Solving FERC Order No. 2222 challenges by taking a look a European energy markets

In September 2020, the Federal Energy Regulatory Commission (FERC) issued Order No. 2222, which levels the playing field for aggregations of distributed energy resources (DERs) to participate in the wholesale electricity markets administered by regional grid operators. Now, a year-and-a-half later, the compliance process is ongoing, with four of the six regional grid operators – NYISO, CAISO, ISO-NE, and PJM – completing their compliance filings but waiting on FERC action. The remaining two markets – MISO and SPP – will submit their compliance filings this month.

DERs are becoming increasingly popular. Not only do they provide flexibility to organizations by enabling them to boost efficiency, resilience and sustainability across their operations – they deliver value to the grid too, by enabling a more sustainable, flexible, and resilient grid infrastructure. It’s essential that aggregations of DERs – which include demand response (DR), generation technologies like solar panels and energy storage systems, and electric vehicles – be allowed to participate in wholesale markets to ensure the grid keeps supply and demand in balance.

Order No. 2222 is the crucial landmark order for DERs to participate in wholesale markets alongside large, centralized, traditional power plants through aggregations. On their own, DERs cannot easily participate. However, aggregators like Centrica Business Solutions can bring together these different types of resources and aggregate them in a portfolio known as a “virtual power plant,” enabling these DERs to provide grid services and receive compensation.

Much has been written about Order No. 2222 regarding how best to integrate aggregations of different types of resources into the energy markets. There is no right answer, and every single market will have its own unique approach and implementation path to how they will be compliant with Order No. 2222 – some, like NYISO, claim that they already are!

Part of the difficulty in adapting market rules for the allowance of aggregated portfolios is that the markets were originally designed with large power stations in mind. Since then, carve-outs have been created for the participation of DR resources, such as the case in NYISO’s ICAP market, creating a “Special Case Resources” carve-out that allowed DR resources to participate in the same market, albeit with adjustments. We must recognize that while the core business of power plants is to generate energy, that is not the core business of most energy-consuming facilities, including those who participate in DR or have various DERs located at their sites. Therefore, while the power stations’ sole reason for existence is to provide power to the grid, it is primarily an economic decision for end-user facilities. The more strenuous the requirements, the less likely they will participate.

Several issues have created consternation for system operators and aggregators alike. Among these are telemetry, the shared value between the system operator and utility, geographical constraints, and aggregation of different types of behind-the-meter and front-of-the-meter resources.

Issue #1: Telemetry

Telemetry, or the metering of energy production or consumption, is vital for system operators to have visibility into the resources under their control and ascertain that they are delivering the service to the grid as expected. However, telemetry requirements for participation in many of these markets were designed with a large power station in mind – a single asset generating millions of dollars a year for participation. With extreme levels of accuracy and granularity, these telemetry requirements are often barriers for smaller resources to participate in programs like ancillary services.

Emerging requirements in the U.S.-organized markets under Order No. 2222 are shaping up to require highly granular and frequent telemetry from every resource in a DER aggregation to the aggregator’s network operations center – and then on to either or both the Independent System Operator (ISO) and Transmission System Operator (TSO) and the local Distribution System Operator (DSO). This requirement is poised to create significant cost barriers to the participation of small resources.

It is also mathematically inaccurate to consider the accuracy of reading for a single 1 MW asset in the same manner as a 1 MW portfolio consisting of 1,000 assets, each at 1 kW. Statistically speaking, 1,000 1 kW assets with 1% accuracy, assuming that this error is a uniform distribution, would be preferable to a 1 MW asset with 1% accuracy.

Let’s now take a look at Europe, where system operators have already addressed telemetry requirements by making exceptions for aggregations:

1. Elia, the system operator in Belgium, has made concessions for aggregations by allowing a lower accuracy. However, this concession is not free. Instead, the more lenient accuracy is offset by a lower compensation for the portfolio. For example, if the telemetry accuracy for a 100 MW portfolio is 97%, then the portfolio prequalified volume is 97% of what it would otherwise be. While an even better way to do it might be to allow for a weighted average of accuracies, this model at least allows for participation without telemetry requirements blocking participation.
2. System operators in Europe have occasionally accepted statistical metering approaches for ancillary services participation. In these approaches, a specific portion of the portfolio requires official metering and the remaining assets’ telemetry if effectively extrapolated. In the U.S., PJM has in fact been accepting statistical metering approaches on an exception basis for over ten years, so the concept is likely not novel to system operators in the U.S.

Issue #2: Operational coordination

Another thorny issue is the operational coordination of DERs and demand side resources between ISOs and utilities. If an asset is part of an aggregation that an ISO uses to alleviate frequency issues on the bulk power grid, that single asset could inadvertently create problems on the distribution level, and the utility would have to deal with it.

This issue has emerged in the ongoing Order No. 2222 implementation debate in the U.S., with ISOs and TSOs proposing mechanisms to ensure that DER dispatch at the wholesale level does not create operational situations that are infeasible at the distribution level. In some cases, these mechanisms still lack specificity – while in others, they appear to be overly deferential to the DSOs that may have financial incentives that do not align with DER aggregators and participants.

While services to the ISO and utility are procured in totally separate ways in Europe, the two entities do similarly require quite a bit of coordination – especially as more distributed and smaller DER assets provide flexibility with potential constraints on the Low Voltage/Medium Voltage (LV/MV) grid.

• In Belgium, for example, in the demonstration project Soteria, ­another role is filled by an entity called the Market Operator, which is different from the ISO or TSO. A Market Operator balances the interests and grid constraints of both the TSO and the DSO. The utility or distribution system operator (DSO) submits their LV flexible bandwidth a day ahead to the independent market operator, and market participants like aggregators submit their aggregation bids and participating assets for ancillary or energy markets. The market-clearing engine of the Market Operator ensures compliance with DSO grid constraints while maximizing social welfare. The DSO typically has to do a grid study for each asset, but this does tend to become burdensome for the DSO and may not be right-sized for smaller assets. The Market Operator is then responsible for determining how much the TSO’s ancillary services market can accept without creating congestion for the DSO.
• The UK’s Low Carbon Network Fund project in Cornwall LEM has also tested innovative approaches to this issue. In this project, the aggregator bids are prioritized according to their effectiveness in contributing to grid stability. For example, if the DSO has congestion in a specific area, it has the first right to buy flexibility in that region, overusing these assets in TSO ancillary services.

Issue #3: Geographical constraints

One of the most significant benefits of aggregation is allowing asymmetric assets to complement each other. Assets that would otherwise not be able to participate individually due to their boundary constraints – such as limited duration, number of activations, or seasonal capability – are allowed to aggregate and complement one another to deliver the expected performance.

In Europe, for example, batteries can be aggregated with industrial and residential DR to deliver the frequency response that the grid expected. However, the region for aggregation should be large enough geographically to allow for assets in different regions to be part of the same pool. Statistically, larger pools tend to deliver more accurately since an unexpected outage of a flexible unit can be compensated by many others.

One interesting use case for geographical specificity is DSO congestion. Once the constrained area has been identified, financial incentives drive investment in a battery in that region. The UK market is an excellent example of a market with commercial products available for congestion management. Some of these products are week-ahead, with day-ahead and intraday options currently being explored. The DSO can procure this flexibility for congestion purposes, while the TSO can also use these same resources for other purposes.

Geographical constraints have been a key issue in the U.S., with significant disagreements arising between ISOs/TSOs and DER aggregators over the geographic and electrical scope over which resources may be aggregated. Some TSOs, like PJM, have proposed rules that would limit aggregations to a single transmission pricing node. Others, like California ISO and NYISO, allow aggregations over a number of such nodes. Practically speaking, too small a scope can essentially make aggregation impossible.

In Europe, aggregation is typically allowed per TSO region, as most European countries have a single TSO. Germany is an example where there are four TSOs, and aggregation is allowed per TSO region. The UK is a more conservative case because it is an island and has lower electrical inertia. Often, the geographical limitation depends on the product procured – and for new products, the system operator may be more conservative.

For example, Fast Frequency Response (FFR) was allowed at first across the UK, but dynamic containment (faster than frequency response) imposed geographical constraints on aggregation. However, aggregating over a wider region could be beneficial to ensure that resources don’t inadvertently negatively impact internal TSO congestion, causing the network to become overloaded.

Additionally, in Europe, there are novel approaches for interconnection and adding new DERs onto the network. In the Netherlands, solar photovoltaic (PV) parks are obliged to reduce connection to a specific limit – or install a battery for storage or to curtail the PV. Innovative commercial solutions (Belgium, Australia) calculate the network hosting capacity and are data-driven, avoiding a lengthy and expensive network study by using more data-driven techniques.

Issue #4: Different technology types

One of the firm requirements of Order No. 2222 is that aggregations should accommodate resources of several technology types – so-called heterogenous aggregations. This aspect of Order No. 2222 compliance has not been as problematic as other concerns.

Aggregating different technologies can create challenges, especially as we consider front-of-the-meter assets that export power to the grid and are aggregated together with behind-the-meter assets that only support site load. Market participants in Belgium and more European markets can aggregate everything – residential sites, storage, front-of-the-meter DERs, and industrial assets. It doesn’t matter if the aggregation delivers the expected result. The only limitation is size – an asset larger than 25 MW cannot be part of a pool and can only participate as a stand-alone resource. Pools themselves don’t have a size limit and can include 1 kW resources alongside 24 MW resources.

There are differences in emerging markets. In Romania, for instance, behind-the-meter assets can be aggregated with other behind-the-meter assets but not with front-of-the-meter resources exporting power to the grid. But in more established markets like the UK, FFR can be delivered by aggregated portfolios consisting of batteries, C&I load reduction, and residential load curtailment. Centrica’s own synthetic portfolios marry together storage to do the “heavy lifting” of frequency regulation while having C&I and residential units that aren’t well suited to frequent activations on the outer bounds of the frequency spectrum, stepping in for larger frequency deviations in the upward or downward direction. This approach is well suited for European markets where grid frequency can be measured directly – less so for the U.S., where most ISOs send an Automatic Generator Control (AGC) signal for a single resource to follow instead of providing the aggregator the freedom to decide which assets are best suited to respond at that point in time.

So what’s next?

Centrica Business Solutions has global operations in energy markets, so we’ve witnessed first-hand how European countries have addressed concerns similar to those currently holding up compliance to Order No. 2222. It isn’t easy to compare U.S. markets directly with European markets. In the U.S., the markets operate to the letter of the law, with much more direct control. In contrast, the philosophy behind European markets is more in the spirit of the law, putting in place the right frameworks and then allowing market participants to develop solutions. There are strengths and drawbacks to each approach. However, from an aggregation perspective, there is potentially more room for creative, technology-backed solutions in European markets at present.

While U.S. markets are different from European markets, we hope that some of these learnings can help with the rollout of DER aggregations in the U.S. At the moment, compliance filings by several ISOs contain numerous deficiencies that would prevent FERC’s vision for DER participation in wholesale markets from being realized – and, more importantly, from customers receiving maximum benefits from participation.

Centrica Business Solutions is a member of the Advanced Energy Member Alliance (AEMA), providing ongoing commentary on the compliance filings that ISOs have submitted for Order No. 2222. In our comments, we are addressing deficiencies and serving as advocates for our customers. We expect additional rounds of comments, and FERC will likely not rule on compliance filings until later this summer.

The jury is out regarding how each ISO’s implementation of compliance with FERC’s Order No. 2222 will genuinely create a level playing field for aggregations. Or not.