The Federal Energy Regulatory Commission’s (Ferc) upcoming ruling on integration will finalise its November 2010 proposal for allowing transmission operators to levy a weighted tariff on wind power and other variable energy resources (VERs) to pay for the ancillary generation reserves that accommodate additional variability on the power system.
The American Wind Energy Association (AWEA) and others contend that Ferc’s proposal discriminates against VERs — but could be remedied by combining sub-hourly transmission scheduling with energy-imbalance markets that provide sub-hourly energy dispatch.
Ferc’s proposal requires transmission scheduling at intervals of 15 minutes or faster. While the majority of US grid operators have already adopted the practice, much of the western third of the country — apart from California — keeps hourly schedules. Faster scheduling helps the grid adjust to changes in demand, which mitigates much of the need for expensive balancing reserves.
But AWEA believes in addition to sub-hourly transmission scheduling Ferc should also require energy-imbalance markets that allow neighbouring grid operators to compensate for fluctuations of generation across a wide transmission footprint. The two reforms would combine to greatly lessen the need for integration charges.
"You’d get the benefit of having a much larger and much more diverse geographic area," said AWEA’s manager of transmission policy Michael Goggin. "If one grid-operating area has extra generation and its neighbour has a generation deficit, they can just net out the difference."
The present situation results from a convoluted transmission system set up decades before wind and other VERs were significant. California and the eastern two thirds of the US are covered by regional transmission organisations (RTOs) and independent system operators (ISOs) that have largely moved to five-minute scheduling. In other words, the major impact of Ferc’s ruling will be felt in western states as they switch to faster scheduling regimes.
"This really only applies in parts of the country without ISOs and RTOs," Goggin said. "ISOs and RTOs have already done most of the grid-operating reforms and their costs are minimal because they’re already being dealt with through their own markets."
Regardless of Ferc’s final ruling, nothing will happen overnight. Integration charges will not apply before transmission operators adopt sub-hourly schedules. Further, the establishment of energy-imbalance markets requires sophisticated computer and accounting systems — and an impartial entity to operate them.
"What will hold this up at some point is the eternal question of how it’s managed," said Robert Kahn, executive director of the Northwest InterMountain Power Producers Coalition. "It should be managed by a third party without a commercial interest in the operation of the market."
On another policymaking front, Ferc signalled a wind-friendly future regarding its interpretation of this summer’s landmark cost-allocation methodology for transmission known as Order 1,000. The signal came in October, when Ferc approved major grid-building cost proposals from a pair of transmission operators in the windy US heartland. Although both proposals predate Order 1,000, they include a broad definition of beneficiaries to ultimately
pick up the tab.
Ferc appears ready to rule that electricity users from a wide geographic area will benefit from new transmission lines — meaning a huge pool of ratepayers will share the costs for transmission expansion that serves remote wind regions. "Ferc’s going to rule on how to define benefits and beneficiaries," said AWEA senior counsel Gene Grace. "So this allows us to see the tea leaves for what they’re probably going to do on Order 1,000."