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Reliability Wars

Power System Planning: Who gets paid (and how much) for backing up the system?

Fortnightly Magazine - June 2005

71 (1st Cir. 2002) , which puts down the notion that an RTO ICAP hearing is a virtual gen plant rate case:

“[The] ICAP charge is not of this ilk. Rather, it is a payment to suppliers over and above the amount they charge for power. …

“If ICAP charges were abolished by FERC tomorrow, the sellers could object that FERC was behaving unreasonably … but not that they were deprived of a just and reasonable rate.”

As the ISO saw it, the developers’ claim of entitlement to a just and reasonable ICAP rate was nothing but an “abused slogan.”

Interestingly enough, FERC made no comment at all about the “rate case issue,” or any entitlement to just and reasonable rates, in its final order approving nearly all the ISO’s proposed elements for various sets of ICAP demand curves. ( See FERC Docket No. ER05-428, 111 FERC ¶61,117, April 21, 2005. For more detail, see Figure 1 and explanatory notes. )

New England: High Costs

The lack of state PUC participation and J&R rate protection stands out clearly in the case to set minimum requirements for installed capacity for utilities and load-serving entities (LSEs) in New England for the 2005-2006 power year, which was still pending before FERC in early May. This requirement, known in New England as OC (Objective Capability), incorporates a 12 percent reserve margin above the nominal load requirement. But while that determination would appear relatively straightforward at first glance, the case in New England has brought a stern admonishment from utilities, state PUCs, and attorneys general from across the New England region. They claim the ISO has ignored stakeholder and consumer interests and has caved to political pressure within the NEPOOL participants’ and reliability committees. And worse than that, they say the ISO has misunderstood its role and has usurped jurisdictional authority to set targets for resource adequacy that resides with the state PUCs. ( See FERC Docket No. ER05-175, filed March 21, 2005, comments and protests filed through Apr. 25, 2005 .)

To set the capacity requirement, the New England ISO (ISO-NE) analyzes three key elements: (1) load forecasts; (2) unit availability ( e.g., how to estimate scope and likelihood of future plant outages); and (3) tie benefits (the projected ability to import power across the grid from other regions, including Canada). It is the second two factors, availability and tie benefits, that have come under fire.

One bone of contention concerns unit availability. The ISO has proposed to abandon the EFOR (Equivalent Forced Outage Rate) model, which calculated random unit failure without regard to whether a plant is running, in favor of EFORD (Equivalent Forced Outage Rate Demand), which focuses on outages that occur when a unit is needed for dispatch.

By all accounts, however, the primary difference between the ISO-NE’s proposed OC target for 2005-06 and that already approved in prior years stems from its move to lower its estimate of tie-benefit capacity from 2,000 MW to 1,800 MW. As lawyer Stephen Teichler explains (representing NSTAR Electric & Gas), that is a very big