A much lower cost for coal generation projected for 2013 is in part due to the shut Sherco Unit 3, said David Horneck, Manager of Generation Modeling at Xcel Energy Services, the service company for Xcel Energy (NYSE: XEL) and its subsidiaries.
Testimony by Horneck was filed June 1 at the Wisconsin Public Service Commission by Xcel’s Northern States Power unit as part of an electric and natural gas rate case. The testimony was redacted, so certain key details are missing.
Northern States Power is projecting a $105.8m decrease in costs for NSP System-owned fossil fuel generation for its 2013 test year. The key contributors to the decline are decreases in costs for coal generation ($74m); natural gas generation ($25.3m); and chemicals for emission control at fossil generating facilities ($7m).
The drop in costs for coal generation is driven by a substantial reduction in the forecast generation from these resources for the 2013 test year, with the amount of the reduction being redacted. The principal contributor to the decline is the absence of Sherburne County Unit 3 (Sherco 3) from the 2013 test year. Sherco 3 experienced a significant failure when returning to service following a planned outage in the fall of 2011. The company did not include the unit in the 2013 test year given the uncertainty surrounding when it would return to service.
The decrease in costs for natural gas generation is driven by a decrease in forecast generation from natural gas units as compared to 2012. In addition, forward natural gas prices for 2013 are currently projected to be lower than final authorized natural gas prices for 2012. Forward natural gas prices for 2013 for the Ventura hub average $3.54/MMBtu, as compared to $3.76/MMBtu for 2012 authorized costs, Horneck noted.
A $5.5m decrease in costs for nuclear generation for the 2013 test year is driven by a decrease in forecast generation from nuclear units as compared to 2012. There are two planned extended outages at nuclear units in 2013 causing the decline in forecast generation. One is for an outage at the Monticello unit to complete extended power uprate (EPU) activities and for refueling. The other is for an outage at Prairie Island Unit 2 to replace the unit’s steam generators and for refueling. Following the outages, both units are projected to have an increase in power level which is offsetting the decline in forecast generation to some degree. However, it is not enough to offset the greater number of outage days in the 2013 test year.
“In terms of total $/MWh generating costs, nuclear is forecast to increase by approximately 1.7 percent while coal generating costs have increased by 9.3 percent,” wrote Horneck about the 2013 test year. “Uranium, enrichment and conversion prices remain relatively stable for 2013 as uncertainty over the expansion of nuclear production in the US and abroad remains. The increase in the average cost for coal generation is largely driven by the absence of Sherco 3 in the forecast, which is one of the Company’s lowest cost coal plants. In addition diesel surcharge costs for rail transportation remain high given sustained high prices for oil and diesel fuels.”
The 2013 test year reflects an additional of purchased wind energy at a net cost increase of $10.8m. This is primarily due to a new purchase of 200 MW under the Prairie Rose Power Purchase Agreement (PPA). Offsetting the increase in wind energy from the Prairie Rose project is a reduction in forecast energy from some new Community-Based Energy Development wind for which the in-service date has been delayed. Overall, for 2013, the average cost for all wind from PPAs is projected to decrease to approximately $39.71/MWh from the 2012 authorized cost of $43.01/MWh.
Shutdown of Bay Front coal unit to help with emissions credits
Also on June 1, Northern States Power filed an answer at the Wisconsin commission to a question in its annual fuel case, with the answer provided by Richard Rosvold, Air Quality Manager at Xcel Energy Services.
The answer said that Northern States Power Minnesota (NSPM) and Northern States Power Wisconsin (NSPW) have an adequate supply of SO2 allowances under the Acid Rain Program (ARP), the Clean Air Interstate Rule (CAIR) and the Cross-State Air Pollution Rule (CSAPR) to cover SO2 emissions from NSPM and NSPW sources. Xcel’s strategy is to hold these allowances for compliance purposes based on the current and future estimated value of these SO2 allowances.
“NSPW is projected to be slightly short to having a slight surplus of annual NOx allowances under CAIR and CSAPR when compared to forecast NOx emissions from NSPW sources,” Rosvold noted. “NSPM is projected to have a surplus of annual NOx allowances under CSAPR when compared to forecast NOx emissions from NSPM sources. Our strategy is to manage NOx emissions from NSPM and NSPW sources and to purchase a limited quantity of allowances for 2012 through 2014, if necessary. NSPW is projected to be slightly short of ozone season NOx allowances under CAIR and CSAPR when compared to forecast NOx emissions from NSPW sources. NSPM is not subject to the ozone season NOx allowance provisions under CAIR and CSAPR. Our strategy is to manage NOx emissions from NSPW sources and to purchase a limited quantity of allowances for 2012 through 2014, if necessary.”
In June 2011, the utility signaled to the Wisconsin Department of Natural Resources (WDNR) through its Preliminary Best Available Control Technology (BACT) Determination for Bay Front Boilers B20, B21, B24 under the Wisconsin Mercury Rule that Unit 5 (B24) will cease burning coal by Jan. 1, 2015, so that the unit will not be subject to the rule. As a result of ceasing coal use in Bay Front Unit 5, estimated NOx emissions are expected to be below the company’s NOx allowance allocations under CAIR and CSAPR. Its strategy is to hold these allowances for compliance purposes in Wisconsin.