The coal-fired Black Dog Units 3 and 4 in Minnesota, long targeted for retirement, were officially retired in April of this year, said David G. Horneck, employed as Manager of Generation Modeling at Xcel Energy Services, the service company for Xcel Energy (NYSE: XEL) and its subsidiaries.
Horneck was among the Xcel officials supplying May 29 testimony at the Public Service Commission of Wisconsin to support a rate hike request from Xcel’s Northern States Power-Wisconsin (NSPW) subsidiary.
The lower cost of coal generation for the 2016 test year is driven by lower forecast coal prices and by a decrease in forecast generation from coal resources, Horneck noted in his heavily-redacted testimony. “The principal contributor to the decrease is the planned retirement of Black Dog Generating Units 3 and 4 which occurred in April 2015,” he wrote. “In addition, delivered fuel prices for the A. S. King and the Sherburne County (‘Sherco’) plants are forecast to be 2.2 percent lower than authorized for 2015, primarily driven by lower forecast diesel fuel surcharges for rail delivery due to low oil prices.”
Projected lower costs for chemicals for control of emissions in 2016 are primarily due to better-than-anticipated performance of mercury sorbent injection systems added to Sherco Units 1 and 2 at the end of 2014. When authorized costs for 2015 were developed, the amount projected for mercury sorbent use for the systems was based on engineering specifications for the equipment. When the new equipment became operational, significant efficiencies in mercury sorbent usage were realized on the new equipment.
The 2016 test year forecast indicates a redcated increase of NSP System-owned wind generation, which is primarily due to the addition of the new Border Winds (150 MW) and Pleasant Valley (200 MW) wind farms. The new projects are forecast to achieve commercial operation during 2015. The additional NSPW System-owned wind generation contributes to a decrease in purchased energy. As a zero-fuel cost resource, the NSP System-owned wind additions also contribute to the reduction in total system fuel and purchased power cost forecast for 2016.
An increase in forecast natural gas generation is largely driven by a shift in the forward natural gas and electric market price relationship that indicates the company’s most efficient and lowest cost natural gas combined-cycle plants should dispatch into the integrated market, thereby displacing purchases by the NSP System from the Midcontinent ISO market. In addition, natural gas generation has increased to offset reductions in purchases of energy from long-term power purchase agreements (PPAs).
“Despite the significant increase in NSP System-owned natural gas generation (~40 percent), costs have not increased substantially (~5.6 percent) because forecast natural gas prices for 2016 are much lower than those authorized for 2015,” Horneck noted. “Forward natural gas prices for 2016 at the Ventura hub have decreased 24.5 percent to $3.08/MMBtu for 2016 as compared to $4.08/MMBtu in 2015.”
Purchases from long-term PPAs are forecast to decrease, principally driven by a forecast reduction in purchases from the Manitoba Hydro-Electric Board (MHEB) and Minnkota Power Cooperative (MPC). Beginning May 1, 2015, new MHEB contracts took effect, replacing existing contracts. Purchase volumes of energy are reduced under the new agreements and contribute to the decrease in energy purchases from long-term PPAs. Offsetting the decrease in the volume of energy purchased is higher prices for energy purchased under the new agreements as compared to pricing terms for the expiring contracts. In addition, the contract with MPC to purchase energy from the Coyote facility terminates in 2015 and is not replaced by another long-term PPA.
The company has entered into PPAs to purchase energy from four solar projects: Aurora, Juwi, North Star, and Marshall. These utility-scale projects are expected to begin delivering energy to the NSP system during 2016 and are the primary driver for a $4.5 million dollar increase in costs for purchases of solar energy for the 2016 test year.
These were the last operating coal units at Black Dog
The Black Dog plant initially consisted of four coal-fired units built in the 1950s. Unit 1 was retired and demolished in the 2001-2002 period. The Unit 2 steam turbine was repowered and operates in conjunction with Unit 5, which is a natural gas combined-cycle unit placed in-service in 2002 and designed to provide intermediate generation during higher load periods.
Units 3 and 4 have been operating on western coal. They had a net dependable capacity of 79 MW and 153 MW, respectively in the summer of 2014.
The decision to retire Black Dog Units 3 and 4 was driven largely by the U.S. Environmental Protection Agency’s Mercury and Air Toxics Standards (MATS), which took effect on April 16 of this year.