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How Needed Is NERC?

Critics say its new budget and business plan could simply duplicate the work of RTOs.

Fortnightly Magazine - November 2006

by transmission-owning utilities in New York, that NERC’s use of historic NEL data for allocating ERO cost assessments to individual LSEs would be “nearly three years old” when the budget year ends—a situation the utilities say would be “unworkable and inequitable.”

By contrast, consider this magazine’s most recent October issue, containing a series of interviews with RTO CEOs, where PJM president Phil Harris recounted how FERC commissioner Jon Wellinghoff had visited PJM’s operations center and was “flabbergasted” at what the RTO software could reveal:

“How much is flowing, where the flows are going, what’s happening to load, what the prices are. It’s all updated every 5 minutes.”

In short, it is the ISOs and RTOs—not NERC—that have their fingers on the pulse of the nation’s bulk power system.

The Scope of Statutory Functions

Perhaps the problem of estimating utility load-share ratios, in calculating funding assessments represents but a minor quibble in the larger scheme of things, and in deciding who should enforce reliability.

In its 40-page letter announcing its 2007 budget and business plan, NERC argued that load-share ratios won’t vary much from region to region over a couple of years. It explained that if individual LSEs within regions should gain or lose customers and load in the interim, rendering assessment to individual companies outdated, then it (NERC) could simply adjust the allocation for “known and measurable changes” as rate-making commissions typically do to update test-year data in rate cases.

Yet larger questions remain. What functions are relevant to the concept of “reliability standard,” as that term is defined in EPACT? What jobs do FERC and the utility industry expect of the federally certified ERO?

Consider this: NERC says it will continue to prepare three key reports each year, much as it has always done, including (1) a long-term reliability assessment, (2) a summer assessment, and (3) a winter assessment. These reports, it says, “will analyze electricity demand and adequacy of supply,” as well as examine the adequacy of transmission. These assertions don’t square very well with the new statutory framework.

Congress took pains in EPACT to limit the ERO’s enforcement of reliability standards to matters of design and operation of bulk-power systems. It stated explicitly that the term “reliability standard” (and hence NERC’s role as enforcer) should not include any requirement to enlarge the facilities of the bulk-power system, or to construct new transmission or generation capacity. (See Federal Power Act, sec. 215(a)(3).)

At the very least, NERC’s promised reports and assessments on generation and transmission adequacy might now extend outside the ERO’s statutory authority. And even if not, how would such assessments mesh with RTO practice, where adequacy of generation supply or grid capacity is increasingly a matter for markets and pricing?

In the Northeast, for example, how would assessments of generation adequacy add much to the data and understanding already available through the New York ISO’s market for installed capacity (ICAP), or New England’s Forward Capacity Market, with its price-setting auction? PJM’s proposed and pending Reliability Pricing Model (RPM), a variant of ICAP/LICAP markets, would rely on a dynamic