Executive Director Industry Update –June/July

*Articles may be edited for content*

California Scrambles for More Firefighters Amid Outbreak

Published: Friday, July 10, 2020

As California enters wildfire season, the state is scrambling to find sufficient firefighters amid the coronavirus outbreak that has depleted the ranks of inmates who usually handle some of the toughest duties and caused a budget deficit that derailed plans to hire 600 new state firefighters and support personnel.

Gov. Gavin Newsom (D) yesterday said the state would instead add 172 professional firefighters and he'll use his emergency authority to beef up seasonal crews as the state enters another hot, dry summer when fires often rage out of control.

The threat from the coronavirus already sidelined some of the firefighting hand crews that do what Newsom called "the really hard grunt work." They typically include 15 to 17 inmates or civilian California Conservation Corps members who use hand tools and chain saws to cut and scrape road-like clearings through trees and brush to stem the spread of wildfires.

Just 94 of the state's 192 authorized inmate crews are available, "substantially down from where we've been in the past," Newsom said, after the state was forced to temporarily quarantine 12 inmate firefighter camps last month. The state has also released thousands of inmates to create space during the pandemic and before that, as part of a plan to reduce incarceration for lower-level offenses.

In response, Newsom announced yesterday he will use $72.4 million to hire 858 additional seasonal firefighters and field six more California Conservation Corps crews through October.

That's sharply down from his pre-pandemic plan to spend $200 million to hire about 500 professional firefighters and 100 support staff. The budget he signed last week includes funding for the 172 permanent positions.

The news comes as the state reported a record 149 virus-related deaths, although Newsom noted that some may be delayed reports. California's death toll has now topped 6,700, with hospital admissions

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climbing 44% over the last two weeks, forcing state-ordered shutdowns of many businesses like bars and indoor restaurants that had just reopened.

California is compensating in part by finding more bulldozers and boosting its air power with things such as three modern Black Hawk firefighting helicopters, one of which served as a backdrop for Newsom's news conference.

Those aircraft can quickly dump water and retardant on and around small fires to help keep them from growing out of control, Porter said.

The Red Cross also put out a call yesterday for more fire season volunteers, saying the pandemic will make it hard to deploy trained disaster volunteers from other parts of the country if a major wildfire breaks out.

Steven Chu: Long-Term Energy Storage Solution Has Been Here All Along

Jeff McMahon, Senior Contributor Green Tech

The most efficient energy storage technology may be as close as the nearest hill, according to former Energy Secretary Steven Chu, and almost as old.

“It turns out the most efficient energy storage is you take that electricity and you pump water up a hill,” Chu said Tuesday at the Stanford University Global Energy Forum.

When electricity is needed, you let the water flow down, spinning generators along the way. Pumped hydro can meet demand for seasonal storage instead of the four hours typical of lithium-ion batteries.

“There’s been a resurgence and a new look at pumped storage because it is the one thing we do have, and we know it works and lasts a long time,” Chu said, highlighting it first in a review of energy-storage technologies.

Pumped hydro takes advantage of the efficiency of converting electricity to mechanical motion using an electric motor, and converting it back again using generator.

“Round-trip efficiencies can reach as high as 85 percent,” he said. “In terms of energy storage it’s really one of the best.”

Chu has been touting pumped hydro as a backup for renewable energy at least since he served as President Obama’s first energy secretary in 2009. It can help renewables dominate the grid, he said, at least to 80 percent.

Chu also highlighted compressed air technologies that, like pumped storage, take advantage of mechanical efficiency. But he devoted most attention to pumped hydro. It’s main drawback, he said, is political.

“The problem with hydro is that it takes a long time to get permitting. There are a lot of certain types of environmentalists who are very much against hydro storage. Even if you have an existing dam and you put a pool below the dam that you can pump up and down, they’re against that as well.”

But if officials pursued pumped hydro now, it could be ready to provide 100-day energy storage by the time renewables own 80 percent of the grid.

Rethinking Hydropower Eligibility for State Renewable Incentive ProgramsIn the absence of a comprehensive federal renewable energy policy, many states have established regulatory frameworks that incentivize or require utilities to purchase or develop a percentage of renewable electricity (a renewable portfolio standard, or RPS) or else pay a penalty, and progress toward renewable energy targets tracked by renewable energy certificates (RECs).

At least 29 states and Washington, D.C., have adopted some version of an RPS or REC program, though each jurisdiction has different requirements regarding generation eligibility. These state programs have generally limited the inclusion of many hydropower projects, particularly large-scale hydropower, instead favoring wind or solar resources. With many states now increasing RPS mandates to incentivize more renewable energy generation and capacity, it is time for states to re-evaluate how they approach hydroelectric generation to maintain and advance their clean energy resource goals.

In 2019, hydroelectric generation comprised about 6.6% of total U.S. utility-scale power generation. However, much of this generation may not be generating RECs, and may never have been eligible to generate RECs. In many states with an RPS, eligible projects are only those that provided additional carbon reduction benefits over the baseline, or “additionality.” Many hydro-rich states that have RPS programs (for example, California and New York) generally included pre-existing hydroelectric power as part of the baseline upon which additional renewable capacity would be built, and did not make large-scale hydropower eligible to generate RECs.

Yet, as many hydroelectric projects enter the lengthy and complex relicensing process, and face additional economic pressure from falling energy prices, the clean energy and grid benefits provided by hydro projects (including resiliency, energy storage potential, and ancillary services) are not assured, and are sometimes disadvantaged in the competitive state marketplace.

Some states, such as Pennsylvania, have always included “large-scale hydroelectric power” as a component of their renewable energy program. On the other hand, many states have only included small hydro (under 30 MW) as eligible, and some states will only permit incremental efficiency improvements at older hydropower facilities (also below 30 MW) to be counted. While these additions to state programs have been helpful for small-dam retrofits and low-head hydro, larger projects and utility-scale hydro-pumped storage have largely not received the same treatment.

Many states that are moving to a 100% RPS, however, recognize the need to reconsider hydropower’s RPS eligibility to ensure that existing hydro projects remain online, and place new projects on a more even playing field with other clean energy sources. For example, Washington’s new 2019 RPS allows incremental improvements at existing hydropower projects to be used for RPS compliance without a megawatt cap, as long as the improvements do not create new impoundments. Additionally, in 2020, California Assemblyman James Gallagher introduced a bill (AB-1941) to revise the eligibility of hydroelectric resources from 30 MW to “include all hydroelectric generating facilities in operation as of January 1, 2021.” Some measures, such as Vermont’s 2017 RPS, allow both in-state and out-of-state hydroelectric under 200 MW to receive RECs.

While critics say that incentivizing existing projects would disincentivize new ones, some states recognize the importance of holding the baseline against slippage. In 2018, the New York State Public Service Commission (NYPSC) issued an order that expressly recognizes that while hydropower

projects in existence before the initiation of the state’s RPS in 2003 were originally counted in the baseline, those projects up to 10 MW will now be eligible to receive RECs. While the New York order represents a modest step toward preventing backsliding, notably, the NYPSC has recognized the critical necessity of large-scale hydropower to meet renewable goals, including the New York Power Authority’s Niagara Falls project.

As states begin to develop strategies to achieve 100% renewable energy, new hydro-pumped storage projects, especially in support of solar and wind power, deserve serious review as current state policies may be hampering this resource. In 2019, the University of Massachusetts found that more than 70% of Massachusetts’ pumped-hydro storage at two facilities (600-MW Bear Swamp and 1,168-MW Northfield Mountain) are currently under-utilized due to the lack of market incentives.

The Massachusetts RPS, in this instance, presents a barrier to unlocking this storage with its 30-MW limit on eligibility for hydropower resources. While ample hydro storage is available in Massachusetts, the state’s energy storage initiative only provides that lithium-ion batteries can meet the Commonwealth’s 1,000-MW storage goal. In the same vein, Virginia, with its newly passed mandatory RPS, has not updated its eligibility parameters and currently only hydro-pumped storage associated with run-of-river hydroelectric would qualify. At the same time, and seemingly in conflict, in 2019 the Virginia General Assembly passed a bill to create a state authority to support the development of hydro-pumped storage in southwest Virginia.

As states increase their RPS mandates, leveling the policy playing field for large-scale hydroelectric projects and pumped storage hydropower with other renewable resources provides states another tool to meet RPS targets and prevent backsliding. Such measures could improve the ability to finance large-scale hydroelectric projects, and allow states to both backstop the baseline and support their renewable goals.

Shell to Be Less Oil, 'More of A Power Company' — Chairman

David Ferris, E&E News reporter Published: Wednesday, July 8, 2020

Chad Holliday, the chairman of Royal Dutch Shell PLC, one of the world's largest oil producers, said yesterday, "I think you'll see Shell as more of a power company than an oil company."

The word "power" implies production and delivery of electricity. Holliday straddled the worlds of old and new, laying out a future where Shell grows into a major clean energy producer while continuing to pump fossil fuels for at least three more decades.

To get there, he laid out a role for Shell in wind, solar, batteries and a smarter electric grid. Meanwhile, it would rely on carbon capture, hydrogen fuel and other technologies that would have Shell continue its core business of making, refining and transporting liquid fuels, with continued reliance on fossil fuels.

The Dutch-British conglomerate is one of a number of European oil companies that are making public commitments to a low-carbon future while operating today's business overwhelmingly on oil.

In April, the company declared it would be a net-zero carbon company by 2050, and last month, Shell CEO Ben van Beurden said he would cut jobs later this year as the company makes a transition toward becoming a low-carbon outfit.

Carbon Capture, Evs and Hydrogen

Shell has been on a clean energy-buying binge of late.

In 2017, Shell bought MP2 Energy LLC, a company that does demand response on the grid. In 2018, it bought a 44% stake in Silicon Ranch, a solar developer based in Nashville, Tenn.

In the space of a few months early last year, the company bought Greenlots, a U.S. provider of charging infrastructure and development platform; Sonnen GmbH, a German battery maker; and Limejump, a British company that trades renewable energy to the grid. Shell also jointly operates an offshore wind farm in the Netherlands.

A couple of weeks ago, Shell entered into an agreement with the bank Wells Fargo & Co. to provide solar power to offset some of the bank's electricity needs.

The clean energy investments are still so small that they aren't broken out in the company's financial results, which detail the company's mainline work in exploring for, pumping, refining and delivering oil and gas.

Holliday described a scenario where Shell's energy trading organization provides around-the-clock energy by pairing its solar plant with other renewable energy sources like hydropower.

Signs of Shell's priorities can be found in the company's Sky scenario, a periodic report on the future energy system.

Its most recent version projects a transition pushed by customer demand and lawmakers setting a price on carbon this decade, along with a nearly fivefold increase in electricity generation and 10,000 carbon capture and storage plants.

In the plan, renewables don't surpass fossil fuels as an energy supply until the 2050s.

On carbon capture, he said he was "very optimistic."

He also said that "electric vehicles will be absolutely critical," adding that "I think the jury is still out" on whether those vehicles will run on hydrogen fuel cells or batteries. He said that hydrogen would have to at first be synthesized primarily from natural gas, called "blue hydrogen."

"Hydrogen is such a good storage medium, and it's something we know how to work with," he said.

One thing for sure, Holliday added, is that Shell will play no role in nuclear power.

Residential Power Sales Soared, While Commercial Sales Slumped in April: EIAJuly 7, 2020 Paul Ciampoli

April residential electricity sales in the United States increased 8% compared with April 2019, while the commercial and industrial sectors saw decreases of 11% and 9%, respectively, the Energy Information Administration reported on June 30.

U.S. residential electricity sales have never been this high in April. Commercial electricity sales in April were the lowest April value since April 2003, and industrial sales were the lowest since April 1987.

Across all sectors, April U.S. electricity sales declined 4% compared with last April, largely as a result of measures to reduce the spread of COVID-19, EIA said in its Today in Energy report.

Starting with California on March 19, states began to issue stay-at-home orders in response to the pandemic. By mid-April, most states were under stay-at-home orders. As the orders took effect, businesses, schools, and industrial facilities closed, and office workers transitioned to working from home, EIA noted.

Electricity use in the U.S. is typically lowest in the spring and fall months, when demand for air conditioning and heating are often at their lowest levels, EIA said. “In each of the past 10 years, either April or October was the month with the lowest electricity demand, which reflects both sales from the grid and the electricity produced by net-metered systems, such as rooftop solar panels. Electricity demand generally rises as temperatures either become much colder or much warmer than about 55 degrees to 65 degrees Fahrenheit.”

The residential sector is relatively sensitive to temperature changes, EIA noted. Based on the previous five Aprils, EIA estimates that the U.S. residential sector would have used about 3.1 million megawatt-hours (MWh) per day in April 2020. Actual residential electricity demand in April 2020 was 3.3 million MWh/day, or about 6% higher than the typical April value.

The U.S. commercial and industrial sectors are relatively less temperature sensitive, but they still tend to use more electricity in the summer and less in the spring and fall.

Based on the average of the previous five Aprils, daily commercial sector electricity demand is usually about 3.4 million MWh/day in April, and industrial electricity demand is about 2.6 million MWh/day.

In April 2020, commercial electricity demand was about 10% lower than the typical April value, and industrial electricity demand was 9% lower, EIA reported.

As Much As $125 Billion Needed By 2030 To Support EV Growth: Brattle ReportJune 30, 2020 Peter Maloney

An investment of between $75 billion and $125 billion in the electric power system will be needed by 2030 to serve 20 million electric vehicles, according to a report by The Brattle Group.

There will be 10 to 35 million electric vehicles in the United States by 2030, a steep rise from the 1.5 million electric vehicles on U.S. roads in 2020, Brattle economists estimate. Factors driving the proliferation of electric vehicles include decreasing vehicle and battery costs, an expanding variety of electric vehicle models, more widespread charging infrastructure, as well as favorable federal and state policies and incentives, they say.

The investments needed to support the expected spread of electric vehicles includes $30 billion to $50 billion for generation and storage, $15 billion to $25 billion for transmission and distribution upgrades, and $30 billion to $50 billion for electric vehicle chargers and other customer-side infrastructure, the

report, Getting to 20 Million EVs by 2030: Opportunities for the Electricity Industry in Preparing for an EV Future, says.

“While EVs and chargers are becoming more common in our everyday lives, the industry is really just seeing the tip of the iceberg when it comes to the impact that EVs will have on the grid,” Michael Hagerty, Brattle senior associate and study coauthor, said in a statement.

Among the challenges Brattle sees as electric vehicles become more prevalent is an increase in charging demand of between 60,000 gigawatt hours (GWh) and 95,000 GWh per year, including a 10 gigawatt (GW) to 20 GW rise in peak load from electric vehicle charging. Those increases in electricity use and load will require the addition of between 12 GW and 18 GW of renewable resources to maintain compliance with state mandates, such as renewable portfolio standards, that require minimum levels of renewable energy.

Deeper penetration of electric vehicles will also necessitate the expansion of charging infrastructure. So far, less than $2 billion has been approved for utilities to build charging infrastructure, but only 159 public charging stations are utility owned, representing about 0.6% of all public charging stations.

In all, the country will need about 1.25 million public chargers to fuel 20 million electric vehicles by 2030, representing a 20-fold increase in Level 2 chargers, a fivefold increase in direct current (DC) fast chargers, as well as 6 million to 10 million of residential Level 2 chargers installed at single family homes, Brattle estimates.

Meanwhile, Tesla has spent about $220 million building out its Supercharger network of over 800 stations. ChargePoint network has 38,000 chargers and plans to add 2.5 million globally by 2025. And Electrify America is investing $2 billion in Zero Emission Vehicle infrastructure by 2027.

Electrify America recently announced the completion of the first charging network that would enable an electric vehicle to travel cross country.

One of the challenges system planners will face is finding reliable, regional forecasts for electric vehicles sales, the report says. Most forecasts provide “limited insight” into local adoption rates as they are based on “black-box” models that can be challenging to understand

According to Brattle’s analysis, states with zero emission vehicle mandates have 26% higher electric vehicles sales, a $1,000 increase in electric vehicle incentives increases sales by 7.5%, a $10/kWh decrease in battery prices leads to a 4% increase in sales, and for every 10 additional electric vehicle models introduced sales increase by 8%.

Brattle recommends that industry planners and policy makers should develop plans, or roadmaps, that include detailed electric vehicle adoption forecasts, craft policies that articulate societal benefits of electric vehicle adoption, and facilitate collaboration across the electric vehicles supply chain to reduce market barriers, such as targeting under-served markets that are not prioritized by private investment.

More specifically, Brattle says the tension between private and utility investment needs to be resolved. Regulators often try to balance the need to provide sufficient charging infrastructure with the desire to keep the market open to competitive suppliers.

The Brattle report says there should be a “Win-Win-Win” approach among utilities, regulators and the private sector that recognizes that private investment will lead to increased product demand and sales

and that increased electric vehicle utilization will lead to higher electricity sales and improved asset utilization for utilities.

Reviving the Economy Should Start With The US Power GridBy Gregory Wetstone And Rob Gramlich, Opinion Contributors — 06/19/20

Spurring economic growth during a global pandemic isn’t an easy task. But there is one clear way to drive new investment in America while also positioning the country for future global economic competitiveness and an effective climate response: an expanded and upgraded electricity transmission grid.

It’s no secret that America’s economy relies on low-cost, reliable power to run. Yet the American Society of Civil Engineers gives a D+ grade to the upkeep of our electricity system, noting that “without greater attention to aging equipment, capacity bottlenecks, and increased demand, as well as increasing storm and climate impacts, Americans will likely experience longer and more frequent power interruptions.” Once a global model, our transmission system is now outdated and balkanized. While China and European countries invest in modern new grid infrastructure, we rely on a grid that fails to fully deploy readily available advanced grid technologies.

Building a new transmission infrastructure would create a stronger, better networked and more efficient economy, much as the construction of the interstate highway system provided the backbone for over five decades of U.S. economic growth by better linking businesses, customers and supply chains. Reforming our nation’s transmission planning and cost allocation processes could enable more interregional lines to deliver power where it’s needed, and allow grid operators to more easily, effectively and affordably balance power supply. Such steps are critically important when we consider that the country’s cleanest, lowest-cost new power sources are often found in more remote areas. In fact, the 15 states between the Rockies and the Mississippi River account for 88 percent of the country’s wind potential and 56 percent of the country’s utility-scale solar potential but are home to only 30 percent of projected 2050 electricity demand.

It’s time for Congress, governors, and other elected and appointed leaders to embrace the need for a Macro Grid that delivers the affordable, pollution-free electricity consumers and businesses are demanding. An advanced Macro Grid will help us compete with Asian and European countries that have already built high-voltage long distance lines deploying 21st century grid technologies and will also enable the integration of higher levels of renewable power. As the costs of wind and solar energy continue to decline precipitously, a Macro Grid will ensure we are taking proper advantage of our nation’s world-class domestic renewable resources. Any serious infrastructure effort from Congress should enable major investment toward this end, which is as central to prosperity as our roads and water systems.

A Macro Grid would also help ensure a secure platform to grow the high-tech U.S. economy of tomorrow, enabling the grid to better respond to demand changes and unforeseen complications. Improving the resilience and security of our grid will become increasingly important in the years ahead, and the ability to transport low-cost power over long distances is critical to achieving the clean grid of the future.

The good news is that we can take significant steps toward the grid of the future while benefitting businesses and households today. In fact, we’ll be saving money. New and upgraded transmission lines deliver benefits that far exceed their cost by reducing power losses and congestion — and moving

lower-cost electricity to high-demand areas. For example, the Midwest grid operator found that a portfolio of nearly completed transmission lines will deliver up to $52.6 billion in net benefits over the next 20 to 40 years. Similarly, increased transmission development at the “seams" between regions could save consumers up to $47 billion a year and return more than $2.50 for every dollar invested, according to a recent federal study.

Those savings are possible because wind and solar energy are cost-competitive with natural gas and far cheaper than coal in most of the country. And renewable power costs continue to decline each year. Wind power is today 70 percent cheaper than a decade ago, while solar power costs have decreased 90 percent over the same period. Foregoing transmission investments is penny wise and pound foolish because spending a little on transmission allows access to low-cost generation, which is the much more expensive part of our electric bills. And, unlike fossil fuels, renewable power costs are fully predictable and not subject to the gyrations and price spikes of global energy markets.

In short, few inputs are more important than energy in determining the competitiveness of the American economy. By unlocking our lowest-cost domestic energy resources through an advanced Macro Grid, we can come out of this crisis well-positioned for a more secure, prosperous and vibrant future.

By 2029, Half of New US Wind Installations Will Be Offshore

Maxwel l Cohen  June 24, 2020

The United States offshore wind industry is set to ramp up from near zero today to as much as 25 gigawatts in 2029, according to new Wood Mackenzie research.That means offshore wind will capture almost half of the U.S. market for new wind power installations by the end of the decade — if the industry can avoid potential permitting and transmission capacity challenges.

On the other hand, if the market moves more slowly, the total build this decade will total just 15 gigawatts.

Today, more than 9 gigawatts of offshore wind projects are already contracted or soon to be approved in the U.S., and up to 6 gigawatts more will be solicited through 2022.

The U.S. offshore wind sector will effectively launch in 2023, when the 800-megawatt Vineyard Wind project comes online to supply Massachusetts customers, along with about 260 megawatts of smaller projects supplying New York, Maryland, and Maine.In 2024, offshore wind will comprise over a third of the year’s wind capacity installations in the U.S., increasing to close or even half of the wind build in each subsequent year to 2029.

In New England and New York, 80 percent of wind build through 2026 will be located offshore. The West Coast market will open gradually, since the commercialization of floating technology will be instrumental in expanding offshore wind’s regional reach to key 100 percent renewable portfolio standard markets such as California and Hawaii.

The U.S. offers an opportunity for experienced European players and oil and gas producers, as well as domestic utilities and supply chain providers.

The large-scale transmission hurdle

The U.S. federal government’s lease program currently supports about 20 to 30 gigawatts of offshore wind, depending on turbine density, and areas supporting as much as 45 gigawatts are under consideration for future leasing.State renewable portfolio standards, wind carve-outs and contracting call for the installation of 34 gigawatts of offshore wind capacity by 2035.However, permitting delays and political risk at both the state and federal level could hamper the sector’s long-term outlook if the transmission grid can’t adapt to higher offshore wind penetration.Building out high levels of offshore wind will be a challenge for the constrained U.S. onshore transmission grid. Some recent large-scale, renewable-energy-focused transmission projects have failed to move forward due to a combination of permit delays, NIMBYism and high network upgrade costs.

Despite the uncertainty, East Coast states have pushed ahead with solicitations and policy expansions, helping position the U.S. as an attractive emerging market for global players.

The role of the PTC and ITCOffshore wind’s rapid expansion in market share is partly due to the expiration of the federal Production Tax Credit. This will see onshore installations dropping from an estimated 14 GW in 2021 to a typical level of under 5 GW per year later in the decade.

The phasing-out of the federal Investment Tax Credit (ITC) adds some uncertainty to the offshore sector’s outlook as well. There are concerns that price declines, driven by technology and economies of scale, may not be sustainable.

The first few commercial-scale projects contracted in 2017 have prices in the $150 to $170 per megawatt-hour range (levelized 2019 dollars).

Vineyard Wind and Revolution Wind shocked with levelized 2019 prices in the $65 to $80/MWh range. This substantial drop made the technology viable as a route to decarbonizing the Northeast’s power grid and encouraged policymakers across the region to increase mandates.

These low prices are made possible by the latest in offshore wind turbine technology, as well as the continued availability of the ITC. It remains to be seen if technology improvements and economies of scale can outweigh the rise in required prices the phaseout will bring.

Max Cohen is the author of U.S. Offshore Wind Market Outlook, 2020-2029, a new report from Wood Mackenzie that shares analysis of expected U.S. offshore wind build-out and market evolution through 2029.

I-5 Clean Energy Corridor Needs Freight-Level EV Charging Every 50 Miles And

$850M, Utilities SayRod Walton, Clarion Energy Content Director 6.17.20

An ambitious build-out of electric charging infrastructure for freight carriers along the West Coast I-5 corridor will need a major buy-in from utilities, customers, transportation firms, state regulators and private partners.

And it should begin with a major deployment by 2025.

The near-term deployment on only the I-5 contains 27 sites spaced about 50 miles apart from California to Washington and could cost $90 million by 2025. The study estimates that electrification of all sites along I-5 plus nine key arterial corridors for both medium duty (like delivery trucks) and heavy duty through 2030 could cost $850 million.

The group advocating for the planned West Coast Clean Transit Corridor Initiative includes nine utilities from the region.

The Initiative revealed its goals last year and on Wednesday announced findings from a study into the needs of converting a large part of the industrial transportation fleet from fossil fuels to electricity in the coming decades. The group sees it not only as a cleaner energy and emissions issue but a health matter, as well.

“We believe reducing emissions from the transportation sector is important,” said Bill Boyce, manager of electric transportation at Sacramento Municipal Utility District (SMUD), one of the initiative key utility backers, adding that the vehicles produce a majority of air pollutants causing health issues.

The study’s final report proposes a phased approach to electrifying I-5 and its major connectors. The first part of that would be installing 27 charging stations at 50-mile intervals from the top of I-5 to the bottom in the next five years.

Those initial charging stations would be focused on medium freight vehicles such as delivery trucks. The capacity generally could be approximately 350-kW charging units, with stations ranging from 3.5 MW to 25.5 MW depending on size and number of “pumps” in the truck stop.

Later, 14 of those 27 charging sites would be expanded to accommodate electric “big rigs” by 2030.

“This requires a firm commitment by all three states to make major investments,” Katie Sloan, director of eMobility and Building Electrification at Southern California Edison (SCE), said during the press conference announcing the initiative study’s findings. She pointed out the long-term economic and environmental impact considering that “40 percent of the goods entering the U.S. come through the Ports of Los Angeles and Long Beach.”

In addition to SCE and SMUD, the other utilities supporting the I-5 Clean Energy Corridor and participating in Wednesday’s release include Pacific Power, Puget Sound Energy, Los Angeles Department of Water and Power, Northern California Power Agency, Pacific Gas & Electric, Portland

General Electric, Seattle City Light, San Diego Gas & Electric and the Southern California Public Power Authority.

With a cost that will almost certainly run into the billions should it become a reality, all of these utilities will likely need to contribute financially and perhaps involve customers through rate cases. The investment, some of the utility speakers added, will also need to come from state and local governments as well as the private sector.

On that last group, the I-5 Clean Energy study looked at location and siting of charging stations in relation to where fueling stations are currently spaced.

“They’re going to have to have partnerships with those sites,” said Eric Seilo, senior manager on the eMobility Strategy side at Southern California Edison. “This is where trucks are already going…and the infrastructure and space already exists. It’s a straight-forward transition to use those locations.”

The utility-led initiative is not a stage where it’s having formal discussions on cost sharing with the private side of the charging station equation, just yet.

The early response, SCE’s Seilo admitted, is mixed.

“They’re going to provide service for fueling, whether it’s electric or liquid,” he said. “The uncertainty and challenges are around the shifting dynamic…are electric trucks actually coming onto the road?”

Some inertia is already being overcome into the freight transportation sector. Three of California’s largest utilities are investing close to $750 million in new EV charging stations, including at the ports and industrial sectors.

Companies such as Amazon, meanwhile, are ordering tens of thousands of electric vans to move products.

Can your home battery help power the grid in times of need?Julia Roether: Energized by Edison Writer 6.17.20

How can homes with solar plus battery systems supply energy to the power grid when it needs it the most? With the help of Sunrun and customers, it is one of the questions Southern California Edison expects to answer by creating one of the country’s largest virtual power plants.

For the next year, up to 300 SCE and Sunrun Brightbox home energy system customers will be part of a network, or virtual power plant that can be called on to send clean energy back to the grid.

“California is leading the way to 100 percent clean energy for all. We’re excited to work with SCE to bring the benefits of Brightbox rechargeable solar batteries to more Californians through this

innovative partnership,” said Lynn Jurich, Sunrun co-founder and CEO.

The program will show how responsive the virtual power plant is in delivering energy to the grid and if it is delivering as expected. Having a dependable and consistent supply of energy is critical to creating a reliable and resilient grid.

For the next year, about 300 SCE and Sunrun Brightbox home energy system customers will be part of a virtual power plant that can send clean energy back to the grid.

When an event is called, the virtual power plant will use energy stored in the batteries for the grid. Some reserve power will remain in the battery for the customers’ use. Customers won’t notice any difference in how their system works and they will receive a $250 incentive at the end of the first year of operation.

Up to 80 calls for energy or energy events will take place throughout the year under six scenarios to better understand how the virtual power plant responds to different types of high-energy demands. While some high-energy demands are predictable, like those that take place almost every day at the same time, others are less so including unexpected weather conditions or emergencies.

“For California to meet its carbon neutrality goal by 2045, we estimate that 40 gigawatts of energy storage will need to be added to the grid, including 10 GW from hundreds of thousands of residential customers in the future,” said Jill Anderson, SCE senior vice president of Customer Service. “The clean energy from these home energy systems will benefit all of our customers.”

“FOR CALIFORNIA TO MEET ITS CARBON NEUTRALITY GOAL BY 2045, WE ESTIMATE THAT 40 GIGAWATTS OF ENERGY STORAGE WILL NEED TO BE ADDED TO THE GRID, INCLUDING 10 GW FROM HUNDREDS OF THOUSANDS OF RESIDENTIAL CUSTOMERS IN THE FUTURE. THE CLEAN ENERGY FROM THESE HOME ENERGY SYSTEMS WILL BENEFIT ALL OF OUR CUSTOMERS.”

Jill Anderson, SCE Senior Vice President

As fossil fuels are replaced with more carbon-free energy sources, like solar, battery storage plays an increasingly important role in maintaining a reliable grid since it can capture energy from the sun for use when it isn’t shining.

SCE’s Pathway 2045 outlines the need to integrate large amounts of utility scale and residential solar energy and energy storage, including 110 GW of solar and 40 GW of storage, into the grid to meet the states carbon neutrality goals.

That’s something more homeowners are interested in taking advantage of as they realize the benefits of clean energy and contributing to a clean energy future.

In April 2015, 116 SCE customers had solar plus energy storage systems. As of this past April, more than 7,900 customers have solar plus energy systems, 1,700 of those installations were in the first few months of the year.

EIA Forecasts 2020 Summer Electricity Demand to Be the Lowest Since 2009June 16, 2020 Paul Ciampoli

The U.S. Energy Information Administration (EIA) on June 10 said it expects U.S. electricity demand to total 998 billion kilowatt hours this summer, the lowest level of summer electricity consumption in the United States since 2009 and 5% less than last summer.

EIA expects electricity consumption to be lower this year largely as a result of efforts to reduce the spread of COVID-19.

Most of the expected decline in retail electricity sales occurs in the commercial and industrial sectors, which EIA forecasts to be 12% and 9% less, respectively, than during summer 2019. EIA said it expects residential electricity sales to grow by 3% this summer because more people are working from home and following social distancing practices.

In its “Today in Energy” report, EIA noted that normally, weather is one of the primary factors in determining electricity demand in the residential and commercial sectors.

The National Oceanic and Atmospheric Administration (NOAA) is projecting that U.S. cooling degree days for June, July, and August 2020 will be 1% lower than last summer.

“This summer, however, other factors are affecting electricity demand more than temperature,” EIA said. “Although state and local governments are relaxing stay-at-home orders, social distancing guidelines will likely result in Americans spending more time at home than usual this summer. In addition, many people that had worked in offices are now working from home, shifting electricity demand from the commercial sector to the residential sector.”

EIA noted that macroeconomic indicators are primary drivers in its forecasts for electricity consumption in the commercial and industrial sectors.

EIA’s short-term economic assumptions are based on a macroeconomic model from IHS Markit. This model projects non-farm employment will fall by 13% in 2020 and that the electricity-weighted industrial production index will contract by 12% in 2020, EIA said.