Month: April 2019

Gas goes out again as top US utility SCE picks energy storage instead

Southern California Edison, one of the US’ top-ranking utilities for energy storage capacity already deployed, has signed contracts for seven more clean energy projects, totalling 195MW in its California service area.

The company has announced contracts for six energy storage facilities and one demand response contract. In April 2018, Smart Electric Power Alliance statistics showed that SCE was the leading utility in the US in the preceding year for deployment across the US, with more than 50MW going online. The utility is one of California’s three major investor-owned utility companies in a group which includes the embattled PG&E and SDG&E, which was joint-leader with SCE in the aforementioned rankings. The IOUs are each mandated to deploy a significant share of a 1.5GW target for energy storage deployment by the mid-2020s.

However, a release sent by SCE to Energy-Storage.news over the weekend said that unlike many previous solicitations for large-scale energy storage in the US and elsewhere, the latest 195MW procurement will directly address local network needs including the shortfall in gas generation locally in the wake of the Aliso Canyon disaster. 

Aliso Canyon’s big leak resulted in some of the world’s fastest deployments of grid-scale storage, as covered extensively on this site. In continuing efforts to provide adequate capacity to the local area, SCE put out the Aliso Canyon Energy Storage 2 Request For Offers and Local Capacity Requirements Request For Proposals, this year and last, respectively.

‘Supporting a clean energy vision for California’

The energy storage systems will be connected to two substations, at Santa Clara and Goleta, with Aliso Canyon Energy Storage 2 also helping supply local network services.

The largest of the seven projects will be a 100MW system contracted to Strata, with the seven coming online commercially either by December 2020 or March 2021.

SCE, a subsidiary of Edison International, awaits regulatory approval from the California Public Utilities Commission for the projects. The utility did not reveal the expected duration of the storage systems, however recent projects to replace gas in California and elsewhere have typically seen two to four-hour systems deployed. The 100MW system at 400MWh would be one of the biggest systems today, albeit by its expected completion date of 2021 it will likely have more competition. 

“Unlike other solicitations to increase the generation capacity of the overall electric system, this solicitation specifically sought to meet local needs in the Moorpark area and address electrical energy storage needs related to restricted natural gas operations at Southern California Gas Company’s Aliso Canyon Natural Gas Field. SCE targeted clean energy resources through an accelerated competitive bidding to meet this identified need before summer 2021. The solicitation results also support SCE’s clean energy vision for California,” SCE vice president of energy procurement & management, Colin Cushnie said. 

Southern California Edison selected demand response resources as well as energy storage from the latest solicitation, while choosing no natural gas generation at all. In a recent PV Tech POWER article, several industry sources and experts also highlighted the competitiveness of solar-plus-storage versus natural gas peaker plants in many parts of the US. 

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New York’s Green New Deal puts US$350m investment into energy storage

US$400 million of funding pledged by New York’s state Governor Andrew Cuomo last week towards his “comprehensive climate agenda” will include US$280 million in support for energy storage.

New York State Energy Research & Development Agency (NYSERDA) emailed Energy-Storage.news to highlight that last week’s investments into de-carbonisation included US$280 million available now from NYSERDA and a further US$70 million to be allocated “based on opportunities that have the greatest potential to support a self-sustaining storage market” in the future, the agency said.

Partly due to New York’s stringent planning restrictions, including the fire regulations necessary for safe operation of electrical systems in its densely populated urban environments, actual deployment of grid-scale energy storage systems has been limited in the state. Residential systems have also not enjoyed high volumes of installation, as net metering and other policies continue to support a standalone domestic solar market.

Nonetheless, Cuomo’s leadership team set the state a target of 3GW of energy storage by 2030 last December, an aggressive update on a ‘1.5GW by 2025’ goal set in a previous iteration. NYSERDA also pointed out that the state is also a provider into the industry: “nearly 100 energy storage companies with expertise in hardware manufacturing, advanced materials, software development and project management” are headquartered or based in New York, while 3,450 people were found to be working in the industry in a report by American Jobs Project. Cuomo fully launched his “clean energy and jobs agenda”, a state-level Green New Deal, in January.  

Cuomo: ‘Energy storage is vital to our resiliency work’

“Energy storage is vital to our resiliency work and this funding will enable us to grow the industry and create jobs while we continue on our path toward meeting the country’s largest energy storage target,” Cuomo said.

“While the federal administration denies the devastating reality of climate change, New York continues to invest in its future by building a more efficient clean energy system.”

Cuomo’s Lieutenant Governor Kathy Hochul re-enforced the point that the funding marks an investment in “aggressive energy goals across the state”. 

“This funding continues our efforts to support clean energy and energy storage projects, growing the industry and creating good jobs,” Hochul said.

‘On the block’ and in bulk: 5MW definition distinction

The freshly announced funding is expected to directly help achieve the 2025 goal, NYSERDA said. It will be issued as:

  • One US$150 million set of funding for “bulk storage” projects, defined as systems over 5MW in size primarily engaged with the wholesale energy market, or distribution services. 
  • A further US$130 million opportunity for “retail storage projects”, behind-the-meter (BTM) customer-sited systems under 5MW. These can be either standalone or paired with solar or other distributed small-scale generation as applicable.

The latter set of funds will be distributed through a “megawatt hour block system”, a system for supporting deployment similar to an existing plan for small-scale solar. The Retail Energy Storage Incentive Program splits the funding into New York City as one region and the rest of the state as the another. The programme then follows market deployment in each region and allocates funding accordingly. A certain number of kilowatt-hours of capacity will be supported until every block of available capacity/funding is taken up.

Meanwhile, bulk storage systems will have the choice of applying for either fixed incentive funding through to 2025 in steadily declining amounts each year, or through responding to a utility bulk storage RFP (request for proposals), which is to be offered later this year. 

3GW by 2030 = US$4 billion in benefits + 2 million tonnes of CO2 saved?

It is believed the achievement of the 3GW by 2030 target “will deliver more than US$4 billion in gross benefits overall to New Yorkers,” while reducing CO2 emissions by 2 million metric tonnes. The latest funding and opportunities sit alongside a Request for Information just issued by utility NYPA (New York Power Authority) for battery integrators, developers and others utilising lithium batteries at utility-scale. NYPA is seeking participants for competitive solicitations to be held within New York State. Earlier this month NYPA also launched an Innovation Challenge, seeking to support both long duration stationary storage tech and business model development, as well as electric vehicle uptake and infrastructure. 

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Open source software launched to help US behind-the-meter projects hit economic sweet spots

An open source software tool to help developers and other stakeholders in the US to analyse the viability of their energy storage system projects has been released by Sandia National Laboratories.

Sandia this week launched QuESt v1.2, which it describes as “open source software for energy storage valuation”, based on the computer programming language Python – which as one expert told Energy-Storage.news – as a quick and versatile system for writing code.

The main software suite performs energy storage system modelling and analysis. In a recent article for PV Tech Power, reproduced as a Guest Blog for this site, commercial provider Pason Power wrote about the growing importance of economic modelling to ensure the solidity of the business case for energy storage projects.

In the latest release, Sandia has emphasised the growth in interest in behind-the-meter (BTM), customer-sited energy storage systems. The new application suite includes QuESt BTM, a brand new modelling app that specifically helps stakeholders analyse BTM systems – before they begin deployment.

Raking across data from the US’ different utility markets and their rate structures, QuESt BTM allows users to estimate cost savings from their storage systems, which can vary hugely across the different regulated markets in the States. Time-of-use utility rates and net metering policies can impact the overall economic case for energy storage. The software assesses the economics of shifting the load to times of lower demand across the network or peak shaving, using storage.

Using simulated load profiles for a range of commercial and residential buildings across the US, the software “leverages a database of US utility rate structures to allow users to select the rate structure most pertinent to his or her project,” Sandia said in a press release.

Given the growth in solar-plus-storage in recent times, QuESt BTM is also designed to analyse and compare simulated solar energy production profiles when co-located or combined with energy storage facilities.

The software application suite also looks to help developers and others to ‘size’ their projects correctly. As mentioned in Pason Power’s recent article, sizing of energy storage systems can have a big impact on the overall economics, due to the relatively high Capex involved in deploying them.

“A grossly oversized storage system will do the job but never pay off or meet the internal rate of return (IRR) requirement. An undersized storage system will not do the job and suffer a similar economic fate,” Pason Power CEO Enrico Ladendorf wrote in that article, ‘The smarts behind the storage’.

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ERCOT’s multiple opportunities a target for GlidePath’s 10MWh Texas project

A large-scale energy storage project to be built in Texas will take advantage of the system’s flexibility to deliver multiple services, as opportunities grow in the state’s Electricity Reliability Council of Texas (ERCOT) market.

Independent power producer (IPP) GlidePath Power has contracted Oregon-headquartered Powin Energy to construct a 10MW / 10MWh energy storage system (ESS) utilising lithium iron phosphate (LFP) battery technology at an as-yet unspecified location in the ERCOT service area.

A GlidePath representative told Energy-Storage.news that the project “has the potential to be co-located” with renewable energy facilities, in a state where there is a large installed capacity of wind energy and a growing interest in solar. The company was tight-lipped on revealing which applications the system will serve but instead issued a general statement on various opportunities within ERCOT.

“ERCOT is a highly competitive market with room for multiple technologies to participate in providing energy, ancillary service and reliability functions,” the GlidePath spokesman said.  

“GlidePath is excited to enter this market with an energy storage system that will demonstrate great value to ERCOT consumers in a market projecting historically low planning reserve margins.”

Going forward, demand for electricity is rising rapidly in Texas, while GlidePath quoted figures to Energy-Storage.news from ERCOT’s preliminary assessment for total resource capacity in the 2019 summer season that show a planning reserve margin of just 7.4% with “total resource capacity being extremely narrow”, the spokesman said.

As well as this shortfall in planned reserve capacity which ESS could help bridge, ERCOT is seeking ways to add dispatchable energy storage markets, in common with other RTOs and ISOs around America. The ERCOT grid is not interconnected with the rest of the US’ electricity networks and does not fall under the jurisdiction of the Federal Energy Regulatory Commission (FERC) Order 841, instructing network operators to incorporate energy storage into wholesale markets.

Nonetheless, GlidePath said the company believes moves by transmission operators including ERCOT to “take advantage of the increasingly cost-competitive technology and the versatility of functions energy storage can demonstrate for the grid and to the market… is just the beginning of seeing market evolutions in bringing storage to the forefront of providing much-needed flexibility to the grid operators”.

IPPs as ‘dynamic stakeholders in the grid community’

GlidePath said it had selected Powin Energy to provide and construct the turnkey system due to the multi-use flexibility and data fidelity/exposure that Powin’s energy management systems (EMS) and battery management systems (BMS) are capable of, which GlidePath described as “industry leading”.

“These features allow GlidePath to leverage a strong commercial base case while maximising future upside from additional use cases at the same site. The site is being designed to easily expand the DC capacity to four- to six-hour duration use cases when they evolve in ERCOT,” GlidePath said.

“This flexibility also allows GlidePath to be a dynamic stakeholder in the grid community as new grid services are contemplated.”

A Powin representative told Energy-Storage.news that the company positions itself as a full services integrator, providing a customer with a single point of responsibility in the event of a problem occurring. The company has delivered around 75MWh of energy storage into North America and claims a further 1GWh+ pipeline of additional awarded battery projects to be deployed in the two years. The Powin spokesman claimed that approximately 150MWh of that pipeline will be deployed by Q3 2019, providing applications including peak demand management, solar load shifting and thermal ramping capacity.

The pipeline appears to have grown rapidly. In September last year Energy-Storage.news reported that Powin Energy had claimed a pipeline close to 500MWh under contract for construction by 2021. Powin pivoted from energy storage project development to become more of a technology provider in late 2017 with the sale of a 116MWh portfolio. Forthcoming large-scale projects for the company include a 6.5MW / 26MWh project for utility San Diego Gas & Electric (SDG&E) in California.

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Infrastructure fund SUSI invests big in Macquarie-AMS California portfolio

The ‘world’s first dedicated energy storage infrastructure fund’ will invest in California battery energy storage projects, with Macquarie set to sell 50% of a 340MWh tranche to the fund’s owner, SUSI Partners.

Switzerland-headquartered SUSI Partners is buying up half of the total 60MW/340MWh of projects, which are located in the western LA Basin. The projects are being designed, installed and deployed by Advanced Microgrid Solutions (AMS), a US provider of commercial and industrial (C&I) energy storage and AI-driven so-called ‘Hybrid Electric Buildings’.

In other words, rather than large or utility-scale front-of-meter energy storage systems supplying power, capacity and flexibility to the grid, dozens of interconnected medium-sized energy storage systems perform the task of a virtual power plant (VPP). AMS will continue to manage and operate 90 separate battery systems of which the 340MWh total portfolio will be comprised.

Energy-Storage.news reported in March that the first phase of deployments in that AMS virtual power plant (VPP) had supplied 2GWh of grid services in its first year (2018), with one analyst dubbing it an “impressive milestone”.

‘A critical enabler of California’s long-term energy transition policy’

AMS is “creating energy solutions and utilising software to effectively aggregate and dispatch them to provide grid services,” Julian Jansen, senior analyst at I.H.S Markit said, adding that much of the value lies in creating a combination, or “value or revenue stack” of services the battery systems can deliver. The projects were built through contracts with Southern California Edison, one of California’s main investor-owned utilities.

Having launched the Susi Energy Storage Fund in 2016, the finance group financed its first 12MW of projects that were in Ontario, Canada, later that year and then reached its first close for €66 million (US$73.85 million) in April the following year. Growing rapidly, final close was achieved at €252 million in June 2018.

In November 2017, Apricum Consulting’s Florian Mayr commented to this site that Susi had “clearly realised the high potential of the energy storage market for its institutional investors seeking attractive risk-adjusted returns in a rapidly growing infrastructure asset class that also contributes to the mitigation of climate change,” as the company financed that first 12MW and then committed up to almost US$100 million for C&I projects in Canada by developer NRStor.

“This is SUSI’s first investment in the US, one of the most mature markets for energy storage globally. The State of California is formally pursuing a target of 100% carbon-free electricity by 2045 and is thus one of the trailblazers for the energy transition,” Susi Partners CIO Marco van Daele said.

“We are thrilled with this transaction in light of the role the portfolio has as a critical enabler of California’s long-term energy transition policy and look forward to continue investing in the US market.”

Macquarie held further debt financing to get pipeline funded

Susi is buying the 50% stake from Macquarie’s own Green Investment Group, which is “focused on investing capital into development and construction of new Green Energy Infrastructure,” Macquarie Capital senior managing director and head of infrastructure and energy Americas, Rob Kupchak said.

A few days ago, Macquarie had said that it closed debt financing to fund a final 97MWh of the remaining 340MWh pipeline. Lending came from leader CIT Group, with Rabobank, Sumitomo Mitsui Banking Corp and ING. The behind-the-meter systems, at grid-constrained pockets of the basin, will add flexible and reserve capacity to the grid, help integrate solar and manage voltage on the local network, as well as tasks typically associated with BTM systems such as demand management, backup and power quality management. All of the 90 battery systems are sited or will be sited at commercial and industrial customer properties or local government and public buildings, while they are “substantially contracted for 10 years,” Susi Partners said in a release.

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8minutenergy: ‘We can do solar peaker plants at half the cost of gas’

Many of the most polluting thermal power plants on the US grid today are also the most lucrative to run, but the service they provide could already be done twice as cheaply using solar and storage, developer 8minutenergy has claimed.

While focusing on specific US states that have a combination of a ‘stressed’ grid and rising penetration of solar energy, 8minutenergy CEO Tom Buttgenbach said that peaker plants – natural gas turbine power stations that fire up only in response to times of peak demand – have run their course, particularly in terms of new developments. Buttgenbach’s comments feature in the PV Tech POWER ‘Storage & Smart Power’ article ‘Peak time to take action’, recently published on this site too.

Daytime peak demand in California or Texas, for example, is covered to a greater extent by solar resources. The peak in demand which used to begin in the early afternoon and continue until around 9pm in those states, is now only about four hours long, from 5pm until 9pm.

“That means their utilisation has gone down, that means their cost goes up per megawatt hour and there are quite a lot of fixed costs like O&M and staff that have to be amortised over a shorter time. So their costs keep going up, our costs keep coming down with solar technology,” Buttgenbach said.

“However, to fill that evening peak, we need storage. You start looking at the economics and power prices in that evening peak can be very high, just because these peakers, typically gas peakers, are now pushed into a shorter period to recover their fixed costs. So pricing levels can be well over US$100 per MWh and we can build a solar plant with a four hour battery to service that peak – we can build that somewhere in the US$50 to US$60 per MWh range.”

The PV Tech POWER feature article forms part of ‘Storage & Smart Power’, ESN’s own dedicated section of the quarterly solar industry journal. The article also looks at some notable examples of solar-plus-storage peaker plants already in operation as well as some of the big proposals in utility and developer pipelines.

“For over 100 years, power plant operators and grid planners have looked their ‘toolkit’ to build solutions that keep the lights on for everybody. It’s very true to say that solar-plus-storage is now clearly a resource that can be considered and it’s more and more included in that ‘toolkit’,” consultant Alex Morris of Strategen Consulting, who was also interviewed for the piece, said.

Read the full article on Energy-Storage.news’ Editor’s Blog here, download the full PDF version to keep from our ESN Resources page, or get the full Volume 18 of PV Tech POWER from our publisher Solar Media, here, free of charge (subscription details required). 

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Undercutting fossil fuels: Hawaii approves 240MW of PV and 988MWh batteries at low cost

A large tranche of utility-scale solar – and storage – projects in Hawaii has been approved by the state’s Public Utilities Commission (PUC), each quoting a cost per kilowatt hour of US$0.10 or under.

In addition to setting up some of the lowest cost per kilowatt hour deals seen in Hawaii, the approvals are also notable for their scale, comprising 247MW of solar PV and 988MWh deployed in six co-located projects. Two further projects remain subject to approvals which would take the total battery storage capacity to be deployed over the 1GWh mark.

Utility Hawaiian Electric issued a release at the end of last week announcing the approvals. The company claimed an “innovative new contract structure” enables the dispatch of energy from the combined solar-plus-storage systems to meet the needs of the grid at any time. In January, Energy-Storage.news reported that the proposed projects will each have four hours energy storage duration.

Due to a combination of pro-environment policies and the simple economics of generating energy on a group of sunny islands with an energy demand profile similar in some respects to other American cities on the mainland, Hawaii has been regarded as a prolific test bed for solar – and latterly storage. Hawaiian Electric said the six projects will help to protect customers from the “volatile prices of fossil fuels”.

Fossil fuels cost around US$0.15 per kWh on the islands, making the economic case for the projects, which are on Hawaii (Big Island), Maui and Oahu, fairly straightforward. Quick approval from the PUC also enabled the developers to “meet the aggressive schedule that was set up to take advantage of federal tax credits,” Jim Alberts, Hawaiian Electric senior VP of business development, said.

Regulators are still reviewing plans for a further 12.5MW PV / 50MWh storage project in West Oahu, as well as a 15MW PV / 60MWh solar array and battery system on Maui. Meanwhile, one of the above-approved projects, Hoohana Solar 1, is to be sited on land currently designated for agricultural use and developer 174 Power Global will need to clear site control and permits, according to the PUC contract.

It’s the latest move forward into dispatchable solar with batteries in Hawaii, which has a 100% renewables by 2045 goal in place, while the Smart Electric Power Alliance (SEPA) found Hawaiian electric cooperative KIUC to be the leader among US utilities for deployment of storage in terms of watts-per-customer during 2017.

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