Historically, electricity “storage” has consisted of hydroelectric pumped storage projects, which pump water to higher-level reservoirs when electricity demand is low, and allow it to flow downhill through electricity-generating turbines when demand increases. However, over the past two decades, new electricity storage technologies have entered the market. These technologies include batteries (lead acid, lithium ion, sodium sulfur, flow, dry cell); flywheels (mechanical devices that harness rotational energy to deliver instantaneous electricity); compressed air energy storage that uses electricity to compress air, then expand it through a turbine to generate electricity later; electrochemical capacitors that store electricity in an electrostatic charge; and thermal energy storage that either uses heat sinks like molten salts to store heat energy, which can either generate electricity or provide heating later, or uses electricity that can be used to freeze water into ice, which can be used to provide air conditioning later.
As defined by FERC, an “electric storage resource” is a resource “capable of receiving electric energy from the grid and storing it for later injection of electricity back to the grid regardless of where the resource is located on the electrical system.”
Within electricity markets, electric storage resources have provided bulk energy services, ancillary services (frequency regulation, energy management, backup power and load leveling), and transmission services (voltage support and grid stabilization).
In April 2016, FERC’s staff sent data requests to Regional Transmission Organizations (RTOs) and Independent System Operators (ISOs). These requests sought information about whether barriers exist to the participation of electric storage resources in the capacity, energy and ancillary services markets operated by the six FERC jurisdictional RTOs and ISOs that could lead to unjust and unreasonable rates for wholesale sales of electricity, which are prohibited by the Federal Power Act (FPA). In addition, the staff wanted to know whether any changes to RTO and ISO tariffs are necessary if such barriers exist. (See Energy Update, Vol. 3, Issue 3, September 2016). FERC also convened a technical conference in November 2016 to discuss utilization of electric storage resources as transmission assets compensated through transmission rates, for grid support services that are compensated in other ways and for multiple services.
Following its review of the information obtained through the data request and technical conference, and prior to the inauguration of President Trump, FERC took two actions to increase the ability of electric storage resources to participate in wholesale electricity markets and clarified its policy with respect to the rates that may be charged by electric storage resources participating in wholesale markets. In January 2017, FERC issued a Policy Statement giving guidance on the ability of electric storage resources to provide transmission or grid support services at cost-based rates while, at the same time, providing other services, such as power sales, at market-based rates. In mid-November 2016, FERC issued a Notice of Proposed Rulemaking (NOPR) to amend its regulations under the FPA and remove barriers that prevented electric storage resources and distributed energy resource aggregators to participate in the capacity, energy, and ancillary service markets operated by the six RTOs and ISOs subject to FERC jurisdiction. These RTOs and ISOs are NYISO, ISO-NE, PJM, MISO, SPP and CAISO.
FERC Policy Statement on Rates Charged by Electric Storage Resources
In its Policy Statement, FERC observed that electric storage resources can both charge and discharge electricity, provide multiple services and switch from providing one service to another almost instantaneously. Based on these characteristics, FERC found that electric storage resources may fit into one or more of the traditional electricity asset functions of generation, transmission and distribution and, further, that an electric storage resource receiving cost-based rate recovery for providing one service also may be technically capable of providing other market-based rate services.
Section 205 of the FPA requires that the rates, terms and conditions of public utilities for the transmission or sale of electricity at wholesale in interstate commerce be on file with FERC, “just and reasonable” and not unduly discriminatory or preferential. Cost-based rates allow a public utility to recover its costs of providing service, allocated among customer classes, and make a reasonable rate of return on its investment. FERC authorizes market-based rates for wholesale sales of electric energy, capacity and ancillary services, where the utility demonstrates that it and its affiliates do not have or have mitigated market power in the relevant market(s), and for merchant transmission.
In the Policy Statement, FERC clarified that, as a matter of policy, an electric storage resource may provide services at both cost-based and market-based rates at the same time, so long as three issues are addressed: the potential for double recovery of costs by the electric storage resource owner or operator to the detriment of cost-based ratepayers; the potential for cost recovery through cost-based rates to inappropriately suppress competitive prices in wholesale electric markets to the detriment of other competitors who do not receive such cost-based rate recovery; and the level of control in the operation of an electric storage resource by an RTO/ISO that could jeopardize its independence from market participants.
As part of its policy guidance, FERC clarified rulings and statements made in two prior orders addressing rates charged by electric storage resources.
With respect to the potential for double recovery of costs by the electric storage resource owner or operator, FERC clarified that, in addition to the approach it approved in its Western Grid order, crediting any market revenues back to the cost-based ratepayers is one possible way to address potential double recovery of costs. In Western Grid, FERC authorized Western Grid to charge cost-based transmission rates for the provision of voltage support and thermal overload services protection to CAISO because, among other things, Western Grid would operate the energy storage projects, at CAISO’s direction, only as transmission assets, and had committed to forego any sales into CAISO’s organized wholesale electric markets.
FERC also indicated that where crediting is utilized to address double recovery of costs, the amount of crediting may vary depending on how the cost-based rate recovery is structured. In a case where the costs of an electric storage resource is recovered through cost-based rates, the electric storage resource owner or operator may credit all projected market revenues earned by the electric storage resource over a reasonable period of time (expected useful life of the asset or the term of the cost-based rate services). Alternatively, the market-revenue off-set can be used to reduce the amount of the revenue requirement to be used in the development of the cost-based rate.
With respect to the second issue, the potential for cost recovery through cost-based rates to inappropriately suppress competitive prices in wholesale electric markets, FERC stated that it was “not convinced” by commenters’ arguments that allowing electric storage resources to receive concurrently cost- and market-based revenues for providing separate services will undermine competition or suppress market prices to subcompetitive levels. Denying electric storage resources the opportunity to earn cost-based and market-based revenues on the theory that dual revenue streams undermine competition would require revisiting years of precedent allowing concurrently cost-based and market-based sales for reactive power and market-based rate wholesale sales, and for cost-based sales to captive wholesale requirements customers and off-system market-based rate sales. FERC also said that the concern that electric storage resources would suppress market clearing prices by offering services for which they receive cost-based rates could be addressed by the manner in which the costs that are included in the cost-based rates are established.
With respect to the third issue, maintaining RTO/ISO independence from market participants, FERC clarified its previous conclusion in its Nevada Hydro order that it would not be appropriate to require CAISO to assume “any level of operation control” over Nevada Hydro’s hydroelectric pumped storage project. “There is nothing unreasonable about an RTO/ISO exercising some level of control over the resources it commits or dispatches where it can be shown that the RTO/ISO independence is not an issue,” FERC said. In Nevada Hydro, FERC denied Nevada Hydro’s request to treat its pumped storage project as a transmission facility under the operational control of CAISO for rate recovery purposes. FERC agreed with CAISO that under Nevada Hydro’s proposal, CAISO would have to decide when the LEAPS project would operate, how much energy it would provide and when it would operate the pumps to store water for future electricity generation, compromising CAISO’s independence.
FERC further stated that in order to ensure RTO/ISO independence, the provision of market-based rate service should be under the control of the electric storage resource owner or operator, rather than the RTO/ISO. Where a service compensated though cost-based rates is needed, the RTO/ISO should give priority to the dispatch of the electric storage resource to address over the electric storage resource’s provision of market-based rate services. Performance penalties could be imposed on the electric storage resource owner or operator for failure to perform at these times.
FERC NOPR on Participation by Electric Storage Resources in Wholesale Electricity Markets
In the NOPR, FERC found that, currently, resource participation in wholesale electric markets operated by RTOs and ISOs is governed by participation models consisting of market rules designed for different types of resources and technical requirements for market services that those resources are eligible to provide. To address this, FERC proposed, among other things, to require each RTO/ISO to revise its tariff to include market rules that accommodate the participation of electric storage resources organized as wholesale electric markets, recognizing the physical and operational characteristics of electric storage resources.
Under the NOPR, RTO/ISO market rules would have to satisfy numerous requirements.
First, electric storage resources must be eligible to provide all capacity, energy and ancillary services that they are technically capable of providing. With respect to this requirement, FERC also proposes that electric storage resources should be able to provide services that the RTOs/ISOs do not procure through a market mechanism, such as blackstart, primary frequency response and reactive power, if they are technically capable. Where compensation for these services exists, electric storage resources also should receive such compensation commensurate with the services provided. FERC proposes to require each RTO/ISO to revise its tariff to clarify that an electric storage resource may de-rate its capacity to meet minimum run-time requirements to provide capacity or other services. RTOs/ISOs with capacity markets that de-rate capacity value for electric storage resources must be consistent with the quantity of energy required to be offered into the day-ahead energy markets for resources with capacity obligations.
Second, bidding parameters (the physical and operational constraints that a resource would identify when submitting offers to sell capacity, energy or ancillary services or bids to buy energy in wholesale electric markets) incorporated in the participation model must reflect and account for the physical and operational characteristics of electric storage resources. With respect to this requirement, FERC explained that bidding parameters allow the RTO/ISO to model and dispatch the resource consistent with its operational constraints. FERC found that by requiring electric storage resources to use bidding parameters developed for traditional generators or other supply resources, RTOs/ISOs may fail to effectively utilize these resources, possibly precluding electric storage resources from providing all of the services that they are physically and technically capable of providing. FERC found that resource bidding parameters vary greatly between RTOs/ISOs. Some require the same bidding parameters from all resources offering into a specific market, while others tie bidding parameters to specific participation models. FERC proposed that the RTOs/ISOs establish state of charge, upper charge limit, lower charge limit, maximum energy charge rate and maximum energy discharge rate as bidding parameters for the participation model. FERC proposes to require that RTO/ISO participation models include the four bidding parameters that market participants may submit, at their discretion, for their resource based on its physical constraints or desired operation: minimum charge time, maximum charge time, minimum run time and maximum run time. Where the RTO/ISO has reserved for itself the right to manage the state of charge of an electric storage resource, FERC proposes to require that the RTOs/ISOs allow electric storage resources to self-manage their state of charge and upper and lower charge limits.
Third, electric storage resources can be dispatched and set the wholesale market clearing prices as both a wholesale seller and a wholesale buyer consistent with existing rules that govern when a resource can set the wholesale price. FERC proposed to require RTOs and ISOs to accept wholesale bids from electric storage resources to buy energy so that the economic preferences of these resources are fully integrated in the market; the electric storage resource can set the price as a load resource where market rules allow and can be available to the RTO/ISO as a dispatchable demand asset. However, these requirements must not prohibit electric storage resources from participating in wholesale electric markets as price takers.
Fourth, the minimum size requirement for electric storage resources to participate in the organized wholesale electric market must not exceed 100 kW. FERC concluded on a preliminary basis that such a minimum size requirement would balance the benefits of increased competition with the ability of RTO/ISO market clearing software to effectively model and dispatch smaller resources often located on the distribution system. FERC proposed to require each RTO/ISO to revise its tariff to include a participation model for electric storage resources that establishes a minimum size requirement for participation in wholesale markets not exceeding 100 kW, including any minimum capacity requirements, minimum offer requirements and minimum bid requirements for resources participating in these markets under the electric storage resource participation model.
Fifth, the sale of energy from the organized wholesale electric markets to an electric storage resource that the resource then resells back to those markets must be at the wholesale locational marginal price (LMP). With respect to this requirement, FERC states that it previously has found that the sale of energy from the grid that is used to charge electric storage resources for later resale constitutes a FERC jurisdictional wholesale sale and, as such, the just and reasonable rate for that sale is the RTO/ISO market’s wholesale price for energy, or LMP. FERC observed that the manner in which an electric storage resource charges (consumes) and discharges (produces) energy will determine whether the electric storage resource is making a jurisdictional sale for resale. In the NOPR, FERC proposes to require each RTO/ISO to revise its tariff to specify that the wholesale LMP is required for the sale of energy from wholesale electric markets to an electric storage resource that the resource then resells back to those markets.
Following its review of comments filed in response to the NOPR, FERC will decide whether to issue a Final Order implementing some or all of the proposals contained in the NOPR. However, FERC cannot issue a Final Order until there is a quorum of Commissioners. It is likely that when the full FERC considers any staff proposal with respect to a Final Order, only one FERC commissioner who voted on the NOPR will still be on the Commission.
Prior to losing its quorum in early February, FERC implemented some of its NOPR proposals in an order granting the request of Indianapolis Power & Light Company (IPL) that it find MISO’s tariff to be unjust, unreasonable and unduly discriminatory because it unnecessarily restricts competition by preventing electric storage resources from providing all the services that they are technically capable of providing, which could lead to unjust and unreasonable rates. IPL had argued that its Battery Facility, a grid-scale lithium ion battery-based energy storage system containing a 20 MW array of lithium ion cells, can provide nearly instantaneous primary frequency response and could become a “Load Modifying Resource” under MISO Tariff that could provide five MW of capacity or Planning Reserve Margin Requirement. IPL also argued that its Battery Facility already was providing primary frequency response, but there was no provision in MISO’s Tariff to compensate IPL for this reliability service.
In its order responding to IPL’s complaint, FERC found that although an electric storage resource, such as IPL’s Battery Facility, can participate in MISO as a “Stored Energy Resource,” this resource category limits the resource to participation in MISO’s regulation market and does not allow it to qualify for capacity, energy, ramp capability and contingency reserves. FERC directed MISO to submit a compliance filing proposing Tariff revisions that accommodate participation of all electric storage resources, regardless of technology, in all MISO markets that they are technically capable of participating in, taking into account their unique physical and operational characteristics. This requirement is similar to the proposed RTO/ISO tariff revisions in the NOPR.
FERC recognized that the issue raised in IPL’s complaint currently is being addressed in its NOPR and stated that, in the event that MISO’s Tariff revisions conflict with required Tariff revisions in any final rule resulting from the NOPR, MISO may be required to adjust its Tariff to align with FERC’s determination in the final rule.
MISO has requested rehearing of FERC’s order. As is the case with the NOPR, FERC cannot act on the rehearing request until it has a quorum of Commissioners. On May 8, President Trump announced his intention to nominate Neil Chatterjee, energy policy advisor to Senator Mitch McConnell (R-KY), and Robert F. Powelson, a commissioner on the Pennsylvania Public Utilities Commission and current President of the National Association of Utility Regulatory Commissioners, to two of the open Republican seats on FERC.
Authors & Contributors