CARMEL, Ind. — MISO last week laid out a more detailed proposal for how it will determine the capacity accreditation of electric storage resources under FERC Order 841.

The RTO is proposing to determine electric storage resources’ capacity based on two different measurements: the resource’s power output capability and its energy storage capacity as measured by MISO’s generator verification test capacity (GVTC).

Speaking at an Aug. 8 Resource Adequacy Subcommittee meeting, Senior Adviser of Capacity Market Administration Rick Kim said the rule will ensure both a megawatt and megawatt-hour measurement of a storage resource’s capability.

Kim said for storage resources under 10 MW or that have fewer than 12 months of operational data, MISO will apply a 5% default equivalent forced outage rate in its unforced capacity calculation. Other storage resources will be assigned a forced outage rate based on their quarterly data inputs to MISO’s generating availability data system (GADS). GADS reporting is required for storage resources 10 MW and above and optional for those under 10 MW.

Because NERC hasn’t yet addressed unit reporting for storage resources, Kim said resource operators should use the “miscellaneous” unit type option when reporting unit data.

“It’s going to be another year before we see registration of energy storage resources,” he added.

Kim also said storage resources connected to the transmission system will require either network resource interconnection service or firm transmission service with MISO to ensure capacity deliverability. If resources are connected at the distribution level, MISO will ensure deliverability with the distribution provider and transmission owner on a “case-by-case” basis, he said.

MISO has said that when storage resources are connected at the distribution level, market participants “must have sufficient metering or accounting for non-wholesale transactions to prevent double counting of energy.”

The RTO in June said it would accommodate Order 841 by dividing storage bid parameters into four operating modes: discharging, charging, continuous operations and offline. Market participants will be left to choose a mode for individual dispatch intervals and will also be responsible for managing the state of charge of their storage units. (See MISO Weighing Feedback to Storage Proposal.) Storage resources will be able to set prices under MISO’s extended LMP.

Minnesota electric cooperative Connexus Energy has confirmed recent press reports that it is building 15MW / 30MWh of battery energy storage, while another not-for-profit, Vermont Electric Cooperative, will build a 1.9MW / 5.3MWh system in its service area.

Connexus is part of Great River Energy, an electric transmission and generation cooperative and the second largest utility in Minnesota. Connexus serves about 130,000 residential and commercial properties in its service area. It issued a statement yesterday stating that the “innovative” solar-plus-storage project is now under construction.

Pairing 10MW of solar across two sites with 15MW of battery storage, also split between the Ramsey and Athens Township solar farm sites, the cooperative wants to use the combination to help manage peak demand. A subsidiary of major developer NextEra Energy will build, own and operate the lithium-ion battery storage systems, which Connexus said will be “fully integrated” with the solar PV. ENGIE North America will be responsible for the solar portions of the projects.

“Energy prices differ throughout the day. Most solar energy is produced when there is lower demand and the price is lower. Our plan is to discharge the stored solar energy during peak hours when energy costs are the highest. We refer to this as time-shifting solar energy to a time of day when it has more value,” Greg Ridderbusch, Connexus CEO said.

Ridderbusch said that the utility had listened to its members, who want more renewable energy on their network, Ridderbusch said, but did not want to pay more for their electricity.

A 2017 study found Minnesota could use energy storage and solar as part of a “least-cost path forward” in direct competition with gas turbines. ‘Modernising Minnesota’s Grid: An economic analysis of energy storage opportunities’, was produced by University of Minnesota’s Energy Transition Lab with Strategen Consulting and Vibrant Clean Energy.

Among the key findings of that report were:

• Under an optimal set of future energy resource investments and operating practices, the least-cost solutions included energy storage.
• Energy storage can be a cost-effective means to help Minnesota meet its state greenhouse gas (GHG) reduction goals.
• The deployment of storage in Minnesota was projected to increase the use of low-cost renewable energy generation dispatched in MISO and to reduce the need for expensive transmission investments.
• Historically, utilities have used gas combustion turbines to meet peak demand. As storage becomes more cost-effective, it will compete with and displace new gas combustion peaking plants (peakers).
• Compared to a simple-cycle gas-fired peaking plant, storage was more cost-effective at meeting Minnesota’s capacity needs beyond 2022.
• Additionally, the Investment Tax Credit (ITC) which discounts storage purchases when made with solar, already makes solar-plus-storage more cost-effective than a peaking plant as well as having an environmental benefit in reducing GHGs.

MISO’s Energy Storage Task Force is making a bid to broaden its role by seeking the authority to evaluate storage issues in addition to identifying them.

The group moved to revise its charter during a Tuesday conference, but any proposed changes are subject to approval by the Steering Committee at its next meeting.

The task force is currently limited to only identifying storage issues requiring MISO’s attention. It then forwards its findings to the Steering Committee, which assigns the issues to larger stakeholder committees for decisions. (See MISO Storage Task Force Defines Role, Seeks Plan.)

But the group now wants the authority to evaluate “issues or topics that are unique to the integration or challenge the realization of benefits of energy storage,” according to the revised charter. It would “also provide ongoing subject matter expertise to MISO entities regarding storage-related issues.”

Task force Chair John Fernandes said the initial charter may have been too restrictive.

“That was a very unilateral, one-way mission statement,” Fernandes said. “What we’re saying here is that there’s an opportunity for extended dialogue.”

He said it can sometimes feel as if the group encounters “radio silence” after it identifies an issue taken up by a larger stakeholder committee.

Fernandes said the group will reconvene in September to discuss next steps if the Steering Committee refuses to approve the expanded charter.

Some stakeholders said the revised charter might open the door to two stakeholder groups having the same discussions about energy storage, violating the spirit of MISO’s stakeholder process redesign three years ago that sought to reduce duplicative discussions across different RTO forums. (See MISO Takes Stakeholders’ Temperature on Redesign.)

But Fernandes said there are broad storage subjects that warrant further task force discussions even if a specific issue may have been escalated to another MISO group. He cited hybrid storage facilities as an example, noting the interconnection of such plants is currently under discussion within the RTO, but the general business model requires more evaluation.

Fernandes also questioned the efficiency of stakeholder committees creating new task teams to discuss unique storage attributes when the task force could evaluate them.

He added that the task force plans to continue to stay out of developing commercial business models for storage, as recommended by the Steering Committee.

Energy storage has been taking root across the country, but coastal states, such as California, Massachusetts and Oregon, have taken the lead in implementing related policies. That could change as states such as Colorado and Nevada move closer to potentially ambitious policies to support energy storage.

Rising renewable penetration combined with falling costs for lithium-ion batteries is driving many states to explore policies that encourage energy storage.

New Jersey became the most recent state to adopt an energy storage target when Democratic Gov. Phil Murphy in May signed a bill that establishes a 2,000 MW by 2030 target. And in New York, the Public Service Commission is in the process of setting an energy storage target that some observers say could end up as high as 3,000 MW by 2030.

But Arizona could be the next state to adopt an energy storage goal, if Commissioner Andy Tobin has his way.

“Energy storage is high on my list,” Tobin told Utility Dive.

The man with the plan

The Energy Modernization Plan that Tobin released in January includes a recommended target for 3,000 MW of energy storage deployed by 2030. The plan would have the state be powered by 80% clean energy by 2050, from 15% by 2025, and directs the investor owned utilities to build 60 MW of biomass plants for service by 2022.

The Arizona Corporation Commission (ACC) “could be voting on the plan by January or February,” Tobin said.

“We thought we had enough votes” to put it on the docket, Tobin said at the commission last month. Instead, the ACC decided to do a study on the financial impact of the plan. That study, being prepared by the state’s Residential Utility Consumer Office, should be ready in about two weeks.

Tobin wants to see the adoption of his plan ahead of the next fire season, as the biomass plant component could burn fuel from Arizona’s forests and lessen the devastation of forest fires.

Tobin is optimistic, noting that some commissioners are already on board.

Renewables are beginning to dominate the energy generation sector, favoured for their low-to-zero carbon emissions and, therefore, the potential to meet climate targets. Though powerful and promising, the unreliable nature of such sources means the industry is increasingly seeking new methods of energy storage.

Currently, lithium-ion batteries are the most popular alternative to traditional lead-acid types, due to their longevity and energy density. However, lithium’s rising costs – going up by 240% in 2017 –  coupled with fears over resource depletion, are prompting developers to look elsewhere for low-carbon battery bases.

While possible alternatives have been sought in water, gold, cobalt and sodium, the latest development has come from German conglomerate Siemens, which launched its ‘green ammonia energy storage demonstrator’ on 26 June at Harwell in Oxfordshire, UK.

The demonstrator uses renewable power to make ammonia, a compound traditionally used to boost crop yields, by combining hydrogen extracted from water and nitrogen from air. The ammonia is stored in a tank and converted back into electricity when needed, either through traditional combustion methods or by ‘cracking’ it into nitrogen and hydrogen. In the latter method, the hydrogen can then be used in hydrogen fuel cells to power devices such as electric vehicles.

Crucially, no carbon emissions are produced during the entire process.

The £1.5m project was developed in conjunction with the Science and Technology Facilities Council (STFC), the University of Oxford and Cardiff University.

The STFC contributed to the site infrastructure, the wind turbine and expertise in interfacing with its site and systems, while the University of Oxford helped design the ammonia synthesis part of the system. Cardiff University converted a methane-fuelled generator set to run on ammonia.

Siemens programme manager Ian Wilkinson says the company’s interest in ammonia is partially driven by the fact that “it is based on mature technology and is therefore rapidly deployable at sufficient scale to be useful in meaningful decarbonisation”. Having an existing ammonia industry ensures there is infrastructure in place to store, transport and handle the compound safely from the offset.

Hawaii has been a prolific installer of both rooftop solar and latterly batteries for energy storage and one of the US state’s smaller islands looks set to get its first ever grid-scale solar-plus-storage system.

The state Public Utilities’ Commission (PUC) approved a power purchase agreement (PPA) deal for the project on the island of Molokai, which is just under 40 miles by 10 miles across and hosts around 3,200 electric utility customers, at the beginning of this month.

It will combine 4.88MW of solar PV with a 3MW / 15MWh battery energy storage system and is expected to be completed by the end of next year. The facility will have to be able to dispatch 2.64MW from the solar-plus-storage system which could be used to mitigate evening peaks in electricity demand.

Local utility Maui Electric would buy power generated from Molokai New Energy Partners, which appears to have been set up by Chicago-headquartered developer Half Moon Ventures. The PPA covers “purchased energy charges and BESS (battery energy storage system) fixed payment”, according to a docket filed by the PUC.

Maui Electric said energy will be delivered for around US$0.17 per kilowatt-hour, less than the cost of the imported diesel which currently lights homes on the island. A website set up by Molokai New Energy Partners argues that “the average homeowner’s bill will be US$60 to US$100 less per year than if this project was not built”.

The PPA runs for 22 years. Interestingly, the project will be getting a financial boost through the federal New Markets Tax Credits (NMTC) programme which is applied to low-income communities that are seeking investment in businesses and real estate, as well as the Investment Tax Credit (ITC). The former has been made possible by the involvement of a community development organisation, Punawai O Puuhonua.

“We are grateful to have the New Market Tax Credit resources that can support the economic feasibility of a Molokai project. During the community engagement meeting a young father shared, ‘This project is really for my daughters…If our parents had done something like this 20 years ago it would have been for us, and this one is for the current children.’ We support and appreciate his foresight,” Punawai O Puuhonua manager Pono Shim said.

The website set up by Molokai New Energy Partners about the project argues that “the ability of the battery to shift peak solar production to the evening is designed so as not to interfere with current rooftop solar,” while the battery capacity could be increased in later years to enable even more rooftop PV, which is a popular choice in Molokai – and the rest of Hawaii.

The group also said that at present, 50% of Molokai residents’ electricity bills come from fixed charges unrelated to generation, while the other half is pegged to the price of importing and burning diesel for power generation. As the cost of oil increases as is expected, savings will remain “locked in”, Molokai New Energy Partners said.

“HMV’s current pricing offer is less than oil at today’s historically lower price. Solar will remain at this lower level whereas we do not know where oil will be for the short or the long term,” the company said. Half Moon Ventures will own the project, according to the website, but the company said that since the deal is based on offering lower cost electricity to islanders, the net result would not be an “out of state” developer “taking money away from Molokai”, according to a ‘frequently-asked questions’ section of the site.

Minnesota electric cooperative Connexus Energy has confirmed recent press reports that it is building 15MW / 30MWh of battery energy storage, while another not-for-profit, Vermont Electric Cooperative, will build a 1.9MW / 5.3MWh system in its service area.

Connexus is part of Great River Energy, an electric transmission and generation cooperative and the second largest utility in Minnesota. Connexus serves about 130,000 residential and commercial properties in its service area. It issued a statement yesterday stating that the “innovative” solar-plus-storage project is now under construction.

Pairing 10MW of solar across two sites with 15MW of battery storage, also split between the Ramsey and Athens Township solar farm sites, the cooperative wants to use the combination to help manage peak demand. A subsidiary of major developer NextEra Energy will build, own and operate the lithium-ion battery storage systems, which Connexus said will be “fully integrated” with the solar PV. ENGIE North America will be responsible for the solar portions of the projects.

“Energy prices differ throughout the day. Most solar energy is produced when there is lower demand and the price is lower. Our plan is to discharge the stored solar energy during peak hours when energy costs are the highest. We refer to this as time-shifting solar energy to a time of day when it has more value,” Greg Ridderbusch, Connexus CEO said.

Ridderbusch said that the utility had listened to its members, who want more renewable energy on their network, Ridderbusch said, but did not want to pay more for their electricity.

A 2017 study found Minnesota could use energy storage and solar as part of a “least-cost path forward” in direct competition with gas turbines. ‘Modernising Minnesota’s Grid: An economic analysis of energy storage opportunities’, was produced by University of Minnesota’s Energy Transition Lab with Strategen Consulting and Vibrant Clean Energy.

Among the key findings of that report were:

• Under an optimal set of future energy resource investments and operating practices, the least-cost solutions included energy storage.
• Energy storage can be a cost-effective means to help Minnesota meet its state greenhouse gas (GHG) reduction goals.
• The deployment of storage in Minnesota was projected to increase the use of low-cost renewable energy generation dispatched in MISO and to reduce the need for expensive transmission investments.
• Historically, utilities have used gas combustion turbines to meet peak demand. As storage becomes more cost-effective, it will compete with and displace new gas combustion peaking plants (peakers).
• Compared to a simple-cycle gas-fired peaking plant, storage was more cost-effective at meeting Minnesota’s capacity needs beyond 2022.
• Additionally, the Investment Tax Credit (ITC) which discounts storage purchases when made with solar, already makes solar-plus-storage more cost-effective than a peaking plant as well as having an environmental benefit in reducing GHGs.

Energy storage has been taking root across the country, but coastal states, such as California, Massachusetts and Oregon, have taken the lead in implementing related policies. That could change as states such as Colorado and Nevada move closer to potentially ambitious policies to support energy storage.

Rising renewable penetration combined with falling costs for lithium-ion batteries is driving many states to explore policies that encourage energy storage.

New Jersey became the most recent state to adopt an energy storage target when Democratic Gov. Phil Murphy in May signed a bill that establishes a 2,000 MW by 2030 target. And in New York, the Public Service Commission is in the process of setting an energy storage target that some observers say could end up as high as 3,000 MW by 2030.

But Arizona could be the next state to adopt an energy storage goal, if Commissioner Andy Tobin has his way.

“Energy storage is high on my list,” Tobin told Utility Dive.

The man with the plan

The Energy Modernization Plan that Tobin released in January includes a recommended target for 3,000 MW of energy storage deployed by 2030. The plan would have the state be powered by 80% clean energy by 2050, from 15% by 2025, and directs the investor owned utilities to build 60 MW of biomass plants for service by 2022.

The Arizona Corporation Commission (ACC) “could be voting on the plan by January or February,” Tobin said.

“We thought we had enough votes” to put it on the docket, Tobin said at the commission last month. Instead, the ACC decided to do a study on the financial impact of the plan. That study, being prepared by the state’s Residential Utility Consumer Office, should be ready in about two weeks.

Tobin wants to see the adoption of his plan ahead of the next fire season, as the biomass plant component could burn fuel from Arizona’s forests and lessen the devastation of forest fires.

Tobin is optimistic, noting that some commissioners are already on board.

The state’s investor-owned utilities have responded to the proposed energy plan with proposals for energy storage projects, according to Tobin. Tucson Electric Power is considering participating in the 2,000 MW Big Chino Valley Pumped Storage Hydroelectric project proposed by ITC Grid Development. And Arizona Public Service has proposed a solar-plus-storage project that includes a 50 MW, 135 MWh battery to serve a 65 MW solar farm.

Following suit

In addition to the progress in Arizona and New York, Timothy Fox, vice president at ClearView Energy Partners, is also tracking developments in Nevada where a regulatory proceeding is underway to create a storage target pursuant to S.B. 204, enacted last spring.

GTM Research also recently began tracking Nevada and Colorado for energy storage policies.

“There are some large utility projects going on” in Nevada, Brett Simon, senior energy storage analyst at GTM Research, told Utility Dive. The state’s constant shifts on net metering policies for solar power are driving interest in residential storage that can be used to time shift solar power generation from mid-day to the evening, he said.

The Alaskan city of Kotzebue has integrated a Saft lithium-ion (Li-ion) energy storage system (ESS) into its off-grid microgrid. The ESS enables the hybrid wind-diesel power system to achieve its full potential, providing cleaner, more reliable and less expensive power to a remote community of 3,700 people.

Kotzebue is located 30 miles north of the Arctic Circle, far from the nearest transmission grid. Historically, KEA (Kotzebue Electric Association), the city’s electricity cooperative, has relied on diesel generators. However, since the late 1990s KEA has committed to making every effort to reduce its dependence on diesel and has invested in wind energy. But the intermittent nature of the wind meant that KEA still had to run its diesel generators, often resulting in curtailment when the wind turbines were providing their peak output. This challenge prompted KEA to seek a solution to utilizeits excess wind capacity.

Maintaining stability and minimizing curtailment

In general, an ESS becomes essential to maintain grid stability when the penetration of renewables within a microgrid rises above 50 percent. In KEA’s case its wind capacity of 2.9 MW is close to its 3 MW peak load, so the same ESS can also time-shift wind energy to help minimize curtailment.

KEA added a Saft Intensium® Max+ 20M ESS to its microgrid with two key aims:

• to achieve the full potential of its wind power by riding through fluctuations in output and time-shifting wind energy,
• to facilitate operation in ‘diesel-off’ mode with power provided only by a combination of wind and storage during periods of high wind and low load.

KEA microgrid – key facts

• Serves a remote off-grid community of 3,700 people
• Winter temperatures can fall to -50°C
• Combines diesel generators, wind turbines and energy storage
• 3 MW peak load
• 19 wind turbines – total 2.9 MW
• 6 diesel generators – total 11 MW
• 500 MW solar planned for the future