(November 2008)Economic uncertainties are raising doubts over utility returns. Will regulators feel the need to consider broader economic effects when engaging in ratemaking? While...
Power System Planning: Who gets paid (and how much) for backing up the system?
“Although a 200-MW difference may sound insubstantial in relation to the over 30,000-MW OC value, [we] estimate that this 200-MW compromise would cost consumers approximately $1.4 billion over the next five years.”
But what was this compromise?
As it turns out, the ISO had put it to a vote. When faced with a range of possible values for tie benefits, the Reliability Committee of NEPOOL (New England Power Pool) had voted 70.65 percent for 1,400 MW, 56.61 percent for 2,000 MW, and 80.12 percent for 1,800 MW. Do the math. Has resource planning become a beauty contest?
To the ISO, all this seems like sour grapes. It counters that a similar vote with similar results was taken for the prior power year of 2004/05, without much controversy. That proves, says the ISO, that current objections center not so much on the ISO’s nominal calculation of the OC target, but more on the much higher dollar impact that will follow if the ISO follows through on its parallel proposal to adopt a still more costly LICAP market.
But the most serious charges come from the Connecticut Consumer Counsel and attorney general, and from PUCs in Vermont, Rhode Island, and New Hampshire (joined by utilities Conn. L&P and Northeast Utilities). They complain, essentially, of a lack of any rate-case-like process to reach a J&R finding:
“Because [the] ISO has ignored the cost of its proposed increase in IC Requirements … it has not provided sufficient information to determine precisely what those added costs will be under any LICAP demand curve being considered.”
Their objections clearly highlight the difference between resource planning at the RTOs versus resource planning at the state PUCs.
California: A Better Way?
PJM, the nation’s most influential RTO market, appears on the verge of joining New England with a locational market for ICAP. The PJM plan, known as the Reliability Pricing Model, originally was scheduled for launch this spring (the proposal, that is) but has since been delayed, at least up until the time of a PJM board meeting that was to have taken place in early May. However, PJM has vetted many details. For example, specific proposed demand curves for three different PJM pricing zones can be found on the PJM Web site. ( See, “Whitepaper on Future PJM Capacity Adequacy Construct,” Nov. 2004, www.pjm.com/committees/workinggroups/prmramwg/pjmramwg.html.)
Nevertheless, the real innovation may come from California, where Cal-ISO deliberately has omitted a classic ICAP model from its proposed MRTU (“Market Redesign and Technology Upgrade,” proposed several years ago as the MD02 — Market Design 2002) model. Instead, Cal-ISO has proposed to achieve supply adequacy in two ways.
First, the ISO would offer an availability payment to certain generators under a construct known as RUC (Residual Unit Commitment). RUC is not a true market, however. Instead, after close and settlement of its proposed Day-Ahead auction, the ISO would “reserve” the right to call on certain resources in real-time, should supplies fall short.
Second, Cal-ISO would extend its real-time must-offer obligation (MOO) to the Day-Ahead market as a temporary stopgap, until the