Impact of Battery Energy Storage Solutions

In the next 5 years, the US will be facing resource adequacy challenges due to a combination of high demand growth, thermal generator retirements, not enough energy storage, and generator interconnection delays. The “not enough energy storage” issue appears because the energy transition is replacing base load generation (high-capacity credit) with variable #renewableenergy (VRE) resources (low-capacity credit). Solar and #windenergy assets need to be combined with energy storage to approach the capacity credit (CC) of the thermal resources being replaced. Capacity credits capture what fraction of a resource’s nameplate capacity can be expected to contribute to meeting demand during peak periods. In November 2024, NREL published a report on CC values of #renewableenergy and #energystorage. The 1st figure below shows average CC’s across technologies from 2026 to 2050. Between regions and scenarios, CC’s differ widely, but still, this is instructive. #Solar CC’s are low and decline as penetration rates increase, which drives a gradual shift of peak net load hours to hours with little solar generation. The wind CCs over time are explained by a combination of project development cycles and penetration levels. Energy storage CC’s are high, and 4-hour #battery capacity credits range between 66% and 100%. The 2nd figure is from FERC’s 2023 Market Report and shows the nameplate capacity net additions & retirements from 2013 to 2023 by resource type. Zooming in on MISO, note that resource additions will only cover retirements if they have similar capacity credit (they don’t), and negligible #energystorage was added. A back of the envelope calculation demonstrates why NERC’s Reliability Assessment (Dec 2024) has characterized MISO as “High Risk” to fall below established resource adequacy criteria. Assumptions were made to simplify this math (MISO’s accreditation for resources is highly seasonal, controversial, and in flux). Remove 26 GW of coal (85% CC) and 2 GW of nuclear (95% CC) means MISO was down 24 GW over the period. Add 17 GW of wind (22% CC), 8 GW solar (25% CC), and 2 GW Nat Gas (80% CC), and this adds back 7.3 GW. This is a net loss of over 16.5 GW of “real” capacity. Obviously, this is not sustainable, especially considering the 9 GW of load growth expected in MISO by 2029 (Grid Strategies). Similar scenarios are playing out across other markets in the US. Delaying thermal retirements is the current answer, but retirements typically happen when assets are no longer economically running. If they suddenly become economic, it probably means they are getting paid more (i.e. electricity prices will rise). This also means #sustainability progress goes in reverse. A better solution is to fix IX processes, carefully plan for load growth, and add more energy storage along with VRE’s. Indeed, the NREL report shows the average CC of 4-hour #energy storage stays above 70% at penetration levels past 50% of peak load. References in comments.

On June 24th, ISO-New England (ISO-NE) hit a peak load of 26,024 MW at 7pm, the highest load experienced since 2013. With load marginally higher than forecast and a spike in outages (primarily natural gas units), real-time locational marginal prices (LMPs) were over $1,000/MWh, over twice the day-ahead market (DAM) price.  Power Advisory analyzed the potential impact that additional battery energy storage system (BESS) and offshore wind capacity could have had on these ISO-NE RTM LMPs (figure below) as well as the market revenues that these two generating resources would have realized. (table below). The figure shows the reduction in real-time LMPs from 5,000 MW of additional BESS capacity. The table shows the: (1) $/MWh real-time LMP reduction attributable to 1,000 and 5,000 MW of additional BESS and OSW capacity: (2) value of these savings on a $/kW basis; (3) net energy revenues the projects would have earned; (4) the net value of the project, which is the sum of (2) and (3); and (5) how these savings compare to the estimated revenue requirements for these two technologies. The savings on a $/kW provides an indication of the indirect benefits (i.e., wholesale price reductions) for these technologies and contrasting the savings on a $/kW basis with the revenue requirement provides an indication of the relative value of these resources. For the BESS we assumed “perfect information”, i.e., that the party dispatching the BESS units would schedule to operate in the hours with the highest RTM LMPs. Clearly, this is overly optimistic. However, the highest RTM prices were generally well correlated with the highest load periods suggesting that an operating strategy of focusing output during the top 4 load hours would have served the BESS operators well. There’s also the issue of whether the BESS operators would have elected to participate in the DAM (rather than the real-time market) to effectively lock in the energy arbitrage margins offered. Regardless, even if they participated in the DAM, this capacity would have yielded significant price reductions. Our analysis also indicates that offshore wind would have made a major contribution to lower RTM LMPs. We estimate that the capacity factor for offshore wind during the June 23rd and 24th heat wave would have been about 48.5% given prevailing wind speeds. #offshorewind #batteries

This spring, California hit a new milestone: battery storage delivered more than 10 GW of instantaneous electricity—2 GW more than last year. Last week, on June 17th, we were even close to 11 GW with 10.9 GW of batteries discharged at 8:00pm. Even more striking: during those peak hours, batteries became the largest single source of electricity on the grid, outpacing gas, solar, and wind. Is that good news? Yes… and no. ✅ Yes, because batteries are stepping in when solar drops off in the evening, helping avoid additional gas-fired generation. They store excess solar energy during the day and release it when demand peaks—exactly how a clean grid should work. ⚠️ But there’s a catch. As summer heats up, air conditioning demand rises, and there’s less surplus solar left to charge the batteries. That’s why we often see the biggest battery discharges in spring or fall, not in July or August. So while solar + batteries is a big part of the solution, it shouldn't be the only one. To get the most out of battery assets—both for the grid and for returns—accurate solar generation and price forecasts are essential, along with smart optimization across markets. Gone are the days when the playbook was simple: charge at midday, discharge in the evening. In today’s market, battery dispatch is anything but routine. And building those tools is an exciting challenge!