The declining competitiveness of DTE Electric’s power units is in part shown by the fact that the capacity factors of most of the company’s coal units have declined significantly since 2008 and are expected to remain flat or decline through 2017.
That was one of the points in June 27 testimony from the Michigan Environmental Council and the Natural Resources Defense Council in a power supply cost recovery case ongoing at the Michigan Public Service Commission. DTE Electric (formerly known as Detroit Edison) is a unit of DTE Energy (NYSE: DTE).
As examples of what they said is declining coal plant usage:
- River Rouge Units 2 and 3 had capacity factors of 72 and 73% in 2008, and are projected to have capacity factors of 43% and 47% in 2013 and 49% and 55% in 2017.
- The capacity factors for the six units at the St. Clair plant ranged from 59% to 67% in 2008, and are projected to range from 42% to 55% in 2013 and 41% to 52% in 2017.
- The capacity factors for the four big Monroe units, DTE Electric’s coal workhouses, ranged from 65% to 77% in 2008, and are projected to range from 48% to 56% in 2013 and from 50% to 57% in 2017.
- The capacity factor for Belle River Unit 2 is expected to decline from 86% in 2008 to 80% in 2013 and 78% in 2017, while Belle River Unit 1’s capacity factor is expected to hold relatively steady at 61% in 2008, and 59% in both 2013 and 2017.
“In short, in a competitive market with relatively low natural gas and market energy prices, DTE Electric’s coal generating units are not being economically dispatched by MISO nearly as much as they used to,” the environmental groups said.
“The non-competitiveness of DTE Electric’s generating units is also shown by the increasing levels of power that the Company is purchasing from the MISO market,” the groups added. “In 2008, DTE Electric purchased 6,278 GWhs of energy from the MISO market, while in 2012 the Company purchased 8,641 GWhs, for an increase of 37.6%. While the Company projects that such purchases will decline to 6,873 GWhs in 2013, it expects the purchases to escalate to between 7,665 GWhs and 8,764 GWhs for 2014 through 2017. And, as explained in Section IV(A), above, DTE Electric has ended up purchasing between two and more than four times as much power from the MISO market in 2010 through 2012 as the Company projected it would, so it is likely that actual MISO purchases for 2013 to 2017 will be higher than assumed in this application.”
DTE Electric’s over-reliance on increasingly non-competitive generating units impact PSCR customers in at least three ways, the groups said. For one thing, declining capacity factors mean that all of the costs of the plant, including PSCR costs, are spread over fewer MWhs of output, which means that cost of operating the plants will be higher on a per-unit basis. Also, DTE Electric’s ratepayers will be paying to purchase more market energy while also still incurring the expenses related to maintaining the company’s aging coal factor is expected to hold relatively steady at 61% in 2008, and 59% in both 2013 and 2017.
In its previous rebuttal testimony in this case, DTE said that it has 2,000 MW of natural gas-fired capacity, which is equal to 16% of the utility’s total capacity. “Upon closer inspection, however, 1,800 of those megawatts are peaking units that are expected to run only very rarely and, therefore, do not meaningfully contribute to fuel diversity,” the environmental groups said. “In fact, over the past five years, many of the units never operated more than 1% of the time, and the most that any of the units operated was one unit that operated 6.46% of the time in a single year. Over the next five years, DTE Electric projects that these units will continue their very limited operation, with capacity factors ranging from 0.4% to 4.7%.
Groups say DTE’s fuel mix will change little out to 2017
DTE Electric’s PSCR filing shows a utility that would look virtually the same in 2017 as it does today and as it did in 2008, the groups said. Outside of the addition of some renewable energy resources required by Michigan law, DTE Electric’s generation mix would be virtually unchanged, with nearly the exact same proportion of energy production coming from coal versus natural gas in 2013 (78% to 1%) as in 2008 (79% to 1%) and as projected for 2017 (78% to 1%).
Faced with significant environmental compliance requirements over the next few years, DTE Electric proposes to retire only two small and underutilized coal units, while seeking increased PSCR costs related to the pollution control sorbents that would be needed to reduce emissions from most of the rest of the coal units, the environmental groups added.
DTE Electric is proposing to use dry sorbent injection (DSI) and activated carbon injection (ACI) at its River Rouge, St. Clair, Trenton Channel, and Belle River plants in order to comply with the Michigan Mercury Rule (MMR) and the federal Mercury and Air Toxics Standards (MATS). DSI and ACI have lower capital costs (though DSI may have higher annual operating costs) than the flue gas desulfurization controls that DTE Electric had previously thought would be needed to achieve compliance with the MMR and MATS rules, the environmental groups said.
“As a result, the Company has abandoned the potential retirement of River Rouge Units 2 and 3, Trenton Channel Unit 9, and St. Clair Unit 7, and deferred the pursuit of new natural gas combined cycle replacement capacity, that had been assumed in its previous PSCR Plan,” the groups added.
A primary reason that the commission should indicate that it is unlikely, on the case record, to authorize the recovery of PSCR costs related to the DSI sorbents is that there is little evidence in the record regarding the level of costs that the DSI would entail, the groups argued.
The June 27 environmental group testimony also criticized other aspects of DTE Electric’s plan, including its use of tax-advantaged reduced emissions fuel (REF), which is coal with chemicals added to reduce emissions of mercury and other pollutants when the coal is burned.