GHG reduction goals in PJM states best met with an RTO-wide carbon price
November 2, 2020
by Peter Maloney
APPA News
November 2, 2020
The PJM Interconnection, the largest wholesale power market in the nation, could create “substantial opportunities for low cost decarbonization” by pursuing policies such as establishing a charge on carbon dioxide (CO2) emissions, consulting firm Energy and Environmental Economics (E3) said in a new report.
A CO2, or “carbon,” price that would apply across the board in PJM’s marketplace, which operates in 13 states and the District of Columbia, would be a better option than “continuing to rely on fragmented and restrictive clean energy policies and subsidies,” the report, Least Cost Carbon Reduction Policies in PJM, argued. The report was commissioned by the Electric Power Supply Association.
Several states within the footprint of the regional transmission operator (RTO) have set up a variety of policies aimed at encouraging renewable energy resources or curbing greenhouse gas emissions, creating a patchwork of regulations
RTO specific policies establishing a carbon price recently gained a glimmer of support when the Federal Energy Regulatory Commission (FERC) on Oct. 15 issued a proposed policy statement, affirming that it has jurisdiction over organized wholesale electric market rules that incorporate a state-determined CO2 price in those markets. FERC’s proposal encouraged operators of organized markets to consider the benefits of establishing a price on CO2.
“Our study of decarbonization policies in the PJM region finds that the most effective policies are ones that maximize market participants’ choices and leverage diversity across the PJM footprint,” Arne Olson, senior partner at E3, said in a statement.
From a near-term policy perspective, current policies aimed at reducing greenhouse gas emissions by subsidizing specific technologies or in-state resources, such as renewable portfolio standards, are inefficient and will become less and less cost-effective as policy targets reach higher levels, the E3 report found.
The report put the cost of existing state policies at more than $3 billion per year by 2030, or $50 per person each year across the 65 million customers served by the PJM system, for a 12% reduction in net GHG emissions.
Instead, E3 said its analysis shows that technology-neutral policies that enable the broadest array of potential solutions will generally be “the most cost-effective by incentivizing coal-to-gas switching, retaining the most competitive zero-emission nuclear generators, and developing the lowest-cost renewables that harness the diversity benefits of PJM’s geography.”
Some current state policies are “well intentioned” but may not have the intended effect, the report said, citing the Regional Greenhouse Gas Initiative (RGGI) as an example of how a partial carbon pricing approach can undercut emission reduction goals.
RGGI, which includes New England and four adjacent Eastern Seaboard states, has limited or negative impact on emissions because of leakage across state lines where compliance costs within RGGI incentivize a shift in energy production to less efficient resources outside of the RGGI region, the report said.
E3 recommended improvements to RGGI to mitigate leakage by expanding the program to encompass more PJM states. Only three PJM states, Delaware, Maryland and New Jersey, are currently in RGGI and such an expansion could drive “significantly deeper emissions reductions.”
E3 also found that that current resource specific mandates for offshore wind and battery storage in PJM “appear premature if immediate GHG reductions or cost savings are the intended goals” and may not be needed to achieve decarbonization goals until after 2030. Such technology-specific policies could cost over $1 billion per year compared with more readily available GHG savings opportunities. Instead, E3 said, targeting cheaper onshore resources would reduce emissions at “significantly lower cost over the next decade.”
Beyond 2030, efficient policy design and resource usage will become increasingly important if GHG reduction goals are going to be met at a reasonable cost, the report said.
While there are sufficient renewable resources to meet 2030 goals, the report identified the availability of land, potential transmission constraints and flexible generation capacity to backstop those resources as key to achieving long-term decarbonization goals.
E3 said there is a “deep pool of flexible gas capacity in PJM” that will allow it to integrate renewables at low cost, though the authors noted that gas plant operations will look significantly different in the future. They will see increased levels of cycling and more seasonal operation.
By 2050, E3 sees at least 35 gigawatts (GW) and likely 50 GW to 80 GW of existing gas capacity remaining valuable for grid reliability. The price of that reliability, though, will likely be more volatile energy prices in certain hours or higher capacity prices may be required to keep these plants online, the report said.
The report also noted that there are limitations to the ability of existing technologies to reach a 100% reduction in GHG emissions by 2050 at a reasonable cost whether those goals are met by renewable resources or clean energy resources.
Moving from an 80% target to a 100% target “would lead to exponential increases in costs,” the report said. Moving from 80% GHG reductions to 100% reductions in 2050 would drive additional costs of over $20 billion per year, moving from an 80% to a 100% renewable portfolio standard policy would increase costs by over $30 billion per year, E3 said.
In conclusion, E3 said the diversity of the PJM system’s loads and resources offers significant cost savings for meeting the collective climate goals of the region and recommended that policy makers should “see the regional marketplace as a critical tool for enabling long-term decarbonization. Efficient policy will be key to meeting climate goals at manageable costs.”
Report highlights benefits of public power utility in Boulder, Colo.
November 2, 2020
by Paul Ciampoli
APPA News Director
November 2, 2020
A local power financial analysis finds that lower renewable electricity prices, lower bond rates and increasing electrification of transportation and buildings means that citizens of Boulder, Colo., can expect that a locally owned utility would at least breakeven financially within five to 10 years of startup.
The analysis was released on Oct. 14 by a coalition called Empower Our Future, a group that opposes approval of a ballot initiative (City Initiative 2C) that is on the Nov. 3 ballot in Boulder. Boulder ballot initiative 2C is opposed by Empower Our Future in part based on the Local Power Financial Analysis, the coalition noted.
If passed, the ballot initiative calls for the city to enter into a new, 20-year franchise with Xcel Energy and end the city’s efforts to create a local, city-run electric utility.
The franchise agreement is a part of a comprehensive settlement agreement with Xcel Energy. The comprehensive settlement agreement would only go into effect if the franchise is approved by voters in the Nov. 3 election.
Empower Our Future “believes that we are experiencing a paradigm shift in world energy markets, largely driven by the imperative to stop and reverse climate change,” the coalition said in the financial analysis.
“Further, we believe that remaining flexible relative to options for sourcing 100% renewable electricity and open to new technologies and policies that make it possible to share electricity more equitably, reliably, and affordably, is critical,” the coalition said.
“We offer this analysis of one option-that of implementing a locally owned electric utility-to demonstrate that we have at least one viable option at our disposal today. All indications are that even more options will be available in the near future, which strengthens our conclusion that entering into a twenty-year franchise agreement with Xcel is both ill-conceived and poorly timed.”
Empower our Future said the report independently evaluates several alternative scenarios using the City of Boulder’s Financial Forecasting Tool, current data, and reasoned projections for the near future to independently determine the financial viability of a locally owned electric utility.
The combination of lower renewable electricity prices, lower bond rates, and increasing electrification of transportation and buildings “has resulted in a situation in which Boulder citizens can, with confidence, expect that a locally owned utility would at least breakeven financially within 5 to 10 years of startup, relative to continuing to source more carbon-intensive electricity from Xcel,” the analysis found.
In addition, the financial scenarios included in the analysis predict that enough savings and cash flow would be created to offer Boulder customers lower electric rates for 100% renewable electricity, and to make investments in the modernization of Boulder’s electric system for the benefit of all.
The analysis also found that the switch to 100% renewable electricity by 2030 would nearly eliminate the City of Boulder’s greenhouse gas emissions from electricity production in contrast to the 80% reduction mandated by the state of Colorado for Xcel.
The report shows that entering into a franchise agreement with Xcel Energy “at this critical time, with the currently proposed terms, is not in the best financial interest of Boulder or its citizens,” the coalition said.
“Rather, Boulder should stay the course, keep our options open, and take the lead in establishing an equitable, clean, modern electricity system for now and generations to come. In our estimation, Boulder can accelerate the electrification of our buildings and transportation systems and enjoy the full environmental benefits of 100% renewably-sourced electricity while capturing the financial benefits of a locally owned electric utility for the welfare of our community.”
East Bay Community Energy seeks offers for renewable energy, storage resources
October 30, 2020
by Paul Ciampoli
APPA News Director
October 30, 2020
California community choice aggregator East Bay Community Energy (EBCE) on Oct. 29 issued a request for offers to procure long-term renewable energy and storage resources.
The RFO also seeks to provide long-term clean energy hedges and resource adequacy and to contribute to EBCE’s Renewable Portfolio Standard (RPS) and Integrated Resource Plan (IRP) obligations under state laws.
EBCE is seeking offers for the sales of RPS-eligible energy for a contract term of 10, 15, or 20 years, with a preference for offers with terms less than 20 years.
EBCE will also evaluate offers for long-term clean energy hedges from large hydro resources and other eligible resources for a duration minimum of five years.
Eligible offers may be for: (1) as-Available RPS product; (2) As-available RPS Product plus energy storage; (3) indexed energy plus RPS attributes; (4) shaped RPS energy product; (5) stand-alone energy storage toll; or (6) shaped clean energy hedge.
Respondents may submit offers for as many or as few products as they wish, relative to their capabilities and expertise.
EBCE seeks energy and related products from both existing and new construction resources.
Projects must begin deliveries no later than December 31, 2024 to qualify for the RFO. EBCE has a preference for deliveries beginning in 2021 or 2022.
Offers are due by Dec. 1 and additional details on the RFO are available here.
The American Public Power Association has initiated a new category of membership for community choice aggregation programs.
Generation backed by utilities accounted for half of new capacity in 2018-19
October 30, 2020
by Peter Maloney
APPA News
October 30, 2020
Power generation projects financially backed by utility ownership or by a utility contract accounted for about half of the new capacity built in 2018 and 2019, according to a new report by the American Public Power Association.
Utility owned new generation also resulted in a greater diversity of resources than merchant generation. In 2018, about half of the utility sponsored new capacity was natural gas, one-fourth was solar, and one-fifth was wind, according to the report.
In 2019, those three technologies each accounted for about one-third of utility capacity additions.
In contrast, new merchant capacity additions, plants that receive revenue solely from wholesale power markets, consisted almost entirely of natural gas-fired generation — 92% in 2018 and 99% in 2019.
Merchant generation itself accounted for about 38% of the new capacity that began service in 2018 – a total of 11,800 megawatts (MW) – and 16% of the capacity that began service in 2019 or 3,700 MW.
“The capacity constructed or contracted by utilities is far more diverse than merchant generation capacity and includes hydropower and geothermal projects, which are not present in new merchant generation,” Elise Caplan, director of electric markets analysis at APPA and author of the report, said.
New merchant generation capacity has fluctuated over the past seven years, from a low of 2.4% in 2013, climbing to a peak of 29.1% in 2017 and then 37.9% in 2018 before settling back to 16.3% in 2019. That trend has not been “a positive development for resource diversity, environmental goals, and risks to consumers,” the report noted.
The downside of the expansion of merchant power plants includes concerns about fuel security as natural gas plants continue to dominate new generation. For example, ISO New England, which represented 30% of the new merchant natural gas generation last year, has said it has an “energy security problem” because it “relies most on gas delivered through its constrained pipeline system.”
Merchant generation also creates a pool of resources with a continued interest in propping up their earnings by administratively increasing energy and capacity prices, the report said, such as the Federal Energy Regulatory Commission’s (FERC) December 2019 order expanding the Minimum Offer Price Rule (MOPR) in the PJM Interconnection’s capacity market.
At the time, FERC said the administratively determined offer floor would “enable PJM’s capacity market to send price signals on which investors and consumers can rely to guide the orderly entry and exit of economically efficient capacity resources.”
Such administrative interventions “pose impediments to state and utility efforts to develop particular types of resources and increase costs to consumers,” the report said.
Overall, 31,200 MW of new capacity came online in 2018, exceeding the 18,750 MW of capacity that retired even though electricity consumption has been relatively flat. In 2019, about 22,700 MW of capacity came online, exceeding the 18,760 MW of capacity that retired.
The fact that the amount of new merchant generation in 2018 and 2019, 11,800 MW and 3,700 MW, respectively, came close to the amount by which new capacity exceeded the retirements – 11,800 MW in 2018 and 3,700 MW in 2019 – indicates that “new merchant generation could have been a contributing factor to the surplus of new capacity compared to retirements,” the report said.
The report also included data that show that public power utilities accounted for almost 20% of new capacity and 17% of all renewable energy and storage installations in 2018 and 11% of all capacity and 15% of renewables and storage in 2019.
Overall, the “data show that resource diversity, technology innovation, and emissions reductions can be best achieved by financial arrangements that consider utility, consumer and state policy goals rather than projects constructed to maximize earnings from wholesale markets,” the report said.
The report used the list of new generating units from the Energy Information Administration and combined it with information on financial arrangements behind the new capacity primarily from utility and developer websites and from news articles, as well as data from the Federal Energy Regulatory Commission and the American Wind Energy Association.
Austin Energy ADMS upgrade advances with COVID-19 safety protocols
October 29, 2020
by Peter Maloney
APPA News
October 29, 2020
Deploying an Advanced Distribution Management System (ADMS) is challenging in the best of times. Deploying an ADMS upgrade during COVID-19 only adds to the challenges.
Texas public power utility Austin Energy had “robust policies” in place to guard against the spread of COVID-19 before its ADMS upgrade, but for the in-person portion of the system operator training sessions related to the software upgrade, they decided to take “a lot of extra precautions,” Danny Ee, Austin Energy’s Director of System Operations and Advanced Grid Technologies, said.
“It was one of the most difficult decisions in my career to elect for a remote go-live during the pandemic,” Ee said. “However, we were determined to deliver the upgraded functionality despite the additional challenges and had the support of senior management and dedicated employees that were well prepared to make it a seamless upgrade.”
ADMS software monitors and optimizes a wide array of utility functions, including integration with outage maps, tie-ins with GIS mapping tools, notifications for utility field workers, distribution grid optimization, as well as providing analytical planning tools.
“ADMS is similar to Emergency Room triage for the healthcare industry,” Ee said. “It helps assess severity of issues, prioritize, and dispatch the appropriate staff to keep Austin’s power going. Without it, we would not have visibility to our grid and the ability to remotely control field equipment.”
Austin Energy deployed its first ADMS system in June 2014.
By 2020, it was time to upgrade to a newer version of the software. The upgrade, which went live in September, was the culmination of more than two years of preparation and was so extensive, “it was almost like installing a brand new system including all new servers and network infrastructure and extended the ADMS system user base by over 600 employees,” Ee said.
The ADMS Upgrade Project was focused on making a good thing better, Ee said. A good portion of the upgrade delivered improvements to usability, situational awareness, visualization and functionality that will improve monitoring, decision-making, optimization, reliability and security assessment of the electric grid and its components.
The ADMS Upgrade delivered expanded and enhanced functionality to existing system users and added applications for mobility/field crews and call centers. The new groups of users will have direct access to more information, which will help resolve customer outages more efficiently.
“The grid is changing, utilities are changing, and we have to be prepared,” Ee said. ADMS is an important tool in the transformation from a utility with one-way power flows to a smart utility that is continually responding to real time inputs and integrating multi-directional power flows, he said.
Austin Energy began implementing safety protocols related to COVID-19 early on. The City of Austin declared a local disaster in early March, allowing the utility to offer aid to customers having trouble paying their bills.
And, through a mix of new protocols and processes, Austin Energy has kept its employees safe and its operations running smoothly throughout the pandemic. About 1,400 of the utility’s 2,000 employees are now working from home.
Ee said the ADMS Upgrade deployment was supported completely remotely and was “intimidating” because the project teams were depending on on-site presence for several weeks leading up to the event, as well as on-site stabilization support after go live. Despite the change in plans due to COVID-19 restrictions, Ee said he is proud how the team worked through the implementation.
To keep employees safe through the pre-deployment system operator training, Ee and his team drew up an eight-page document of protocols. The training plan allows for only one trainer from the vendor, Mosaic, to be onsite. The trainer drove from Tulsa, Okla., to Austin, instead of flying, and quarantined for about one week before training began. The trainer also agreed to an initial COVID-19 test and restrict his movements to his hotel and Austin Energy facilities for the duration of the training.
The trainer and the employees participating in the training, in addition to following regular COVID-19 safety protocols, such as wearing face masks and washing hands frequently, also agreed to regular temperature checks.
Austin Energy marked off six-foot perimeters around the work stations that will be used during the training, provided daily cleaning and has limited the areas of the utility’s facilities that can be accessed by the trainer and trainees.
The utility is also providing boxed breakfasts and lunches and bottled water to the participants. The pre-deployment system operator training course lasted four days and was limited to three or four trainees within the same shift per course to prevent cross-contamination. Six weeks of courses were scheduled.
Post-deployment in-person field crew training is ongoing – it will last until December – and sessions that are underway currently are focused on situational awareness and efficiencies that are now available to the Field crews.
“ADMS will bring us to the future,” Ee said. He credits the utility’s robust safety and health protocols with winning the support of management and employees alike. “I am pleased to report that the employees that were offered in-person training are a dedicated bunch of individuals that chose to participate in training despite these uncertain times. I’m honored by the commitment that is continually demonstrated. The high buy-in is what made it successful.”
Authority overseeing new Calif. municipal utility executes agreement tied to microgrid
October 28, 2020
by Paul Ciampoli
APPA News Director
October 28, 2020
Concentric Power Inc. and Gonzales Electric Authority (GEA), which was established by the City of Gonzales, Calif., to oversee its new municipal electric utility, have executed an energy services agreement to deliver wholesale electric power via a community-scale microgrid.
The microgrid will initially have 35 megawatts of capacity to provide power to the Gonzales Agricultural Industrial Business Park, which houses processing facilities for fresh vegetable and wine producers. It will also meet the clean energy requirements of the city’s climate action plan.
Concentric Power said in an Oct. 7 news release that it designed the microgrid to integrate a mix of 14.5-MW-AC of solar energy, 10-MW/27.5 MWh of battery energy storage and 10-MW of flexible thermal generation, all of which will be managed by the company’s Advanced Microgrid Controller.
The system will allow the park to island from the wider energy grid, “ensuring that end users have reliable, high-quality power 24 hours a day, 365 days a year, even when facing planned or unplanned grid outages,” Concentric Power said.
The microgrid will also include a privately owned substation that will allow energy and capacity services to be sold into the California electricity grid.
The City of Gonzales, which is located California’s Salinas Valley, formed GEA to help attract and retain a strong agriculture and industrial base as well as to protect companies doing business there from unplanned power outages and poor power quality, Concentric Power noted.
The project will support continued economic development and job creation to further build the city’s tax base. With the Agricultural Industrial Park currently one-third occupied, the ESA allows for the power infrastructure to expand and meet growing demand.
The $70 million project will be funded primarily by Concentric Power, with supplemental funding from GEA and the Gonzales Municipal Electric Utility towards ownership of the distribution infrastructure.
Concentric Power will develop, design, build, operate and maintain the microgrid assets, including both generation and distribution. The distribution assets will be transferred to Gonzales Municipal Electric Utility.
The initial term of the energy services agreement is 30 years and the project is expected to break ground in mid-2021 and be ready for service in 2022.
Power sector keeps close eye on physical, cybersecurity in lead up to elections
October 28, 2020
by Paul Ciampoli
APPA News Director
October 28, 2020
The power sector is keeping a close watch on potential threats to physical security and cybersecurity from international and domestic actors in the lead up to next week’s elections in the U.S.
A number of electric utilities including public power utilities recently participated in an Electricity Subsector Coordinating Council call related briefing from the Federal Bureau of Investigation, two peer utilities, as well as the E-ISAC. The FBI has set up a command center to monitor potential civil unrest related to the elections.
Meanwhile, the North American Electric Reliability Corporation’s Electricity Information Sharing and Analysis Center (E-ISAC) on Oct. 27 released an All-Points Bulletin (APB) on Electricity Industry Preparedness for 2020 U.S. Election.
The E-ISAC routinely monitors all threats to the grid and provides alerts to industry as needed when new or continuing threats emerge.
In its bulletin, the E-ISAC noted that the power industry has undertaken weeks of preparation and analysis and collaboration with federal, state and local partners to ensure continuity of operations during the U.S. election cycle.
“At this time, the E-ISAC is not aware of any known specific or credible threats to the North American electric grid in conjunction with the election,” the E-ISAC said, noting that the bulletin is being shared to raise awareness and promote preparedness during the election.
Also, the E-ISAC has coordinated with the Elections Infrastructure-ISAC and the Department of Homeland Security’s Cybersecurity Infrastructure and Security Agency over the last two months to provide awareness and produced a 2020 Election Threat Awareness and Preparedness White Paper and Executive Summary, which offers an overview of the industry-specific threat and mitigation measures. Additionally, CISA has created a Rumor Control webpage, that will be constantly updated to help the general public understand what is fact and fiction with regards to misinformation efforts by foreign or domestic groups.
In terms of relevant resources provided by the American Public Power Association, APPA’s All-Hazards Guidebook helps public power utilities, joint action agencies, state associations, and other industry representatives in the development or continuous improvement of emergency preparedness programs and all-hazards planning efforts. As utilities prepare for potential civil unrest, the guidance in this resource may be helpful.
APPA encourages its members to coordinate with local, state and federal law enforcement, before any potential physical or cybersecurity incident, to ensure a rapid and coordinated response. For information on how to connect with your local FBI or CISA representatives, please email Cybersecurity@PublicPower.org.
Utility scale battery costs down about 70%, according to the EIA
October 27, 2020
by Peter Maloney
APPA News
October 27, 2020
The costs of utility scale battery storage in the United States fell about 70% between 2015 and 2018, according to data compiled by the Energy Information Administration (EIA), a part of the Department of Energy.
The average energy capacity cost of utility-scale battery storage went from $2,152 per kilowatt hour (kWh) in 2015 to $625/kWh in 2018, according to the EIA. The agency noted, however, that costs vary widely by region and by application.
Regionally, average utility scale battery costs between 2013 and 2018 ranged from $1,946/kWh in the PJM Interconnection to as low as $947/kWh in Hawaii. And in California, which had the most battery capacity of any state in 2019, average battery storage cost was $1,522/kWh.
In its analysis, the EIA grouped cost data into regions based on regional transmission organizations and independent system operators and aggregated entities to avoid disclosing confidential information.
Battery storage costs are usually published in terms of energy capacity, that is, cost per kilowatt hour or the total amount of energy that can be stored by a battery. But costs can also be expressed in terms of power capacity, or cost per kilowatt. Power capacity is the maximum amount of power a battery can provide at a given point in time. In power capacity cost terms, short-duration batteries cost less than long-duration batteries. In energy capacity cost terms, long-duration batteries are less expensive.
In PJM where most batteries are used for frequency regulation, there is an emphasis on shorter duration batteries rather than batteries capable of discharging over longer periods of time. That makes power capacity installed costs a better indicator of price for value in PJM, EIA said.
About two-thirds of battery storage capacity in California is used for frequency regulation. Batteries in the state also provide ancillary services, black start service and are used to help ease transmission congestion, EIA added.
At the end of 2018, the United States had 869 megawatts (MW) of installed battery power capacity and 1,236 megawatt hours (MWh) of battery energy capacity. In 2019, there was 152 MW of battery storage capacity installed in the United States and another 301 MW added through July 2020, according to EIA data.
The EIA expects battery storage to increase by more than 6,900 MW in the next few years with about 2,300 MW of that total being reported April and June. Large battery storage systems are increasingly being paired with renewable energy plants to increase grid reliability and resilience, EIA noted.
Just before the EIA published its data on Oct. 23, investment bank Lazard released its annual report on energy storage costs.
Lazard’s latest annual Levelized Cost of Storage Analysis (LCOS 6.0) shows that storage costs have declined across most use cases and technologies, particularly for shorter-duration applications, in part driven by evolving preferences in the industry regarding battery chemistry.
Calif. CCA Clean Power Alliance seeks renewable energy, storage proposals
October 27, 2020
by Paul Ciampoli
APPA News Director
October 27, 2020
California community choice aggregator Clean Power Alliance recently released a request for offers to expand its renewable energy portfolio.
Clean Power Alliance on Oct. 22 said it will solicit offers for long-term clean energy power purchase agreements, with an eye towards diversifying its renewable energy sources, adding long-duration storage, and securing structured products to deliver energy at specific key times.
The CCA said within the renewable energy contract category, it will be seeking renewable portfolio standard (RPS)-eligible generation and RPS plus storage projects that are 5 megawatts to 300 MW in size.
Within the standalone storage contract category, Clean Power Alliance will be seeking standalone storage projects that are 5 MW–100 MW in size.
For projects that include a storage component, eligible storage durations include conventional four-hour duration as well as longer storage duration (up to 12-hour duration).
Eligible projects must have a commercial operation date no later than the end of 2025. However, projects with commercial online dates of December 21, 2023 or sooner are preferred.
The CCA said that the projects solicited under the RFO will complement its recently expanded portfolio, which includes new solar plus storage, standalone storage, wind, and small hydroelectric projects approved by the CCA’s board over the past year.
Bid submissions are due by Nov. 20, 2020.
Clean Power Alliance serves approximately three million customers and one million customer accounts across 32 communities throughout Southern California.
Additional details about the RFO are available here.
The American Public Power Association has initiated a new category of membership for community choice aggregation programs.
DOE partnership to help remote and island communities improve electric service
October 26, 2020
by Peter Maloney
APPA News
October 26, 2020
The Department of Energy (DOE) has announced a partnership that aims to support remote and islanded communities seeking to transform their energy systems and lower their vulnerability to energy disruptions.
The Energy Transitions Initiative Partnership Program (ETIPP) draws together resources from several DOE offices and laboratories that will work with five community groups.
Together the partners will work with competitively selected communities to plan for, withstand, and recover from disruptions. In fall 2020, communities will be able to apply to participate in the multi-year program.
The ETIPP partners will identify and advance strategic, tailored technological solutions designed to bolster community resilience and reduce economic risk for the selected communities.
The targets of the program include 31 rural villages in Alaska prone to flooding and erosion, inland American Indian reservations in rural Northern California at risk of being islanded from the grid should a wildfire disable a single transmission line, year-round residents of 15 island communities off the coast of Maine, and communities in the U.S. Virgin Islands.
The DOE offices involved in the Energy Transitions Initiative (ETI) initiative are the Office of Strategic Programs, the Water Power Technologies Office, and the Solar Energy Technologies Office. The participating laboratories are the National Renewable Energy Laboratory (NREL), the Pacific Northwest National Laboratory, the Lawrence Berkeley National Laboratory, and the Sandia National Laboratories.
“The same technical assistance framework NREL developed and used in collaboration with ETI to advance successful energy transitions in Hawaii and the U.S. Virgin Islands can be tailored to ETIPP communities seeking to strengthen their resilience posture and mitigate their risks,” Elizabeth Doris, laboratory program manager for state, local, and tribal governments at NREL, said in a statement.
The community groups involved in the program are the Alaska Center for Energy and Power, the Coastal Studies Institute in North Carolina, the Hawaii Natural Energy Institute, the Island Institute in Maine, and the Renewable Energy Alaska Project.