Xcel shelves Black Dog repowering, plus wind and nuclear additions

The Northern States Power unit of Xcel Energy (NYSE: XEL) has shelved, due to a slump in projected power demand, a long-planned conversion of two coal units at its Black Dog plant to burning natural gas, said NSP in a resource plan update filed Dec. 1 at the Minnesota Public Utilities Commission.

The utility’s revised forecasts and refreshed analysis conclude that NSP’s next generating resource is no longer needed in 2016, which led to the Black Dog repowering being shelved. Its next capacity need will be in 2018 under the revised forecasts. To date, NSP has performed significant preliminary development and permitting work on Black Dog and believes that work will have continuing value.

“In the end, the Black Dog Repowering Project may prove to be the best alternative for meeting our customers’ medium-to long-term needs,” said NSP. “It is also possible that other generation alternatives will prove to be better options. Given the continued volatility in our customers’ future needs, we propose to continue monitoring the situation and thoroughly address the 2016 to 2018 planning horizon in our next Resource Plan cycle.”

Xcel Energy said in its Oct. 28 Form 10-Q filing that in March 2011, NSP filed a request with Minnesota regulators to approve retirement of the last two coal-burning units, units 3-4, at the Black Dog plant and to replace them with combined-cycle natural gas units. Units 1-2 were converted to natural gas combined-cycle operation in 2002. The latest repowering project would replace the remaining 253 MW of coal-fired capacity at the site with about 700 MW of natural gas-fired generation. The proposed natural gas powered facility was expected to cost about $600 million and was proposed to come on line in 2016.

At the same time, NSP said in the Dec. 1 resource plan update it has made considerable progress toward completing the engineering to support the upgrade of the capacity of the Prairie Island nuclear plant. Based on current information, though, it has scaled back its estimate of achievable capacity increases at the plant. The current base cost analysis suggests the capacity upgrade program remains cost effective. However, given NSP’s experience with the Monticello extended power uprate, other utilities’ experiences with similar nuclear projects, and the ongoing analysis of regulatory requirements in the aftermath of the Fukushima Daiichi nuclear incident in Japan, NSP believes this project would benefit from further review and risk assessment.

To date NSP has gained an additional 18 MW of generation at Prairie Island through work already authorized by the Nuclear Regulatory Commission. Additionally, significant project engineering work has been advanced and its recently received bids from vendors for various parts of the upgrade program at Prairie Island. The current base cost analysis indicates only 117 MW of the remaining 146 MW of generation that was originally expected to be added as a result of the upgrade should be pursued if it continues to be cost effective.

The third major revision in the updated resource plan relates to wind power. It appears unlikely that the federal production tax credits (PTCs) for wind generation will be renewed at the end of 2012, so NSP said it plans to reassess its wind power acquisition program after 2012 since it has adequate installed generation and renewable energy credits to maintain compliance with Minnesota standards for several years.

NSP had in September 2010 issued a request for proposal for up to 250 MW of wind energy to be in service by the end of 2012. It received 143 proposals on 106 sites comprising 9,189 MW of distinct resources. As a result of that process, NSP entered into a power purchase agreement with Geronimo Wind Energy for the 200 MW Prairie Rose Wind Farm, which was approved by the commission on Nov. 10, 2011. The Prairie Rose transaction also includes an option for the company to take an additional 100 MW of generation, subject to commission review and approval.

“We have explored the opportunity to procure low-cost wind generation between now and the expiration of the PTC, but the short timeframe also created significant construction, permitting and financing challenges,” said NSP. “The Company will continue to explore opportunities to procure as much as 300 MW of additional wind generation prior to the PTC expiring. While we are eager to obtain low priced, cost-effective wind generation for our customers, we seek to avoid the risks of incomplete or failed projects.”

Sherco unit 1 downtime not known yet

As part of the Dec. 1 filing, NSP updated the commission about a recent occurrence at the coal-fired Sherco plant. As part of an approved action plan, in recent years NSP has added generating capacity and improved production efficiency at the 800-MW Sherco Unit 3, which is jointly owned by NSP (59%) and the Southern Minnesota Municipal Power Agency (41%).

In September, the plant owners began a scheduled maintenance overhaul that included some of the work necessary for some of these upgrades. On Nov. 19, Sherco Unit 3 experienced a significant failure during turbine testing while returning to service following the scheduled maintenance overhaul. The failure resulted in fires in both the turbine and generator, and caused major damage to the unit, including the generator exciter and some turbine components.

Units 1-2 at Sherco were unaffected and are operating normally. An investigation into the cause of the equipment failure is underway. “At this time we do not believe this incident will cause us to revise our Five Year Action Plan in the Resource Plan,” NSP said. “However, we will reassess possible impacts to the Resource Plan after we conclude our investigation. While initial assessments indicate significant damage, repair scope and a projected return to service date for Sherco Unit 3 will not be known until the unit is disassembled and the extent of damage is fully known.”

NSP also said that it continues to evaluate potential options for Sherco units 1-2 as they approach the end of their initial depreciation schedule in 2023. The U.S. Environmental Protection Agency’s pending review of the Minnesota Pollution Control Agency’s determination of the appropriate Regional Haze emission controls for these units might substantially impact this analysis.

By voluntarily and proactively addressing emissions at some of its oldest facilities as part of the Metropolitan Emissions Reduction Project (MERP), the utility said its system is well positioned to address pending and future EPA regulations, provided these early actions are given their full credit. NSP has challenged EPA’s failure to recognize the benefits of MERP in its implementation of the Cross-State Air Pollution Rule (CSAPR), which goes into effect in January.

According to NSP’s analysis, five units at three plants would be impacted by EPA’s Utility Maximum Achievable Control Technology rule. These facilities are: Black Dog units 3-4, which are the subject of the shelved coal-to-gas conversion; Sherco units 1-2; and Bay Front unit 5. The Utility MACT rule, as drafted, would also apply to two other units on the NSP system, which are Unit 1 at the Allen S. King plant and Unit 3 at Sherco, but it does not appear that additional controls are required for compliance at either unit.

In addition, a related EPA rule – known as the Industrial Boiler MACT – may impact two other units at the Bay Front plant. The IB MACT has been stayed, pending EPA’s upcoming reconsideration of multiple aspects of the final rule.

Sherco units 1-2, totaling a summer-rated capacity of 1,379 MW of coal-fired generation, are located in Becker, Minn., and were constructed in mid-1970. NSP believes that Utility MACT compliance will require two projects at these units. To control mercury emissions, it expects to add activated carbon injection at these two units, with an estimated project cost of $12 million over the 2012-2014 period. NSP also expects that it will need to replace and upgrade components of the wet electrostatic precipitators on these units to further reduce fine particulate emissions. This project would cost $10.5 million over the 2012-2016 period.

Bay Front units 1, 2 and 5 total 76 MW of generation capacity, are located in Ashland, Wisc., and were constructed between 1948 and 1956. These units used a combination of coal, waste wood, railroad ties, tire-derived fuel, natural gas, and petroleum coke as fuel. The proposed Utility MACT rule applies only to Unit 5 and, as with Black Dog units 3-4, NSP concluded that it would be cost prohibitive to perform the upgrades necessary to allow for continued operation on coal. It plans to comply with the proposed Utility MACT rule by switching Unit 5 from coal to natural gas-only firing on or about Jan. 1, 2015.

NSP also anticipates needing to install fabric filter baghouses on Bay Front units 1-2, at a cost of about $13 million in 2013-2014, to comply with the IB MACT and the Wisconsin State Mercury rule. Depending on baghouse effectiveness in removing mercury, it may also be necessary to add an activated carbon injection system to units 1-2, at a cost of about $1 million, in 2014 or 2015.

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.