By Robert Mullin
Tucson Electric Power retained its right to sell power at market-based rates in the southwestern corner of Arizona on Thursday after FERC concluded the utility does not exercise market power within its own balancing authority area (ER10-2564-009, et al.).
The ruling concludes a investigation under Section 206 of the Federal Power Act initiated by FERC in March, when TEP informed the commission that while it passed the “pivotal supplier” indicative screen for all seasons in its BAA, it failed the “wholesale market share” screen for the winter season. FERC relies on the screens as a preliminary test to establish a “rebuttable presumption” that an energy seller exercises horizontal market power within a geographical area.
TEP, along with its parent company UNS Energy, faced similar scrutiny of its market-based rate authority (MBRA) three years ago after filing a “change in status” notice indicating the utility passed FERC’s pivotal-supplier and market-share screens for so-called “first-tier,” or neighboring, BAAs but failed the market-share screen covering its own territory. (See Tucson Electric Could See Loss of Market Rate Authority in its BAA.)
In that instance, TEP — along with other Southwestern utilities — was able to retain its MBRA when FERC approved a set of simultaneous import limit (SIL) calculations showing the utility maintained enough transmission capacity into its home market to offset concerns about market power under constrained circumstances (ER10-2302, et al.). The commission at the time commended the region’s utilities for coordinating their SIL studies and sharing SIL values with each other to facilitate market analyses. (See FERC OKs SW Import Studies, Offers Future MBR Filers Guidance.)
In its most recent ruling, FERC cleared the way for TEP’s MBRA after finding the utility passed the crucial delivered price test (DPT), a secondary screen that factors in native load commitments to capture a detailed picture of an electricity supplier’s “available economic capacity” — energy available for offer in the open market — over multiple seasons and load conditions. The analysis also considers the load commitments for, and available supply from, other generators in the region.
The DPT measures market concentration based on the Hirschman-Herfindahl Index (HHI). As FERC explained, “An HHI of less than 2,500 in the relevant market for all season/load levels, in combination with a demonstration that the applicants are not pivotal and do not possess more than a 20% market share in any of the season/load levels, would constitute a showing of a lack of horizontal market power, absent compelling contrary evidence from intervenors.”
TEP’s DPT results showed that, when considering economic capacity absent load obligations, the utility’s HHI exceeded 2,500 in six out of 10 season/load periods, which consist of super-peak, peak and off-peak intervals for the summer, winter and shoulder periods plus an additional highest additional super-peak for summer.
But when considering the available economic capacity that factors in the utility’s load, TEP passed the DPT during all season/load levels.
“In light of applicants’ native load obligations, we find that the available economic capacity measure of the DPT more accurately captures conditions in the relevant market,” the commission said.
FERC noted that TEP provided additional sensitivity analyses to measure what effect a 10% increase or decrease in prices would have on the results of the DPT.
“Under the available economic capacity measure, when prices are increased by 10%, applicants’ market shares for winter peak and winter off-peak season/load periods increase to 22% and 37%, respectively. However, applicants are not pivotal, and the market’s HHI remains below the 2,500 threshold in all season/load periods,” FERC said. The test showed similar outcomes when prices were decreased by 10%.
TEP in May signed an agreement with Tucson Electric Power Signs up for Western EIM.)
