Experience with time-of-use pricing programs shows that a large majority of low-income customers will benefit from dynamic prices. In fact, not making such prices available to these customers...
Yes, We Have No Negawatts
When you sell demand response back to the grid, how much capacity are you now not buying?
test should be treated as having sold their demand response into the energy market, and should receive the energy price.
In agreement was Andrew Ott, PJM’s senior vice president for markets, who appeared at the conference and likened the situation to a generator who bids and clears the market to supply 90 MW of capacity, but then runs at 100:
“I’ve got to pay him 100 MW for the energy, but [the] capacity payment remains unchanged.”
So, too, with demand response:
“All I’m going to make sure is they gave me at least what they committed to give me in the capacity market, just like with the generator. If they gave me more, great, they get a payment in energy and everybody’s happy, including us.”
Well, perhaps not everybody.
Constellation and Energy Connect explained in joint written comments why an aggregator would want to design a portfolio to ensure capacity credit, rather than simply accept the energy price. Since you don’t know in advance when a peak emergency will occur, a DR capacity bid gets paid every day, 365 days a year, for having committed to stand ready, whereas a DR customer supplying energy gets paid only for the exact hours of curtailment.
Consider the DR product known as ILR (interruptible load for reliability). Constellation and Energy Connect showed that as the 2011/12 price for ILR came in at $110.04 per MW-day, 10 MW of cleared ILR would earn the customer over $400,000 over the course of a year. (Comments of Demand Response Aggregator Coalition, p.9, n.15, FERC Docket ER11-3322, filed April 28, 2011.)
Selling that same demand response for a few hours into the energy market—even at a typical peak price of $250/MWh—probably wouldn’t return such a high income stream.
In the end, however, the story belongs to EnerNOC and its outspoken advocate.
At the July technical conference, Sipe presented several graphs to illustrate how PJM’s policy could produce absurd results, such as for a ski resort, or amusement park (see Figures 1 and 2) .
The ski resort might well likely carry a peak load contribution of zero, as it likely wouldn’t consume energy during the heat of the summer, when the year’s five highest daily peak hours would occur, and so likely wouldn’t be eligible for any DR capacity credit, even if it curtailed snowmaking operations during the winter.
The amusement park, by contrast, would sport a high PLC, but likely would remain too busy during a summer heat emergency to consider selling demand back to the grid.
Another example involved a business with a high energy consumption and PLC in a year one, but which was closed, shuttered and bulldozed in year two, yet remained eligible for capacity credit even as it no longer operated, as its demand fell below its PLC, thus appearing to free up capacity for use by other businesses.
Responding in early September, PJM termed these two examples “extreme,” and “not representative” of the “vast majority” of DR participants in the region, but suggested that the two facilities could submit a “composite bid,” with