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Frequency Regulation

Not Just for Reliability Anymore

Putting market economics ahead of reliability, the Federal Energy Regulatory Commission (FERC) has told regional transmission organizations (RTOs) and other grid system operators (ISOs) to rethink the prices they pay for the ancillary service known as frequency “regulation.”

In short, FERC wants all power plants to do what they do best — recognizing that some may be well adapted to providing regulation service, but others perhaps not.

Thus, the commission has ruled that when ISOs and RTOs pay power producers to provide frequency regulation, the compensation must reflect not only the capacity that generators set aside for such service, but also must reward generators for (1) the faster ramping rates achievable by newer, more unconventional technologies, (2) the total energy provided (known as “mileage,” which reflects total frequency movement “up” and down”), and (3) the greater accuracy that faster-ramping resources can achieve in responding quickly and precisely to dispatch signals from system operators. (Frequency Regulation Compensation in the Organized Wholesale Power Markets, FERC Order 755, Docket Nos. RM11-7, AD10-11, Oct. 20, 2011, 137 FERC ¶61,064.)


FERC wants all power plants to do what they do best - recognizing that some may be well adapted to providing regulation service, but others perhaps not.

In effect, the decision says that by paying the wrong price for regulation, RTOs and ISOs, have encouraged too many gas-fired turbines and other conventional fossil power plants to supply frequency regulation. Instead, says FERC, they could achieve greater efficiency by relying on faster-ramping resources, such as battery and flywheel storage, or even demand response.

This strategy, FERC explained, would benefit both the newer and the older, more conventional fossil-fired technologies: “[T]he payment to resources is structured to justly compensate resources for the work performed, thus freeing other resources to perform service more in line with their operational characteristics.” Importantly, FERC rejected arguments by the Edison Electric Institute (EEI) that it was giving short shrift to electric system reliability: “EEI contends that [FERC] has not shown that changing the compensation mechanism to increase compensation for faster-ramping resources will result in enhanced reliability … Contrary to EEI’s arguments, the justness and reasonableness of the compensation mechanism directed here does not hinge on a finding that it will improve reliability.”

Batteries and Flywheels

Crucial to FERC’s decision was the evidence supplied by various power producers showing how current RTO pricing methods created unfair results. For example, a power plant with a ramp rate of 1 MW per five minutes would only be able to offer a maximum of 5 MWs of useful capacity over a five-minute dispatch, regardless of plant’s total nameplate capacity (five minutes being the interval at which most RTOs and ISOs dispatch resources for frequency regulation service).

Yet a storage device capable of holding a 20-MW charge and ramp rate of 10 MW per minute could offer its full 20 MW of capacity. Thus, Beacon Energy had provided data showing that its 1-MW energy storage flywheel could provide more than four times as much frequency regulation service to the New England market (0.48 MWh vs. 0.11 MWh) as would a 1-MW resource with an allowable ramp rate of 1 MW per 5-minute period.

A study from the Pacific Northwest National Laboratory had shown that fast-ramping storage technologies (batteries and flywheels) could be 17 times more effective than conventional generation in how quickly they might respond to a system imbalance. A study from the California Energy Commission stated that, “on an incremental basis, storage can be up to two to three times as effective [for frequency regulation] as adding a combustion turbine to the system.”

Yet, under the typical RTO pricing structure, the grid would pay each resource the same price — reflecting the fact that each had committed 1 MW of capacity to the regulation market, thus incurring the same measure of lost opportunity costs in terms of energy sales forgone.

Mileage Up & Down

FERC also cited market inefficiencies concerning the practice of energy netting versus so-called “mileage” rates. As a frequency imbalance may be positive or negative, dispatchers at five-minute intervals call on generators providing regulation service either to inject or withdraw energy. RTO pricing structures generally net those injections and withdrawals in calculating an energy payment to regulation suppliers.

However, as FERC explained, dispatchers in fact may reverse their over short timeframes (asking for withdrawal rather than injection), and so a slower-ramping resource may fall behind in responding to the dispatcher’s signal, thus “overshooting” dispatch instruction, and thus causing the resource to work against the need of the system, forcing the system operator to commit additional resources to frequency regulation. Thus, FERC will require RTO pricing structures to pay frequency regulation suppliers for their full mileage — the full amount of useful energy they supply in response to dispatch requests, in terms of electrical “work” performed in moving frequency up or down.

Measuring Opportunity Costs

In its technical details, FERC’s new rule forbids RTOs from paying for regulation only according to the offered capacity. Rather, RTOs must now offer a two-part payment, reflecting both (1) capacity value, as reflected by a uniform energy market clearing price and the lost opportunity cost of not selling energy into the market (multiplied by the ramp rate, in MW/minute), and (2) and the total “mileage” or electrical work performed in response to dispatch signals, as again keyed to a uniform energy market clearing price times to total absolute movement in MW-hours for frequency “up” and “down” service, without netting.

However, RTOs likely will find the new rule difficult to comply with in calculating opportunity costs keyed to a uniform clearing price.

First, the uniform clearing price must reflect not only the clearing price for energy as shown in the real-time energy market, but also must somehow reflect the bids submitted by market participants offering to supply regulation service. Such bids (from suppliers of ancillary services) have always proven difficult for RTOs to evaluate, as in essence there is no real “market” for ancillary services — the only logical “buyer” for such services is the RTO itself, which must remain independent and thus cannot really be seen as a true counterparty or competitive market participant.

Second, the new rule will require RTOs to calculate both inter-temporal and cross-product opportunity costs. Inter-temporal costs represent the foregone value when a generating resource must operate in a particular time interval and therefore must either forego a profit from selling energy at a later time, or incur costs due to consuming at a later time. The trade-off could prove tricky for a thermal storage resource.

Meeting complaince deadlines could prove difficult, for all the software programming.

Thus, as FERC noted, a thermal storage operator ordinarily would prefer to “charge” up the plant (e.g., heating bricks or freezing water) when wholesale power prices are low. Yet, if such a resource were to provide frequency regulation, it could be asked to stop charging during low price periods and then be forced to charge during high-price intervals.

Finally, the new rule requires RTOs to design a pricing structure that rewards accuracy of response. For example, if an RTO receives telemetry data every 10 seconds, it must measure how often over a five-minute period that the regulation resources delivered exactly the megawatts requested, and then pay compensation for the fraction of the total “mileage” that met the dictates of the dispatch signal. The order does not deal with primary frequency response service, accomplished primarily through automated systems that employ generator governors. Rather, it pertains to secondary frequency response — the injection or withdrawal of real power, pursuant to dispatch instructions from the regional grid balancing authority, and often carried out through Automatic Generation Control, or AGC, for the purpose of mitigating frequency deviations or an interchange power imbalance, as measured by the Area Control Error (ACE).

It is believed that FERC’s order will become effecitive December 30, meaning that RTOs and ISOs must file compliance plans with the commission by April 30 or next year, for implementation no later than August 2012. Nevertheless, those deadlines could prove difficult for competing all the necessary software reprogramming. ISO New England, for example, has asked for an extension of time until August 10, 2012, for filing its compliance plan.

ABOUT THE AUTHOR: Bruce W. Radford is publisher of Public Utilities Fortnightly magazine, and covers FERC regulation in the monthly "Commission Watch" column. This article was adapted from a story that appeared in Utility Regulatory News #4042, Oct. 21, 2011.