Learned Behavior: Advances in machine-learning lead the way to true solar + storage profitability

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In the compelling short story “Lifecycle of Software Objects,” author Ted Chiang explores a world in which artificial intelligence (AI) is reared and cared for just as you would a child. He did this because he sees the commitment life-long learning and development as the only true way for AI to ever achieve conscious intelligence. Point being, there is only so much pre-programming can accomplish.

Advanced energy control software companies would agree with this philosophy. It’s not exactly full consciousness, but today’s energy storage controllers are using various machine-learning and artificial intelligence to make savvy decisions that balance priorities of asset generation, optimal storage use, tariff schedules, demand charges and miscellaneous grid responsibilities. For C&I solar + storage projects, these abilities aren’t a bonus, they are crucial to maximize the assets and hit key production and revenue goals. The main questions at hand here:

  • What’s the electrical tariff for the site, and how should the system maximize the cost avoidance or value captured under it over time?
  • What charge and discharge schedule for the asset makes sense for that moment in time?

Misjudging the answers to these questions is likely to be a $100,000 mistake or more in some cases.

Thinking fast and slow

Pason Power provides one of the top advanced energy storage control solutions on the market, and we asked Bryce Evans, head of customer and partner success, to give us a peek into how these systems think.

Pason Power’s autonomous control systems and machine-learning capabilities emerge first from two broad buckets of information processing — micro and macro — which can have conflicting agendas (all humans begin to nod).

Micro adaptations. Every second, the Pason system gathers data from a variety of real-time data sources — from the energy storage system’s power conversion systems (PCS), battery management system (BMS), meters at the site (for the current building load, on-site solar generation and sub-metering on machinery or sub-circuits), and other instrumentation data such as temperature sensors. It’s also consulting weather reports, cloud characteristics and maybe a weather station or irradiance sensor at the site (if applicable).

All of that is driven into a patent-pending forecasting engine, which produces two forecasts: the expected site demand over the next 24 hours and the expected output of the solar array. This is where the learned responses prove their worth as the system considers the forecasts within the context of various site constraints.

“Our system responds in real time to the instantaneous changes in site load among other factors and generates new forecasts every 15 minutes based on all of the information gathered,” Evans says.

Macro adaptations. Over a longer period of time (days, months and years), a model will need to be adjusted within the broader context of the evolving load of the site, potential changes to rate tariffs and new revenue stream opportunities. Pason handles the evolving energy usage patterns at the site by periodically deploying new AI models that are retrained to include the most recent gathered information from the site’s measurements. Most changes to rate tariffs are usually handled automatically by the AI control system, which has the capability to optimize battery operations for thousands of rate tariffs. Pason also deploys updates to the machine-learning model to explore other ways to best produce savings for this site given what’s been learned since the system was commissioned. This process is enabling continuous AI learning.

A primary application of C&I solar + storage is demand charge reduction. The most basic way to do this is to look at historical electrical consumption of the facility and configure the system with a fixed threshold. If site demand ever goes above X, the asset discharges. That requires no machine-learning sophistication.

But, what if you have a really hot month (an increasing likelihood in the age of global warming)? A fixed threshold approach might completely miss the peak demand charge.

“You might start to discharge the asset too soon because the threshold could be too low for this particular day,” Evans explains. “The HVAC system is going to run longer than usual because of the anomalous month, and because of how demand charges are billed, if you let one through the whole billing period is sunk from a cost avoidance standpoint.”

An adaptive system can assess such situations with more nuance.

“We see HVAC loads as a sweet spot for our system, which are highly correlated with weather,” Evans says. “We’ll be able to anticipate that increased need and be less aggressive in our demand charge reduction, counter intuitively, because raising the threshold makes sure we effectively shave the peak. If you discharge too soon, you miss part of the peak, and there’s no changing that now for the rest of the billing period.”

Consider the needs of others

Then there are the batteries themselves. Batteries need to be operated within specific use parameters to meet performance expectations and maintain their warranties, which is hugely important to buyers.

“We see a strong pull from the market for 10-year warranties for the batteries because customers want the modules warrantied in line with the system,” Evans says.

Demand for higher density battery modules at lower price points has driven rapid innovation and resulted in a market full of newer battery modules that don’t have enough testing behind them to know for certain how they will perform. To protect against this risk, battery warranties are getting more restrictive when specifying use conditions like state of charge, depth of discharge and temperature range.

It would be impossible for a non-adaptive control system to account for the unknowns of the battery’s performance while still adjusting the usage to not void the warranty.

“Our system has to keep all of that in mind while operating the asset and co-optimize all of these constraints,” Evans says.

Seeing the bigger picture

Intelligent energy storage control systems also mean more value stacking opportunities for system owners. Example: A system is designed with demand charge reduction as the primary application. Late in the monthly billing period, the system might reasonably surmise the highest peak for that month was already hit. Maybe instead of peak shaving that day, an intelligent system will perform PV self-consumption or TOU arbitrage instead.

Knowing a controller has the smarts to put every asset to optimal use, an asset owner might want to plan for it in system design by adding a little more storage than a system would need for just demand reduction.

Evans hints that Pason is preparing for that with a new application based on value stacking. The good news is, you don’t need to jump right in and buy those batteries now. The machine-learning of these systems will only improve over time as more data is compiled, and all of those smarts will be pushed back into the brains of your controller (software updates are included with the annual subscription fee).

Playing nice with others

Deploying all of this is becoming easier for novice, mid-market solar installers too. Consider Stem, another big name in machine-learning storage systems. Since 2012, Stem has captured data from its systems on a one-second basis to feed its predictive analytics, machine-learning and grid-edge computing AI. The company has largely functioned as its own project developer, becoming one of the top storage companies in California by combining its advanced AI Athena platform with the SGIP rebate to uncover big savings for customers.

Solar installers can now put all of this accumulated knowledge to use as Stem is now looking to partner with solar companies to deploy even more systems in the C&I mid-market through its Stem Partner Network.

“Through the Stem Partner Network, we deliver end-to-end partner support and services, such as training, project development advisory services, marketing and lead generation, deal support and access to a partner portal with educational resources,” Christy Martell says. “We worked with a few developers to help them understand how to design storage into their projects and ultimately bring more value to their end customers.”

Stem partners with the strongest names among solar providers across the United States to unlock new value from solar projects for their customers, backed by performance guarantees. To that end it has partnered with Energy Toolbase to provide developers an efficient path to design systems and map out projected savings.

Typically, Stem will work with the developer to suggest a combination of value streams, and this is especially valuable going forward as the market grows for complex grid services or utility programs such as demand response.

“We have seen an uptick in deal size going into 1 to 4 MW, and that’s continuing to grow,” says Than Tran, VP of global demand generation and marketing for Stem. “As we grow larger, we want to bring in other strategic providers to help us build a comprehensive solution to address all C&I customers.”

Pason Power recently partnered with Chint Power Systems (CPS), which integrates Pason Power’s software into its Energy Storage System as the exclusive platform for commercial and industrial (C&I) customers.

Smaller storage systems

Smaller storage systems leave less room for testing integrations in the field, which is why Pason Power partnered with CPS to pre-integrate their systems.

“CPS is bringing the entire solution to the commercial segment,” says Casey Miller, VP of products and business development for CPS America. “We are enabling solar installers to get in the storage game by offering their commercial building customers a turnkey storage solution with clear economic benefits and managed risk.”

This integrated energy storage solution fosters a simplified, single-source procurement process for customers rather than having to rely on multiple vendors. Hardware and software will arrive pre-built and pre-configured, making it easy for developers to install so customers can quickly begin seeing the benefits. Why this integration is important:

  1. The bankability of the firms involved is a huge factor in decision making when procuring storage components. Chint is a strong brand with a reputation for reliable products and excellent service, and Pason has been around for 40 years.
  2. The practical advantages. “By partnering with Chint, we can pre-integrate our control system into their product, do all of our testing in our facility and then sell a turnkey product that can be installed in half a day,” Evans says. This means decreased install costs, decreased commissioning costs, higher reliability and no misfires in the early billing periods that equate to missed savings opportunities.
  3. Because Pason’s modeling and energy management software were designed together, they use the same logic which ensures a truly integrated system. This enables users to pre-select the hardware which also improves accuracy when modeling the system and economics.

“Pason Power is doing the little things right to make the solution easy for customers,” Miller says “The net-net is our customers get the predicted economic benefits over the full life of the solution, not just year one or two.”

— Solar Builder magazine

Stacks on Value Stacks: The large-scale solar plus storage is coming together


Large-scale solar + storage is on the drawing boards of a host of major EPCs, with the current round of demonstration plants leading to wholesale installations by 2020, say several industry players.

“While we are early in the deployment cycle for large-scale solar + storage, we expect a ramping at the end of 2020, then an acceleration of the market with scale in 2021,” says David Stripling, NEXTracker’s global manager of storage products. This timetable is a year or two ahead of what he expected several years ago, he notes.

The predictions for solar + storage range widely, but Stripling suggests that the independent system operators (ISOs) across the country are a good indicator. “My own research on interconnection queues across the five ISOs suggest solar + storage will amount to 20 GW by 2023. For a general order of magnitude, you could say that over the next five years, a 5-GW target will be easily achieved.”

The United States will grow to be the largest global market for solar + storage this year, where peaking capacity requirements are driving procurement, opines IHS Market in arecent study.

Utility-scale solar + storage projects now are online or being built in Arizona, California, Hawaii, Indiana and Florida, and the list grows. In March, NextEra Energy said it would build the Florida Power and Light (FPL) Manatee Energy Storage Center’s battery system, with four times the capacity of the world’s largest battery system currently in operation. The 409-MW/900-MWh battery system at Manatee will be added to an existing 74.5-MW solar plant on the west coast of the state near Tampa.

“Replacing a large, aging fossil fuel plant with a mega battery that’s adjacent to a large solar plant is another world-first accomplishment,” said Eric Silagy, CEO of FPL, in a March announcement. The utility plans to accelerate the retirement of two 1970s-era natural gas generating units with the Manatee facility.

Similarly, Pacificorp says, “sharp declines in battery storage have occurred more recently, making it increasingly economic to pair variable renewables with storage at lower cost than existing coal-fired generation.”

More aggressively, 8minute Solar Energy, the largest solar + storage developer in California, “will maintain its focus on delivering exceptional value and executing on the nationwide solar + storage projects under development, now surpassing more than 10 GW,” said Tom Buttgenbach, the company CEO, in an end-of-the-year statement.

“We have two 400 MW solar + storage plants proposed now, and going forward, 300 MW will likely be an average size,” says Jeff McKay, the marketing director for 8minute Solar Energy.

One way the adoption of the technology will roll out is through a broader deployment broken into stages of saturation, such that storage products may be designed, optimized and developed for each stage, Stripling says. “One future grid scenario that NREL came up with is smart controls and storage, so deployment in stages allows us to look at the total grid, based on policy and market forces,” he says.

Extended duration

Energy storage combined with solar PV can address a large number of traditional problems, such as energy issues — like time shift, arbitrage, curtailment, transmission congestion — and power issues — like frequency response, ramp rate control and renewables smoothing. Such value factors stack up to build a case of economic feasibility, but the key feature for large-scale is eight to 16 hours of storage, says Stripling.

“That duration is going to be the biggest opportunity for solar + storage over the next 10 years,” he reckons.

To achieve long duration and high cycle storage, or bulk storage, will require some combination of flow batteries, pumped hydro and compressed air. Of these, flow batteries seem to have the strongest lead, and among flow battery chemistries, vanadium may be the top contender.

The vanadium redox battery (VRB), also known as the vanadium flow battery (VFB) or vanadium redox flow battery (VRFB), uses sulfuric acid and water and can infinitely charge and discharge, returning to its original core state without degradation.

Other leading flow battery chemistries include iron-chromium batteries (ICB) and zinc-bromine batteries (ZNBR), according to the Energy Storage Association.

PPAs leading the way

As storage becomes a standard partner to PV, power purchase agreements (PPAs) will grow more flexible to accommodate the various value streams of storage. Such PPAs have been called hybrid PPAs, where revenue streams and risks are integrated in order to meet a limited risk appetite from infrastructure investors and asset owners.

“Hybrid PPA structures include route-to-market services for balancing the sale of the physical spot electricity production and may include all relevant risks and revenue streams from individual installations or multiple assets,” said Anders Bauditz, the director of origination at Neas Energy.

Bauditz says it’s not an option to offer outright fixed prices or floors on durations longer than market liquidity will allow, which means they need to be creative in structuring deals where revenues and risks can be balanced out to meet the risk profiles and investment horizon of the investors.

“It resembles putting a complex and mixed puzzle — of both physical and financial pieces — together,” he says.

One element of such hybrid PPAs that seems ripe for adoption in the U.S. market is time-of-use terms. McKay notes that hybrid PPAs are still evolving but 8minuteenergy is using them to guarantee energy supply between 7 a.m. and 11 p.m., for example, and Stripling suggests NEXTracker could address special PPA rates for 5 p.m. to 9 p.m. generation.


Photo courtesy of NEXTracker.

Cost declines with volume

With or without the new battery production that Tesla has promised the market, costs are declining. In Nevada, NV Energy is closing a coal plant in 2021 by contracting for 401 MW of new solar capacity and 100 MW/400 MWh of storage with 25-year PPAs in the low- to mid-$30/MWh range, notes the Institute for Energy Economics and Financial Analysis (IEEFA). The projects are being built by NextEra Energy and Cypress Creek Renewables.

Similarly, in its 2017 bid solicitation in Colorado, Xcel Energy received proposals for 66 projects of either solar + storage or wind + solar + storage, the IEFFA notes. In total, the proposals added up to more than 14,000 MW of new capacity at a median price of $30 to $36/MWh, IEEFA found.

“By 2021, we will definitely blow through the $30 floor to the $27.5 to $30 range,” Stripling predicts, and McKay says 8minuteenergy “has already broken through the $30/MWh price on large solar + storage,” with several plants under development now.

Part of the cost reduction process will arise from the strategic partnerships between large EPCs and storage solution providers. For example, in May, ENGIE North America announced the acquisition of Genbright LLC of Hingham, Mass., a company specializing in the integration of distributed energy resources (DERs) into wholesale electricity markets. ENGIE’s acquisition of Genbright ensures that the company is positioned to deliver capacity, energy and ancillary services in markets operated by regional transmission organizations and ISOs as these rules are rolled out.

“This acquisition paves the path toward realizing the stacked-value stream potential of energy storage referred to by so many in the energy industry,” says Tim Larrison, chief financial officer of ENGIE Storage.

Charles W. Thurston is a freelance writer covering solar energy from northern California.

— Solar Builder magazine

Burn before you build: The importance of destructive battery testing

burn test

Batteries solve the problem of intermittent solar irradiance and reliable clean energy. With energy storage systems, PV project owners and off-takers can continue using solar power long after the sun sets. After years of hype, battery systems are finally gaining traction in major markets, especially in states such as Hawaii, which no longer offers net energy metering to new residential solar customers. Yet energy storage systems remain a niche application in most of the United States and across the global solar market.

Safety is an important factor preventing adoption of solar + storage. Lithium-ion batteries, the dominant chemistry in energy storage systems (ESS) today, can pose significant risks to life and property when they are poorly designed, installed or maintained. These batteries contain volatile hydrocarbon electrolytes that can cause large, uncontrollable fires or explosions in certain conditions. Fire codes and standards designed to make ESS safer are currently being developed and adopted, but there is significant uncertainty and lack of awareness regarding these safe practices.

We now are facing the consequences

Since May 2018, nearly two dozen large-scale ESS fires have occurred in South Korea. On April 19 this year, an explosion and fire at an Arizona Public Service (APS) battery factory hospitalized eight firefighters, with three requiring airlift evacuation. APS took steps to shut down two of its other battery systems immediately following the event to assess safety concerns. These incidents are raising justifiable alarms with code officials and authorities having jurisdiction (AHJs), the fire service and utilities across the United States and beyond. Many developers, independent power producers and utilities are temporarily pausing operations to reassess the safety of their own systems following these alarming incidents.

The role of burn testing

Fire codes such as the National Fire Protection Association (NFPA) 855 will be instrumental for improving ESS safety. While NFPA 855 and other codes are nearing completion, they are still years away from broad adoption. To deploy energy storage systems safely in the meantime, the industry needs additional test data that proves and validates system response under non-ideal conditions and that helps define product standards.

PV Evolution Labs (PVEL) and its partners conduct large-scale destructive battery testing, or burn testing, that can address safety concerns, especially in the absence of regulation. The testing reveals how specific energy storage systems behave during failure by simulating realistic field failure conditions during battery operation. Burn testing results are used to assess installation safety and to help first responders determine the best ways to react when failures occur.

With better information about how failing batteries behave, stakeholders can identify the risks that are most likely to emerge for first responders, buildings and other infrastructure if an incident occurs. Developers and system owners can therefore design and implement better ways of managing and containing fires and explosions. For example, test results can be used to determine the level of ventilation or suppressant needed, which are both required in storage-equipped buildings or containers. Test results can also determine whether or not water or other nontraditional agents are adequate to contain fires.

How it works

Large-scale destructive battery testing starts with understanding the basic composition of energy storage systems. Batteries are comprised of cells — in some cases thousands of cells. A certain number of cells are placed in a single structure called a pack or module. These modules are then assembled in series and parallel combinations to form a full battery system. Compromising any one of the components at the cell, module or system level can result in the escape of flammable gases that may explode when exposed to oxygen and an ignition source. Fires usually originate in a single cell, but they can quickly propagate from cell to cell (an effect named thermal runaway) if the battery system is poorly designed.

PVEL follows the UL 9540A Method for Evaluating Thermal Runaway Fire Propagation in Battery Energy Storage Systems. The standard requires destructive testing of the battery at the cell, module, rack and full system levels. In each case, the cell is heated or otherwise forced into thermal runaway, releasing off-gas until the reaction results in fire, explosion or other thermal event. Dozens of variables related to off-gas composition and release rate, temperature, heat flux, heat release rate and explosion risk are collected at each level.

Burn testing provides insights into where a fire is likely to spread, how quickly and any explosion risks that may exist. This information helps first responders create proper emergency action plans and standard operating procedures for safe, rapid incident response — whether that is to quickly apply water or another extinguishing agent to the fire, or to simply allow it to burn and instead focus on containing the conflagration to a finite and defined area. The results also guide the design of suppression and detection systems, explosion modeling and protection and siting requirements.

Future outlook

Without burn testing, safe ESS deployment will not be feasible. Insurance companies are also taking note of ESS risks because of the fires in South Korea and Arizona. It is reasonable to believe compliance with standards will soon become a requisite for financial backing and insurance.

The standards and codes the industry needs for ESS safety are a work in progress. Although burn testing is only required in a few jurisdictions today, PVEL anticipates that it will be mandated across the vast majority of U.S. jurisdictions by 2021. The codes that we expect to be adopted also require large-scale fire testing to overcome a number of extremely conservative spacing and sizing requirements for battery systems.

With the right information, the industry can leverage this promising technology without undue risk to life or property, even before much-needed standards and codes are refined, implemented and required.

Michael Mills-Price is head of inverter and energy storage business at PV Evolution Labs (PVEL).

— Solar Builder magazine

The Riddle of Resilience: What’s important for society and the economy and yet has no value?

The Apollo Elementary School in Titusville, Fla

The Apollo Elementary School in Titusville, Fla., lost power during Hurricane Irma and used the solar + storage system to power emergency lights and charge cell phones. Photo Credit: Nick Waters, Florida Solar Energy Center

The Union of Concerned Scientists convened a group of diverse stakeholders in Chicago late last year to discuss the equitable deployment of energy storage. The participants developed a set of consensus principles for storage deployment that elevate the critical importance of community-led clean energy solutions. Listed second in those principles was improving resilience. From their report:

“2. Ensure that energy storage helps make residents and communities more resilient to both human-caused and natural disasters — which will become more frequent and severe due to climate change — by deploying local, onsite power to keep essential services operating during extended power outages and by restoring power after a disaster.”

That’s the buzzword in renewable energy now: resiliency. Resiliency means the “robustness and recovery characteristics of utility infrastructure and operations, which avoid or minimize interruptions of service during an extraordinary and hazardous event.” A resilient system is built with the understanding that random emergency outages can occur, is prepared to minimize their impact when they occur and is able to restore service quickly, while being nimble enough to improve performance in the future.

This is not the same as reliability, which remains a hallmark of the U.S. electrical grid. One could argue though that our long-term strategy to ensure reliability was a contributor to our current concerns about resilience — the large-scale centralized burning of fossil fuels contributing to global warming, which is causing more frequent extreme weather events, thus necessitating plans for more distributed renewable energy resources. Mother Nature is not without irony.

Resiliency is being cited in a ton of regulatory project plans and rule-makings. The National Association of Regulatory Utility Commissioners looked at the various instances of resiliency planning in a new report, The Value of Resilience for Distributed Energy Resources: An Overview of Current Analytical Practices. In it, NARUC reviewed the methodologies used to quantify the value of energy resilience, particularly as it relates to investments in distributed energy resources in both regulatory decision-making and non-regulatory cost-benefit analyses. The group wanted to determine if, and how, a value of resilience was calculated and applied. Some examples:

  • Following Superstorm Sandy, the most high profile example of the need for better resiliency, the New Jersey Board of Public Utilities considered new grid hardening investments, approving more than $1 billion, with costs to be recovered by PSE&G through a dedicated Energy Strong Adjustment Mechanism.
  • The Maryland Public Service Commission created specific resilience surcharges for two investor-owned utilities (IOUs).
  • New York State’s Reforming the Energy Vision (REV) proceeding connects resilience with the need for DER expansion.
  • The California Public Utilities Commission (CPUC) recently mandated that IOUs in the state pursue at least one pilot for DERs to demonstrate distribution grid services — including “resiliency (microgrid) services.”

The problem NARUC discovered is there’s no real consensus as to what tangibly constitutes “resilience” and even less understanding of how it should be valued and financed (and by whom).

Value shopping

Valuing resiliency is difficult because discussions quickly turn into abstract existential quandaries. What’s the value to you of avoiding the potential of going without water for a week? What’s the value of a human life?

When NARUC did a comprehensive review of those proceedings mentioned above along with a bunch more, the group discovered over and over again that “resilience is not quantified or valued in a way that impacts decision making. Resilience is consistently identified as an important but intangible benefit of microgrid development. Resilience is unquantified in the formal regulatory proceedings surveyed.”

NARUC examined four specific methods they found in non-regulatory proceedings for valuing resiliency 1) contingent valuation, 2) the defensive behavior method, 3) the damage cost method and 4) input-output modeling. The report goes into serious depth on those four, but they each fell into either an economy-wide vs. bottom-up approach.

  • Bottom up approaches for assessing value involve surveys or interview data that ask customers about their preferences. How much are you willing to pay to avoid power interruption or to be guaranteed a higher level of supply security? This method feels suspect though. Do ratepayers know how to value any utility investments? Another bottom-up approach is using other real world data as a proxy for revealing those preferences, such as the costs associated for purchasing and maintaining a backup generator or by using a damage cost calculation, like FEMA’s Benefit-Cost Analysis (BCA) tool.
  • Economy-wide approaches on the other hand analyze the effects of power interruptions on regional economies using indicators such as economic output and employment. Some economy-wide approaches rely on models that reflect the financial flows and transfers within a geographic area. The economy-wide input-output modeling (using the commercially available IMPLAN database) showed the most promise for estimating the impacts of longer-term duration interruptions, examining effects of power interruption scenarios for up to seven days, including additional impact on labor income at the county and state levels. The researchers noted this might not be scalable enough to sufficiently calculate the economic impact of smaller-scale resilient DER systems and is instead best suited for microgrids serving many C&I facilities.

In fact, none of the methods analyzed in the report met the four specific criteria NARUC used to evaluate the resilience valuation methodologies, which were ease of use, scope of outputs, geographic scalability and power interruption duration analysis capability.

“These results highlight uncertainties as to whether the resilience provided by DER investments represents a public or private good,” the report stated. “The report finds no standardized approaches for determining a specific value of resilience when making investment decisions.”

Designing a business case

Yes, resiliency is hard to put into a spreadsheet, but spreadsheets also seem to keep pumping carbon into the atmosphere. The good news is resiliency projects don’t have to be pure public-good charity causes. Dr. Imre Gyuk, director of energy storage research with the U.S. DOE-OE, presented two ways to solve this riddle so far on a recent Clean Energy Group webinar:

1. Pinpoint project sites with clearly identifiable revenue streams.
2. Select a suitable method to place a value on resiliency for that location.

The NARUC report suggests No. 2 is still in its infancy, but compelling resiliency projects are being built around the country using No. 1.

“Resiliency is unmonetized, so the project often needs to be justified through monetized benefits,” Gyuk said. “But resiliency, when the term is included within a project’s objectives, is often a primary reason for a project.”

Unlike other traditional backup power systems utilized in emergency situations, solar + storage assets don’t sit idle and can therefore perform grid services and cut down on electric bills.Developers, non-profits and pro-active jurisdictions are teaming up across the country to develop projects with resiliency functions at their core, but that also have multiple benefit streams to build compelling business cases.

“If you have a large load and are looking at a term longer than eight hours, you should have three systems — renewables, storage and transmission,” noted Dan Borneo, engineering program and project lead at Sandia National Laboratories. “That makes the most sense.”

As an example, Gyuk highlighted a project the Vermont Public Service Dept., the Department of Energy and Green Mountain Power collaborated on — a 4-MW/3.4-MWh storage system with 2-MW PV integrated by Dynapower on a brownfield site. The system can be islanded to provide emergency power for a resilient microgrid serving a high school or emergency center. The project’s resiliency function is to power an emergency shelter, which is obviously not usually the case. Thus, the system primarily provides its ancillary grid services functions.

The project is paying for itself via two levers of demand charge reduction. The battery is used to target annual and monthly peaks, resulting in $600,000 in savings in one year.

The pilot project has performed so well that it has generated five other storage projects, which are all now viewed as a “Vermont Storage ecosystem.” Gyuk is specifically trying to identify other locations for their storage ecosystem potential when developing solar + storage-focused microgrids to bolster resiliency, having all of them add up as pieces of a larger whole.

Superstorm Sandy

Superstorm Sandy is the most high profile example of the need for better resiliency planning and valuation strategies.

Case study: Oregon’s EWEB project

The webinar Gyuk presented on, “Oregon’s New Energy Storage Project for Resiliency and Cost Savings,” detailed the development of a solar + storage project in Eugene, Ore., that will provide backup power for emergency services, as well as cost savings and electricity services to the municipal utility, Eugene Water and Electric Board (EWEB).

As noted by EWEB’s Matt Ibaraki, the entire Northwest is overdue for a potentially devastating earthquake, and EWEB has heeded these warnings. The idea here was to construct a system that would power a water well and community shelter in the event of such an emergency. EWEB serves 90,000 users with both water and electric utility services.

“Originally we looked at all utility-owned sites, but then instead we went to distributed wells because we wanted parking and flow through to pick up water, but that brought up interesting issues concerning behind the meter projects,” he says, although later noting that utility-owned sites would be preferable when possible.

Howard Elementary School ended up being picked because of how it met the emergency planning objectives and penciled out a revenue justification by reducing the school’s demand charges.
For these sites, EWEB wanted something scalable, turning to NEC Energy Solutions for a containerized 500-kW/1,000-kWh battery energy storage system. It integrates the controls, DC medium (li ion) and the balance of plant and conversion in one outdoor enclosure.

“We wanted to get water as long as possible considering constraint on size,” Ibaraki said. “If we had peak solar during the disaster, which may be less likely, but if we had it, we could stretch it for a couple weeks, but it depends on what you’re planning for. If we lose transmission for these well pumps, we were looking at one or two weeks.”

Sandia will be monitoring the use cases to better understand the economic value of a solar + storage project that is resiliency first.

“It’s like an insurance policy,” Borneo said. “Look at it through the eyes of actuarial science, the same way you’d value a policy. It’s in the early stages. We’re now looking at the lost production costs during downtime as one way to get at it.”

This system in Oregon is a great example for one possible future predicament, but the best takeaway from all of the above is the need to define resiliency, identify its needs and risks in your area and get creative.

Southeast Resilience Snapshot

In a new report series, Resilient Southeast, Clean Energy Group asked: Does solar paired with battery storage make economic sense for strengthening the resilience of cities in the Southeast? Spoiler Alert: The answer is yes. Here is a snapshot of the five cities evaluated in the report ranked from best to worst in terms of solar + storage economics and regulatory barriers.

Solving the riddle

After reading all of these reports and listening to these webinars, I found no magic bullet, but I will conclude with what I found to be the most practical tidbit. In the Oregon case study, Robert Del Mar, senior project manager at Energy Trust of Oregon, said one of the biggest barriers to new resilient solutions that incorporate solar + storage is a lack of understanding. Engineers at a utility aren’t very likely to pursue a design that doesn’t feel 100 percent comfortable. This is why he and the Oregon Department of Energy launched an education campaign as a key organizational strategy for deploying more storage-focused microgrids. They visited utilities in Oregon and Washington to meet with engineers and discuss technical information for building and planning these facilities — digging into stuff like switch gear, nuts and bolts, sizing, single line diagrams, islanding and so on — instead of how to fund them.

“We recognize funding is a big piece of this, but it’s not what we were tackling in this workshop. We wanted to overcome technical hurdles at the small utilities because there can be a fear of batteries before you even talk about cost. We want to build confidence and excitement by expanding technical knowledge.”

This suggests that, like all good riddles, an answer is already staring us in the face. Someone smart just needs to see it and tell the rest of us.

Chris Crowell is the managing editor of Solar Builder.

— Solar Builder magazine

Send in nominations for the Solar Builder Project of the Year Awards

Solar Builder Project of the Year awards

Attention all solar industry stakeholders: Each year, Solar Builder seeks to highlight the most outstanding PV projects in the solar industry. Any PV project is eligible — big or small — and we want you to tell us about them.

Was your installation innovative in some way? Did it help a community? Does the site just look really awesome? If it’s inventive, interesting or impactful, it will be considered for our annual Project of the Year awards.

How to nominate a project:

Step 1: Head to www.solarbuildermag.com/project-awards

Step 2: Fill out the form by Aug. 31, 2019 (construction completion date must fall between Oct. 1, 2018 and July 31, 2019).

That’s it! At that point we will gather the submissions, choose a field of the best nominees, and then let our readers vote on which project stands out the most during the month of September.

The top vote-getters will be awarded with Gold, Silver and Bronze designations. All remaining nominees are eligible to be selected for an Editor’s Choice award. Every winner will be featured in our November/December magazine, with the Gold Project of the Year earning the cover story.

Pro tip

We leave the criteria for choosing winners vague because we want the project submissions themselves and the stories conveyed to lead the way. Spare no detail in explaining what was unique or outstanding about the project. Top vote-getters last year stood out for everything from their large-scale financial complexity to their creativity in small-scale, off-grid problem-solving. Back in 2017, the Project of the Year was located on tribal lands. In 2014, the winner was a brewery. What wins this year is anyone’s guess. All we know for sure right now are the losers: Those who read this and don’t send in a nomination.

— Solar Builder magazine