Investor-owned utilities might seem fairly robust, but they’re not impervious to unpredictable black-swan events. Ensuring the industry’s survival might depend on our ability to reduce our...
'T' Party Revolt
Transmission expansion costs are spread unevenly, driving a wedge between utilities and regions.
plants on nearby transmission lines. LODF meant that the TO utilities closest to the site of the new projects would end up carrying the lion’s share of the 50-percent refund obligation. This tendency did no harm at first, during the years 2004 through 2006, in which the ratio of new projects to MISO load trended around replacement level, and when developers tended to site their new projects homogenously across the entire MISO footprint.
However, as pointed out by attorney Carmen Gentile (Bruder, Gentile & Marcoux), in written comments he filed on the MISO proposal for Integrys Energy Group, the building of large quantities of generation in remote, low-density areas, known as far load simply “breaks the back of the current defective cost allocation scheme.” MISO’s method, writes Gentile, is “ill-suited to the dynamics of a centrally dispatched transmission system that is in a state of continuous growth and evolution.” (See, Comments of Integrys Energy Group Cos., FERC Docket ER09-1431, filed Aug. 13, 2009.)
Testifying for MISO in support of the new tariff proposal, among others, were Eric Laverty, MISO’s director of transmission access planning, and JoAnn Thompson, manager of Otter Tail’s federal regulatory compliance and policy.
According to Laverty and Thompson, the many gen projects now slated for MISO’s geographic Group 5 study area (Dakotas, Iowa, Minnesota) would boost Otter Tail’s net-up costs by 5,200 percent, giving rise to a 24-percent increase in Otter Tail’s transmission rate charged to retail ratepayers. Counting all new gen projects across the entire MISO footprint, Thompson reported that Otter Tail’s share of net-up cost allocations would climb 9,500 percent, forcing a 44-percent hike in the transmission-related retail rate.
Figures for MDU were comparable, though not quite so shocking: For Group 5 projects, net-up costs would rise 826 percent, with retail T rates up 1.8 percent. For MISO-wide projects, net-up costs climb 2,600 percent, with retail T rates up 5.9 percent. (See, Supporting Comments of Montana-Dakota Utils. filed Aug. 13, 2009.)
Suffice it to say, however, that these numbers don’t tell the whole story. Wind power advocates dispute them, claiming that Otter Tail, MDU and MISO both have overestimated the real effects on North Dakota ratepayers, and underestimated the likely chilling effect on wind project development. Others point out these rate impacts ignore benefits from integrating more wind into resource portfolios, such as avoided carbon emissions and the likely lowering of locational marginal clearing prices (LMPs) in regional energy markets.
For example, MISO, Laverty, Thompson and other witnesses argued that the new tariff would increase wind project development costs by only 4.8 percent, based on data sets showing an installed capacity cost of $2,000/kW, and a typical unit net-up cost of $200/kW, on the assumption that wind-driven upgrades in the Group 5 study area would involve only the smaller 115- and 230-kV lines.
But key opponents, including Edison Mission Energy, Nextera Energy Resources, Iberdrola Renewables, Horizon Wind Energy, GE Energy, the Natural Resources Defense Council, and the American Wind Energy Association, question MISO’s cost estimates.
They allege that the $200/kW figure comes from the $195 estimate in