Capacity Markets (Part I): How to cash in on demand response

Demand response is here to stay

On January 25th, 2016 the Supreme Court of the United States ruled on a case that has been highly anticipated by the energy community—Federal Energy Regulatory Commission v. Electric Power Supply Association Et Al.

The case concerned a practice known as demand response in which wholesale market operators (e.g. ISO-NE, NYISO, PJM, etc.) pay consumers for commitments to reduce their electricity consumption during periods of peak energy demand or grid instability. A key provision at issue in the case was the Federal Energy Regulatory Commission’s (FERC) Order 745, which requires market operators to pay the same price for demand response as they pay for generation.

The case resolved two questions:

  1. Does FERC have the authority (under the Federal Power Act) to regulate the rules governing how wholesale market operators pay for demand response?
  2. Are FERC’s rules for governing demand response payments arbitrary and capricious?

The decision: FERC does have the authority to regulate how wholesale market operators pay for demand response, and FERC’s demand response payment rules are just and reasonable.

Translation: Demand response is here to stay. Or more precisely, the current iteration of how wholesale demand response is regulated (by FERC) and compensated (at the same level as generation) is here to stay. 

Higher capacity prices are driving up demand response payments

But the story doesn’t end there. Demand response rates are established in forward capacity auctions at a level known as the clearing or capacity price. These auctions occur three years before each capacity commitment period in ISO-New England (ISO-NE) and PJM Interconnection (PJM), and seasonally or monthly in New York ISO (NYISO). The higher the capacity price, the more attractive demand response becomes. And capacity prices have been on the rise.

(For a primer on how forward capacity auctions work and how demand response fits in, click HERE.)

A squeeze on coal-fired and less efficient power generation is driving up capacity costs

This rising cost of capacity reflects a mismatch between forecasted electric demand and available generation in the future. The market is intended to provide industry with incentives to build more generation when and where it is needed. By mid-2019, recent and pending retirements of coal, oil and nuclear generation capacity in ISO-NE will total more than 4,200 megawatts (MW). Multiple drivers are contributing to these shutdowns.

To comply with increasingly stringent limits on greenhouse gas emissions, many coal power stations are being forced to shut down or retrofit their plants. Many of the nuclear plants in the Northeast were built in the 1970's and are now either approaching the end of their useful lives, struggling to compete with cheap natural gas, or both. Finally, new Pay-for-Performance in ISO-NE and PJM rules now prevent poor performing peaker plants that fail to contribute to the grid from collecting capacity payments. This simultaneously drives inefficient plants off the grid and incentivizes the construction of more efficient replacements.  These trends are combining to squeeze electricity supply in the Northeast and, consequently, drive up capacity prices.

ISO-New England capacity prices more than double

Take ISO-NE as an example. The average clearing price over the first seven forward capacity auctions was $3.40/kilowatts (kW)-month with a high of $4.50/kW-month and a low of $2.95/kW-month. The three most recent forward capacity auctions have seen capacity prices rise substantially. The average capacity payment from 2017/18 through 2019/20 is $7.87/kW-month, more than double the average capacity price of the preceding commitment periods.

In sub-regions that are particularly constrained such as Northeast Massachusetts (i.e. greater Boston), the clearing price has reached $15.00/kW-month, a significant increase in just a few years. At that rate, 1 MW of either generation or demand response could receive fixed reservation payments of as much as $180,000 per year. 

ISO Forward capacity results

PJM sees rising trend


Similarly, we see a rising price trend for PJM Interconnection (PJM), though the pattern is not quite as severe. Over the three most recent commitment periods the capacity price has for the majority of PJM (aka RTO clearing price) has risen from $1.81/kW-month in 2016/17, to $3.66/kW-month in 2017/18, to $5.02/kW-month in 2018/19.

NYISO pricing threatened by pending retirements

NYISO runs seasonal capacity auctions every 6 months and then administers reconfiguration auctions on a monthly basis. As such, the capacity price beyond 2016 has not been established yet. Nonetheless, many of the market trends that are driving increased capacity costs up for ISO-NE and PJM are also present in NYISO. For example, two nuclear operating units at the Indian Point nuclear facility, with a combined operating capacity of 2,078 MW (representing 25 percent of downstate New York’s energy needs), risk shutdown if Entergy, the facility owner, is unable to relicense the reactors.

Depending on location and operational capability, demand response resources in New York may also qualify for ongoing reservation and performance payments from the local utility, making some of these programs the most lucrative in the country.

How to cash in on demand response

Taken together, the Supreme Court ruling and trends in capacity market prices point decisively towards one conclusion: now is the time to consider demand response.  Follow the steps below to get started: 

1. Quantify and optimize your demand response load profile. Your demand response capacity (MW) is based on your non-critical base load as well as your load flexibility. Quantifying that requires a detailed load profile analysis and detailed inventory of equipment, operations, and processes. Large industrial facilities tend to be good candidates for pursuing demand response, but demand response can be economical for a wide variety of load profiles.


2. Determine your internal break-even price. What is the opportunity cost of your electricity consumption? What is the lowest capacity price you would accept in exchange for your commitment to provide demand? 


3. Outline a successful demand response program. A qualified energy consultant, familiar with the competitive energy market, can help represent your interests and define your favorable conditions throughout contract negotiations.


4. Engage with the demand response supplier that is right for your organization. Demand response suppliers aggregate demand response across energy users to participate in the forward capacity auction. A detailed review of available options, performance obligations, and contractual language is required before enrollment in a demand response program.


5. Prepare your facility for demand response. As a demand response provider, you must be prepared to shave load at the market operator’s request. An energy consulting firm can help you:

  • Install a smart control system that can distinguish between critical and non-critical equipment and automate the shutdown of non-critical load;
  • Consider investing in a properly sized back-up generation system to ensure reliable operations in your facility;
  • Optimize financial returns by selecting the right strategy and seeking tax incentives, subsidies, and investment incentives where available;
  • Negotiate favorable contracts that strike the risk/reward profile and performance capability of your organization.

6. Collect your demand response revenue!


With demand response here to stay, now is the time to evaluate how to make it work in your favor. If you have further questions, don’t hesitate to contact SourceOne’s strategic commodity management team at

Stay tuned for our next post which will focus on how capacity charges are reflected in your utility bill and how you can use passive demand response and energy efficiency measures to minimize your exposure to this growing cost.

forward capacity markets