Xcel’s Minnesota unit alters 2010 resource plan

The 2011-2025 integrated resource plan (IRP) of Northern States Power Co. (NSP)-Minnesota has changed since it was first filed in August 2010, but one thing has remained the same throughout – no planned new coal capacity.

The staff of the Minnesota Public Utilities Commission in an Oct. 18 filing laid out the issues covered under that plan and under revised offerings that the utility has filed with the commission since then. The Oct. 18 filing is a 62-page briefing paper that lays out the arguments of the utility and various intervenors in the case ahead of an Oct. 25 commission meeting on the matter.

NSP-Minnesota is one of Xcel Energy’s (NYSE: XEL) four regulated operating companies. It serves about 1,400,000 electricity customers in Minnesota, primarily in the Twin Cities. NSP-Minnesota purchases power generated by Manitoba Hydro, wind, and other renewable resources in Minnesota and the Midwest. NSP-Minnesota’s system has about 7,100 MW of Midwest Independent System Operator (MISO)-accredited generation capacity. About 35% of the capacity is coal, 33% is natural gas and oil resources, and 18% nuclear.

Xcel’s proposed expansion plan includes:

  • An extended agreement with Manitoba Hydro to receive 725-850 MW of hydro through 2025;
  • 187 MW of increased capacity at the Monticello and Prairie Island nuclear facilities;
  • Five 195 MW combustion turbines, one each in 2018, 2019, 2020, 2023, and 2024 (the combustion turbines in 2018 and 2019 are part of a replacement plan for not pursuing the Black Dog Repowering Project, involving a coal plant);
  • One 729 MW natural gas combined cycle unit in 2025; and
  • No coal or wind units beyond 2012.

Xcel’s updated five-year action plan includes:

  • Withdrawing the Certificate of Need request for the Black Dog Repowering Project, which was a coal-to-gas switch;
  • Retiring existing Black Dog Units 3 and 4 by 2016, since the updated forecast indicates these coal units are no longer needed;
  • Completing the capacity uprate project for Monticello;
  • Proceeding with the Prairie Island uprate; and
  • Reassessing the company’s wind acquisitions, largely due to the expectation that the federal production tax credits will expire at the end of 2012.

Primarily due to downwardly shifted economic projections, Xcel revised its forecast and now does not expect to need resources until 2018. Instead, Xcel expects to add “one or two more peaking units” rather than pursue the Black Dog Repowering Project, the staff report said. Xcel provided in a 2011 update results of a scenario analysis comparing combustion turbines to the Black Dog project. In general, the savings from the Black Dog project exist in years 2030 and beyond, but Xcel believes combustion turbines are the most cost-effective strategy in the next 20 years.

Savings exist by pursuing the Black Dog project in almost all sensitivities, staff wrote. “However, these savings are largely accrued in 2031-2050,” it added. “Xcel reasons that, since savings are not expected to be realized during the planning period, and since longer term projections are generally less reliable and more uncertain than short-term projections, the Company proposes to withdraw its certificate of need for the project in order to conduct further analysis. The scenario analysis Xcel conducted indicates the Black Dog Repowering Project may still ‘prove to be the best alternative for meeting customers’ medium-to long-term needs.’ Xcel proposes to continue to ‘thoroughly address the 2016 to 2018 planning horizon’ in the Company’s next resource plan.”

Prairie Island nuclear uprate gets downgraded

Xcel’s initial IRP filing in August 2010 included a 164-MW uprate at the Prairie Island nuclear facility, with two 82-MW capacity increases scheduled for 2014 and 2015. The initial filing indicated that capacity increases could provide $500m of benefits.

The 2011 update concluded that a change in circumstances proceeding would be necessary. In the company’s initial filing, Xcel proposed to uprate Prairie Island by 164 MW in 2014-2015. In October 2010, Xcel increased the capability at Prairie Island by 18 MW, due to “enhanced precision in monitoring,” leaving 146 MW of capability yet to be increased. In the 2011 update, Xcel scaled back the potential capacity increase by 29 MW. Thus, Xcel found that only a 117-MW increase at Prairie Island could feasibly be realized, instead of the 164 MW proposed in the initial filing.

Xcel’s five-year plan, as of the 2011 update, includes the 117-MW uprate as two 58-MW increases in 2014 and 2015. On the cost side, Xcel calculates that the total cost of the uprate will be about $250m, $187m of which can be avoided if Xcel were to terminate the program. While Xcel still maintains the uprate will have an economic benefit, the expected value has greatly diminished, staff noted.

Xcel’s initial filing in August 2010 also included a 71-MW uprate at the Monticello nuclear facility. Xcel expected the Monticello uprate to be completed by 2011, but the 2011 update delayed the target date to 2013.

The 800-MW, coal-fired Sherco Generating Station Unit 3 is jointly owned by Xcel (59%) and Southern Minnesota Municipal Power (41%). In November 2011, Sherco Unit 3 experienced a “significant failure” while returning to service following a scheduled overhaul. Xcel noted that the failure caused major damage to the unit, and said an investigation into the cause was being conducted. Xcel plans to open a new docket for future reports so that any updates related to the Sherco 3 outage can be reviewed in a separate proceeding, staff reported.

Since the 2010 IRP filing, Xcel added about 330 MW of wind, and the company expects to add at least 200 MW in 2012. These additions would result in 1,800 MW of wind in total on Xcel’s system. Xcel also noted a possibility of another 300 MW before the scheduled expiration of the production tax credit.

MATS drives Black Dog 3 and 4 shutdown, look at Sherco 1 and 2

In terms of air emissions, Xcel foresees the U.S. Environmental Protection Agency’s Mercury and Air Toxics Standards (MATS) rule to have the most significant impact on its operations. Xcel identified the coal-fired Black Dog Units 3 and 4 and Sherco 1 and 2 as units which will be impacted by MATS. MATS would also apply to the King plant and Sherco 3, but Xcel does not expect that additional controls are required for compliance at either unit.

According to Xcel’s evaluation of the EPA regulations’ impact on Black Dog 3 and 4: “We evaluated the costs of retrofitting these units to comply with the [MATS] and other pending EPA regulations. Based on our analysis, including an assessment of the compliance costs and the units’ age, we concluded it would not be in our customers’ best interests to continue operating these units using coal. Instead, we developed plans to switch these two units to natural gas-only operations prior to the compliance deadline. We expect to ultimately retire these units and replace them with new natural gas generation but, as described in this update, decisions about the size and timing of that replacement generation are still pending.”

Xcel expects to retrofit Sherco 1 and 2 with pollution controls instead of retiring them. Xcel stated that the most cost-effective strategy for Sherco 1 and 2 would be to control mercury via Activated Carbon Injection technology, and to control particulate matter with a new wet electrostatic precipitator.

Other parties involved in the IRP case have different takes on the situation. For example, the state Department of Commerce recommends that the commission require Xcel to:

  • Continue to pursue the uprate at Prairie Island;
  • Continue to pursue the uprate at Monticello;
  • Pursue 100 MW to 200 MW of wind in 2015-2016 if the price is $50 per MWh or less;
  • Procure 400 MW to 600 MW of natural gas capacity in 2017-2018, at least half of the natural gas capacity should be combined cycle;
  • Procure a 1.3 percent level of demand side management;
  • Use short term purchases to fill any capacity needs in 2015-2016; and
  • Require Xcel to continue working with the department to fully address the forecasting issues prior to Xcel submitting any certificate of need or rate case filing.

In addition, the department recommends approval of Xcel’s base energy forecast and the department’s peak demand forecast for planning purposes only.

Xcel’s reply comments to the various parties outline the company’s preferred commission order, update their resource needs assessment, discuss the IRP’s rate impacts and how rate impacts are projected in the Strategist computer model, and respond to comments of the intervening parties.

Xcel proposes that the following recommendations be included in the commission’s order:

  1. Approve Xcel’s base energy and peak demand forecast as adequate for resource planning purposes.
  2. Direct Xcel to procure 400-600 MW of natural gas capacity in the 2017 to 2019 timeframe, but make no finding regarding the type of natural gas.
  3. Reassess acquiring new wind generation for the 2015 to 2016 timeframe, except if unique, high-valued opportunities arise before then.
  4. Submit a baseload diversification study by July 1, 2013, that examines the feasibility and cost-effectiveness of continuing to operate Sherco Units 1 and 2, in comparison to non-coal-based alternatives;
  5. Direct Xcel to work with interested parties to identify useful measures of rate impacts associated with the Company’s resource plans and incorporate them into the next resource plan filing; and
  6. Find that Xcel’s proposed DSM savings of 1.3% is reasonable for planning purposes.

Xcel also recommends the commission take the following action on the Black Dog Repowering Project:

  • Revise the scope of the Black Dog Repowering Proceeding to identify the best plan to meet the resource need of 400 to 600 MW over the years of 2017 to 2019;
  • Direct the ALJ for the Black Dog Repowering Proceeding to protect the disclosure of confidential information related to bids from competing parties; and
  • Retire Black Dog Units 3 and 4 in 2015.

Xcel requests that the commission reject the following recommendations made by intervening parties:

  • Fully address forecasting issues prior to the submission of any certificate of need or rate case filing (department recommendation);
  • Direct Xcel to conduct a solar resource study prior to submission of Xcel’s next resource plan (environmental groups recommendation); and
  • Immediately issue an RFP for a 20-year fixed price gas contract (Minnesota Chamber of Commerce recommendation).

To comply with the MATS rule by February 2015 at Black Dog Units 3 and 4, Xcel has identified that a fabric filter baghouse, spray dryer absorber, and sorbent injection would be required to reduce particulate matter. Both units currently have electrostatic precipitators for particulate control, which the company sees as insufficient for MATS compliance. Additionally, the design and limited space at the plant site would make the addition of fabric filters and flue gas scrubbers to control SO2 “very complicated.” Xcel also has determined that there are other upcoming environmental regulations that would require additional control equipment upgrades and construction in addition to MATS.

The December 2011 Xcel update assumed that Sherco 1 and 2 would continue to operate after the end of their book lives in 2023. Xcel is currently verifying this assumption via a Life Cycle Management Study. Xcel stated in its reply comments that the preliminary findings of the study suggest Sherco 1 and 2 can be “operated well beyond” 2023. Sherco 1 and 2 both have wet scrubbers for SO2 and ash control, a wet electrostatic precipitator for particulate emissions, and low NOX burners, overfire air, and combustion controls to reduce NOX. To meet near-term compliance requirements, Xcel expects to implement the following emissions control equipment: Activated Carbon Injection to control mercury emissions; Wet Electrostatic Precipitator to further reduce fine particulate emissions; and Sparger Installation Project to further reduce SO2 emissions.

Xcel notes that an important unknown, at this time, is whether further NOX controls will be needed. If so, Xcel said the Sherco units will also require Selective Catalytic Reduction (SCR) for NOX control. The timing of SCR installation is a key component of Xcel’s ongoing Life Cycle Management Study, as is the timing for retirement in the event these emissions controls are not cost-effective.

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.