The marriage between Exelon and PSEG would create the largest electric utility in the United States. The policy implications could loom even larger, however. Standing at risk is nothing less than...
The Too-Perfect Hedge
Congress gives FERC an impossible task: Craft long-term transmission rights to save native load from paying grid congestion costs.
argue (as many others have) that this required payment of congestion costs thwarts best efforts at power-plant development:
“The high installed cost of base-load coal generation,” they say, “cannot be justified if, as a result of congestion, the LSE is likely to pay gas-based LMPs for the energy produced.”
According to testimony from Thomas W. Ingwers, director of energy trading and contracts for the Sacramento Municipal Utility District (SMUD), RTO market regimes built on nodal LMPs and FTR congestion hedges threaten to create a new version of “stranded investment” in utility-owned generation located far from load because of the steep energy price differentials seen between producing and consuming areas.
In SMUD’s case, notes Ingwers, the absence of any long-term firm rights in transmission service may prove “a serious obstacle” to the utility’s planned Solano Wind Project, a 205-MW development to be located within the control area of the California Independent System Operator (Cal-ISO).
Ingwers adds that last September, during California Independent System Operator (Cal-ISO) stakeholder discussions regarding the development of a new market design with full nodal locational pricing and financial transmission rights known as CRRs (“conges- tion revenue rights”), Bonneville Power had warned the ISO that congestion-cost exposure in the style of the northeastern RTOs could lead BPA to reconsider decisions to buy or sell in the new market. Ingwers cites written stakeholder comments from BPA, available on Cal-ISO’s Web site, stating that California’s expected configuration for CRRs was “not suited to the sporadic nature of our marketing of surplus energy to the ISO.”
(Cal-ISO has since submitted its new market design to the commission, including financial CRRs. See FERC Docket No. ER06-615, filed Feb. 2, 2006.)
This new problem with “stranded” generation becomes even more vexing, however, because RTOs generally offer FTRs only for terms of one year or less. By contrast, a load-serving utility in a state that retains full, traditional cost-of-service regulation, without retail choice, might well want a 30-year long-term FTR to match the life of its coal-fired power plant or power supply contract.
None of this, however, will come as any surprise to the Federal Energy Regulatory Commission (FERC), which has recognized the problem for some time now, and which last year (in its Docket No. AD05-7) had asked the utility industry for ideas on how to solve it. (See, “Coal’s Raw Deal: The bias in RTO markets, and how FERC might fix it.” Public Utilities Fortnightly, September 2005, p. 20.)
Now however, comes Congress, attempting to fix the problem in EPACT sec. 1233. That section gives a complex and ambiguous set of instructions to FERC, and then commands the commission to carry them out within the year. Those instructions appear to many to guarantee to LSEs the same degree of protection from congestion charges that they would have enjoyed before RTO markets, through a physical, long-term reservation of transmission capacity rights (an “LTTR”) and to do it within the operating and market protocols of the RTO itself.
There’s a problem, however. It very likely cannot be done.
An Ambiguous Assignment
FERC took the first step