The nascent electricity storage industry is starting to make progress both in California and at the federal level.
The California Public Utilities Commission proposed in June that the state’s three investor-owned utilities — Pacific Gas & Electric, Southern California Edison and San Diego Gas & Electric — be required to buy approximately 1,300 megawatts of energy storage by 2020. The Federal Energy Regulatory Commission issued an order in late July that expands opportunities for competitive suppliers of ancillary services, which can include energy storage providers.
The California Public Utilities Commission is proposing to set the electricity storage targets in the chart below. The figures are in megawatt amounts. Individual targets are set for each utility. Targets will have to be met starting in 2014. The targets will ramp up every two years.
There are separate targets for electricity storage tied to the type of benefit provided by the storage system. To qualify as transmission storage, the services provided should reduce the need for transmission upgrades, for example, by helping to shave the peak demand on the transmission system, improve grid operation and reliability or provide relief from congestion. To qualify as distribution storage, the services provided should include peak capacity support and voltage control. To qualify as customer storage, the storage should provide back-up power and improve quality for a customer.
The proposal, or a variation of it, will be approved or modified by the full commission and is expected to become final by October 1, 2013.
Utilities would be required to buy “commercially available, eligible storage technologies utilized in grid applications that may have been demonstrated but are not yet generally deployed on the grid in California.” The targets subsume other storage directives already issued by the CPUC, including a storage directive in a recent CPUC procurement decision for Southern California Edison. In that decision, the CPUC ordered a 50-megawatt set aside for Southern California Edison to procure 1,400 megawatts of energy storage in the western Los Angeles basin in order to meet its 2021 local capacity requirements.
The CPUC is proposing that storage be procured through a mechanism modeled after the “renewables auction mechanism” currently used as the primary method for California utilities to take bids from renewable energy generators to supply electricity on a short-term basis. Renewable generators bid into four competitive auctions. The winners sign standard nonnegotiable contracts. Generators bid their full costs and, if selected, are paid their costs as bid, less any portion of the cost that is publicly funded, over the life of the contract.
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If adopted, the CPUC proposal would require that the first storage auction be held by June 30, 2014. Auctions would be held biannually thereafter, in 2016, 2018 and 2020. The auctions would use the CPUC’s least-cost, best-fit analysis to evaluate bids, and each investor-owned utility would employ an independent evaluator to assess the competitiveness and integrity of its auction. Following the auction, each utility would submit an advice letter to the CPUC, providing details on the winning bids and requesting approval and rate recovery.
The CPUC is also proposing an evaluation, measurement and verification program to ensure the integrity of the energy storage procurement program. The CPUC plans to monitor the progress of the energy storage market in California as well as the operational data collected and the cost effectiveness of deploying energy storage technologies.
The auction process and proposed new storage targets are not the only programs for storage in California. The CPUC has a “self-generation incentive program” or “SGIP” that gives utilities an incentive to support existing, distributed energy resources, including advanced energy storage systems. While SGIP was originally introduced to reduce peak loads after the 2001 California energy crisis, SGIP has evolved into a comprehensive set of incentives on a per-watt basis for renewable and waste heat technologies ($1.19/watt), non-renewable conventional combined heat and power ($0.48/watt) and emerging technologies such as advanced energy storage ($1.80/watt) and fuel cells ($2.03/watt). The utilities pay these dollar amounts per watt of capacity to the retail utility customer on whose premises the storage device is located. The payments start when the storage device is put in service and continue until the customer has been paid the $5 million limit.
The CPUC also has a “permanent load shifting” program that is currently authorized for $32 million in funding and provides incentives for utilities to transfer load (or demand for electricity) from congested peak times to over-generating off-peak times. An energy storage device helping with load shifting would be located behind the meter — meaning on the customer side of the electric meter — but could be owned by the customer, utility or a third party. Payments are made by the utility to the owner of the storage device as an inducement to participate in such load shifting. The utility is repaid, in turn, out of the $32 million in funding for the program.
FERC Action to Promote Storage
The Federal Energy Regulatory Commission has been wrestling with whether to classify storage devices connected to the grid as transmission, generation or a hybrid. If the devices are transmission assets, then their cost can be recovered from all users of the grid through rates the grid operator charges for transmission.
In the meantime, the agency made it easier in late July for electricity storage companies to compete to provide ancillary services to the grid at market-based rates.
The agency has been evaluating how to classify storage projects to date on a case-by-case basis.
For example, in one decision, FERC evaluated a request by Western Grid Development LLC for various incentives, as well as a finding that the company’s projects were eligible for incentive ratemaking treatment that is available to wholesale transmission facilities. FERC granted the request for incentives, but required Western Grid to operate as a “participating transmission operator” or “PTO” subject to the California Independent System Operator’s tariffs and enter into a transmission control agreement. As a PTO, Western Grid will be responsible for energizing the project’s batteries, as well as performing all the duties associated with the day-to-day operations and maintenance of the projects, but its operations will be subject to CAISO control.
FERC has also encouraged storage through other ratemaking orders and rulemakings. In June 2012, it issued a notice of proposed rulemaking to encourage the development of competitive markets for the supply of ancillary services, such as those provided by energy storage projects.
The final rule on this subject came out in late July as Order No. 784. It permits third parties to supply various ancillary services at negotiated rates to transmission utilities, without the third party having to prove it lacks market power for such services, if the third party passes existing market power screens for sales of energy and capacity, the rates are established in a competitive solicitation or they do not exceed the published rates in the utility’s “OATT” or open-access transmission tariff for the services. (Independent generators and other suppliers sometimes are not allowed to charge negotiated, “marketbased” rates if they have too much market power, calling into question whether the negotiated rates are truly arm’s length.) The expansion of the market for ancillary services should boost the fortunes of energy storage providers since they are well suited to provide various ancillary services.
Order No. 784 also requires each transmission utility to add to its OATT schedule 3 a statement that it will take into account the speed and accuracy of regulation resources in its determination of reserve requirements for regulation and frequency response service, including as it reviews whether a self-supplying customer has made “alternative comparable arrangements” as required by the schedule. The order also requires each public utility transmission provider to post on the open access sametime information system — called OASIS — historical one-minute and 10-minute area control error data for the most recent calendar year, and to update the information once a year. The reforms are supposed to enable transmission customers who want to self-supply regulation and frequency response service to demonstrate that the resources they use for such service are comparable to those of the transmission utility and address the potential for discrimination against transmission customers choosing to “self-supply” regulation and frequency response service.
The hope is that the reforms will ensure that an appropriate quantity of resources is used for self-supply, whether those resources are faster and more accurate or slower and less accurate than those used by the transmission utility and enhance the customer’s ability to meet the self-supply requirements at the lowest possible cost. For example, a self-supplying customer could save money either by relying on a smaller amount of high quality regulation resources at a slightly higher per-unit price or by relying on a larger amount of lower quality regulation resources at a much lower per-unit price.
The order creates significant opportunities for fast responding sources such as batteries and flywheels that bid into frequency regulation service markets.
Implementation of storage continues to be hampered by the need for a commercial model that values storage intrinsically, rather than on the basis of the energy or capacity that it provides to the market. Without that commercial model, it will be difficult to see investment made in storage other than by those responsible for maintaining grid stability. California’s storage initiatives may force the creation of that model by promoting demand through the currently-proposed storage targets.