Jay Morrison, Senior Regulatory Counsel, National Rural Electric Cooperative Association: I was disappointed to see that two different articles in the October 2005 issue erroneously stated...
Letters to the Editor
Congress in enacting the Energy Policy Act of 2005 (EPACT): creating a robust grid that supports competitive markets and meets the reasonable needs of load-serving entities.
Inconvenient Fact #1: Absence of Needed Cost Certainty. As the TDAs recognize, for redispatch to be effective, it must be predictable and reasonably certain at the time a customer decides whether to take transmission service. However, particularly for the long-term service it claims to facilitate, the TDAs’ proposal provides anything but cost certainty. Indeed, TDAs concede that the level, frequency, and cost of redispatch for a particular long-term transaction cannot be predicted with any precision. The proposed exposure of long-term service to unpredictable, directly assigned redispatch market costs would extend to customers outside of RTO markets the congestion-cost volatility that, as Congress recognized in enacting EPACT’s long-term rights provision, undermines load-serving entities’ ability to commit to long-term power supply arrangements. Customers seeking to lock in long-term generation costs would be reluctant to gamble on long-term transmission service predicated on an open-ended obligation to pay whatever redispatch charges are required in real time, especially where the deck is stacked. The frequency, level, and cost of redispatch over the long term likely will be driven by decisions of the vertically integrated transmission provider (with whom the customer likely competes) as to dispatch, adding or retiring generation, acceptance of additional transmission requests, and upgrading the grid (or not), as well as being influenced by all other factors affecting the dynamic AC grid.
Inconvenient Fact #2: Charges in Excess of the Actual Cost of Redispatch. TDAs also assert that for redispatch service to be effective, it must reflect actual costs. But redispatch prices produced by the TDAs’ proposal will likely be much higher than actual cost.
While the TDAs’ proposal suggests that in non-market environments, real-time redispatch values “can and will necessarily be cost-based,” it in fact permits market-based bids, even from vertically integrated transmission providers, as long as the bidder has market-based rate authority in the control area. Many vertically integrated transmission providers have market-rate authority for energy sales within their control areas, based on control-area-wide assessments of market power. But control-area-wide tests do not measure market power in supplying more targeted redispatch service.
In many cases, very few generators, or perhaps only one, will be in a position to efficiently relieve the constraint, making such generators pivotal. Even if multiple generators can affect the constraint, the high concentration of transmission-provider-owned generation within its control area means that the transmission provider often will be able to name its redispatch price, even assuming it is generally subject to effective competition for energy sales within its control area. In other instances, an independent generator, because of its location relative to the constraint, may have market power with regard to redispatch.
Nor can it be assumed that redispatch prices will be disciplined by customer decisions as to whether to take service. If a customer were foolish enough to have accepted long-term transmission service subject to the obligation to pay for real-time redispatch (as the TDAs’ proposal contemplates), the resulting redispatch price would