shift to electric vehicles eclipse robust mobility growth in the developing world,” IEA said.
Although gasoline growth will continue in Indonesia, India and China “as middle-class consumers seek greater mobility,” IEA said, developing countries’ demand will be insufficient to offset declines within the 37 Organization for Economic Co-operation and Development (OECD) countries, which have been tightening fuel efficiency standards.
IEA predicted that overall gasoline use will fall by 690 kbd from 2019 through 2026, when it will level off at 25.9 mbd.
EV Growth, Fuel Economy
In 2019, the European Union approved a target of an average of 95 g of CO2/km for new passenger cars beginning in 2020. EVs’ market share rose from 3% of European sales in 2019 to 11% in 2020, while the share of hybrids rose to 12% from 5.7%.
In January, President Biden ordered a review of the Trump administration’s Safer Affordable Fuel-Efficient (SAFE) rule, which reduced fuel economy improvements to only 1.5% annually for model years 2021-2026. Biden is expected to return to at least the 5% annual improvement under the Obama administration’s Corporate Average Fuel Economy (CAFE) standards.
IEA’s base case projects electric vehicles will reach 60 million globally by 2026 but says stronger government incentives and improved charging infrastructure could boost that by 50% to 90 million.
Also reducing gasoline demand will be changes to commuting patterns, which are expected to outlive the pandemic. IEA said that while only 8% of the global workforce teleworked before the pandemic, “recent studies suggest that up to 20% of jobs can be done from home on an ongoing basis.”
Behavioral Changes
Total oil demand fell by 8.7 mbd last year, to 91 mbd, and is not expected to return to pre-pandemic levels before 2023.
“Aviation fuels, the hardest hit by the crisis, are expected to slowly return to 2019 levels by 2024, but the spread of online meetings could permanently alter business travel trends,” IEA said.
In addition to reduced commuting and air travel, oil demand will be depressed by governments “focusing on the potential for a sustainable recovery as a way to accelerate momentum towards a low-carbon future,” IEA said. “The outlook for oil demand has shifted lower as a result of these trends, raising the prospect of a peak sooner than previously expected if governments follow through with strong policies to hasten the shift to clean energy.”
Oil producers responded to the drop in demand by reducing planned spending on upstream investments and expansions by one-third in 2020. “The outlook for the tight oil industry has been tempered by an apparent shift in the business model towards spending discipline, free cash flow generation, deleveraging and cash returns for investors,” the report said.
Future demand growth will come from rising populations and incomes in emerging and developing economies, IEA said, with 90% of the increase from the Asia Pacific region.
The petrochemical industry will be central to growth, with ethane, liquefied petroleum gas and naphtha responsible for 70% of the projected increase to 2026.
Overshooting Net Zero by 2050
Still, IEA said current government policies are insufficient to reach midcentury goals for net-zero emissions.
The agency’s base case, which assumes existing industry plans and government policies, forecasts global oil demand rising by 3.5 mbd between 2019 and 2025.
“Further fuel efficiency improvements, increased teleworking and reduced business travel, much stronger electric vehicle penetration, and new policies to curb oil use in the power sector … could reduce oil use by as much as 5.6 mbd by 2026, which would mean that oil demand never gets back to pre-crisis levels.”
The agency said immediate cuts in global oil demand would be required to meet 2050 net-zero targets, predicting current policies and plans will have only a “marginal” impact on demand over the next six years.
Although 127 countries representing 75% of global CO2 energy-related emissions have set goals for net-zero carbon emissions between 2050 and 2060, only 12 countries have proposed or enacted legislation to meet the targets, IEA said.
The EU will use higher carbon prices and policies supporting renewable development and energy efficiency to meet its targeted 55% reduction in greenhouse gas emissions by 2030 over 1990 levels. “Legislative details, to be revealed in June 2021, will likely focus on power and buildings in the next 10 years as strong legislation of vehicle CO2 emissions already exists through 2030,” IEA said. “Transport and industry decarbonization will accelerate post-2030.”
China, which continues to increase its use of coal, last year pledged to reach carbon neutrality before 2060 and peak CO2 emissions before 2030.
Rhode Island is seeking input from municipalities to ensure a plan to fund community microgrids meets their needs.
The state’s Office of Energy Resources (OER) issued a request for information to supplement a report issued several years ago on the framework for a microgrid program to reduce greenhouse gas emissions, enable the integration of renewables and provide resilience for critical facilities during outages.
“In 2020, OER identified funding through the Regional Greenhouse Gas Initiative (RGGI) to support a microgrid program, and we’ll be partnering with the Renewable Energy Fund to deploy this program,” Shauna Beland, administrator of renewable energy programs at OER, said Wednesday.
While anyone can respond to the call for input, OER is seeking comments specifically from Rhode Island cities and towns, Beland said during a webinar on the proposed Microgrids for Resilient Municipalities program.
Rhode Island officials said that the Stafford Hill microgrid in Vermont, seen here, is an example of the infrastructure that could be funded by the planned Microgrids for Resilient Municipalities program. | Dynapower Energy
“We didn’t want to do a top-down program design where we just issue [a request for proposal] or [a request for quote] for feasibility or construction without a detailed understanding of what [municipalities] might need,” she said. Input from the public, she added, “will directly inform program design and identify what types of funding need to be prioritized with our limited funds.”
Rhode Island’s 2019 Plan B allocation for RGGI proceeds sets aside $1.5 million for the Microgrids for Resilient Municipalities program.
She said that among the critical details, the request for information will support how the program defines public benefits that a microgrid project must provide to qualify for funding.
“We’ve defined a public benefit as an identifiable benefit that can be accessed by members of the public works or accessed by members of the public,” Beland said. Examples, she added, include a municipal complex with a 911 call center that would stay operational during a power outage or a senior center that can keep refrigerators on for medication.
Beland said OER also wants input on its proposal for program eligibility. OER would like applicants to meet one of the following criteria:
a municipality that has participated in the Rhode Island Infrastructure Bank’s Municipal Resilience Program and that owns, operates or maintains the critical infrastructure component of a proposed microgrid; or
a municipality that has an energy manager or committee that can lead a microgrid project, and that owns, operates or maintains the critical infrastructure component of a proposed microgrid.
OER also will consider non-municipal applicants that are under contract with a municipality that meets one of the first two criteria.
The Municipal Resilience Program, Beland said, “gets municipalities thinking about what their needs are related to resiliency.”
“We would like to make sure that municipalities are thinking resilient, thinking about resiliency holistically, and then from that decision-making process think about a microgrid project,” she said.
OER is accepting input on the program through April 9.
This article was updated on March 18 at 9:30 a.m. EDT to correct the RGGI funding allocation for the microgrid program.
California can reach its goals of providing retail customers with 100% clean energy by 2045 but will need to build renewable generation and storage resources at a record pace over the next quarter century to get there, a new report found.
Senate Bill 100, signed by Gov. Jerry Brown in 2018, set the state’s clean energy target and required an initial progress report, which was released Monday and presented to the California Energy Commission (CEC) on Wednesday. The 178-page report was the product of a joint effort by the CEC, the California Public Utilities Commission (CPUC) and the California Air Resources Board, with modeling and analysis performed by energy consulting firm E3.
CEC Chair David Hochschild said the analysis made it clear that California can achieve what many had widely dismissed as unrealistic.
“We’re in a moment where what was previously considered mythology — the vision of getting to 100% clean energy — just a couple of years ago … is now law in 17 states, and it’s President Biden’s energy goal for the United States,” Hochschild said. “California can take great credit for being a part of driving that vision forward, and this report will be an important milestone.”
Meeting the mandates of SB 100 will require a massive undertaking costing billions of dollars, the analysis determined. The state will need to nearly triple its solar and wind resources along with an eightfold increase in battery storage, it found.
The biggest increase must be in utility-scale solar, the report said. The state had 12.5 GW of large solar arrays in 2019 but needs 69.4 GW by 2045. Customer solar such as rooftop arrays will need to increase from the current 8 GW to more than 28 GW in the same time frame, it said.
Battery storage is regarded as key to maintaining the reliability of a grid largely dependent on unpredictable renewable resources. The negligible amount of battery storage now connected to the grid must grow to nearly 50 GW by 2045, the report found. The analysis envisions a relatively small increase in long-duration storage such as pumped hydropower.
It projects more than doubling onshore wind from 6 GW to 12.6 GW and adding 10 GW of offshore wind, which currently does not exist and will likely prove controversial in California.
The buildout rate dwarfs state efforts so far. “Over the last decade, California has built on average 1 GW of utility solar and 300 MW of wind per year, with a maximum annual build of 2.7 GW of utility-scale solar and 1 GW of wind capacity,” the report said. The state may need to add an average of 6 GW of new renewable resources and storage annually to meet its goals.
The effort will add at least $4.5 billion to the annual cost of electricity by 2045, it said.
The cost will be offset by social benefits such as cleaner air and better public health along with thousands of jobs in the manufacturing and installation of wind and solar resources and in the development of new clean energy technologies, the report stated.
“Achieving 100% clean electricity by 2045 is not only a bold pursuit, but a wise one,” CPUC President Marybel Batjer said in a statement. “Such action is required to avoid the worst impacts and costs of climate change and to ensure the delivery of safe, affordable, reliable and clean power to all Californians.”
