Today the LPO announced a conditional commitment for a low-interest loan guarantee of up to $15 billion for PG&E’s Project Polaris, which was submitted to the feds for consideration in June 2023. If finalized, the loan guarantee will support a portfolio of projects to expand hydropower generation and battery storage, upgrade transmission capacity through reconductoring and grid-enhancing technologies, and enable virtual power plants throughout PG&E’s service area. The utility, which serves about 16 million customers in Northern and Central California, says the loan will help it meet forecasted load growth, increase electric reliability, and reduce costs for its rate base.

Today’s announcement is the second Energy Infrastructure Reinvestment (EIR) project under LPO’s flexible loan facility and disbursement approach tailored for regulated, investment-grade utilities. The first was for the restoration and repowering of the Holtec Palisades nuclear plant, slated to become the first shut-down nuke plant to be recommissioned in the United States.

Electric utility borrowers for EIR projects must demonstrate that the financial benefits received from the DOE loan guarantee will be passed on to the customers of that utility or the communities it serves. LPO borrowers must develop and implement a comprehensive Community Benefits Plan (CBP), which ensures borrowers meaningfully engage with community and labor stakeholders to create good-paying, high-quality jobs and improve the well-being of the local community and workers. In its CBP, PG&E plans to expand its outreach programs to boost engagement and deliver community benefits in partnership with key stakeholders, including local governments, Native American Tribes, community-based organizations, and low-and-middle-income customers. PG&E has committed to locating many projects in disadvantaged communities, as identified by the Climate and Economic Justice Screening Tool.

LPO’s holiday spending spree

It’s no secret that the LPO is trying to get as much money as possible out the door before the Trump Administration takes office on January 20. In September, Trump pledged to rescind any unspent funds under the Inflation Reduction Act (IRA), the bipartisan infrastructure law that has pumped billions of dollars into the domestic supply chain and clean energy projects from coast to coast.

“To further defeat inflation, my plan will terminate the Green New Deal, which I call the Green New Scam,” Trump promised.

While it’s understandably easier for the President-elect to reign in unspent funding, he will have a tougher time navigating conditional loan guarantees and virtually no chance of recalling funds that have been distributed. According to the Wall Street Journal, the LPO is expected to extend the loan to PG&E via multiple cash installments spread out over several years, and the funding cannot be withdrawn by subsequent administrations. The LPO has closed on more than a dozen loans so far, totaling more than $13 billion.

The LPO has been especially this month, announcing a flurry of new loan activity. Yesterday, it announced $9.63 billion for BlueOval SK to finance the construction of three electric vehicle (EV) battery plants in Tennessee and Kentucky. Last week, DOE closed on a $1.25 billion guarantee with EVgo to expand public fast-charging infrastructure nationwide. The week before that was highlighted by a $303.5 million loan guarantee for Eos Energy Enterprises to support two Pennsylvania-based manufacturing facilities developing long-duration batteries. DOE also inked a conditional commitment of up to $7.54 billion with StarPlus Energy, a joint venture between automaker Stellantis and South Korean battery maker Samsung SDI, that will finance two lithium-ion battery cell and module factories in Indiana. According to an analysis by TechCrunch, automakers and battery manufacturers have attracted more than $112 billion via the IRA to build out domestic facilities.

How much more can DOE’s LPO spend?

The LPO has been granted the authority to distribute hundreds of billions of dollars to innovative clean energy and advanced manufacturing projects.

Through September 2024, the office reported financing nearly $44 billion worth to date. As of the EVgo announcement referenced above, that total was closer to $55 billion. Tacking on the billions for BlueOval SK’s battery plants and the PG&E guarantee brings LPO’s total near $90 billion. And there’s more to come.

Through November 2024, DOE’s LPO reports more than 200 active applications accounting for more than $324 billion in requested funding.

As of the start of this month, DOE estimated it had around $397 billion left to play around with, including more than $244 billion for Title 17 Energy Infrastructure Reinvestments, which PG&E just dipped into.

Cause for concern?

Electric utilities are rightfully concerned with the survivability of the LPO once Trump returns to the White House. Entire programs went dormant during his first presidency, and Trump will have the support of a Republican-majority House and Senate this time around.

Earlier this month, Duke Energy Carolinas and Duke Energy Progress paused their consideration of utilizing DOE loans, recognizing the money may not be there under Trump 2.0. According to a recent filing, Duke was about to hire a consultant to review EIR opportunities, but will now wait for the dust to settle.

“It is in the best interest of customers to pause any further efforts or expenditures until February, following the appointment of the new administration to gain clarity on the future of the EIR Program,” Duke Energy said.

PG&E is curious to see how it shakes out too.

“I think the number one thing that we’re interested in learning more about is the approach to the DOE loans,” detailed Shawn Adderly, director of PG&E’s Transmission Performance Center in a recent webinar on POWERGRID.

Adderly notes the application language is currently tied to renewable projects coming online, and he wonders whether the incoming Trump Administration will reframe consideration around something like predictability or grid security.

“We do need to upgrade our infrastructure,” Adderly admitted, referencing transformers operating past their expected lifespan and aging transmission lies. “I’m really hopeful, especially with the incoming administration campaigning on removing some of the bureaucracies, that they would encourage the permitting reforms to continue and to streamline the processes of regional planning and actions siting.”

“The biggest concern is just where the DOE loans land,” he reiterated.

Originally published in Renewable Energy World.

The effort to keep Diablo Canyon running was backed by Gov. Gavin Newsom but opposed by some environmental groups. Newsom has cited the need to shore up the state’s electric reliability and prevent rolling blackouts.

In 2016, California legislators decided to shut down the power plant – a decision that it reversed last year. The current operating licenses for Units 1 and 2 would otherwise expire in 2024 and 2025, respectively.

In Sept. of 2022, California legislators and Newsom pushed to keep Diablo Canyon open and signed Senate Bill No. 846 into law, which directed PG&E to pursue the extended operations of the massive energy facility, located near Avila Beach in San Luis Obispo County, to 2030.

However, Newsom has no direct authority over the operating license for the Diablo Canyon Power Plant. The vote opened the way for Pacific Gas & Electric to begin a two-pronged effort to seek a longer run for the plant beyond a scheduled closing by 2025, but uncertainties remain and it does not guarantee that will happen.

DCPP is California’s largest power plant and producer of clean energy. It generates 2,200 MW of baseline electricity, providing approximately 17% of the state’s zero-carbon electricity supply and 8.6% of the state’s total electricity supply. California wants to produce all of its electricity from clean sources by 2045, but has faced challenges with that transition, such as rolling blackouts during a summer heatwave in 2020.

In compliance with federal regulations, PG&E’s license renewal application includes general, environmental, and technical information about DCPP. Once the NRC determines whether the application is sufficient for its review, a multi-year evaluation process will begin, which includes opportunities for public feedback and involvement. Under federal regulation, DCPP will continue to operate until the NRC has taken final action on PG&E’s application.

LOS ANGELES (AP) — An environmental group on April 11 sued to block Pacific Gas & Electric from seeking to extend the federal operating licenses for California’s last nuclear power plant.

A complaint filed in San Francisco Superior Court by Friends of the Earth asks the court to prohibit the utility from sidestepping its 2016 agreement with environmentalists and plant workers to close the twin-domed Diablo Canyon Nuclear Power Plant by 2025.

The possibility of a longer operating run emerged last year after Democratic Gov. Gavin Newsom and the Legislature opened the way for PG&E to seek an extended lifespan for the twin reactors. The company intends to apply to the Nuclear Regulatory Commission by the end of the year to extend operations by as much as two decades.

The operating license for the Unit 1 reactor expires next year and the Unit 2 license expires in 2025.
Hallie Templeton, legal director for Friends of the Earth, said in a statement that “PG&E has been acting as if our contract has disappeared.”

California is the birthplace of the modern environmental movement that for decades has had a fraught relationship with nuclear power, which doesn’t produce carbon pollution like fossil fuels but leaves behind waste that can remain dangerously radioactive for centuries. The Newsom administration is pushing to expand solar power and other clean energy, as the state aims to cut emissions by 40% below 1990 levels by 2030.

Newsom’s decision last year to support a longer operating run for Diablo Canyon shocked environmentalists and anti-nuclear advocates because he had once been a leading voice for closing the plant.

PG&E said in a statement it had not yet seen the lawsuit, but that as a regulated utility will follow state policy.

The lawsuit marks the latest development in a long-running fight over the operation and safety of the decades-old plant, which Newsom says should keep running beyond 2025 to ward off possible blackouts as California transitions to solar and other renewable energy sources.

Diablo Canyon produces 9% of the state’s electricity.

At issue in the lawsuit is how a complex 2016 agreement figures in the Legislature’s decision reverse itself and to try and keep the reactors running. At the time the agreement to wind down Diablo Canyon was made, California utility regulators, the Legislature and then-Democratic Gov. Jerry Brown agreed to the closure.

The complaint describes the 2016 agreement as a “contract,” and asks the court to find it binding. It also asks for an order prohibiting PG&E from violating the contract.

“PG&E acts as if it has no remaining contractual obligations,” the complaint said, while asserting that the utility still has a responsibility to retire the nuclear power plant on schedule.

It’s not clear if the reactors will continue operating beyond the expiration of their 2024 and 2025 licenses — and if so, for how long — since many regulatory milestones and unanswered questions remain. Last year, PG&E CEO Patricia “Patti” Poppe warned that the “permitting and relicensing of the facility is complex and so there’s a lot of hurdles to be overcome.”

For example, it’s not yet publicly known what it will cost to update the plant for a longer run given that the company was preparing to close it for years. The state could consider backing out if capital costs climb over $1.4 billion and a string of state agencies also has to review extending the plant’s lifespan.

Construction at Diablo Canyon began in the 1960s. Critics say potential shaking from nearby earthquake faults not recognized when the design was approved could damage equipment and release radiation.

One fault was not discovered until 2008. PG&E has long said the plant is safe, an assessment the NRC has supported.

The U.S. nuclear industry has been through a tough stretch, with reactors retiring and its share of energy production slipping since 2012. But many industry leaders see a renaissance on the horizon, as climate change has brought attention to carbon-free power.

The Biden administration last year launched a $6 billion effort to rescue nuclear power plants at risk of closing, citing the need for nuclear energy as a carbon-free power source that helps to combat climate change.

The lawsuit also named labor groups from the plant that were involved in the 2016 agreement as defendants, including the Coalition Of California Utility Employees.

Storage developer Energy Vault and utility Pacific Gas and Electric Company (PG&E) have proposed a partnership to deploy and operate a grid-scale battery plus green hydrogen long-duration energy storage system (BH-ESS).

The BH-ESS would power the downtown and surrounding area of Calistoga, a city in Northern California, for a minimum of 48 hours during planned outages and shutoffs due to high wildfire risk. The system would provide a minimum of 293 MWh of dispatchable energy. Capacity could eventually be expanded to 700 MWh, which would allow it to operate for longer without refueling.

The project is still pending regulatory approval. PG&E submitted the project contract for review to the California Public Utilities Commission (CPUC) on Dec. 30, with a request for a final approval by May 15.

If approved, construction could begin in the fourth quarter, with commercial operation expected by the end of second quarter of 2024. Energy Vault called the project a “first-of-its-kind” and the largest utility-scale green hydrogen project in the U.S.

The storage system will be owned, operated and maintained by Energy Vault while providing dispatchable power under a 10+ year agreement with California’s largest utility.

Energy Vault’s BH-ESS would replace the diesel generators used in PG&E’s Calistoga microgrid during grid outages. The system would integrate a short duration battery system, for grid forming and black start capabilities, with a long duration fuel cell plus green liquid hydrogen storage system. The fuel cell would be powered by electrolytic hydrogen from renewable energy sources.

PG&E would use and upgrade its existing distribution infrastructure to establish the microgrid. The entire system would be developed on less than one acre of land and is expected to serve as a model for Energy Vault’s future utility-scale hybrid storage system deployments.

A June 2020 CPUC Decision required large electric investor-owned utilities to accelerate deployment of microgrids and resiliency projects to minimize the impacts of power outages. In 2021, CPUC directed PG&E to implement a microgrid program to support the resiliency of local governments.

LOS ANGELES (AP) — California legislators and Gov. Gavin Newsom’s office are discussing a possible compromise over the future of the state’s last operating nuclear power plant that could allow operator Pacific Gas & Electric to seek federal funds for a longer lifespan for the reactors.

The tentative proposal would amount to a legislative placeholder, keeping the idea of an extended run for the Diablo Canyon Nuclear Power Plant in play while giving the Legislature more time to consider earthquake safety, delayed maintenance and other issues at the site, located midway between Los Angeles and San Francisco.

The plan surfaced amid the chaotic, final days of the Legislature’s two-year session, which ends at midnight Aug. 31.

On Aug. 12, the Democratic governor proposed extending the plant’s operating run by five to 10 years beyond its scheduled closing by 2025, which he said was necessary to maintain reliable power supplies in the climate change era.

But legislators have complained about being bull rushed at the last minute with a vastly complex plan, which would have to be in print as a bill by late Sunday to be considered in this session.

At a state Senate Energy Committee meeting Thursday, Sen. John Laird, a Santa Cruz Democrat whose district includes the plant, raised the possibility of the Legislature doing what is “absolutely necessary” to allow investor-owned PG&E to seek the federal funds, while putting off other, more contentious questions tied to the future of the reactors until next year when the Legislature returns.

The Biden administration has established a $6 billion program to rescue nuclear plants at risk of closing, but to apply by a Sept. 6 deadline, Diablo Canyon needs state legislation to show it has a pathway to continue operations beyond its planned shutdown.

At the hearing, a top Newsom administration official, Ana Matosantos, agreed that Laird’s proposal was a possibility to allow PG&E to seek the funds, among other options that could be considered. The state expects to know by January if the reactors would qualify for a share of the funding, which some critics have doubted.

“There is active conversation, and there will be bill language circulating at some point” on a possible compromise, Laird said in an interview after the hearing. With negotiations continuing, it wasn’t immediately clear what the final proposal would look like.

Newsom’s late-hour plan that included a $1.4 billion forgivable loan for PG&E also has seen resistance from other Democratic legislators, who have proposed an alternative that would speed up the development of solar and other renewable power sources but require the nuclear plant to close as scheduled.

Newsom’s proposal would attempt to unspool a complex 2016 agreement among environmentalists, plant worker unions and the utility to close the decades-old plant by 2025. The joint decision also was endorsed by California utility regulators, the Legislature and then-Democratic Gov. Jerry Brown.

In doing so, he’s restarted a long-running debate over seismic safety at the site, which has several earthquake faults in the vicinity, with one running 650 yards (594 meters) from the reactors.

Environmental groups depicted the move as a “dangerous” betrayal of the 2016 pact. Plant workers and pro-nuclear activists have supported an extended run for the plant, citing the need for its carbon-free power amid a warming climate.

There is little time to work out a compromise. PG&E CEO Patricia “Patti” Poppe told investors in a call last month that state legislation would have to be signed by Newsom by September to open the way for the utility to reverse course.

In an appearance in Los Angeles this week, Newsom expressed confidence his proposal would be approved.

“I’m confident we’ll land this,” he said.

PG&E also would have to obtain a new operating license from the Nuclear Regulatory Commission to run the plant beyond 2025. The utility is following two tracks — assessing the possibility of a longer run, while simultaneously continuing to plan for closing and dismantling the plant as scheduled.

PG&E Vice President Maureen Zawalick told the Diablo Canyon Decommissioning Engagement Panel this week that if the state enacts the needed legislation “we would take immediate actions” to seek an extended license, while applying for the federal funding.

Pacific Gas and Electric Co. (PG&E) is launching an end-to-end hydrogen study and demonstration facility. The effort is intended to examine the future potential of hydrogen as a zero-carbon fuel source for not only PG&E customers, but the broader natural gas industry.

The study, known as Hydrogen to Infinity (H2∞), would feature a large-scale project to blend hydrogen and natural gas in a stand-alone transmission pipeline system. PG&E and its partners would study different levels of hydrogen blends in a multi-feed, multi-directional natural gas pipeline system that is separate from PG&E’s current natural gas transmission system.

Partners of PG&E in this study include Northern California Power Agency (NCPA), Siemens Energy, the City of Lodi, GHD Inc., and the University of California at Riverside.

H2∞ would also allow the experimentation of hydrogen blends in a variety of end uses. NCPA’s Lodi Energy Center power plant is located adjacent to H2∞ and plans to use a hydrogen-natural gas blend for electric generation in a Siemens 5000F4 gas turbine.

H2∞ would use a new facility in Lodi to serve as a study laboratory incorporating production, pipeline transportation, storage, and combustion. In addition, PG&E could use the facility as the centerpiece for a potential Northern California hydrogen hub.

Many experts see joint use of natural gas infrastructure for hydrogen and natural gas as a win-win transition strategy. This would allow for a scale-up of production from renewables and from the electrolyzer industry by tapping into large, existing demand and its supply chain, specifically gas pipeline infrastructure. Transport and combustion of hydrogen and hydrogen-natural gas blends continues to be explored.

Major OEMs in the power generation industry like GE, Siemens and Mitsubishi Power have been focusing their efforts on hydrogen combustion in gas turbines, particularly for large-scale generation.

The industry has developed materials and systems to increase the concentration of hydrogen that can be combusted. According to the U.S. Department of Energy (DOE), these advances have allowed hydrogen to be fired at concentrations over 90% in simple-cycle turbines or aero-derivative machines, and at concentrations of up to 50% in large-frame combined-cycle turbines.

Large-frame turbines capable of firing hydrogen and natural gas blends of up to 30% hydrogen and aeroderivative turbines capable of firing over 90% hydrogen are commercially available today.

Inspectors with the U.S. Nuclear Regulatory Commission (NRC) failed to properly inspect Diablo Canyon Power Plant pipes before a cooling system leak shut down one of the plant’s two reactors for eight days in 2020.

The findings were released by the U.S. Office of Inspector General (OIG) on March 28.

In the last few years inspectors said they had reviewed multiple concerns about the NRC’s oversight of Diablo Canyon’s safety-related structures, systems, and components. Concerns included specific allegations that the NRC had inadequately inspected the plant’s auxiliary feedwater system (AFS) prior to the cooling system leak.

An AFS is a backup water supply that can be used to cool the reactor if normal feedwater is out of service.

According to the OIG’s findings, the NRC failed to identify AFW piping insulation in Diablo Canyon’s Unit 2 that had long been in a degraded condition. This degradation led to the leak which Pacific Gas & Electric (PG&E) employees found while working at the plant on July 23, 2020. PG&E owns and operates Diablo Canyon, the last operating nuclear plant in California.

The OIG found that at no time during the NRC’s January and April 2020 AFW system inspections, or during weekly plant status inspections, did the NRC report any findings regarding SSCs that exhibited defects--such as degraded insulation on the AFW system--that would impact function.

MORE: NRC to Address Inoperable Safety System at Diablo Canyon Nuclear Plant

The OIG findings also said the NRC had not inspected the area where the leak occurred, even though its inspection report indicated that inspectors had conducted a complete walkdown of the AFW system in April 2020.

The OIG report also said the five hours NRC staff spent directly inspecting AFW systems in both Diablo Canyon reactors was fewer than the 12 recommended in the applicable NRC inspection procedure for the complete April 2020 walkdown.

“Senior regional officials acknowledged that the inspection was inadequate,” federal inspectors said in their report.

Eight days after the Unit 2 shutdown, PG&E restarted the unit after inspecting 40 pipe sections and repairing piping in several locations to ensure pipe thickness met requirements. The NRC issued PG&E a notice of violation for “failure to appropriately screen relevant operating experience.” The commission the violation was based in part on the fact that the utility received information in 2009 and 2010 relating to corrosion of carbon steel piping under insulation, but did not identify the AFW as being susceptible to corrosion under insulation.

OIG Inspectors said PG&E remedied the AFW system failure and that the plant continues to operate safely.

The inspectors also said the NRC should ensure that its inspectors are trained to identify corrosion under insulation, that inspection procedures are adequate for walkdowns (especially with a single unit versus a multiple-unit plant), that NRC managers are involved in reviewing whether inspectors follow procedures, and that managers are appropriately involved in helping select systems and components for inspection.

The plant has two Westinghouse-designed 4-loop pressurized-water nuclear reactors. Unit 1 entered service in May 1985 and Unit 2 in March 1986.

As part of its congressionally mandated mission, the NRC regularly inspects commercial nuclear power plants. NRC inspections assess whether licensees are properly conducting operations and maintaining equipment to ensure safe operations.

In a statement sent to Clarion Energy, the NRC said it continues to have “full confidence” in its staff.

“We are reviewing the Inspector General’s report and will take appropriate action if needed," said Victor Dricks, NRC senior public affairs officer. “At no time was public safety endangered because of this incident.”

A spokesperson with PG&E said that “safety is and always will be our most important responsibility at PG&E and Diablo Canyon, and the plant has an excellent safe operating record.”

In 2018, the California Public Utilities Commission approved a settlement to shut down Diablo Canyon. The plant currently provides 8% of California's electricity production and 15% of its carbon-free electricity.

PG&E intends to begin active decommissioning of the plant in 2025 and to complete the project in one decade.

The Oregon utility shared plans Friday to reduce emissions by at least 80% by 2030, 90% by 2035, and to reach zero emissions by 2040. To reach the 2030 goal, PGE will eliminate coal from its portfolio and approximately 1,500 – 2,000 MW of clean and renewable resources and approximately 800 MW of non-emitting dispatchable capacity resources.

“We are taking action to reduce greenhouse gas emissions while maintaining an affordable, reliable energy future for everyone,” said Brett Sims, PGE Vice President of Strategy, Regulation and Energy Supply. “Working collaboratively with our stakeholders, we are advancing plans to add more renewables and non-emitting resources and partnering with our customers on building an equitable, two-way electric grid.”

PGE expects 25% of power needed on the hottest and coldest days to come from distributed energy resources like solar, battery storage, and electric vehicles by 2030. The utility anticipates adding four times as much distributed solar and storage than exists today for a total of 500 MW by the end of the decade.

A bill approved by Oregon lawmakers in June mandates nearly all carbon emissions be eliminated from the power grid by 2040.

As a refresher, a microgrid is mostly designed to deliver resiliency for its owners – be they utilities, large C&I companies, municipalities, universities, and communities. What defines a microgrid is its ability to island from the main grid to provide energy during an outage. As a California-based conference, public safety power shutoffs (PSPS events) figured prominently as drivers for microgrid adoption in the state.

In addition to resiliency, microgrids can also provide grid services during normal grid operation. These services include peak shaving, demand response and, once DERs are fully unlocked, other ancillary services like volt/var regulation, reactive power and frequency regulation, can also be provided by a microgrid. This potential additional economic adder is another driver of microgrid adoption.

The Projects

The conference was organized around projects with project developers and owners sitting on the panels and answering questions about their challenges and lessons learned building, owning and operating microgrids. Four sessions highlighted microgrids for businesses and utilities; microgrids for agriculture/food Industry; microgrids for education and campuses; and microgrids for government, communities and CCAs.

Among the many microgrids that attendees learned about were the following projects:

• Domaine Carneros Winery microgrid, developed by PowerFlex, an EDF Renewables company
• Liberty Utilities Sagehen Creek Field Station microgrid, developed by BoxPower
• A fully-islanded microgrid in Santa Cruz owned by Sandbar Solar
• A fully-islanded microgrid designed for Bluehouse Greenhouse
• City of San Diego’s eight microgrids, financed by Shell Energies
• City of Berkley’s microgrid upgrade project

You can read about the specifics of each one by clicking their links. All include renewable energy (mostly solar PV but some wind), energy storage (mostly lithium-ion batteries but some lithium ferro phosphate), and a diesel or natural gas genset. But the key is the microgrid controller which makes all of the pieces work together. After projects were presented, moderator Ken Horne turned to the audience for questions. Below are the top ten lessons learned from the owners, developers and technology suppliers to the projects.    

Top 10 Lessons Learned from Building Microgrids

1. Don’t have a pandemic (watch your supply chain). Unfortunately for Stacy Ellis, Capital Projects Manager at Domaine Carneros, Covid-19 struck at just the wrong time with their project beginning as stay-at-home orders were implemented, impacting restaurants and wineries first. Once the dust settled and the project was able to move forward again, supply chain disruptions meant that getting the needed components for the microgrid was another issue.

2. Understand it is a jigsaw puzzle and decide who you want to put it together. Microgrid developers say projects are like jigsaw puzzles that require careful consideration of how all of the parts and pieces go together. Savvy facilities managers may wish to assemble the puzzle themselves, as was the case for Sandbar Solar. The solar installation company decided to go with a fully-islanded microgrid because the PG&E interconnect for its new warehouse was going to take up to two years and cost $75,000. As a solar developer already, Sandbar CEO Scott Laskey knew he was up to the challenge of specifying equipment and microgrid controllers.

On the other hand, many microgrid owners aren’t interested in specifying their own equipment and should look for a full-service microgrid developer instead and pursue either the Energy-as-a-service (EaaS) model where they sign a PPA to offtake the energy or they finance the system via bonds, their own capital or through bank financing. All options are readily available but customers need to decide early on if they want to do that work themselves or let a developer put the jigsaw puzzle together for them.

3. Make sure your technology vendors can stand up to their warranties. It’s a hot industry and there are a lot of players providing energy storage, solar PV, controllers and other technologies. With equipment manufacturers offering 10-, 20-, even 25-year warranties, it’s important to make sure your provider actually plans to be around that long. That message is from Laskey who was stuck with technology from a company no longer in business. In addition, experts point out that financing a project is more difficult with young companies who don’t have much of a balance sheet to back them up.

4. Put your customers’ needs first. For Liberty Utilities, the decision was between hardening a transmission line that delivered energy to UC Berkeley’s Sagehen Creek Field Station at a cost of $3.5M or developing a microgrid around the station so it could island during the summer months. Either way, the work was needed for wildfire mitigation. When the price of the microgrid coming in near $800,000, the non-wires alternative microgrid was the way to go, said Lindsay Maruncic, Liberty’s Sr. Manager Renewable Energy Assets. The insurance that the utility is going to need to purchase to protect it against wildfire damage will already be increasing customer rates so anything Liberty could do to keep those rates lower for customers was important. Maruncic said the regulators were fully in favor of the microgrid once the costs were compared.

5. Weigh the costs and benefits of being grid-tied or not. While Sandbar Solar’s Laskey went with the microgrid because the utility interconnection was going to take too long, he says in terms of the environmental benefits of the system, he sometimes wishes he was grid-tied so he could turn some of the solar energy he produces over to the greater grid instead of having to curtail it. “By 10 AM in the summer, our batteries are full and our solar is being curtailed,” he said, adding that his company has considered adding excess mobile storage and becoming “the milkman of energy.”

6. Get your interconnection application started as early as possible! Laskey’s microgrid was one of two at the conference that are fully islanded only because the utility interconnection was going to take too long. The other project is for Bluehouse Greenhouse, an ag-tech company that will yield 30X more per acre than traditional farming methods, according to CEO Ari Kashani. The greenhouse is energy intensive and will require around 9 MW of energy capacity and the utility infrastructure required to deliver that energy isn’t in place yet and will take more than 2 years to interconnect, said Kashani. While Kashani said he fully intends to be grid-connected eventually, he plans to start islanded in order to get up and running more quickly. So the advice is whether or not you plan to do the work yourself, get your interconnection application filed with your local utility as soon as you can.

7. Understand how much resiliency is worth for you. John Larrea, director of government affairs for the California League of Food Producers, explains that for agricultural producers, the cost of resiliency is pretty simple to pin down. Once produce is picked, he said, the process requires about 6 hours of continuous production to get the food ready for market. The produce cannot sit and wait out a PSPS event, he explained, or it begins to transform and could become a health hazard, costing the growers hundreds of thousands of dollars. While it might be more difficult for a school or municipality to quantify the cost of an outage, it’s a good idea to try to put a number on it. Once an entity knows how much resiliency is worth, it’s pretty easy to compare the cost of building a microgrid to the cost of an outage.

8. Don’t be afraid of Big Oil. When Lindsey Hawes, Municipal Energy Program Manager for the City of San Diego brought a proposal from Shell New Energies to fund the city’s eight planned microgrids before the city council, the reaction she received was lukewarm at best. But the city, which relies on a bustling tourism industry, was in a tough financial spot. Tourism was down from Covid and there was no option to use capital funding, said Hawes. Shell’s EaaS 25-year contract would allow the city to achieve its sustainability goals, bring energy resiliency to its inhabitants and the per kWh cost of energy was going to be lower than what it is from the utility. The city had been awarded a grant for the project, but it would only cover a portion of the cost and Shell New Energies was willing to finance the remainder. It took a bit of convincing, but Hawes managed to get the project approved. According to Candice Yu, Shell New Energies Business Development Advisor, the project was exactly the profile that it is looking to invest in.

9. Get help identifying and applying financial solutions. When the University of California, Berkley campus decided to upgrade its microgrid, Sally McGarrahan, Associate Vice Chancellor, Facilities Capital Renewal Program, knew there were a lot of incentives, grants, tax credits and other financial opportunities available for projects like hers but she didn’t think she could identify and synthesize them all herself. That’s why the University issued an RFP this summer for a financial consultant to help find the right financial solution to fund the $70M project. McGarrahan said the financial advisor should be able to help her pin down the best way to finance the project.

10. Make the regulatory model match the state goals and Support the Microgrid Act. While the conference didn’t specially cover the regulatory woes experienced by microgrid developers, their frustration with the long and costly interconnection process came across loud and clear via audience questions, comments and many of the project examples. Utilities are simply taking too long and charging too much money for microgrid interconnects. Elisa Wood, Editor-in-chief of Microgrid Knowledge, producer of the conference surmised that an increasing number of projects deciding to go completely islanded to circumvent the utility might be the wake-up call utilities need to reform their processes. Others complained that a state like California with aggressive renewable targets ought to be doing more to make sure these renewable energy powered microgrids can easily, quickly and cheaply connect to the grid.

Erik Svanholm, VP, Non-wires alternatives with S&C offered sage advice on this topic.

“Regulators are people, too,” he said, adding “they do in fact have the community’s best interest at heart.” He suggested microgrid stakeholders attend the NARUC conferences to share their ideas about best practices. “They tend to be open to new ways of thinking about things,” he said.

In Hawaii, for example, utilities are no longer allowed to profit off of infrastructure upgrades but must instead meet performance requirements that are aligned with state decarbonization and energy reliability goals.  This is a model that should be examined for other jurisdictions, many speakers said.

Related: Hawaii Takes Historic First Step Toward Creating ‘Utility of the Future’ Now

Lastly, Congressman Jimmy Panetta of California presented on the bill he authored and introduced called “Making Imperiled Communities Resistant to Outages with Generation that is Resilient, Islandable, and Distributed” otherwise known as the Microgrid Act. The act, which was included in the human infrastructure bill currently making its way through Congress, would give a 30 percent tax credit to microgrid owners. The tax credit is fully refundable, which means that municipalities, universities, churches and schools, who may not have a tax burden, can still take advantage of the credit and receive it in the form of a direct payment.

Microgrid Knowledge’s annual conference will take place June 1-2, 2022 in Philadelphia

The Low-Carbon Resources Initiative (LCRI) is an international collaborative spanning the electric and gas sectors that aims to help advance global, economy-wide deep decarbonization. With 18 anchor sponsors, the LCRI leverages the collaborative research model employed by both companies, bringing industry stakeholders together to conduct clean energy R&D for society’s benefit. Seeded with $10 million from the EPRI collaborative, funding for the initiative is expected to be leveraged many times over its $100 million target through public and private collaboration.

Sponsors of the initiative include:

American Electric Power, Con Edison, Dominion Energy, Duke Energy, Exelon Corporation, Lincoln Electric System, Los Angeles Department of Water & Power, Missouri River Energy Services, Mitsubishi Hitachi Power Systems, Americas, National Fuel, New York Power Authority, Portland General Electric, PPL Corporation, Salt River Project, SoCalGas, Southern California Edison, Southern Company, and the Tennessee Valley Authority

The LCRI is targeting advancements in low-carbon electric generation technologies and low-carbon energy carriers, such as hydrogen, ammonia, synthetic fuels and biofuels. This worldwide collaborative will:

• Identify and accelerate fundamental development of promising technologies,
• Demonstrate and assess the performance of key technologies and processes, and
• Inform key stakeholders and the public about technology options and potential pathways to a low-carbon future.

EPRI President Arshad Mansoor, said, “Achieving ambitious targets will require technologies and processes beyond those widely available today. This global initiative will advance affordable pathways to economy-wide decarbonization.”

“This initiative advances the next-generation clean energy technologies that are critical to achieving net zero emissions within Dominion Energy and across the broader economy. Hydrogen is one of the most promising of these innovations because of its potential to decarbonize many sectors, including power generation, heating, transportation, shipping and manufacturing,” said Mark Webb, Chief Innovation Officer, Dominion Energy.

“This partnership will further efforts to initiate new highly-technical research projects that will address LADWP’s evolving needs and engage in new low-carbon channels for the generation, delivery and end use of electricity in ways that support reliability, sustainability and efficiency,” said Reiko Kerr, Senior Assistant General Manager, Power System Engineering, Planning, and Technical Services, LADWP

Learn more about the LCRI at www.LowCarbonLCRI.com.