Under the Colorado Clean Air Clean Jobs Act (CACJA), Public Service Co. of Colorado has received approvals for the conversion of Cherokee Unit 2 to a synchronous condenser, for the decommissioning of Cherokee Units 1-2, and for emissions controls at the Pawnee coal plant, said PSCo parent Xcel Energy in its Feb. 24 annual Form 10-K report.
In addition, PSCo has filed with the Colorado Public Utilities Commission (CPUC) for approval of the new natural gas combined-cycle unit at the Cherokee plant and needed emissions controls on the Hayden coal plant. The act required PSCo to file a comprehensive plan to reduce annual emissions of NOx by at least 70% to 80% from 2008 levels by 2017 from the coal-fired generation identified in the plan. The plan allows PSCo to propose emission controls, plant refueling, or plant retirement for at least 900 MW of coal-fired units by 2017.The total investment associated with the plan is about $1bn through 2017.
In December 2010, the CPUC approved the following:
- Shut down of Cherokee Units 2 and 1 in 2011 and 2012, respectively, and Cherokee Unit 3 (365 MW in total) by the end of 2015, after a new natural gas combined-cycle unit is built at Cherokee (569 MW).
- Fuel-switch Cherokee Unit 4 (352 MW) to natural gas by 2017.
- Shut down Arapahoe Unit 3 (45 MW) and fuel-switch Unit 4 (111 MW) in 2014 to natural gas.
- Shut down of Valmont Unit 5 (186 MW) in 2017.
- Installation of selective catalytic reduction (SCR) for controlling NOx and a scrubber for controlling SO2 on Pawnee in 2014.
- Installation of SCRs on Hayden Unit 1 in 2015 and Hayden Unit 2 in 2016.
- Conversion of Cherokee Unit 2 and Arapahoe Unit 3 to synchronous condensers to support the transmission system.
Myriad air issues are scattered on Xcel’s path to a cleaner future
Other issues being faced by PSCo and other Xcel subsidiaries include the U.S. Environmental Protection Agency’s new Cross-State Air Pollution Rule (CSAPR), Mercury and Air Toxic Standards (MATS) and various state-by-state Best Available Retrofit Technology (BART) findings under the agency’s regional haze rule.
If CSAPR is upheld by a federal appeals court and emerges from court review unmodified, Xcel said it believes that this rule could ultimately require the installation of additional emission controls on some of Southwestern Public Service’s (SPS) coal-fired units. If compliance is required in a short time frame, SPS may be required to redispatch its system to reduce coal plant operating hours and therefore emissions. SPS has estimated capital expenditures of about $470m over the next four years for CSAPR compliance.
In July 2011, the EPA issued CSAPR to reduce emissions of SO2 and NOx from utilities located in the eastern half of the U.S. For Xcel, the rule applies to Minnesota, Wisconsin and Texas. The CSAPR sets more stringent requirements than the proposed Clean Air Transport Rule and, in contrast to that proposal, specifically requires plants in Texas to reduce their SO2 and annual NOx emissions. Xcel said it intends to comply by reducing emissions and/or purchasing allowances.
On Dec. 30, 2011, the U.S. Court of Appeals for the D.C. Circuit issued a stay of the CSAPR, pending completion of judicial review. The court is expected to hear the case in April and may rule in the second half of 2012.
If the CSAPR is upheld and not modified, NSP-Minnesota would likely utilize a combination of emissions reductions through upgrades to its existing SO2 control technology at the coal-fired Sherco plant, which is estimated to cost a total of $10m through 2014, and system operating changes to the Black Dog and Sherco plants. NSP-Minnesota would also consider allowance purchases. NSP-Minnesota has filed a petition for reconsideration with the EPA and a petition for review of the CSAPR with the U.S. Court of Appeals for the D.C. Circuit seeking the allocation of additional emission allowances. NSP-Minnesota contends that the EPA’s method of allocating allowances arbitrarily resulted in fewer allowances for its Riverside and High Bridge plants than should have been awarded to reflect their operations during the baseline period, which included coal-fired operations prior to their conversion to natural gas.
If the CSAPR is upheld and unmodified, NSP-Wisconsin would likely make a combination of system operating changes and allowance purchases. NSP-Wisconsin estimates the cost of compliance would be $0.2m, and expects the cost of any required capital investment will be recoverable from customers.
In 2005, the EPA issued the Clean Air Interstate Rule (CAIR) to further regulate SO2 and NOx emissions. The CAIR, which CSAPR was designed to replace, applies to Texas and Wisconsin. The CAIR does not currently apply in Minnesota because the appeals court specifically found that the EPA had not adequately justified the application of the CAIR to Minnesota. In granting the stay of the CSAPR this past December, the court specifically said CAIR would remain in place during its pending review of the CSAPR.
Under the CAIR’s cap-and-trade structure, companies can comply through emission controls or purchase of emission allowances. To comply with the CAIR in 2012, NSP-Wisconsin will likely make a combination of system operating changes and allowance purchases, if available. In the SPS region, installation of low-NOx combustion control technology began on Tolk Unit 1 in January 2012. Installation will begin on Tolk Unit 2 at a later date. These installations will reduce or eliminate SPS’ need to purchase NOx allowances. SPS has enough SO2 allowances to comply with CAIR in 2012.
In December 2011, the EPA issued the final MATS rule to replace the proposed Maximum Achievable Control Technology (MACT) rule. The MATS rule sets emission limits for mercury and other hazardous air pollutants and will require coal-fired utility plants greater than 25 MW to demonstrate compliance within three to four years. Xcel said it believes these compliance costs would be recoverable through regulatory mechanisms.
Colorado’s mercury regulations require mercury emission controls capable of achieving 80% capture to be installed at the Pawnee plant by the end of 2011.The cost for the Pawnee mercury controls was $1.1m for capital costs with an annual estimate of $0.5m for sorbent expense. PSCo has evaluated the Colorado mercury requirements for its other units in Colorado and believes that no further controls will be required.
Under 2006 mercury legislation in Minnesota, NSP-Minnesota installed sorbent control systems at the Sherco Unit 3 and A.S. King plants. NSP-Minnesota has also obtained Minnesota approval to install mercury controls on Sherco Units 1-2 by the end of 2014.
The status of regional haze BART varies by state
In 2005, the EPA finalized amendments to its regional haze rules regarding provisions that require the installation and operation of emission controls, known as BART, for industrial facilities emitting air pollutants that reduce visibility in certain national parks and wilderness areas throughout the U.S. Xcel plants in several states will be subject to BART. Individual states are required to identify the facilities located in their states that will have to reduce SO2, NOx and particulate emissions under BART and then set emissions limits for those facilities.
In 2006, the Colorado Air Quality Control Commission promulgated BART regulations. In January 2011, the commission approved a revised regional haze BART SIP incorporating the Colorado CACJA emission reduction plan, which will satisfy regional haze needs. The Colorado SIP is currently pending before the EPA. PSCo expects the cost of any required capital investment will be recoverable from customers through the CACJA plan recovery mechanisms or other regulatory mechanisms. Emissions controls are expected to be installed between 2012 and 2017.
In December 2009, a Minnesota board approved a regional haze SIP, which has been submitted to the EPA for approval. The suggested BART controls for Sherco Units 1-2 consist of combustion controls for NOx and scrubber upgrades for SO2. The combustion controls have been installed on Sherco Units 1-2, and the scrubber upgrades are scheduled to be installed by 2015. At this time, the estimated cost for meeting the BART and other CAA requirements is about $50m of which $20m has already been spent on projects to reduce NOx emissions at Sherco Units 1-2.
In June 2011, the EPA provided comments to the Minnesota regulators on the SIP, stating the EPA’s preliminary review indicates that SCR controls should be added to Sherco Units 1-2. The state has since proposed that the CSAPR should be considered BART for electric generating units (EGUs). The EPA has proposed that states be allowed to find that CSAPR compliance meets BART requirements for electric units, and specifically that Minnesota’s proposal to find that CSAPR meets BART requirements should be approved. It is not yet known what the final requirements will be, Xcel noted. NSP-Minnesota does not expect that a finding that the CSAPR meets BART requirements would result in changes to the control equipment plans already in place, and has requested that the Minnesota regulators retain the 2009 BART determination.
Harrington Units 1-2 of SPS are potentially subject to BART. Texas has developed a regional haze SIP that finds the CAIR equal to BART for EGUs, and as a result, no additional controls for these units beyond the CAIR compliance are required, Xcel said.
In March 2011, NSP-Minnesota filed a request with Minnesota regulators to approve a project to retire its last two coal units (Units 3-4) at the Black Dog plant in Burnsville, Minn., and replace them with combined-cycle natural gas units. Units 1-2 were converted to gas combined-cycle in 2002. In December 2011, NSP-Minnesota requested to withdraw the application and that request is pending an administrative law judge decision. NSP-Minnesota will re-evaluate the Black Dog repowering project as part of the next resource plan expected in 2013.
Sherco Unit 3 downtime to cut into NSP coal needs
The NSP system normally maintains about 40 days of coal inventory. Coal inventories at the ends of 2011 and 2010 were about 48 and 39 days usage, respectively. NSP-Minnesota’s plants use low-sulfur western coal purchased primarily under contracts with suppliers in Wyoming and Montana. During 2011 and 2010, coal requirements for the NSP system’s major coal-fired plants were about 9.5 million tons. The estimated coal requirements for 2012 are only about 8 million tons, including adjustments to account for Sherco Unit 3, which was shut in November 2011 after experiencing a failure of its turbine, generator and exciter systems. It is uncertain when Sherco Unit 3 will restart.
PSCo normally maintains about 41 days of coal inventory. Coal inventories as of the ends of 2011 and 2010 were about 48 and 34 days, respectively. PSCo’s plants use low-sulfur coal primarily under contracts with suppliers in Colorado and Wyoming. During 2011 and 2010, PSCo’s coal needs for existing plants were about 10.5 and 10.7 million tons, respectively. The estimated coal requirements for 2012 represent a boost to 11.6 million tons.
SPS purchases all of the coal for its Harrington and Tolk plants from TUCO Inc. TUCO is responsible for negotiating and administering contracts with coal suppliers, transporters and handlers. The coal supply contract with TUCO expires in 2016 and 2017 for Harrington and Tolk, respectively. As of the ends of 2011 and 2010, coal inventories at SPS were about 43 and 41 days, respectively.