Ultracapacitors and batteries work together to solve power quality problems.
A Candy-Coated Grid
Incentives for transmission investment could boost postage-stamp pricing over license-plate rates.
10 percent (akin to the interest rate stated in the commission’s regulations on rate refunds), the S&P 500 Electric Utility Stock Index in 2004 earned an overall 13.9 percent. He adds that FERC at least should adjust its ROE model—applied currently to book value—to reflect an industry average market-to-book ratio of 2.47 to 1, according to the S&P 500 Utility Index as of year-end 2005.
At Progress Energy, Deputy General Counsel Len Anthony suggests that FERC ought to consider restating the incentive adder in terms of dollars per kilowatt-month of new added grid capacity, rather than as a bonus to ROE allowance (though the effect would be the same).
By contrast, FERC’s idea of using hypothetical capital structures in rate making, with higher equity ratios, has not fared so well.
Representing the Transmission Access Policy Study Group, attorneys Robert McDiarmid and Cynthia Bogorad (Spiegel & McDiarmid, in Washington, D.C.) suggest that skewing capital structure to fashion a financial incentive represents a distortion of reality, since markets treat the transmission business as lower-risk than generation, so that a stand-alone transco, in the real world, actually would be highly leveraged, and would sport a thinner equity ratio than a traditional utility.
For example, McDiarmid and Bogorad note that the capital structure for ITC’s parent company contains less than 29 percent equity, and more than 71 percent debt. (They add that as of Jan. 3, 2006, ITC’s price earnings ratio was 29.21, and its market-to-book ratio was 3.46, according to data taken from the Yahoo Finance Internet site.)
State PUC Prerogatives
If FERC’s plan suffers an Achilles’ heel, it’s that utilities cannot pocket any federal bonus for grid investment or RTO participation until state regulators OK that extra cost in retail rates. True, the filed-rate doctrine ordinarily requires state PUCs to passthrough any charge approved via FERC tariff, but you never know—as shown by a case now pending in the upper Midwest, within the RTP footprint of the Midwest Independent System Operator (MISO).
On Dec. 21, the Minnesota PUC agreed to allow Minnesota Power (Allete) and Northern States Power (Xcel) to use the state’s fuel clause adjustment (FCA) law to recover certain net costs that MISO had billed the two utilities under its “day 2” market regime, but not other costs that appeared to fall outside the scope of the FCA. (See Minn. PUC Docket Nos. E-002/M-04/1970, Dec. 21, 2005.)
The ruling shows clearly the potential difficulty in trying to use state PUC rate cases to reconcile and recover FERC-approved costs unique to special federal programs created through industry restructuring. The items involved in the case had included: (1) net fuel-related costs incurred in buying and selling power through the day-ahead market; (2) administrative “uplift” charges related to MISO management of uncollectible accounts of defaulting traders; and (3) net “congestion” costs related to LMP differentials in nodal energy prices, and activity relating to FTRs (financial transmission rights). Citing the limited scope of the FCA law, the PUC had denied authority to recover the congestion costs through the FCA. Yet these congestion costs had represented nothing