Faced with the end-of-2010 expiration of a low-cost coal transportation contract, Detroit Edison shipped some extra coal in 2010 that it only planned to burn in 2011, but that transportation costs savings is now over and coal costs have jumped, said utility fuels official James Good.
Detroit Edison, a unit of DTE Energy (NYSE: DTE), filed May 3 testimony from several officials at the Michigan Public Service Commission as rebuttals to testimony from other parties in the utility’s latest Power Supply Cost Recovery (PSCR) case. Good was rebutting testimony from Michigan Environmental Council (MEC) witness George Sansoucy regarding the prudency of the projected fuel expense in the 2012 PSCR plan. This case began in September 2011.
A significant increase in the rail transportation rates of western coal occurred in 2011, after the expiration of a long-term, highly-favorable rail agreement, Good noted. In recognition of this pending increase, additional coal was shipped in 2010 under the previous rail agreement to help mitigate the increase in fuel expense in 2011. In 2012, the “full” effect of the increase is affecting fuel expense since previous lower cost deliveries have been consumed and the average fuel cost to be booked as fuel expense is now fully reflective of the higher transportation cost, Good noted.
“The projected 2012 expense of western coal is about $80 million more than the actual 2011 expense,” he said. “This increase is almost entirely attributable to the increase in average transportation costs due to the full year effect of the new western rail transportation agreement. If the projected 2012 coal expense as shown in my 2012 PSCR Plan Exhibit A-2 were reduced by the $80 million, the resulting coal expense would be about $840 million, or about 240 cents per MMBtu, which is within 1 cent per MMBtu of the actual expense as submitted in my testimony in the 2011 PSCR Reconciliation [case].”
The 9% increase in coal expense from the 2011 actuals to the 2012 projected expense is almost entirely due to increases in transportation costs. “Furthermore, it should be noted that a portion of this cost increase was avoided in 2011 due to the pre-shipment of PRB coal in 2010 as described by Witness Hoffman in the Commission approved 2011 PSCR Plan case,” Good added.
Asked the company’s view of coal prices from 2012 through 2016, Good noted the future coal prices (FOB mine) in the 2012 PSCR Plan were calculated using a combination of existing coal contract prices and projected future coal prices (for 2012-2014) obtained from an over-the-counter coal broker. The projected coal prices were then held unchanged from 2014 to 2015 and 2016. In general, the projection used for the 2012 Plan shows coal prices increasing slowly from 2011 to 2014.
There have been several discovery questions from MEC in this proceeding relating to the assumption that was made by the company to hold the coal prices unchanged for 2015 and 2016. These questions and responses all document the company’s belief that there is enough uncertainty in the coal prices for 2015 and 2016 that there is no compelling argument to assume either an increase or a decrease in pricing, Good noted.
There is no consensus around coal mine mouth prices increasing in 2015 and 2016. For Sansoucy to opine that “in the longer term, however, projected increases in the exporting of coal to markets in Asia and Europe are likely to exert upward pressure on the price of coal,” seems to not be in line with the uncertainty that exists in future pricing, Good said. “Witness Sansoucy’s projection is just one of many possible future outcomes in coal prices, but he has provided no factual basis, other than his opinion, to support his projection.”
Detroit Edison is able to utilize a broad mix of fuels for generation, including coal from various regions (which has been a reasonable and economic choice for Detroit Edison customers for decades), natural gas (which has been a relatively higher cost peaking fuel for decades), No. 2 oil, No. 6 oil, used oil, coke oven gas, and nuclear as well as renewable energy sources like solar and wind, Good noted.
Detroit Edison’s natural gas and oil price projections, in general, are reflective of current prices, Good noted. “For example, our Greenwood plant recently burned spot market gas at a price of approximately $2.50 per MMBtu,” he wrote.
Detroit Edison lays out case for REF coal
Detroit Edison witness William Rogers addressed Sansoucy complaints about the use of Reduced Emission Fuel (REF) and its cost-effectiveness for reducing mercury emissions. REF is coal with chemical additives. At coal-burning plants with no flue gas desulfurization (FGD) system, such as Belle River and St. Clair, utilizing REF will significantly lower the consumption of powdered activated carbon used in activated carbon injection (ACI) systems to reduce mercury emissions. At coal burning plants with FGD, such as Monroe, the use of REF eliminates the need to install an additional chemical injection system and use additional reagents to reduce mercury emissions, Rogers wrote. “Both of these benefits support the cost effectiveness of utilizing REF,” he added.
Asked whether ACI and Dry Sorbent Injection (DSI) are viable options for meeting the new Mercury and Air Toxics Standards (MATS), Rogers said they are. Tests have been conducted on coal-fired boilers demonstrating the effectiveness of DSI for SO2 and HCl removal. EPA identifies DSI as an alternative to FGD for MATS compliance with acid gas limits, and, in fact, forecasts 44 GWs of DSI installations across the country for MATS compliance, he added.
“DSI was tested on two separate Detroit Edison coal-fired units corroborating EPA and vendor forecasts for performance,” he said. “These tests clearly demonstrated that DSI technology is capable of reducing emissions to MATS-compliance levels on Detroit Edison units burning predominantly subbituminous coals.”
Detroit Edison’s Gary Lapplander also addressed criticism from various witnesses about the REF program, which involves the sale of coal inventory at the power plants by Detroit Edison to non-regulated fuel companies, then the sale of the altered coal back to Detroit Edison for consumption. Lapplander said this method is effective and fair to Detroit Edison ratepayers, despite the criticism. Detroit Edison is not undertaking a “transfer” of its fuel function in this case, he emphasized.
“In fact, Detroit Edison has sold the coal inventory in consideration for cash, without subsidizing its affiliates, without compromising the intent of the code of conduct, to the benefit of Detroit Edison customers,” said Lapplander. “Detroit Edison has retained its coal handling and transportation functions and there is no change in its logistics functions.”
There were reasons to outsource the REF work to the fuels companies, Lapplander said. First and foremost was the fact that this provided Detroit Edison a risk free option to help it attain the mercury reduction requirements contained in a Michigan rule beginning in 2015. Detroit Edison was not required to make any capital investment to support the REF facilities and therefore did not assume any risk that the REF project would not be successful. Detroit Edison also reasonably determined that the tax risks and commitment to an unproven technology at its power plants were not appropriate for a regulated utility, he said.