Until some new regulatory burden comes along that makes it impossible to do so, Northern States Power thinks that continued operation of the coal-fired Units 1 and 2 at the Sherburne County (Sherco) plant is the best option.
The Sherco generating facility in Becker, Minn., is the company’s largest power plant in the Midwest, with its three units capable of providing a total of 2,400 MW. Units 1 and 2 have a production capability of 750 MW each and provide about 20% of the electricity used by Northern States Power’s Minnesota customers each year. Unit 3 is bigger and newer, so it didn’t fall into this analysis.
“Sherco’s size, age, role in our generation fleet, and existing pollution control investments differentiate it from other coal-fired power plants in Minnesota that have been retired or are scheduled to be retired in the next few years,” said Northern States Power, a unit of Xcel Energy (NYSE: XEL), in a life-cycle analysis for the plant that it filed on July 1 at the Minnesota Public Utilities Commission.
In its 2010 Resource Plan filing, the company noted that Sherco 1 and 2 are over 30 years old and that the utility had begun the process of investigating how best to manage the units for the future. In its November 2012 Resource Plan order, the commission directed the company to prepare a study that examines the cost of continuing to operate Sherco 1 and 2 and evaluates retrofit and retirement scenarios.
The company said in the July 1 filing that it has completed extensive modeling, thoroughly reviewed the status of environmental regulation, and engaged stakeholders of various backgrounds and perspectives. The company used the Strategist resource planning model to evaluate the cost of retrofitting the units with additional pollution control equipment or retiring them. The retrofit scenarios evaluate the installation of Selective Catalytic Reduction (SCR) equipment for NOx control, while the retirement scenarios evaluate replacing Sherco 1 and 2 with new natural gas generation, renewable energy, and conservation or a combination of those options.
The modeling results show that when the anticipated direct costs to operate Sherco 1 and 2 (including SCRs) are compared to the alternatives, continued operation of Sherco 1 and 2 is clearly the most cost-effective option, the utility wrote. “Only a significantly lower forecast of natural gas prices or a much higher forecast of coal prices calls that conclusion into question,” it added.
When the commission’s carbon proxy cost values are applied, however, there is very little cost difference over the long term between continued operation and some of the replacement scenarios. Thus, the timing and cost of carbon regulation is a key factor in determining the relative costs of retrofit and retirement scenarios. Under the base assumptions, including a CO2 cost of $21.50/ton, the cost difference between installing SCRs and retiring the units is negligible. This implies that there is no significant cost advantage of either the retirement or the retrofit strategies with carbon priced at $21.50/ton.
The need for SCR is not a certainty at this point
There is considerable uncertainty around the need to further reduce NOx emissions, which would force the SCR installations. Units 1 and 2 are well-positioned to comply with current environmental regulations and do not need SCRs at this time. However, SCRs might be required if Minnesota has areas that do not meet the ozone NAAQS as it may be revised in 2014 or falls into nonattainment for particulate matter.
Also, the company could be required to install SCRs under the Regional Haze Rule or “reasonably attributable visibility impairment” (RAVI) visibility regulations, which is currently subject to litigation between the U.S. Environmental Protection Agency and environmental advocates. “While the timing is uncertain, we anticipate that SCRs may be required late this decade or sometime the following decade,” said Northern States Power.
Each SCR is estimated to cost about $170m in 2012 dollars. The cost to replace both Sherco units with combined-cycle natural gas plants, for example, is estimated at $1.7bn.
“The Company believes the most prudent course of action at this time is to continue to operate Sherco 1 and 2 as we await greater clarity and certainty around the development of environmental regulation and the resulting timing and costs,” the utility said. “This strategy aligns the timing of a decision on the future of Sherco 1 and 2 with the availability of more complete information. To ensure timely action when additional information becomes available, we recommend the Commission establish firm triggers for reevaluation and future decision-making. Specifically, we recommend the Commission require reanalysis when: 1) air quality regulations establish a need for SCRs, or 2) a carbon regulation framework takes shape. Should an SCR requirement emerge prior to development of carbon regulation, the Company will reevaluate the cost-effectiveness of installing SCRs and recovering the cost over a shorter period to preserve the option to retire the units earlier than 2040 in the event of eventual carbon regulation.”
Incidentally, Northern States Power told the Minnesota commission in a June 21 update that the coal-fired Sherco Unit 3, offline since November 2011, should be back in service in early September. The 884-MW Unit 3 went off-line in November 2011 while being restarted after a repair shutdown. During the testing procedure after unit restart, specifically the overspeed test, the turbine and generator instrumentation showed vibration levels significantly above normal, and the unit was shut down. The vibration damaged many of the seals in the turbines and generator, and also caused a fire.
Sherco burns low-sulfur Western coal from mines in Montana and Wyoming. The plant normally burns more than 9 million tons of coal a year. Westmoreland Coal is a major supplier out of its Absaloka strip mine in Montana.