Colorado Springs Utilities plans emissions spending in 2016 on coal-fired capacity

Costs to add emissions-control installations on a coal-fired Ray D. Nixon unit are included in the proposed 2016 budget for Colorado Springs Utilities.

This proposed budget for the Colorado municipal utility is currently being circulated, with the upcoming schedule on it being:

  • November 28 – Rates presentation at Utilities Board meeting
  • November 24 – Public rate hearing at City Council meeting
  • December 8 – Rate case decision at City Council meeting
  • January 1, 2016 – If approved, new rates take effect

The proposed budget noted: “The proposed 2016 Budget is $972.5 million, a decrease of $110.2 million, or 10.2 percent, from City Council’s Approved 2015 Budget. This decrease is primarily the result of lower capital expenditures driven by the 2016 completion of the SDS water project and emissions controls at the Martin Drake Power Plant Units 6 and 7.”

The Colorado Springs coal units, with their summer capacities, are: Drake Unit 5 (46 MW); Drake Unit 6 (77 MW); Drake Unit 7 (131 MW); and Nixon Unit 1 (208 MW).

Included in the budget proposal are:

  • Nixon 1 Sulfur Dioxide Reduction, $45,249,996 proposed 2016 spend – Install SO2 emissions controls on Ray D. Nixon Unit 1 to comply with Colorado’s Regional Haze State Implementation Plan (SIP) that was approved by the Colorado State Legislature and the U.S. Environmental Protection Agency in 2012. The Colorado Department of Public Health and Environment issued a Final Determination in 2013 establishing that the emission controls must be installed and Colorado Springs Utilities must be able to demonstrate compliance with new SO2 emission levels by Dec. 31, 2017.
  • Drake 6 Sulfur Dioxide Reduction, $8,768,520 proposed 2016 spend – Install SO2 emissions controls on the coal-fired Drake Unit 6 to comply with Colorado’s Regional Haze State Implementation Plan.
  • Nixon 1 NOX Generation Reduction, $5,937,252 proposed 2016 spend – Install new ultra-low NOx burners and combustion air system to reduce NOx production from Nixon 1 boiler and meet emissions requirements for Colorado Regional Haze Rule / Reasonable Progress.
  • Drake Scrubber(s) Sorbent Processing System, $1,714,812 proposed spend in 2016 – Install SO2 emissions controls on Drake Units 6 and 7 to comply with Colorado’s Regional Haze State Implementation Plan (SIP). The Sorbent Processing System is shared by the Drake Units 6 and 7 scrubbers.
  • Drake 7 Sulfur Dioxide Reduction, $604,044 proposed spend in 2016 – Install SO2 emissions controls on Drake Unit 7 to comply with Colorado’s Regional Haze State Implementation Plan.
  • Drake 5 DSI Scrubber, $500,004 proposed 2016 spend – Engineer, purchase and install a dry sorbent injection (DSI) system for sulfur SO2 control and a powdered activated carbon (PAC) injection system for mercury control for Drake Unit 5. SO2 control is required for Drake 5 under the state Regional Haze Rule. Installation of DSI is anticipated to cause a collateral mercury emission increase which will be controlled by the PAC system. Activities in 2016 will be for engineering and preliminary sitework.
  • Drake 6 & 7 Sootblowers, $324,996 proposed spend in 2015 – In order to maintain operational reliability, unit heat rate targets and boiler efficiency of Drake Unit 6, it will be necessary to install boiler cleaning controls on the unit to address increased soot and slag deposits which are inherent to boilers firing Powder River Basin (PRB) coal as the primary fuel source. Sootblowing controls were identified by a 2013 study to determine best control strategies. This will be a onetime capital improvements project.

Another part of the proposed 2016 budget has to do with fuel costs. Fuel costs make up over one-half of all operating and maintenance expenses for the electric service. Coal and natural gas make up the majority of the fuel supply used for generating electricity at eleven different generating units. By capacity, electric generation fuel mix is approximately 50% natural gas, 40% coal, and 10% hydro and renewables. This diverse fuel mix allows flexibility to adjust the generation fuel mix to take advantage of market conditions, the budget proposal noted.

  • (Decrease of $5.4 million over 2015 coal costs) – In 2016, approximately 3% less MWh unit generation is planned compared to 2015. The remainder of this variance is due to decreases in 2016 projected coal prices.
  • (Natural gas costs for power generation down by $7.3 million in 2016 as compared to 2015) – Lower natural gas prices forecasted in 2016 compared to 2015.
  • ($3.5 million higher costs in 2016 for purchased power) – In 2016, approximately 26% more MWh will be purchased off the market than in 2015. The decision to purchase from the market versus self generate is determined based on load, unit availability, and market conditions.

The budget noted that a fire at the Martin Drake Power Plant in May 2014 immediately took the coal plant off-line for several weeks. The Front Range Power Plant provided more power due to the Martin Drake Plant fire in 2014. Purchased power was utilized in 2014 to provide generation due to the Martin Drake Plant fire.

About Barry Cassell 20414 Articles
Barry Cassell is Chief Analyst for GenerationHub covering coal and emission controls issues, projects and policy. He has covered the coal and power generation industry for more than 24 years, beginning in November 2011 at GenerationHub and prior to that as editor of SNL Energy’s Coal Report. He was formerly with Coal Outlook for 15 years as the publication’s editor and contributing writer, and prior to that he was editor of Coal & Synfuels Technology and associate editor of The Energy Report. He has a bachelor’s degree from Central Michigan University.