Six weeks ago, FERC opened a notice of inquiry to invite industry comments on whether wind, solar, and other intermittent energy sources face unfair obstacles in wholesale power markets. Now...
Power System Planning: Who gets paid (and how much) for backing up the system?
years (each year beginning with the summer capability period). This figure shows the old and new demand curves for each of the three zonal markets for the power year 2005-2006. The two succeeding years show demand curves with slightly steeper slopes and slightly higher prices, but those curves are not shown here. ( See FERC Docket No. ER05-428, proposal filed Jan. 7, 2005, approved April 21, 2005, 111 FERC ¶61,117. )
Understanding the Figure. The scale on the x-axis assumes a pre-existing margin of generating reserves of 18 percent in excess of load. In other words, the point of 100 on the x-axis denotes a level of capacity equal to 118 percent of the load requirement. That is the equilibrium level that the market is designed to “incentivize,” for all LSEs and for all zones in the ISO. Thus, at the point of x = 100, the curves produce a price for capacity equal to the equilibrium benchmark or reference price. This benchmark price reflects what the ISO believes it ought to cost to acquire new generating capacity, in the form of a single-cycle gas-fired combustion turbine of standard design. Cost is calculated by making certain specific assumptions regarding size, startup times, efficiency, heat rate, emissions restrictions, and all relevant costs for such items as fuel, labor and maintenance, land, site preparation, insurance and financing, property taxes, and so on. The ISO also assumes that the plant will earn revenues from sales of energy and ancillary services in spot markets and bilateral contracts, and credits such revenues against costs to arrive at the benchmark price for the equilibrium point of x = 100.
As shown here, for power year 2005-2006, that benchmark price is $6.78/kilowatt-month for NYCA, $12.52 for Long Island, and $13.70 for New York City.
A key item at issue in the FERC case concerned the point on the graph representing the intercept with the x-axis, known as the “zero crossing point.” That point shows the point at which supplies of electric capacity are considered so plentiful that the price falls to zero. That point, coupled with the reference price at x = 100, defines the slope of the curve and thus the exact price at all other points along the curve.
Some parties in the case argued that the crossing points (such as 112 for NYCA) were set too high and thus produced prices higher than needed at each point along the sloping sections of the curves. Why not 109, for example, which would produce lower prices and a steeper curve for NYCA? Such arguments won a degree of sympathy, but FERC chose to retain the existing crossing points, since it thought that steeper curves would create greater volatility in capacity prices and thus impair incentives for investment. — B.W.R.
California’s RAR Plan
The California PUC’s proposal would imposed a resource adequacy requirement (RAR) that obligates utilities and load-serving entities (LSEs) to maintain enough generating and other resources to maintain a planning reserve margin (PRM) of 15-17 percent in excess of load.
LSEs must acquire a mix of