(November 2008)Economic uncertainties are raising doubts over utility returns. Will regulators feel the need to consider broader economic effects when engaging in ratemaking? While...
The Too-Perfect Hedge
Congress gives FERC an impossible task: Craft long-term transmission rights to save native load from paying grid congestion costs.
clearing of nodal LMPs.
Congress offers little guidance. It simply instructs FERC to act in a way that facilitates grid planning and expansion, and to meet the “reasonable needs” of LSEs to satisfy their service obligations and secure “firm transmission rights or equivalent tradable or financial rights on a long-term basis for long-term power supply arrangements.”
The Bonneville Power Administration proposes a five-year term length for LTTRs. TAPS suggests 10 years. One popular idea would link LTTR term lengths to the RTO’s planning horizon for transmission, on the theory that Congress designed EPACT sec. 1233 to promote grid expansion.
The American Public Power Association (APPA) worries that RTOs could “go short,” and in fact, both Cinergy and the New York ISO suggest that a one-year duration ought to qualify as “long-term,” since current FERC rules in many areas (such as Order 888, the original open-access mandate) say that power contracts as short as one year in length will qualify as “long term.” If that’s the correct definition, then the RTOs already would satisfy EPACT by offering one-year FTRs, and the law would serve no purpose.
A coalition of municipal, government- or consumer-owned utility systems from New England contends that simply extending the length of RTO-issued FTRs, while retaining the same RTO-designed attributes for allocation, trading and risk management would not do the trick because of an overall lack of simultaneously feasible FTRs or auction revenue rights. (Some RTOs award revenues from FTR auctions to utilities in place of direct allocations of FTRs. Utilities then can use these “ARRs” to purchase FTRs, or can choose simply to keep the money.)
The New England public systems complain also that ISO New England allocates ARRs among congestion-paying LSEs on the basis of zonal load-ratio shares that reflect only the average zonal market-clearing price of FTRs in the auctions, offering no assurance, then, that ARR recipients can use the revenues to buy specific FTRs to hedge congestion on a particular grid path between a specific source and sink.
The requirement of simultaneous feasibility, alluded to above, tends to make sequential allocations or issuances of financial transmission particularly problematic, and instead favors an all-in-one calculation performed by RTO software. The underlying reason, according to testimony from Scott Harvey (director) and Susan Pope (principal), from LECG LLC consulting, submitted to FERC in support of Cal-ISO’s recently filed new market design, stems from a mathematical proof developed in 1992 by Harvard economist William Hogan, concerning the adequacy of congestion revenue collected by RTOs to pay back the congestion costs incurred by FTR holders. (See, testimony of Scott Harvey and Susan Pope, pp. 16-17, FERC Docket No. ER06-615, filed Feb. 8, 2006, citing William W. Hogan, “Contract Networks for Electric Power Transmission,” Journal of Regulatory Economics, Vol 4, No. 3, Sept. 1992, pp. 211-42.)
As Harvey and Pope explain, Hogan’s work proved that if an RTO relies upon the same grid topology both to (A) conduct a security-constrained dispatch of generating resources and calculate nodal locational clearing prices, and (B) determine the simultaneous feasibility of FTRs ( i.e.