The core of a good regulatory proceeding is a conversation.
The Too-Perfect Hedge
Congress gives FERC an impossible task: Craft long-term transmission rights to save native load from paying grid congestion costs.
If “perfect” be the enemy of the “good,” then look no further for proof than in Federal Power Act section 217(b)(4), enacted by Congress in last year’s landmark energy bill, EPACT 2005.
That section, as many see it, would grant a virtual long-term immunity against liability for transmission congestion costs—a “perfect hedge,” if you will—to any electric utility that retains the traditional obligation to serve native load (a load-serving entity, or LSE), even if that utility operates within the footprint of a regional transmission organization (RTO), and even if the RTO essentially has adopted a day-ahead spot market for wholesale power, complete with locational marginal pricing (LMP) and financial transmission rights (FTRs).
Before RTOs, the utility seeking base-load generating capacity simply would build its own power plant and transmission lines, or sign a long-term supply contract with a plant owner and buy or reserve enough transmission service to ensure physical delivery. Congestion? Not a factor, except for the occasional line outage or blackout. The power flows, or it doesn’t.
Fast-forward to today’s financial world. The LSE as RTO customer gains access to all manner of cheap power supplies—a cornucopia of supply options—but to purchase any actual quantity for delivery to consumers it must “buy through” any congestion it encounters, as measured in the difference between the price of power at the source and sink.
FTRs offer a financial hedge against congestion risk, of course, but no more, since the typical RTO rarely will guarantee the sufficiency of FTR payments through what is called “full funding.”
Even if the LSE owns its power plant and chooses to “self-schedule” the unit through the RTO’s dispatch process, the LSE in effect “sells” the plant output to itself at the wholesale price that prevails at the point of injection into the grid (the “nodal” price), and then “buys” back the output at point of withdrawal from the grid and delivery into its local distribution network, again at the prevailing local price. In each case, the nodal price reflects the opportunity cost of alternative power available at the given location.
Under this RTO market regime, a utility might pay $1 billion to construct a 600-MW coal-fired generating plant, with running costs of about $20 per megawatt-hour (or pay dearly for that capacity over a long-term supply contract), but then end up “buying” the output on behalf of its native load at $80/MWh—the approximate running cost of a gas-fired peaking turbine that would cost a third as much to construct. The extra payment represents congestion—the premium required for moving power in the same direction as everyone else (sparsely populated producing area to the densely populated consuming area).
Attorneys Robert McDiarmid and Cynthia Bogorad (Spiegel & McDiarmid), representing the Transmission Access Policy Study Group (TAPS), an informal association of transmission-dependent utilities (TDUs) in more than 30 states that comprises mostly municipal utilities and other public power entities,