State and federal incentives provide the carrot for utilities to invest in grid intelligence. But regulatory and technological incentives are not enough without customer participation. Smart-grid...
Bad Day at Black Oak
Beware even the best of attempts at apportioning grid rights and costs.
Consider the fate of the borough of Chambersburg, Pa., population about 17,800, and its not-for-profit municipal electric utility, which serves about 10,000 retail customers, give or take.
Earlier this year, the town heard from the PJM regional grid operator that for the 2006-2007 planning year it would receive only about 53 percent of its nominated and requested auction revenue rights (ARRs). That news came despite the fact that Chambersburg had not experienced significant load growth, nor changed its pattern of power-supply sources or ARR nominations in any material way from recent prior years, when typically it had received 100 percent of its requested hedging rights.
(ARRs, allocated to load-serving entities and keyed to identified source/sink pairs, serve within the PJM scheme of things as a financial derivative exchangeable for an equivalent share of FTRs—financial transmission rights—as the more commonly known term. PJM chooses to allocate ARRs, rather than FTRs, as the practice affords more flexibility to the recipients.)
As a result, the Chambersburg municipal utility faces the potential risk of having to pay some $5.7 million in added congestion costs. And this risk, according to a complaint filed recently at the Federal Energy Regulatory Commission (FERC), represents no less than 31 percent—nearly a third of its entire retail-revenue requirement—collected from native-load customers for the 12 months ended in April. To hear it from Chambersburg, PJM’s apportionment has simply failed. Its tariff, therefore, must be unlawful.
The town of Front Royal, Va., of roughly similar size, has joined the complaint. It claims it faces the risk of $1.4 million in unhedged congestion costs, plus $1.9 million in lost FTR revenues, meaning that each customer of the town’s municipal utility could expect to pay an additional $470 per year for electricity, or around $40 per month.
These examples, while perhaps unique, mark only the tip of the iceberg. In fact, this case, one of several involving PJM and now at FERC, poses fundamental questions on how regulators and grid operators should attempt to price and allocate grid rights and costs, and whether such allocations should continue to respect historical artifacts, such as the boundaries between utility service territories:
• Congestion and FTRs. Should regional FTR allocations serve to maximize system-wide commerce and revenues, on a transactional basis, or rather, protect market participants from the sort of injury that resembles traditional rate discrimination? (Borough of Chambersburg, FERC Docket Nos. EL06-94, filed Aug. 1, 2006);
• Regional Grid Expansions. Should grid operators allocate costs of required grid upgrades across the entire system, or only across affected zones? How does one determine which zones are “affected?” Moreover, should they focus primarily on reliability or market commerce in choosing which upgrades to fund? (PJM Regional Transmission Expansion Plan (RTEP), FERC Docket Nos. ER06-1271, filed July 21, 2006; ER06-1474, filed Sept. 8, 2006);
• Transmission Rate Design. Should FERC preserve license-plate pricing for the regional grid-access charge, to respect differences in the traditional revenue