DOE awards $9.4 mil grant to EPRI-led advanced hydrogen production project that includes NPPD
November 25, 2020
by Paul Ciampoli
APPA News Director
November 25, 2020
A team led by the Electric Power Research Institute (EPRI) has been awarded a $9.4 million grant from the U.S. Department of Energy to support research and development related to hydrogen production from fossil assets without carbon emissions.
The team includes Nebraska Public Power District (NPPD), Bechtel, Gas Technology Institute, Hamilton Maurer International, Inc., Nexant Energy and Chemicals Advisory, and Wärtsilä North America, Inc.
The award is part of a DOE Initiative “to advance innovative power plant concepts that are capable of flexible, net-zero operations while producing hydrogen to support economy-wide decarbonization goals,” EPRI noted in a Nov. 23 news release.
The project will investigate design options for hydrogen production in a hybrid coal and biomass power plant. The integrated design study will assess multiple gasification systems that utilize the water-gas shift, a process that converts carbon monoxide and steam to hydrogen and carbon dioxide.
The system will be paired with pre-combustion carbon dioxide capture and pressure-swing adsorption, which produces high-quality hydrogen and a synfuel capable of generating flexible power using an engine or gas turbine, EPRI said.
The design study is a stepping stone to a future demonstration plant that will be strategically located at NPPD Gerald Gentleman generating station. NPPD is a sponsor of the Low-Carbon Resources Initiative, jointly led by EPRI and the Gas Technology Institute.
John Swanson, Director of Generation Strategies and Research at NPPD, noted that Nebraska is an area where opportunities for enhanced oil recovery and sequestration are being investigated for carbon dioxide storage, “and where the need for clean power and hydrogen is increasingly important to support low-carbon and long-term storage targets.”
The primary biomass to be used in the demonstration project is corn stover — stalks, leaves and cobs left over after a corn harvest. Corn stover, which is abundant in Nebraska, will be mixed with Powder River Basin coal, necessitating a flexible gasifier that can use this fuel source, among others, including waste.
The study will begin in early 2021, which complements technology assessments underway as part of the Low-Carbon Resources Initiative, EPRI said.
EPRI conducts research and development relating to the generation, delivery, and use of electricity.
Texas public power cities to buy energy from 1,310-MW solar facility
November 25, 2020
by Paul Ciampoli
APPA News Director
November 25, 2020
Three public power cities in Texas – Bryan, Denton and Garland – have entered into agreements to buy energy from a 1,310-megawatt solar energy generation facility to be built in the state.
Invenergy, the project’s developer, said that the facility will be the largest solar project in the United States upon completion. The Samson Solar Energy Center is currently under construction in northeast Texas.
Along with Bryan, Denton and Garland, the following corporations will also purchase energy from the solar facility: AT&T, Honda, McDonald’s, Google and The Home Depot.
The breakdown of energy to be purchased from the facility is:
- AT&T: 500 MW
- Honda: 200 MW
- McDonald’s: 160 MW
- Google: 100 MW
- The Home Depot: 50 MW
- City of Bryan, TX: 150 MW
- City of Denton, TX: 75 MW
- City of Garland, TX: 25 MW
Located in Lamar, Red River and Franklin Counties, Samson Solar is a $1.6 billion capital investment, Invenergy said.
Samson Solar will be constructed in five phases over the next three years, with each phase commencing operation upon completion.
The full project is slated to be operational in 2023.
Study finds electrification is key to decarbonization of New England
November 24, 2020
by Peter Maloney
APPA News
November 24, 2020
New England will require economy wide electrification to achieve greenhouse gas reduction targets, according to a new report by Energy + Environmental Economics (E3) and Energy Futures Initiative (EFI).
All six New England states have adopted economy wide greenhouse gas (GHG) reduction targets of at least 80% reductions by mid-century, and Massachusetts recently adopted a net-zero commitment. And every state in the region, except Vermont, has seen its gross emissions decline since 1990 aided by the power sector’s transition from coal to natural gas as a generation fuel.
The region does pose unique challenges in achieving its emission reduction goals, the authors said.
The proportion of emissions in New England attributable to the transportation sector is higher than the national average while emissions from industrial sources are lower.
Transportation accounts for 42% of carbon dioxide emissions in New England while electricity accounts for about 20%, the report, Net-Zero New England: Ensuring Electric Reliability in a Low-Carbon Future, noted.
The report was sponsored by Calpine, an independent generation company that is heavily invested in gas-fired power plants. Calpine provided “input and perspectives” regarding the scope and analysis of the study but “all decisions regarding the analysis were made by E3 and EFI.” The authors also noted that the report “solely reflects the research, analysis, and conclusions” of E3 and EFI.
The report found that New England’s unique energy profile means that the region will not “be able to attain its GHG reduction goals with an exclusive focus on electricity production; it will be necessary to implement aggressive decarbonization on an economy-wide basis.”
Another unique factor in New England’s energy profile also creates a challenge. Fossil fuels used for residential and commercial heating contribute about 25% the region’s emissions, and New England is the only region in the country where oil is the most common heating fuel, the report said.
Direct energy use for transportation and buildings makes up two-thirds of New England’s emissions, therefore, mitigating GHG emissions will require strategies that emphasize the aggressive deployment of energy efficiency; widespread electrification of buildings, transportation and the industrial sector; development of low-carbon fuels, and deep decarbonization of electricity supplies, the report found.
The study modeled two scenarios: one focused on electrification (High Electrification) and the other on low-carbon fuels (High Fuels) to achieve 95% carbon emissions reductions in the region, although the scenarios use both strategies to some degree. As New England states draw closer to their GHG reduction goals, electricity demand in the region will increase significantly over the next three decades, the report said. In the two primary scenarios studied, annual electricity demand grows by 70 terawatt-hours (TWh) to 110 (TWh) by 2050, roughly a 60% or 90% increase from current levels. And electric peak demand would rise to between 42 gigawatts (GW) and 51 (GW).
Meeting GHG reduction goals while increasing electrification will also require a greater reliance on renewable energy, the authors said. Under the two scenarios, a mix of 47 GW to 64 GW of new renewable generation capacity would be needed by 2050, including land-based solar and wind, offshore wind, and distributed solar, along with 3.5 GW of incremental Canadian hydro. The authors also noted, however, that New England’s constrained geography, “slow pace of electric transmission planning, and historical difficulty siting new infrastructure are significant challenges that the region must overcome.”
Higher levels of renewable energy would also require firm capacity to ensure cost-effective and reliable energy supplies, the report said. As much as 46 GW of firm capacity could be needed in 2050 to ensure resource adequacy. Relying on renewable energy resources backed by battery storage, would be “extremely costly,” the authors added. Firm capacity would include about 34 GW of gas-fired generation, 3.5 GW of nuclear power, 8 GW of energy imports, and 1 GW of biomass and waste energy, the report found.
New resources, such as advanced nuclear, natural gas plants with carbon capture and sequestration, long duration energy storage, or generation from carbon-neutral fuels such as hydrogen, could be used to provide firm capacity, but until any of those technologies are commercially viable, natural gas generation is the most cost-effective source of firm capacity, the report said, adding that “some reliance” on gas generation is consistent with achieving a 95% carbon-free electricity grid in 2050 as long as the gas plants operate at a “suitably low capacity factor.”
NYPA completes work on first segment of transmission line project
November 24, 2020
by Paul Ciampoli
APPA News Director
November 24, 2020
The New York Power Authority (NYPA) on Nov. 24 announced the completion of work and energization of the first segment of one of the lines for its Smart Path Transmission project, the upgrade of the Moses to Adirondack transmission lines 1 and 2.
“The Smart Path transmission project is critically important to the resiliency of New York’s north-south transmission system,” said Gil Quiniones, NYPA president and CEO, in a statement. “The benefits of this important transmission work accrue incrementally, so every time we complete a section, New York State’s transmission system becomes that much stronger, more resilient and reliable.”
The Smart Path project involves rebuilding approximately 78 miles of the total 86-mile transmission artery that was constructed originally by the federal government in 1942 and acquired by the Power Authority in 1950.
Running north to south through St. Lawrence and Lewis counties in the North Country, the newly rebuilt lines will connect renewable energy into the statewide power system, including low-cost hydropower from NYPA’s St. Lawrence-Franklin D. Roosevelt Power Project as well as power from newly constructed renewable energy sources.
Construction involves the replacement of the original H-frame wood poles, some of which are more than 80 years old with single steel monopoles in the existing right of way. The project, which has been broken into six parts — three segments per line — includes high-voltage transmission lines from Massena to Croghan.
Work on the first 21-mile section of the Moses to Adirondack 2 line began at the beginning of the year. A total of 104 new structures have been installed and the rebuilt section was energized earlier this month. It will provide improved resiliency to support the transmission of clean energy from Northern New York, NYPA noted.
There are five remaining transmission line segments to be rebuilt under the Smart Path project. Work will begin next month on the replacement of the Moses to Adirondack 1 line in segment 1.
The first phase of the Smart Path project is expected to be complete in 2023. The project will strengthen the state’s electric power grid, and help the state meet the goals set forth in New York Gov. Andrew Cuomo’s Climate Leadership and Community Protection Act.
The rebuilt lines will be capable of transmitting up to 345 kilovolts (kV). However, they will be operated in the near-term at the 230 kV level.
Together the lines are currently rated to carry 900 megawatts during the winter months. “This ability to increase the voltage when the demand requires it is a cost-effective way to add on more renewable power, especially from in-state renewable generation, anywhere along the transmission line, as New York continues to advance its clean energy goals,” NYPA said.
Analysis finds adequate Eastern Interconnection frequency response
November 24, 2020
by Ethan Howland
APPA News
November 24, 2020
The Eastern Interconnection should be able to maintain system frequency for at least the next five years, according to a group of transmission planning coordinators.
However, with the addition of non-synchronous generation (intermittent wind and solar) and planned power plant retirements, maintaining frequency in the Eastern Interconnection is a concern that warrants continued study, the Eastern Interconnection Planning Collaborative (EIPC) said in a report issued Nov. 11.
The Eastern Interconnection electric grid covers about two-thirds of North America from the Rocky Mountains to the East Coast.
The North American Electric Reliability Corporation asked the EIPC, a coalition of 19 transmission planning coordinators, to study how the changing resource mix could affect frequency response in the Eastern Interconnection.
Frequency response is a measure of the grid’s ability to stop and stabilize frequency changes after the sudden loss of generation or load. If unchecked, sharp frequency changes can lead to power outages.
Load along with large fossil-fueled and nuclear power plants provide inertia to help maintain the grid’s frequency, but some plants are being replaced with renewable resources, which until a 2018 decision by the Federal Energy Regulatory Commission generally didn’t provide frequency response. To help maintain the grid’s stability, FERC ordered that all new generating facilities be able to provide frequency response.
The loss of inertia from the large power plants could trigger “under-frequency load shed” events, or blackouts, according to the EIPC.
At NERC’s request, the EIPC finished an initial frequency response study in April 2019.
“As the generation resource mix continues to evolve over time to incorporate new and emerging technologies and address energy and environmental policies, it is essential to understand how the Eastern Interconnection will be poised to maintain system frequency under a wide range of operating conditions,” said Keith Daniel, senior vice president of transmission policy at Georgia Transmission Corp. and chairman of the EIPC Executive Committee.
The EIPC task force that wrote the report studied four hypothetical events, including including generation losses of 2,300 megawatts, 3,850 MW and 4,500 MW as well as a 10,000 MW event.
The EIPC’s Frequency Response Working Group will continue to update its analysis, according to Daniel.
The EIPC is conducting additional power system analysis that will provide information to help maintain grid reliability and to inform state and federal regulators and policy makers, Daniel said.
The EIPC’s frequency response analysis will supplement NERC’s 2021 Long-Term Reliability Assessment.
The EIPC members include public power entities Municipal Electric Authority of Georgia (MEAG Power) and Santee Cooper.
FERC looks to improve accuracy and transparency of transmission line ratings
November 23, 2020
by Paul Ciampoli
APPA News Director
November 23, 2020
The Federal Energy Regulatory Commission recently issued a notice of proposed rulemaking (NOPR) aimed at improving the accuracy and transparency of transmission line ratings, which represent the maximum transfer capability of each transmission line.
FERC took the action at its monthly open meeting on Nov. 19.
At the meeting, FERC staff noted that under current typical practices, transmission line ratings are seasonal or static ratings.
These ratings are based on conservative assumptions about the worst-case, long-term ambient conditions that equipment might face. They are typically updated only when equipment is changed or ambient condition assumptions are revised, and therefore may not accurately reflect the near-term transfer capability of the system.
FERC staff said that more accurate ratings include ambient-adjusted ratings (AARs) and dynamic line ratings (DLRs), both of which are the subject of the NOPR.
Unlike seasonal or static-based ratings, ambient-adjusted ratings incorporate near-term forecasted ambient air temperatures. Dynamic line ratings are based not only on forecasted ambient air temperature, but also on other weather conditions such as wind, cloud cover, solar irradiance intensity, precipitation, and/or on transmission line conditions such as tension or sag.
There can be consequences to using an inaccurate representation of system transfer capability, FERC staff said.
For example, FERC staff said that because ambient air temperatures are typically less extreme than worst case assumptions, seasonal and static transmission line ratings typically indicate that there is less transmission system transfer capability available than the transmission system can actually provide. This increases congestion costs. At other times, however, seasonal or static transmission line ratings may overstate the near-term transfer capability of the system, creating potential reliability problems and inaccurately low congestion pricing, which may prevent occurrences of rates for scarcity pricing. In either case, the use of seasonal and static assumptions results in transmission line ratings that do not accurately represent the transfer capability of the transmission system.
To address this concern, the NOPR proposes to require transmission providers to implement ambient-adjusted ratings and seasonal line ratings on the transmission lines over which they provide transmission service. Transmission providers would use AARs for evaluating requests for near-term transmission service, and would use seasonal ratings for evaluating other, longer-term transmission service requests. The NOPR also proposes to revise the rules for setting seasonal ratings to make them more accurate.
In addition, the NOPR proposes to require RTOs and ISOs to establish and implement the systems and procedures necessary to allow transmission owners to electronically update transmission line ratings at least hourly.
The NOPR recognizes that there may be instances in which transmission owners may wish to implement transmission line ratings that may be more accurate than AARs, such as dynamic-line ratings, but are unable to have such ratings reflected in RTO/ISO markets under those markets’ current capabilities. This proposed requirement seeks to remove this barrier to adoption of these more accurate line ratings.
The NOPR also proposes to require transmission owners to share transmission line ratings and transmission line rating methodologies with their respective transmission provider(s) and, in RTOs/ISOs, with their respective market monitor(s). Such information sharing would increase situational awareness and improve the ability to verify the accuracy of transmission line ratings.
Finally, the NOPR seeks comment on whether to require transmission providers to use unique emergency ratings.
Comments are due 60 days after publication in the Federal Register.
The NOPR is available here.
CPS Energy signs deal to provide renewable natural gas for San Antonio’s buses
November 23, 2020
by Peter Maloney
APPA News
November 23, 2020
CPS Energy in San Antonio, Texas, has signed a deal to provide renewable natural gas (RNG) to the city’s mass transit provider.
Under the deal, the public power utility would provide the gas, which will be produced from landfill biogas, to VIA Metropolitan Transit beginning in 2021.
The transit agency will use the gas in its fleet of 502 buses, which are now powered primarily by compressed natural gas (CNG) along with some diesel-electric hybrid, electric, diesel and propane-fueled vehicles.
As the waste in a landfill decomposes, it produces methane, a powerful greenhouse gas, that, unless captured, is released into the air. Renewable natural gas can be created from captured methane and blended with natural gas. CPS Energy said it would distribute the enhanced natural gas through its existing natural gas distribution pipelines.
The gas will be captured from a landfill site in Converse, Texas, at a facility that is being designed, built and will be owned and operated by EDL of Australia, which will inject into CPS’ gas pipeline. The utilities will have to build spur lines to connect its pipeline network to the landfill facility.
CPS Energy has agreed to buy the gas EDL produces. On the other end, VIA Metropolitan Transit has agreed to take the beneficial environmental attribute of the non-fossil fuel gas, known as Renewable Identification Numbers (RINs) that are like Renewable Energy Credits (RECs) for fuel. “This is a unique opportunity for CPS,” utility spokesman John Moreno said.
VIA began converting its bus fleet to CNG in 2017 in an effort to reduce nitrogen oxide emissions by 97% from the diesel buses they replaced. As a vehicle fuel, renewable natural gas also reduces carbon dioxide emissions by 85% compared with diesel fuel vehicles.
The renewable natural gas program is “one more component of our creative Flexible Path strategy, which has been designed to leverage emerging environmental stewardship opportunities, which we keep our customers’ bills affordable and our services reliable,” Paula Gold-Williams, president and CEO of CPS Energy, said in a statement.
In 2019, as part of its Flexible Path strategy, CPS Energy made a commitment to reduces its next emissions profile by 80% by 2040. The utility is also working toward full carbon dioxide neutrality by 2050 in support of the City of San Antonio’s Climate Action & Adaptation Plan (CAAP) that was endorsed by the utility’s board of trustees in August 2019.
CPS Energy in San Antonio, Texas, has signed a deal to provide renewable natural gas (RNG) to the city’s mass transit provider.
Under the deal, the public power utility would provide the gas, which will be produced from landfill biogas, to VIA Metropolitan Transit beginning in 2021.
The transit agency will use the gas in its fleet of 502 buses, which are now powered primarily by compressed natural gas (CNG) along with some diesel-electric hybrid, electric, diesel, and propane-fueled vehicles.
As the waste in a landfill decomposes, it produces methane, a powerful greenhouse gas, that, unless captured, is released into the air. Renewable natural gas can be created from captured methane and blended with natural gas. CPS Energy said it would distribute the enhanced natural gas through its existing natural gas distribution pipelines.
The gas will be captured from a landfill site in Converse, Texas, at a facility that is being designed, built and will be owned and operated by EDL of Australia, which will inject into CPS’ gas pipeline. The utilities will have to build spur lines to connect its pipeline network to the landfill facility.
CPS Energy has agreed to buy the gas EDL produces. On the other end, VIA Metropolitan Transit has agreed to take the beneficial environmental attributes of the non-fossil fuel gas, known as Renewable Identification Numbers (RINs) that are like Renewable Energy Credits (RECs) for fuel. “This is a unique opportunity for CPS,” utility spokesman John Moreno said.
VIA began converting its bus fleet to CNG in 2017 in an effort to reduce nitrogen oxide emissions by 97% from the diesel buses they replaced. As a vehicle fuel, renewable natural gas also reduces carbon dioxide emissions by 85% compared with diesel fuel vehicles.
The renewable natural gas program is “one more component of our creative Flexible Path strategy, which has been designed to leverage emerging environmental stewardship opportunities, while we keep our customers’ bills affordable and our services reliable,” Paula Gold-Williams, president and CEO of CPS Energy, said in a statement.
In 2019, as part of its Flexible Path strategy, CPS Energy made a commitment to reduce its net emissions profile by 80% by 2040. The utility is also working toward full carbon dioxide neutrality by 2050 in support of the City of San Antonio’s Climate Action & Adaptation Plan (CAAP) plan that was endorsed by the utility’s board of trustees in August 2019.
CPS’ Flexible Path also includes initiatives such as its FlexSTEP energy efficiency program In July, as part of its FlexPOWER Bundle initiative, CPS Energy released a request for information to evaluate potential partners that can help the utility in the process of adding up to 900 MW of solar power, 50 MW of battery storage, and 500 MW of new technology solutions.
NERC sees no reliability problems this winter but warns of fuel supply risks
November 23, 2020
by Peter Maloney
APPA News
November 23, 2020
There will be sufficient resources in service to meet electrical demand during the upcoming winter season, according to the latest reliability assessment by the North American Electric Reliability Corp. (NERC), but the organization also cautioned that there are continuing risks regarding supplies of natural gas in New England, California and the Southwest.
NERC’s 2020-2021 Winter Reliability Assessment covers December, January and February. The report found that anticipated reserve margins will meet or surpass reference reserve margins in all areas under normal conditions.
Sufficient fuel supplies, specifically of natural gas, remains a concern in some areas, however, as demand for natural gas, both as a fuel for power generation and for space heating, continues to grow, NERC said.
During particularly cold weather generating units that lack alternate fuel sources or that do not have contracts for firm fuel delivery may not be able to meet demand, the report noted.
In New England, where natural gas availability is limited, firm load would still be able to be served even under abnormally cold conditions, but under more severe conditions, such as those experienced in January 2018, limited oil inventories could lead to “eventual loss of generation and firm load shed,” NERC said.
The NERC report also noted that California and the southwest area in the Western Interconnection could face “fuel supply curtailment or disruption from extreme events that impact natural gas supplies,” as those regions rely on natural gas-fired generation capacity for over 60% of on-peak demand and have limited gas storage.
Overall, extreme weather conditions – such as wind generation blade icing, frozen coal piles, and curtailment of natural gas pipelines – continue to pose a risk to the bulk power system during the winter, NERC said. Unusually cold temperatures could result in increased demand and higher levels of generation forced outages and create conditions that would lead system operators to take emergency actions.
The NERC report also examined ongoing impacts from the COVID-19 pandemic, which it said is causing “increased uncertainty in electricity demand projections and presents cybersecurity and operating risks.” The reliability organization noted that no specific threats or degradation to reliability have been identified for the winter season. However, the report also noted that if maintenance operations on generation and transmission assets are not able to be performed because of the pandemic, “forced outages may escalate.”
The pandemic could also affect the accuracy of demand projections in the near term and have the potential to exacerbate or alleviate planning reserve shortfalls in areas that are below or near reference margin levels, NERC said.
NERC’s assessment also noted that restoration efforts in response to the recent hurricane season could continue into the winter. While restoration efforts in Arkansas, Texas, and north Louisiana have been completed, restoration work that is often characterized as a rebuild, continues in southwest Louisiana, primarily in and around the city of Lake Charles.
Lincoln Electric System board adopts 100% net decarbonization goal by 2040
November 23, 2020
by Paul Ciampoli
APPA News Director
November 23, 2020
The administrative board of Nebraska public power utility Lincoln Electric System (LES) on Nov. 20 adopted a 100% net decarbonization goal by 2040.
“LES acknowledges that the emissions of greenhouse gases from fossil fuel-fired power generating plants contribute to increased concentration levels of atmospheric carbon dioxide, which in turn contributes to climate change,” LES said in a news release. The board adopted this goal in response to the risks associated with climate change.
The board’s action came after participating in a year-long educational series on establishing a new carbon reduction goal and soliciting public opinion at the beginning of the month.
In 2019, the mayor of Lincoln began developing a new Climate Action Plan for the community. The board “recognized its role in helping to achieve a community goal while also maintaining high levels of electric system reliability and affordable retail electric rates to every customer in the area,” LES said.
In October, the city released a draft of its Climate Action Plan, in which a citywide goal to reduce net greenhouse gas emissions 80% by 2050, relative to 2011 levels, was announced.
At its Nov. 20 meeting, the LES Administrative Board committed to striving to mitigate its reliance on fossil fuels by establishing a goal to achieve net zero carbon dioxide production from its generation portfolio by 2040.
Moving forward, LES staff will continue its ongoing process of technological and financial evaluations to make prudent resource planning decisions.
Additional information is available here.
Another Nebraska public power utility, Omaha Public Power District (OPPD), has begun a decarbonization study to understand how it can make progress toward its goal of net-zero carbon production by 2050.
Meanwhile, based on a two-year rolling average from 2018 and 2019, 61% of the electricity that Nebraska public power utility Nebraska Public Power District provides to its customers is carbon-free “thanks to powerhouses like nuclear and green energy sources like solar, hydropower and wind,” wrote NPPD President and CEO Tom Kent in a blog this past summer.
“We’re participating in carbon capture and sequestration studies funded in part through a competitive grant from the U.S. Department of Energy. And this year, we were granted the authority to pursue the development of innovative carbon-free and carbon-neutral fuels,” Kent wrote.
“It speaks to our willingness to not just listen to and accommodate customer expectations for low-cost, reliable and sustainable energy sources, but also to take it upon ourselves to move toward further reducing our carbon footprint and adapting to this growing trend,” Kent said.
CAISO board moves to integrate storage resources and improve reliability for fall 2021
November 23, 2020
by Paul Ciampoli
APPA News Director
November 23, 2020
The California Independent System Operator (ISO) Board of Governors last week adopted market tools that it said will help integrate new battery storage resources and improve overall reliability for next fall.
The board’s approval of Hybrid Resources Phase 2 was expedited to accommodate more than 1,500 megawatts of storage capacity expected to connect to the grid by the end of next year.
The storage capacity is part of California’s procurement goal of 3,300 MW of battery resources by 2023 to help replace retiring fossil fuel generation.
The proposal adopted by the board:
- Allows hybrid storage resources to provide energy and ancillary services to help maintain the reliability of the transmission system. Additionally, the hybrid resource owners will use a newly developed tool that gives grid operators visibility into the amount of energy these hybrid energy resources can provide in real-time;
- Expands the functionality of co-located batteries by allowing such storage resources to provide grid reliability services; and
- Requires both hybrid and co-located storage resources to provide the battery’s maximum output data to help with forecasting and improve operators’ visibility into the resource during the day.
In related news, the Federal Energy Regulatory Commission on Nov. 19 adopted CAISO’s Hybrid Resources Phase 1 tariff.
FERC’s order responded to a September filing made by the grid operator. In that filing, CAISO proposed revisions to its open access transmission tariff regarding modeling separate resources that are co-located at a single generating facility, and data requirements for hybrid resources that include a wind or solar generation component.
The Board of Governors approved the first phase of the Hybrid Resources proposal at its July 27 meeting.
Implementation of Phase 1 is scheduled for fall 2020.