The latest dispute over PJM’s bidding rules has raised the level of uncertainty in organized electricity markets. Efforts at reform have created a market structure so jumbled that it can’t produce...
Kicked Off and On Schedule
Cal-ISO files a new market design, but has it traded efficiency for software?
senior regulatory counsel for San Diego Gas & Electric Co., “The Great War over locational marginal pricing has been brought to armistice.” As he explains, SDG&E is reasonably satisfied and will not force the ISO to prove that every new tariff element will go off without a hitch:
“SDG&E rejects this review standard,” writes Garber, “as too friendly to the devil we know and too hostile to the friend we can reasonably anticipate.”
In fact, an objective look at the record would indicate that all three of the state’s large investor-owned electric utilities now appear to stand behind most features of the ISO’s new market design, with some caveats. Even the state PUC now “generally supports” the new tariff, including LMP.
Nevertheless, as with any 5,000-page proposal, enough questions remain unresolved to fill a dozen or more magazine columns. Here is a short list of some of the more serious criticisms and disagreements concerning Cal-ISO’s proposed new market design:
1. Resource Adequacy . ISO insistence on providing reliability services as a backstop to state-mandated rules on resource adequacy requirements and for allocating such costs to ISO market participants, even for publicly owned utilities not under PUC jurisdiction, could create unconstitutional interference with state’s RAR standard.
2. Resource Exports . MRTU gives too much discretion to ISO to curtail exports of gen resources that qualify as satisfying resource adequacy requirements imposed by state PUC.
3. Transmission Line-Losses . Recognition of losses in LMP pricing algorithm on a marginal, rather than average-cost basis, will lead to over-collection of losses at the ISO ($200 million per year) and impose a crushing cost burden, especially on PG&E and other LSEs using PG&E’s LAP pricing node for load. PG&E historically has shown a lower customer density and higher reliance on distant generation, yielding higher loss factors, and it will receive inadequate reimbursement under the ISO’s scheme to repay excess loss collections through average load-share ratios.
4. Transmission Outages . Stretching the mandatory notice period for scheduled transmission outages, from 72 hours to 45 days, appears unworkable to many.
5. Long-Term FTRs . The ISO in some minds appears hostile to the issuance of long-term transmission congestion rights (LTTRs), as mandated by Congress in the Energy Policy Act of 2005. Need for LTTRs remains clear, they say, since the California PUC bars use of financial rights payable on liquidated damages clauses to satisfy state-enforced requirement for resource adequacy.
6. Hour-Ahead Scheduling Process . Rules for HASP, which bar self-scheduling of exports (they must schedule day ahead), but which allow self-scheduled imports (but cleared not against demand bids, instead against Cal-ISO load forecast), reveal alleged tendency of ISO to favor load and over-regulate supply. Critics say HASP rule could backfire and prevent ISO from ridding itself of excess generation—a real threat because market design makes it difficult to de-commit a resource. Timing of HASP closing also fails to mesh comfortably with gas markets, raising fuel costs and minimum-run and ready-to-serve costs for gen resources seeking to provide real-time ancillary services.
7. CRR Terms . Rights should be monthly, some