Interstate Power and Light (IPL) on Dec. 3 filed its 2012 Baseload Diversification Study with the Minnesota Public Utilities Commission, which describes various pending actions, including shutdown of older coal-fired capacity.
This 2012 Baseload Diversification Study was filed by this Alliant Energy (NYSE: LNT) subsidiary under the commission’s March 2 order, which stated that within nine months of the date of the order, IPL had to file this study. The commission also ordered that IPL:
- specify the costs of environmental controls on each of IPL’s Tier 1 units, the environmental controls to be used, the in-service dates, and the regulations with which they are intended to comply;
- justify its assumptions regarding heat rates and availability over time at its generating units, with a specific emphasis on the operational performance of its Tier 2 coal units; and
- run contingencies for coal of +30%, +20%, +10%, and -10% of their base assumptions, and contingencies for a broad range of natural gas prices.
IPL has in this baseload report updated its 2010 integrated resource plan (IRP) approved by the commission (2010 IRP), with the 2012 IRP included with the Baseload Diversification Study as Attachment A. The 2012 IRP incorporates a revised analysis of IPL’s future resource mix.
“The 2012 IRP identifies the retirement of some older peaking units and steam units by 2017, and the need for a nominal 600 MW combined cycle unit in 2017,” said the utility. “Concurrent with filing the 2012 Baseload Diversification Study, IPL is filing a Notice of Changed Circumstances for these changes to the approved 2010 IRP. IPL currently intends to file its next Integrated Resource Plan consistent with the 2010 IRP Order, by November 1, 2013, unless the Commission prefers some other action as a result of this Baseload Diversification Study.”
Duane Arnold power deal part of the latest plan
IPL’s comprehensive 2012 IRP is not only reasonable, but a cost and risk effective plan which provides the best value for customers, the utility said. IPL’s plan includes:
- A new power purchase agreement (PPA) with NextEra Energy Duane Arnold LLC for the output of the DAEC nuclear plant through 2025, as described in IPL’s Notice of Changed Circumstances filed with the commission on Aug. 28 in this docket;
- Adding environmental controls to IPL’s largest coal-fired power plants (Tier I) to allow these units to serve customers well into the future, as noted in IPL’s current Emissions Plan and Budget filed with the commission on July 13 in this docket;
- Adding “light” controls at IPL’s mid-sized coal-fired plants (Tier II) to allow these units to operate for an intermediate term;
- The addition of new energy supply from the Marshalltown Generating Station (MGS), a new gas-fired combined-cycle generating facility;
- Retirement of older, small steam units, using either coal or natural gas (Tier II and III);
- Retirement of some peaking units that are at the end of their useful lives; and
- Continuing analysis and implementation of cost effective energy efficiency, demand side management and renewable energy supplies.
There are parts of the IRP and baseload study that are redacted from the public versions. A few facts that survive include a plan to retire Fox Lake 3 effective with the addition of a new combined cycle facility in the second quarter of 2017. Also, to retire Sutherland Units 1 and 3 effective with the addition of a new combined cycle facility in the second quarter of 2017.
Other unredacted plans include:
- Implementing Ottumwa Generating Station capacity and efficiency upgrades as proposed in the 2010 Resource Plan, as well as a scrubber and baghouse installed by 2015;
- Implementing Lansing Unit 4 capacity and efficiency upgrades as proposed in the 2010 Resource Plan, as well as a scrubber installed by 2016 in addition to the existing selective catalytic reduction (SCR) and baghouse installation;
- Modifications at MidAmerican Energy-operated units Neal 3, Neal 4, and Louisa as proposed by MidAmerican Energy;
- The addition of a nominal 600 MW combined cycle plant operational in the second quarter of 2017;
- The purchase of short term capacity in 2016 as needed before the installation of the new combined cycle unit; and
- Completing existing purchase power contracts.
In the long term, the plans are for:
- Adding incremental renewable generation (for example, the Reference Case selects 1,000 MW of wind in the last five years of the study period);
- Acquiring new purchased power contract(s) (for example, the Reference Case selects several one-year peak power purchases at the end of the study period between 2022 and 2027; and
- Adding new generating units (for example, the Reference Case selects 800 MW of gas fired combustion turbine and combined cycle facilities in the last three years of the study period).
Larger, newer coal plants get emissions controls
In the IRP, the company noted these emissions control considerations for coal-fired capacity:
Ottumwa – This plant was modeled with a scrubber and baghouse installed by 2015 to reduce SO2, mercury (Hg), and particulate matter (PM) emissions to comply with the Mercury and Air Toxics Standards (MATS) and a rule similar to the Cross-State Air Pollution Rule (CSAPR). SCR installed by 2021 to reduce NOx emissions. This SCR control is a modeling assumption, though not required to comply with existing emission regulations. This assumption was included as a placeholder for compliance with potential emission regulations or resolution to potential Environmental Protection Agency (EPA) issues/concerns. Turbine upgrade and capacity/efficiency upgrades by 2015. Various other costs to comply with coal combustion residuals (CCR) and water rules (such as 316b and effluent limitation guidelines).
Lansing – Lansing 4 was modeled with an SCR and baghouse installed by 2010 to reduce NOx, mercury, and particulate emissions to comply with MATS and a CSAPR-like rule. A scrubber installed by 2016 to reduce SO2 to comply with a CSAPR-like rule. Turbine upgrade and capacity/efficiency upgrades by 2016. Various other costs to comply with CCR and water rule 316b and effluent limitation guidelines, and also including a potential cooling tower in 2020 for potential 316a/b compliance.
Louisa and Neal Units 3 and 4 – IPL is a minority owner to Louisa and Neal units 3 and 4 (4%, 28% and 25.695% respectively), while MidAmerican Energy operates the units. At Louisa, IPL assumed no additional controls. At Neal 3 and 4, the EGEAS modeling assumes a scrubber, baghouse and selective non-catalytic reduction (SNCR) by 2014 as part of MidAmerican Energy’s compliance plans.
Tier 2 Coal Fired Units – At coal-fired Tier 2 units the EGEAS modeling assumes the installation of “emissions lite” control projects by 2015 for MATS compliance. “Emissions lite” control projects include activated carbon injection (ACI) installation and electrostatic precipitator (ESP) upgrades. The units also assume various other costs to comply with CCR, water rules and effluent limitation guidelines, and potential 2020 cooling towers.
Intermediate Unit Retirements – IPL plans to retire several intermediate units, some of which were identified in the 2010 Resource Plan. These units are older, smaller, less-efficient steam units that when constructed, operated on coal and have since been converted to natural gas as their primary fuel. Fox Lake 3 was converted to natural gas in 1996, Dubuque 3 and 4 were converted to natural gas in 2011 and Sutherland 1 and 3 were converted to natural gas in early 2012. Fox Lake 3 and Sutherland 1 and 3 are assumed to be retired by the end of 2016, while Dubuque 3 and 4 would be retired by the end of 2014. The Dubuque units, as well as Sutherland 1, were assumed to be retired by the end of 2014 in IPL’s 2010 Resource Plan. IPL modified the retirement date of Sutherland 1 from the end of 2014 to preserve the capacity from this unit for two additional years.