Territorial fights emerge in the interregional transmission plans proposed for compliance with FERC Order 1000.
Kicked Off and On Schedule
Cal-ISO files a new market design, but has it traded efficiency for software?
Eyeing a launch date of November 2007, the California Independent System Operator (Cal-ISO) at last has come forward with plans for revamping its widely disparaged wholesale market design. The formal proposal, known as the MRTU (Market Redesign and Technology Upgrade), was filed this past February at the Federal Energy Regulatory Commission (FERC). It embraces many, if not most, of the ideas that already have won wide acceptance among utilities, regulators, traders, and power producers that deal with markets operated by regional transmission organizations (RTOs) in the Northeast and Midwest.
All told, the package includes some 5,000 pages of tariffs, testimony, and explanatory language, governing the management of some 4,000 geographic market nodes. The proposal appears so complex that Western Area Power Administration (WAPA), a skeptic of RTO-style trading regimes for the Western Interconnection, has estimated that it will need some 12.5 GB of computing power to provide portfolio management and scheduling services to wholesale power customers under the MRTU.
This daily data requirement stems from a complex market design that for the first time will introduce Californians to such features as: (1) a day-ahead spot energy market; (2) a centralized, bid-based, and security-constrained dispatch of generation; (3) locational marginal pricing (LMP) for both supply and load; and (4) tradable financial rights to manage grid congestion.
The tradable grid rights will be known as CRRs (congestion revenue rights), to distinguish them from the Cal-ISO’s previous physical construct of “firm transmission rights” (not to be confused with Eastern-style “FTRs”). Thus, the Cal-ISO’s MRTU would build on a fully nodal network grid model, thus avoiding the inefficient zonal approximations that in the past have led to trouble.(See, FERC Docket No. ER06-615, filed Feb. 9, 2006, and industry comments filed through May 12, 2006.)
In a key departure from Eastern RTO practice, however, the Cal-ISO’s MRTU would not immediately include an ISO-administered capacity market, in the manner of the ICAP, UCAP, and LICAP models, which have proved so controversial. Instead, to assure fixed-cost recovery for power producers, the MRTU would look to the state public utilities commission (Cal-PUC), and its resource adequacy requirement (RAR).
All the same, this lack of a proposed capacity market has not necessarily simplified the new California market structure. To the contrary, the ISO now must coordinate its tariff with state-imposed rules, which may not prove easy.
The Cal-PUC’s RAR rule, enabled by state legislation (Assembly Bill 380, enacting new sec. 380 to the state Public Utilities Code) obliges load-serving entities (LSEs) under PUC jurisdiction to sign contracts that will ensure access to power supply resources. (See Cal-PUC Decision 05-10-042, Oct. 27, 2005, 244 PUR4th 341.) Importantly, Assembly Bill 380 also enacts new Public Utilities Code sec. 9620, which assigns a prudent resource planning obligation to publicly owned utilities outside PUC jurisdiction, with a reporting obligation to the California Energy Commission.
To echo the locational aspects of capacity markets proposed back East ( e.g., New