Fitch Ratings said April 18 that Colorado Springs Utilities (CSU) has a heavy spending burden to get its coal plants in compliance with air regulations, but it does plan to keep them in operation over the long term instead of shutting them.
“CSU has considerable capital needs through 2016,” Fitch noted. “The utility expects to spend $1.5 billion primarily for long-term water supply development and regulatory spending required to upgrade the utility’s coal-fired generation. Fitch views the capital pressure to be manageable at the current rating level given CSU’s planned funding of 52% of capital needs from ongoing revenues and future rate increases.”
CSU is a combined utility system serving customers in the city of Colorado Springs and surrounding suburban communities. The combined utilities system serves a population of more than 416,000 in the south-central Front Range area of Colorado. The 2011 fuel (energy) mix for CSU consisted of: coal (61.6%), natural gas (24.4%), hydroelectric (10.4%), and wholesale purchases (3.6%).
“The coal-fired assets require capital investments to comply with anticipated more stringent environmental standards but CSU anticipates making these investments in its near-term capital plan and retaining its coal-fired plants,” Fitch added. “CSU is well positioned to meet the state’s relatively modest renewable portfolio standard through the purchase of renewable energy credits.”
CSU plans to spend approximately $473m on its electric system, primarily to fund new scrubbers at its coal-fired facilities, Fitch said.
Colorado Springs relies on home-grown scrubber for compliance
The CSU website said that the utility’s Martin Drake and Ray D. Nixon coal plants have baghouses that remove more than 99% of particulates. Some of the ash that is collected by the baghouses is sold to concrete companies for use as an additive that strengthens cement. The plants also use low-sulfur coal from northern Colorado and Wyoming mines. They also utilize low-NOx burners.
“We have partnered with local entrepreneur Dr. David Neumann (Neumann Systems Group) to test his emissions control technology at the Drake Power Plant,” the website added. “Small-scale testing to remove sulfur dioxide, or SOx, has proved successful, and a larger-scale test for removal of SOx began in August, 2009. It’s possible that this partnership will help us meet air quality standards for a third of the cost of traditional technologies in less than one-tenth of the physical space.”
CSU announced in October 2011 that it and Neumann Systems Group (NSG) have executed an agreement for the design and installation of new emissions control technology for the Drake plant. The technology, NeuStream, will remove SO2 from the emissions of the coal-fired plant, letting it comply with new regional haze air pollution requirements in Colorado. Work was slated to begin last fall and the project is scheduled to be completed in 2014.
NSG is a Colorado Springs-based advanced technology company focused on commercializing gas-liquid contractor systems for emissions control and other applications. NSG has been awarded a $7.2m grant from the U.S. Department of Energy for research for CO2 emissions control, which will also take place at Drake.
An April 11 emissions project update attached to the agenda for the CSU Utilities Board meeting of April 18 shows NSG scrubber installations spanning the January 2011-April 2014 period at Drake Units 6-7, and April 2014-March 2017 at Nixon.
CSU’s 2012-2016 strategic plan has a couple of notations about plans for Drake in particular.
- “Drake 6 and 7 Sulfur Dioxide (SO2) and Nitrous Oxide (NOx) Reduction: This multi-year project will result in the purchase and installation of a ground breaking SO2 scrubber technology to meet projected future emissions permit requirements. This new technology can be constructed in a much smaller area at a significantly reduced cost and be operated at lower annual operating costs than other available technology.”
- “Drake Plant Fuel Flexibility: The Drake plant fuel flexibility project will involve modifications to the boilers and fuel handling systems on Drake units 6 and 7 that will allow both units to burn 100 percent low sulfur Powder River Basin (PRB) coal in place of the higher sulfur coal traditionally used without reducing the plant’s generation capabilities. This results in both less emissions and lower costs as the PRB is a lower cost fuel.”
The U.S. Energy Information Administration database shows Drake as only taking coal in January from Arch Coal‘s (NYSE: ACI) Black Thunder mine in the Wyoming PRB. The only coal deliveries to Nixon in January came from Peabody Energy‘s (NYSE: BTU) North Antelope Rochelle mine in the Wyoming PRB.