U.S. regulatory innovation to boost power system flexibility and prepare for ramp up of wind and solar

Well-designed electricity markets can help deliver sustainable, reliable and cost-effective power systems and are key to integrating variable renewables. Prices from such markets can signal where and when the power system needs more flexibility, but they cannot deliver optimal outcomes if market access to new competitors is limited.

Comprehensively reviewing and removing market barriers is an important task worldwide. As part of IEA’s mission to help countries learn from their counterparts’ best practices, this commentary highlights how the U.S. is facilitating its transition to a cleaner power system while keeping costs in check for electricity consumers.

Specifically, the U.S. Federal Energy Regulatory Commission (FERC), which regulates the wholesale electricity markets and the high-voltage transmission system, has issued a landmark ruling to review its market rules and remove unnecessary barriers to energy storage participation. This rule opens the doors for all types of energy storage resources sited anywhere on the power system to participate in FERC’s organized energy, capacity and ancillary services markets.

Ideally, markets would drive technological innovation, but current electricity market rules are largely tailored to legacy power plants, which can inhibit progress. While incremental market revisions may be appropriate for specific problems, regulators must comprehensively correct for the systemic lag between the markets and the innovation driving electricity sector transformation today. The ongoing market reforms in many regions, while potentially helpful, don’t cover all markets, technologies or power sector levels.

For example, the UK is revising its balancing services and capacity markets in parallel processes, Australia has made interim accommodations and proposed rule changes for utility-scale batteries while consulting on its post 2025 market design.

Ontario, Canada is identifying obstacles to fair competition within its current markets for energy storage resources and proposing mitigation strategies through an advisory group.

France’s energy regulator also started reviewing the technical rules of capacity mechanism from the perspective of battery storage resources. The EU’s Electricity Market Design legislation mandates competitive procurement of flexibility services and fair rules for network access and charging, but whether it could more broadly reduce barriers to energy storage depends on how the legislation is implemented by its members.

The US has a diverse portfolio of gas, coal, nuclear and renewable resources. Solar and wind power in the U.S. grew to 8.3% of annual generation in 2018 and is forecasted to surpass 13% by 2024 according to the the IEA's Renewables 2019.

However, individual states have already experienced higher levels of variable renewables: 36% of the electricity generated in Kansas came from wind in 2018, with similarly high penetrations in other midcontinent states (34% in Iowa, 32% in Oklahoma and 16% in Texas according to EIA).

With growing shares of renewables in the U.S. and elsewhere, power systems will need more flexibility to balance variable wind and solar generation against demand. Today, conventional resources like gas and pumped hydro, together with electricity networks provide most of the system flexibility, but energy storage (especially batteries) and demand response are expected to play significant roles in the coming years, as highlighted in the Status of Power System Transformation 2019 report and in the 2040 scenarios of the World Energy Outlook 2018. Indeed, there significant opportunity to scale up these technologies

Unlike traditional power plants, newer technologies such as batteries and demand response may have smaller individual outputs, respond more accurately and quickly, and absorb as well as deliver energy. They can provide the services traded in electricity markets, but their deployment has been limited by rules that do not account for some of their characteristics.

Historically, market rules have been tailored to the operating parameters of traditional power plants like large hydropower and gas peaker plants, not smaller storage technologies. For example, some grid operators imposed minimum size requirements of up to 1 MW, which excluded smaller batteries.

While different resources, whether traditional or new, may excel at providing different services, a well-functioning market would allow any qualified resource to compete on price for a given service. FERC’s new rule, Order 841 is trying to do just that—ensure that all resources capable of providing market services are at least able to access the markets.

Order 841 requires FERC-regulated grid operators to review their capacity, energy and ancillary services market rules and remove unnecessary barriers to energy storage participation.

FERC’s new rule applies to energy storage resources “capable of receiving electric energy from the grid and storing it for later injection of electric energy back to the grid”. This rule requires that grid operators recognize the physical and operational characteristics of electric storage resources in their rules and create a “participation model” for storage to access the market. For example, the order contemplates storage resources as both a wholesale seller and buyer in determining market prices. The order also reduces a market barrier to smaller resources by requiring that the minimum size be 100 kW or below.

While FERC’s new rule contemplates smaller storage resources, its scope doesn’t include distributed storage resources smaller than 100 kW, such as electric vehicles or grid-enabled water heaters. To address this issue, FERC’s initial proposal also had a component allowing distributed energy resources (DERs) to aggregate into larger resources to participate in wholesale markets. This is proposal is similar to FERC’s existing rules enabling demand response to aggregate (Orders 719 and 745).

The DER proposal would enable aggregated resources mostly located on the lower-voltage distribution system to compete in the FERC-regulated markets. Doing so would tap into a deeper layer of flexibility available on the distribution system, but it also makes the proposal more controversial. The DER proposal was thus severed from the energy storage proposal to facilitate finalizing the latter.

FERC’s rule also invites storage resources located on the distribution system (potentially behind-the-meter) to participate in the wholesale electricity markets. Again, therein lies the main controversy. While FERC can open the gates to its wholesale electricity markets and the high-voltage transmission system, states and other local authorities regulate the distribution system (a dichotomy formalized in the 1935 U.S. Federal Power Act). States and other local entities have therefore challenged the FERC rule.

The tension between federal and state authority is a common theme with newer, smaller resources like demand response, storage, and DERs that could provide services to both the transmission and distribution systems. Similar issues arise in other two-tiered jurisdictions like Australia, Canada India, and the European Union. FERC’s existing rule enabling demand response to participate in its markets allowed states to bar aggregators of demand response resources within their territories. Critics of this “opt-out” note that it protects the interests of the monopoly energy companies that operate in these states. Meanwhile, state and local regulators argue that this opt-out should also apply in the storage rule and DER proposal.

Market rules can be region-specific and complicated with software systems to match. FERC’s rule is therefore a comprehensive framework that allows its grid operators to tailor the details to their systems. However, these details are key to market participation. For example, stakeholders in PJM (the grid operator for much of the U.S. Mid-Atlantic and Midwest) have been debating whether its 10-hour duration requirement for storage resources to participate in its capacity market is an unnecessary barrier to batteries, which typically last around 4 hours. FERC’s most recent order on PJM’s proposal to comply with Order 841 found sufficient evidence to investigate whether this requirement is unnecessarily inhibiting access to PJM’s market.

Stakeholders and grid operators are also trying to craft rules balancing who manages the “state of charge” on storage resources participating in the markets. While grid operators with visibility of their systems as a whole can optimize for efficiency, storage resource owners have better information about what is feasible for their individual storage units and how to minimize battery degradation by managing charging/discharging. These discussions are leading to complex rules that will impact how these resources participate in the market.

FERC’s development of the storage rule began in 2015 and builds on earlier policies pioneered by some grid operators. The rule was finalized in 2018 and is scheduled for implementation at the end of 2019, but some grid operators have asked for extensions. Broader market access requiring more complicated changes, such as software updates could take a couple more years to fully implement.

The DER proposal, which is still going through FERC’s rulemaking process, also leverages existing FERC precedent on demand response as well as the work of California’s grid operator. FERC has been taking additional input on the proposal since severing it from the storage rule. Whether it is finalized in the near term and what it will look like remains an open question. 

Comprehensive and timely market reforms will be critical for new technologies to play a significant role in renewables integration. Without market reforms to level the competitive playing field and better integrate the transmission and distribution systems, resources that could perform existing services more cost-effectively or offer new services would see limited deployment and revenue streams. Further, to ensure reforms anticipate the coming ramp up of renewables requires that regulators start the administrative process and stakeholder engagement soon.

Other ways to support renewables integration include facilitating solar and wind to provide flexibility themselves, which FERC has pioneered in Orders 824 and 827.

Market reform in light of technology evolution is a challenge for power system regulators in many countries. The IEA will continue sharing economic and regulatory innovations, which not only foster economic growth but also enable the transition to a cleaner and more flexible power systems.