By Jill Feblowitz, Feblowitz Energy Consulting
The utility industry is just beginning to discover energy storage’s potential to meet the needs of markets, grid operations and customers. Technology has advanced and prices dropped and are expected to continue to do so. Regulation, funding and the penetration of renewables have tremendous influence on utilities’ commitment, experimentation and planning. Representatives from three utilities-Southern California Edison (SCE), Pacific Gas and Electric (PG&E) and Oncor-recently shared their experience.
Even though Tesla raised the visibility of residential back-up storage with the general public, energy storage can bring much more to the industry. The Rocky Mountain Institute (RMI) laid out 13 potential services that energy storage could provide to the wholesale markets (RTO/ISOs), utilities and customers in its report “Economics of Battery Energy Storage” published in October 2015.
RMI reviewed 13 studies and found the value of energy storage ranged from $0 to $200 per kW-year, with the outliers, distribution deferral and transmission deferral, coming in at $500 per kW-year and $900 per kW-year, respectively. The study also found that the value of energy storage was higher when units could be used to provide multiple or “stacked” services. Figure 1 provides a useful categorization of the applications of energy storage.
The Regulatory Landscape
Panelists from SCE, PG&E and Oncor, who spoke during the DistribuTECH 2016 Conference and Exhibition panel “Energy Storage and the T&D Grid,” provided insight into the economic impacts and the planning models for progressive energy storage deployments at their utilities. Each had his own take on uses applicable to his grid configurations and markets. It was clear that one size does not fit all.
Legislation and regulation will play a significant role in how quickly energy storage is adopted. For SCE and PG&E in California the regulatory landscape is positive. California has been early to the game, establishing a mandate for the investment in energy storage. Under AB 2514, the California Public Utility Commission (CPUC) adopted a total energy storage procurement target of 1,325 MW, allocated to each of the investor-owned utilities (IOUs) in four biennial solicitations through 2020. As part of the Energy Storage Procurement Framework and Design Program, which is an ongoing regulatory process, the CPUC is setting requirements for allocation of storage investment across domains (transmission, distribution and customer), developing a consistent evaluation and reporting across utilities, approving eligible storage technologies, approving utilities’ storage investment plans, and determining cost recovery. At this time, utility ownership cannot exceed 50 percent of storage across all three (San Diego Gas & Electric, SCE and PG&E) grid domains.
Both PG&E and SCE have the same goals for energy storage-580 MW of storage planned by 2020 and operational by 2024. The storage will be split with 53 percent in transmission, 32 percent in distribution and 15 percent customer connected. There may be some flexibility in the allocation between transmission and distribution.
In Texas, the most recent version of the Title II of Public Utility Regulatory Act defines electric energy storage equipment or facilities that are intended to be used to sell energy or ancillary services at wholesale as generation assets. Oncor, as a regulated transmission and distribution company, cannot deploy energy storage for market purposes. Under the act, transmission and distribution companies can use storage only for reliability and outage mitigation. Because the legislature meets every other year, the next chance to change legislation will be in 2017.
Prior to the California storage mandate, in 2010, SCE launched a dedicated energy storage strategic planning effort. As part of that effort, SCE conducted an internal study to evaluate the economics and feasibility of energy storage. The effort looked at operational uses (by domain and output duration), bundling of operational uses as applications (variable distributed generation integration, ancillary services, microgrid formation, on-peak intermittent energy smoothing and shaping, etc.) and matching these with best fit technologies. SCE detailed the study results in a white paper titled “Moving Energy Storage from Concept to Reality,” which is available on the utility’s website. The utility found that cost effectiveness for most applications would not occur until 2020. The more cost-effective applications targeted peak capacity over number of hours used. In addition, SCE found that the closer energy storage is to the customer, the more likely it is that peak capacity infrastructure is deferred.
With the drop in the cost of storage, Oncor launched an initiative to study the economics of grid-integrated storage deployment in the ERCOT market. The company wanted to know if it could take advantage of market arbitrage and capital investment deferrals without increasing rates. The study, “The Value of Distributed Electricity Storage in Texas,” conducted by the Brattle Group and published in November 2014, examined cost-effective storage from the perspective of the wholesale markets, customers and society as a whole. The findings were similar to those revealed in the RMI study mentioned earlier-there is a need to combine services to achieve value. According to the Oncor-commissioned study, the break-even point for grid integrated distributed electricity storage would be $350/kWh with diminishing returns at 5,000 MW of storage on ERCOT. The benefits to customers would be in reduced bills and better reliability in areas where storage is installed. It is unlikely, however, that merchant developers of storage could achieve a desired return on investment because 30 percent to 40 percent of the benefits of storage come from transmission, reliability and distribution functions; wholesale market arbitrage would not earn enough.
Where are They Now?
PG&E’s guiding principles for procuring storage are grid optimization, renewable energy integration and greenhouse gas reduction. The utility has completed the first cycle of competitive procurement through a request for offer (RFO) and recently released a second RFO with procurement decisions coming at the end of this year.
SCE got a head start on storage due to the requirement to obtain 50 MW of storage, which needed to be met quickly due to constrained capacity. The utility has issued RFOs for third party storage behind the meter and for transmission and distribution. This latest RFO is written to secure enough storage to allow SCE to skip the next RFO cycle. The bidders’ responses were surprisingly attractive. As for utility-owned storage, the company has a 2.4 MW distribution pilot under development, as well as distribution demonstration projects totaling 8 MW.
Oncor is focused on using storage for feeder reliability. The company has issued a request for analysis to determine which feeders to target. In addition, a request for proposal to study ownership and services models includes 87 selection criteria. On the ground is a demonstration project to support homes during outages. In addition, five 25 kW and 25 kWh batteries are installed near transformers in Dallas neighborhoods. So far, more than 1,000 minutes of outage have been avoided.
Additional Work Needed
In many ways, energy storage remains an emerging technology, presenting challenges to be worked through. Those challenges include:
• Integrating storage. At this point, there is general agreement that control systems can handle one or two battery systems. It is unclear, however, what happens when many more units are integrated across a “fleet,” including storage behind the meter. Control systems are not ready for that yet and additional communications infrastructure must be in place.
• Dealing with heterogeneity. Oncor is grappling with integration of a heterogeneous group of batteries and distributed energy resources with different control systems. In its Lancaster microgrid project, the company integrated 35 storage, solar and other equipment vendors to assess interoperability.
• Contract vehicles. There are ownership models where storage is provided as a service to the grid by third parties. These services could span the gamut from installation to operation, with or without utilities owning the asset. If a contractor were to provide reliability services to a utility, service level agreements would need to be put in place to ensure that utilities would be first in line for energy storage resources.
With the cost of storage declining rapidly and increased penetration of renewables on the grid, utilities should already be testing energy storage applications and developing insight on the value of energy storage at nodes in the distribution grid. The business case requires benefits from stacked services, so systems must be able to support multiple services. A well-reasoned strategy will be needed sooner rather than later.
Jill Feblowitz is founder of Feblowitz Energy Consulting and an internationally recognized expert on innovation in the energy industry. With over 30 years of experience leading research and delivering consulting projects, Feblowitz provides advice to energy companies in the areas of energy markets, business models, operations, policy, regulation and technologies.