Six months back, when ISO New England was mulling over various reforms that FERC had mandated last fall in Order 719 for the nation’s six regional transmission organizations and independent system...
Kicked Off and On Schedule
Cal-ISO files a new market design, but has it traded efficiency for software?
say rather than seasonal, as ISO proposes, since demand and congestion data show significant monthly volatilities that seasonal rights will leave unhedged.
8. CRR Allocations . Initial eligibility rules will penalize competitive retailers (still 12 percent of big-three IOU load), who cannot easily substantiate future load requirements. Grandfathering rules will discriminate against LSEs that gain load from year to year. Non-member LSEs in California serving load external to ISO will suffer especially, as rule for proving “legitimate need” is too strict, and since ISO-member LSEs enjoy residual CRR allocation rights once needs are met for existing contracts (ETCs) and transmission owner rights (TORs). ISO explanation that non-members can use imports or counter-party deals to schedule alternative gen sources to avoid use of ISO grid and exposure to unhedged congestion costs proves false, since renewable portfolio standards impose a certain physical inflexibility.
9. Market Power Mitigation . ISO reliance on PJM-style mitigation, testing mere potential for exercise of market power through 3-pivotal-supplier test, rather than more concrete conduct/ impact test, could fail to distinguish price increases driven by scarcity rather than gaming, and thus fail the judicial standard set in D.C. Circuit’s 2005 ruling, Edison Mission Energy v. FERC, 394 F.3d 964.
10. Demand-Response Bids . Postponement of demand-response bidding by participating load until the second-phase implementation of MRTU will penalize competitive retail energy service providers and large customers, such as the state water project.
At this point, the lion’s share of opposition to Cal-ISO’s market-reform initiative tends to come not from state regulators or investor-owned utilities, but from the public power sector, including municipal utilities and irrigation districts, which remain loyal to a physical-rights model.
For example, the Control Area Coalition, including Bonneville Power, WAPA, and the Sacramento and Los Angeles municipal utilities, asks why California should now rush to embrace a new market design when the chief shortcoming of the current regime— the ISO’s inability to manage with intra-zonal congestion—has abated of late. In particular, the coalition cites a 52 percent drop in intra-zonal congestion costs, from $426 million in 2004 to $203 million in 2005, as reported by Cal-ISO. (See, 2005 Annual Market Performance Report, March 2, 2006, www.caiso.com/ 17b1/17b1887672ff0.pdf ).
Virtual Bidding: A Moral Affront?
Many industry players fault Cal-ISO for proposing to delay implementation of convergence bidding in the day-ahead market, especially as Cal-ISO proposes also in the MRTU to eliminate the current requirement, introduced in November of last year, in Cal-ISO tariff Amendment 72, that otherwise has required that scheduling coordinators must submit day-ahead schedules that reflect at least 95 percent of their forecasted daily demand, and which provide data to Cal-ISO on a weekly basis regarding actual daily loads. These players fear that just as power producers can withhold supply to drive up the day-ahead wholesale energy price, so can utilities withhold demand to drive the energy price down, and thus take advantage of relationships between the day-ahead and real-time markets. The solution, they argue, is to allow market participants to bid day-ahead and real-time, even if they lack physical positions (those without generating capacity or