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MMWEC Uses DEED Grant To Develop Model To Undergrounding Cost-Benefits

July 28, 2022

by APPA News
July 28, 2022

The Massachusetts Municipal Wholesale Electric Company (MMWEC) has completed an in-depth study of the costs and benefits of the combined undergrounding electric and broadband internet lines in metropolitan areas with a grant from American Public Power Association’s Demonstration of Energy & Efficiency Developments (DEED) program.

MMWEC’s research team used the grant to build a model that optimizes construction of new utility corridors based on estimated cost and projected benefits, including enhanced reliability of electric service and access to broadband.

MMWEC’s researchers conducted a literature review to collect background information on electricity and broadband cost elements. They also collected data on undergrounding from public and commercial sources, including member utilities such as Shrewsbury Electric and Cable Operations and Concord’s public power utility, as well as the 2020 Underground Distribution Systems Reference Book (Bronze Book) from the Electric Power Research Institute and real estate data from Zillow that was used to assess aesthetic benefits from undergrounding in the form of increased property values.

The researchers analyzed the co-deployment of electric and broadband lines to develop data-driven cost and benefit models. “Our synthetic and disaggregated approach is readily deployable to other similar study areas and provides effective decision-making capabilities with limited amounts of data,” the MMWEC researchers said in their report.

MMWEC also took into consideration costs beyond the plainly financial, such as environmental damage caused by undergrounding from soil erosion and the disruption of ecologically sensitive habitats, as well as safety hazard for crews attempting to locate and repair failed equipment that has been undergrounded.

In their preliminary analysis, the MMWEC researchers found that the per-mile cost of underground installation is a major cost driver. The lifespan expected from underground cable is also a key cost factor, and they found that commonly assumed lifespan values may be significantly underestimated.

“Undergrounding electric and broadband cables is a viable approach for improving resilience,” MMWEC said in its final DEED report, noting, however, that there are many variables that have to be taken into consideration. “The massive investment costs [of undergrounding] require frameworks to analyze costs and benefits of competing strategies. Prior efforts have been too generalized and not accounted for broadband.

Thus, we present a framework that demonstrates a localized approach, using Shrewsbury, MA, as a case study.”

The researchers also found that aggressive conversion strategies, that is, those that convert to underground from overheard well before the lifespan of the overhead cable is reached, lead to greater aesthetic benefits, yield higher avoided economic losses, and, in the Shrewsbury case study, netted benefits totaling over half $500 million.

On the other hand, the researchers said, moderate conversion strategies exhibited benefits toward the end of the simulation. Optimal potential benefits can be achieved by undergrounding after the complete lifespan of the overhead lines has been reached, they said.

Looking forward, MMWEC said it plans to publish a paper with the detailed models and results of its research and another paper that will use a Monte Carlo simulation to analyze competing strategies. “This will also allow us to improve the generalizability of the model by incorporating additional factors critical to the estimation process,” such as segment length and type and the effect of a variety of conditions on the network’s sustainability and resilience, MMWEC said.

APPA Grant Helps Rock Hill, S.C., Integrate SCADA Fault Data

July 28, 2022

by Peter Maloney
APPA News
July 28, 2022

The City of Rock Hill in South Carolina has used a grant from American Public Power Association’s Demonstration of Energy & Efficiency Developments (DEED) program to help make fault detection more visible to repair crews and thereby improve reliability and reduce the duration of electrical outages for customers.

The project aimed to improve outage restoration times using smart overhead and underground fault indicators to communicate and integrate with the utility’s Supervisory Control and Data Acquisition (SCADA) and Outage Management (OMS) systems.

Fault data was already being sent to the SCADA system, but Rock Hill’s dispatchers and field technicians did not have a visual representation of the faults. The City applied for and was awarded a DEED grant to develop an OMS integration module.

The module allows the SCADA integration of the fault indicators to be displayed on the OMS map viewer whenever the server has indicated a fault has been detected by a device in the power network.

The project was designed to address two problems. First, service personnel would spend the first part of a call trying to pinpoint the location of a fault, draining financial resources and dragging out restoration times.

The second problem was a lack of real-time mapping of system strengths and weaknesses that could be used to identify areas where there are repeated outages and faults. That information can be used to target resources for improvement. Without real-time data, the utility said it is not able to make as many preventative decisions that benefit the long-term success of its electrical system.

Under the Fault & Load Indicator Technology Integration Project, Rock Hill was able to develop a software module through dataVoice, its OMS vendor, to integrate the information provided from smart fault indicators on the V3 outage map.

System status indicators was delivered from the SCADA to the OMS system with location and unique identifiers imported via GIS Publisher and is made available in the dataVoice’s mobile application.

The original termination date of the grant award was July 1, 2021, but the original fault indicators failed to perform to expectations, delaying progress for one year.

New technologies were explored, tested, and one was selected for implementation during the last two quarters of 2021. The equipment was installed during the first quarter of 2022.

A contract was signed with dataVoice in January 2022 and a kick-off meeting was held in March 2022 to initiate the software integration. During software testing, Rock Hill discovered malfunctions that dataVoice corrected, and the project was implemented and completed in June.

The completed project enables data from field sensors to communicate with a SCADA system which relays the information to an OMS system in a way that provides users with a visual representation of faults and outages.

The completed application reduces the complexity of information from the OMS by giving a direct visual representation of what kind of fault is occurring and the approximate location on the line based on the locations of the sensors. Rock Hill said.

The overall cost of the project was $154,401 of which the City of Rock Hill contributed about $129,066 and the DEED grant provided $25,335.

The project is applicable to all utilities as we share the same goal, to improve customer satisfaction by reducing the duration of outages by adapting the latest technology, Rock Hill said in its final DEED report.

As a next step, the City of Rock Hill said it plans to train its dispatchers and field technicians to use of the software. The utility also intends to budget a reoccurring $40,000 each year for the purchase of additional sets of smart overhead and underground smart fault sensors.

The City of Rock Hill offers electric, water, and wastewater utilities to its customers. It distributes electric power to approximately 32,000 residential and 8,000 commercial and industrial customers in the greater Rock Hill area.

FEMA Announces $2.3 Billion In Funding For Building Resilient Infrastructure and Communities Program

July 25, 2022

by Paul Ciampoli
APPA News Director
July 25, 2022

The Federal Emergency Management Agency (FEMA) recently announced $2.3 billion in funding for its Building Resilient Infrastructure and Communities program for Fiscal Year 2022 as part of a series of new executive actions unveiled by President Biden on July 20.

This funding will help communities increase resilience to heat waves, drought, wildfires, flood, hurricanes, and other hazards by preparing before disaster strikes, a White House fact sheet on the executive actions said.

In addition, the Department of Health and Human Services on July 20 issued guidance that for the first time expands how the Low Income Home Energy Assistance Program (LIHEAP) can promote the delivery of efficient air conditioning equipment, community cooling centers, and more.

In April, the White House released $385 million through LIHEAP to help families with their household energy costs, including summer cooling—part of a record $8 billion that the Administration has provided, boosted by the Infrastructure Investment and Jobs Act.

The White House also announced that the Department of the Interior proposed the first Wind Energy Areas in the Gulf of Mexico.

Biden previously directed the Secretary of the Interior to advance wind energy development in the waters off the mid- and southern Atlantic Coast and Florida’s Gulf Coast.

These actions follow the President’s launch of a new Federal-State Offshore Wind Implementation Partnership.

Biden made the announcements at a former coal-fired power plant in Brayton Point, Massachusetts that will host a cable manufacturing facility to support the offshore wind industry.

Capacity Constraints, Rolling Blackouts Not Seen As Near-Term Risk To Public Power: Fitch

July 20, 2022

by Paul Ciampoli
APPA News Director
July 20, 2022

Summer capacity constraints and rolling blackouts are not viewed as a near-term risk to public power and electric cooperative credit quality, Fitch Ratings said on July 15.

Fitch noted that its rated portfolio of public power issuers “typically own or contract for sufficient electric generation during the summer months to match or exceed their expected load demand, providing a financial hedge against market scarcity and volatile energy prices.”

However, general economic inflationary pressures “will necessitate rate increases in the sector, and customer tolerance for rate increases could be diminished by recurring rolling blackouts. To the extent utilities cannot pass through needed rate increases, utility financial profiles would likely weaken and could put pressure on credit quality over the longer term,” the rating agency said.

Supply shortages and the potential for rolling blackouts are likely to happen with more frequency across the U.S., Fitch said.

It said that public power and cooperative utilities tend to own or contract for generation supplies conservatively so that they have more than sufficient reserves to meet potential increases in demand “but there may be residual risk if temperatures cause demand to be substantially higher than anticipated.”

Costs of meeting demand in excess of power supply are typically modest in relation to utilities’ overall budgets, Fitch said, adding that most utilities have a power cost adjustment feature in their rate structure that recovers power costs above budget or reduces rates to customers if power costs are below budget throughout the year.

“As a result of the conservative planning in the sector, public power utilities are often net sellers during scarcity events, protecting the financial profile of utilities during shortage or volatile pricing periods,” Fitch said.

The Electric Reliability Council of Texas (ERCOT) earlier this month asked Texas residents and businesses to voluntarily conserve electricity as extreme hot weather created record power demand across Texas.

Fitch noted that the call for voluntary conservation was successful, reducing peak demand to approximately 78.3 gigawatts on two days, and no rolling blackouts occurred.

If rolling blackouts occur during a heat event in Texas this summer, they will likely last for a few hours, not days, as occurred in February 2021 during Winter Storm Uri, and would not impact long-term public power utility credit quality, the rating agency said.

In a recent episode of the American Public Power Association’s Public Power Now podcast, Woody Rickerson, Vice President of System Planning and Weatherization at ERCOT, detailed ongoing efforts by the grid operator to bolster reliability in the state.

Lawmakers Ask EPA To Detail Plans And Actions Tied To Reliability Risks

July 20, 2022

by Paul Ciampoli
APPA News Director
July 20, 2022

House Energy and Commerce Committee Republicans on July 11 sent a letter to Environmental Protection Agency (EPA) Administrator Michael Regan asking for the agency to respond to a series of questions related to EPA plans and actions regarding risks to electric reliability. The letter was signed by all 26 committee Republicans.

Following similar letters on risks to electric reliability sent to both the Federal Energy Regulatory Commission (FERC) and the Department of Energy (DOE), this letter questions many recent actions and proposals by EPA that may impact reliability. 

“In recent months, you announced a suite of EPA actions to target fossil fueled electric generating units, an “EGU Strategy,” to drive the Biden Administrations climate agenda,” the House members wrote in their letter.

This strategy includes many major new regulations now under development or proposed: the Interstate Transport Rule, Regional Haze, Risk and Technology Review for the Mercury Air Toxics Rule, a new set of greenhouse gas performance standards, effluent limitations, and a legacy coal combustion residue rule, “all of which directly affect power plants that are essential for reliable electric operations,” the letter said.

“We are concerned that EPA actions threaten to accelerate fossil generation retirements, at the very same time electric system operators report growing shortfalls in such baseload capacity will accelerate blackout risks,” the lawmakers told Regan.

“At a time of widespread economic and inflationary burdens, the last thing this nation needs are agency actions that press headlong into creating a major electricity crisis. Therefore, it is important that Congress have information from EPA to assess how the Agency’s actions are affecting electric grid reliability,” the letter said.

Among other things, Regan was asked to describe what specific actions “you are taking or are prepared to take to address energy or electricity emergencies this summer in the bulk power system.”

In addition, the lawmakers want the EPA to list all waivers or other emergency actions being considered or that have been taken over the past two years in connection with electricity reliability.

They also asked for a list of all regulatory actions “you are considering or have taken over the past two years to alleviate electricity reliability risks.”

The letter also asks Regan to detail the agency’s interactions with the DOE, FERC, grid operators and states.

Regan was asked to reply to the questions by July 26, 2022.

APPA Seeks Nominations for Three Openings on RP3 Review Panel

June 22, 2022

APPA News
June 22, 2022

The American Public Power Association (APPA) is accepting nominations now through Tuesday, July 5, 2022 for an open position on the Reliable Public Power Provider (RP3) Program Review Panel. 

APPA’s RP3 program is based on industry-recognized leading practices in four important disciplines:

A RP3 designation is a sign of a utility’s dedication to operating an efficient, safe, and reliable distribution system. Being recognized by the RP3 program demonstrates to community leaders, governing board members, suppliers, and service providers a utility’s commitment to its employees, customers, and community. Currently 275 of the nation’s more than 2,000 public power utilities hold a RP3 designation. 

Each member of the Panel can serve for up to three consecutive two-year terms (for a total of six years), and is expected to attend three meetings per year, one in the spring and two in the fall. The appointed member’s first term will begin immediately and expire after two years in 2024 (at the Business meeting of that year). Please find the position requirements below:

More information on the RP3 program is available on the RP3 website. To nominate someone, please click here to download the nomination form: 

The completed nomination form and any supplementary materials should be emailed to RP3@PublicPower.org. If you have questions, contact RP3 Staff at RP3@PublicPower.org or 202-467-2931.

FERC Aims To Boost Grid Reliability Against Extreme Weather Conditions

June 20, 2022

by Paul Ciampoli
APPA News Director
June 20, 2022

The Federal Energy Regulatory Commission (FERC) on June 16 launched two rulemakings aimed at improving the reliability of the bulk power system against the threats of extreme weather.  

FERC noted that these are the first proposed rulemakings stemming from a climate change and extreme weather proceeding that the Commission initiated in June 2021.

Commissioners voted on the Notice of Proposed Rulemakings (NOPRs) at FERC’s monthly meeting.

NOPR on Transmission System Planning Performance Requirements For Extreme Weather

In one of the NOPRs (Docket No. RM22-10), FERC proposes to direct the North American Electric Reliability Corporation (NERC) to develop and submit for Commission approval modifications to Reliability Standard TPL-001-5.1 (Transmission System Planning Performance Requirements). The modifications will address transmission system planning for extreme heat or cold weather events that impact the reliable operation of the bulk power system.

FERC staff noted that this proposed rule focuses on Reliability Standard TPL-001 because this standard establishes transmission system planning performance requirements to ensure the reliable operation of the bulk power system over a broad spectrum of system conditions and following a wide range of probable contingencies, including extreme events based on operating experience. 

However, while TPL-001 references studies for “extreme events,” it does not specifically require performance analysis for extreme heat and cold weather conditions that affect wide geographical areas simultaneously over several days. 

In addition, FERC staff noted that while the standard requires responsible entities (i.e., planning coordinator and transmission planner) to evaluate possible actions to reduce the likelihood or mitigate the consequences of extreme events, these entities are not obligated to develop and implement corrective actions.

To address this reliability gap in bulk power system planning, the NOPR proposes to direct NERC to develop modifications to Reliability Standard TPL-001-5.1 to require responsible entities to:

In addition to extreme heat and cold weather events, the NOPR also seeks comment on whether drought should be included in the scope of Reliability Standard TPL-001 to be modeled in the future to improve system performance during these events.  

One-Time Reports On Extreme Weather Vulnerability Assessments

In the second NOPR (Docket Nos. RM22-16 and AD21-13), FERC proposes to direct transmission providers to submit one-time informational reports describing their current or planned policies and processes for conducting extreme weather vulnerability assessments and mitigating identified extreme weather risks. 

FERC staff noted that the NOPR builds on the record of FERC’s June 2021 Technical Conference on Climate Change, Extreme Weather, and Electric System Reliability. FERC staff said that during this conference there was widespread agreement that utilities and other industry participants should assess the vulnerabilities of their systems to these risks. 

However, the record to date does not indicate whether and to what extent transmission providers are conducting extreme weather vulnerability assessments, the methods used to conduct those assessments, and what is done with the information from those assessments, FERC staff said.

The proposed one-time reports would ensure the Commission can fulfill its statutory obligations with respect to system reliability and just and reasonable rates. 

FERC staff said the goal of this proceeding is to gather information, not to establish new requirements. Therefore, the NOPR does not require transmission providers to conduct extreme weather vulnerability assessments where they do not do so already, or to require transmission providers to change how they conduct or plan to do such assessments.  

The NOPR proposes to define an extreme weather vulnerability assessment as any analysis that identifies where and under what conditions jurisdictional transmission assets and operations are at risk from the impacts of extreme weather events, how those risks will manifest themselves, and what the consequences will be for transmission system operations. 

The NOPR also proposes to require transmission providers to submit one-time informational reports on how they: (1) establish a scope for their extreme weather vulnerability assessments, (2) develop inputs, (3) identify vulnerabilities and determine exposure to extreme weather hazards, (4) estimate the costs of impacts, and (5) develop mitigation measures to address extreme weather risks.

Commissioners Weigh In

“Increasingly frequent cold snaps, heat waves, drought and major storms continue to challenge the ability of our nation’s electric infrastructure to deliver reliable affordable energy to consumers,” FERC Chairman Richard Glick said in discussing the NOPRs. The actions “are necessary to ensure that we are prepared for the challenges ahead.”  

Commissioner Willie Phillips in his opening statement for the meeting said he agreed with the NOPR on transmission system planning performance requirements for extreme weather “to emphasize the critical importance of ensuring that the bulk power system is prepared for extreme weather events in both the near-term and long-term.” 

While the NOPR “has the potential to reduce the threat to the reliability of the electric system, I note that we must remain vigilant as much work remains to ensure reliable delivery of power to consumers during times of stress and to resolve resilience concerns on the transmission system,” he said.

“In my view, this NOPR is another step on the path to mitigating the long-term effects of extreme weather; however, I remain concerned about the grid’s near-term reliability, particularly during the upcoming summer and winter seasons,” he said.

Phillips also said that the regional nature of extreme weather “highlights the difficulties facing our industry in addressing highly variable risks. The challenges facing California are very different from the challenges facing Texas. I believe a minimum transfer capability requirement is needed, because enhanced transfer capability may be the best way to take advantage of the diversity of energy sources and the many ways in which we can support the grid.”

Commissioner Allison Clements offered a concurrence on the NOPR directing NERC to revise its transmission planning reliability standard.

She said that while the NOPR represents “an important step in tackling extreme weather’s myriad impacts on the transmission system, strong follow through from NERC will be required to ensure a reliability standard that addresses extreme weather reliability challenges in a comprehensive and cost-effective manner.”

Clements said that while the NOPR seeks comments on whether drought should be included along with extreme heat and cold weather events within the scope of Reliability Standard TPL-001-5.1, she believes “that what we already know about meteorological projections and drought’s anticipated impacts on the electricity system compel the development of drought benchmark events in applicable regions of the country.”

The question for her is not whether such events should be included, but how TPL-001-5.1 should cover the impact of drought induced reductions in supply on regions already experiencing unprecedented reductions in reservoir supply and increased wildfire risk.

Clements also said that it is important to note “that if we are to cost-effectively ensure system reliability as the frequency and intensity of extreme weather events continues to increase, further action is necessary to complement” the NOPR.

Commissioner James Danly, while concurring in both NOPRs, challenged the Commission’s focus on extreme weather.  In his concurrence to the NOPR directing NERC to revise Reliability Standard TPL-001-5.1, he argued that “even if one were to grant that certain parts of the United States were experiencing statistically unusual weather when compared to historical baselines, that has absolutely nothing to do with whether the markets and regulated utilities are procuring sufficient generation of the correct type to ensure resource adequacy and system reliability.”  According to Danly, weather is not the problem, “[t]he problem is federal and state policies which, by mandate or subsidy, spur the development of weather dependent generation resources at the expense of the dispatchable resources needed for system stability and resource adequacy.” 

Comments on both proposals are due 60 days after the date of publication in the Federal Register.

Lawmakers Highlight Supply Chain Challenges Facing Public Power In Letter To FEMA

June 20, 2022

by Paul Ciampoli
APPA News Director
June 20, 2022

A group of federal lawmakers from Florida on June 10 sent a letter to the Federal Emergency Management Agency (FEMA) in which they highlight “the dangerous supply chain shortages affecting Florida’s electric cooperatives and municipalities.”

The letter, which was sent to FEMA Administrator Deanne Criswell, said that labor shortages and competition from other industries for steel have made equipment procurement difficult.

“As a result, critical electric grid equipment delivery times have increased 20-fold in the past 2 years. Transformers, the most integral pieces in ensuring electricity to homes, took only 3 months to be delivered in 2018. Currently, delivery delays for transformers are averaging 52 to 75 months, and some manufacturers are not even taking orders,” the letter said.

“This is particularly concerning given that the 2022 Atlantic hurricane season is forecasted to produce hurricanes and tropical storms of above-average strength,” the lawmakers said.

“As the onset of the 2022 Atlantic hurricane season approaches, we urge FEMA to mitigate this issue before a severe hurricane or tropical storm devastates our Floridian communities.”

The letter noted that each year, Florida electric cooperatives and municipalities prepare for the upcoming hurricane season by stockpiling supplies. “When disasters occur, destroyed equipment needs to be replaced to ensure quick power restoration. The severe delay of critical parts has made this preparation nearly impossible, leaving many electric companies without reserves. It would take only one hurricane or severe tropical storm to cause devastating damage to our constituents, and with the absence of a stockpile, power restoration for these communities would take substantially longer than previous years.” 

Local electric utilities “play a critical role in the growth and development of the communities they serve. Unfortunately, these new supply chain issues adversely affect the growth and management of these communities.  Without proper equipment, local utilities must triage parts, which delays upgrades and ‘non-essential’ repairs,” the letter said.

The weakened systems “will make them more susceptible to damage when disaster occurs. FEMA must employ mitigation efforts with the local Florida electric community to ensure that transformers, bare wire, meters, and other electric grid equipment will be available ahead of the first disaster.”

New Resource Adequacy Modeling Tools Needed For The Evolving Grid, NRRI Says

June 14, 2022

by Peter Maloney
APPA News
June 14, 2022

Traditional resource adequacy tools are not sufficient to ensure reliability in a rapidly changing electric power system, according to a new report from the National Regulatory Research Institute (NRRI), the research arm of the National Association of Regulatory Utility Commissioners (NARUC).

Power grids are evolving rapidly from a system served by dispatchable resources to a system that relies on variable energy resources (VERs) and duration-limited storage, the report noted. Those changes are making many of the tools power system planners relied on “obsolete,” according to the report, Resource Adequacy Modeling for a High Renewable Future.

In the past, electric system planners only needed to worry about unusually high loads or high forced outages, the report said. “Now, they must worry about unusually high loads during periods of unusually low renewable output and limited storage duration” that, coupled with more extreme weather, can compound risks and require “a fundamental rethinking of planning for low probability, high impact events,” the report said.

The NRRI report, like other recent reports, highlighted that weather is emerging as a fundamental driver of power system conditions and will require changes in resource adequacy planning to account for increasing uncertainty on both the supply and demand side of the equation.

The North American Electric Reliability Corp.’s 2022 Summer Reliability Assessment identified an “elevated or high risk” of energy shortfalls this summer because of predicted above-normal temperatures and drought conditions.

And earlier this year a paper by NARUC, the National Association of State Energy Officials and Converge Strategies recommended new approaches to estimating the value of resiliency in the face of changing grid conditions and weather patterns.

Updating reliability planning for a “new energy paradigm” will require taking into account meteorology, variable renewable energy generation, forced outages, and energy limited storage, the report said.

The report’s authors argue in favor of using a Monte Carlo simulation that is capable of factoring in multiple inputs and uncertainties while maintaining historical correlations. For example, “traditional models used average or typical time profiles of load and renewables while focusing on generator outages as the primary source of uncertainty, greatly underestimating the risk of load shedding,” they said.

The report also noted that traditional models for resource planning often fail to include weather data, climate impacts, behind-the-meter resources, transmission, or sophisticated data on energy storage availability.

The authors included another example of the failure of traditional resource adequacy modelling. They ask, “At the high end of renewable penetration, how much storage would be required to cover Dunkelflaute, the ‘dark doldrums,’ that occur in the winter when wind ceases to blow for several days?”

To ensure that resource adequacy models can provide valid risk assessments, the report recommended they should simulate random variables as weather dependent; benchmark simulations against historic data; model generator outages as weather driven; scale simulations to match future expectations, and include climate effects in simulations.

California Renewable Energy Microgrid Comes Online

June 7, 2022

by Paul Ciampoli
APPA News Director
June 7, 2022

California’s first 100% renewable energy, front-of-the-meter, multi-customer microgrid is now fully operational. Located in Humboldt County, Calif., the microgrid provides energy resilience for a regional airport and U.S. Coast Guard Air Station.

This microgrid was developed through a first-of-its-kind partnership between the Schatz Energy Research Center at Cal Poly Humboldt, the Redwood Coast Energy Authority, Pacific Gas & Electric, the County of Humboldt, TRC, The Energy Authority, Tesla, Inc., and Schweitzer Engineering Labs.

Research and development was supported through a $5 million grant from California’s Electric Program Investment Charge (EPIC), a statewide program which invests in scientific and technological research to accelerate the transformation of the electricity sector to meet the state’s energy and climate goals, as well as by $6 million from the Redwood Coast Energy Authority, a joint powers agency that provides renewable energy to Humboldt County.

The Redwood Coast Airport Microgrid (RCAM) features a 2.2-megawatt solar photovoltaic array that is DC-coupled to a 2-megawatt (9 megawatt-hour) battery energy storage system, comprised of three Tesla Megapacks.

During standard blue-sky operations, RCAM generates renewable energy for the North Coast, and participates in the California Independent System Operator (CAISO) wholesale energy markets, including the day-ahead, real time, and ancillary services markets.

When a power outage occurs, the microgrid islands from the main grid and energizes the circuit that encompasses the airport, the adjacent Coast Guard Air Station, and several neighboring facilities. RCAM will provide seamless, ongoing electricity for all customers in the microgrid circuit during any local outages, Redwood Coast Energy Authority noted.

As the first microgrid in the CAISO market and the first renewable, front-of-the-meter microgrid system in the state, RCAM is building a replicable business model for renewable microgrid deployment, it added.

Additional details about the microgrid are available here.