(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...
FERC says it won’t ‘change’ the native-load preference, but don’t bet on it.
not with transmission providers behaving badly, but with the basic geographic design of the power grid, and the carving up of grid management into small, uneconomic fiefdoms.
In short, this view states that native load still served by stand-alone, vertically integrated LSEs even now is getting a raw deal, as measured in dollars. This alleged discrimination, the argument goes, comes from failure to take advantage of scale economies. It stems from paying more in rates to accommodate an inferior dispatch of a limited number of resources across a small footprint. So why should FERC jump through hoops just to design a tariff that assures comparable rights (that are equally bad)?
Rather, the solution to discrimination lies in broad and ruthlessly efficient regional centralization of the dispatch function, so that ratepayers can take advantage of the economies of scale present in the most fully diversified generating portfolio, as is now available to ratepayers served by RTO participants.
According to the ISO/RTO Council, ISO New England reports that wholesale electricity prices in its region have declined 5.7 percent ($400 million in savings since 2000. Similarly, PJM reports that fuel-adjusted energy prices dropped 4.2 percent ($500 million in annual savings) after integrating American Electric Power into the RTO. The council identifies some 10 studies calculating consumer benefits from a broad, region-wide economic dispatch. (Global Energy Decisions, ESAI, Cambridge Energy Research Associates, ERCOT, Synapse Energy Economics Inc., MISO, Center for Study of Energy markets, Lawrence Berkeley National Lab. ( See, Comments of ISO/RTO council, pp. 10-11, FERC Dkt. RM05-25, filed Nov. 22, 2005 .)
Consider also the Department of Energy’s recent report to Congress on economic dispatch across the power grid, comparing practices conducted both by the RTOs, under their financial rights regimes, and by traditional, regulated, vertically integrated utility LSEs on behalf of native load.
The report contains a treasure-trove of lessons in basic economics. It identifies additional studies of costs and benefits gleaned from dispatch practices, concluding that a security-constrained economic dispatch (SCED) in the style currently conducted by RTOs in the Northeast United States, outshines all other methods in ratepayer benefits. So much so, in fact, that the study builds a strong case that anything less represents per se discrimination—much worse in dollar terms than any alleged behavioral irregularity in carrying out FERC’s OATT.
Space precludes a full analysis here. However, among all the discussion of all the relevant characteristics of generating resources (fuel costs, startup costs, ramp rates, load following, reactive power, must-runs, must-takes, energy limitations, emissions limitations, etc.), and their profound effects on ratepayer costs, one question jumps out: How large should a dispatch area be?
The Southern Co. system, for one, performs economic dispatch for about 43,000 MW of resources (nuclear coal, hydro, pumped-storage hydro, gas-fired, oil-fired, and purchased power) across a region of 120,000 square miles.
That compares favorably with RTO dispatch portfolios:
- New York. 335 generating stations, 37,500 MW capacity;
- New England. 350 generators, 31,00 MW installed capacity, six states;
- PJM. 163,800 MW of resources, 51 million consumers, 14 states, 164,260 square miles;
- MISO. 132,000 MW capacity 16.5