Our annual survey of rates of return on common equity authorized by state public utility commissions in recent rate cases for electric and gas retail distribution utilities.
What everybody missed in setting up the regional grids.
While the electric utility industry has largely agreed on what elements to include in a standard market design (SMD) to govern wholesale power trading in a given region, recent experience shows that the regulators from time to time have overlooked a number of things.
These omissions keep cropping up even in the most successful of the regional markets (New York, New England, and PJM in the mid-Atlantic). They are proving difficult to correct or reconcile for the various independent system operators (ISOs) and regional transmission organizations (RTOs) spread out across the country. And the Federal Energy Regulatory Commission (FERC) has not issued much in the way of guidance.
Consider a brief sample of three nagging questions-"holes" in the market, if you will, that few people fully anticipated. These problems undermine the cost efficiencies that we looked for under a market regime, but by no means do they take us to the end of the list:
The Gen Plant Rate Case.
Despite having "deregulated" the generation sector, RTOs now find themselves conducting virtual rate cases for power plants in an effort to set a value for capacity. RTOs can be seen gathering evidence and reviewing all manner of actual and hypothetical costs and inputs for the gen sector, such as labor, taxes, fuel, insurance, maintenance, heat rates, and efficiency profiles. What can be done?
Must-Run Gen Costs.
Who should pay the steep and unpredictable reliability must-run (RMR) costs that RTOs incur in real-time to dispatch "regulatory must-run" power plants to erase deviations from day-ahead schedules and stabilize the grid?
Gen Plant Retirements.
With Order No. 2003, FERC has mandated procedures to get new plants interconnected with the grid, but how do we decide when to retire a plant? Who signs off on that? It may seem to be a simple matter, but RTOs can wreck incentives for new investments if they don't take care in managing these retirements.
These questions remained largely unanswered when ISOs and RTOs began installing their market regimes. In fact, they may not have fully realized that the problems existed in the first place, or their full implications. Yet, these questions now take center stage in a handful of disputes pending at FERC.
In one such case, the New York ISO (NYISO) has proposed to reconfigure the sloping demand curve for its ICAP market (installed capacity), which helps power-plant owners recover fixed costs by rewarding them for the long-term capacity value they contribute to bolster the adequacy of regional power supplies. But power producers and utilities question the ISO's assumptions regarding benchmark levels of cost and profitability for new gen units ().
Why should the regional grid operator be the one to decide the ideal hypothetical prototype for a new gas turbine, and then spend more time tallying up what costs would be for that make-believe unit?
In a second case, ISO New England believes that high and unpredictable RMR costs have discouraged participation in the day-ahead spot market by so-called "virtual" traders-buyers and sellers who do