ACTION PLAN - Plains Justiceplainsjustice.org/files/IPL Action Plan 11-1-10.pdf · 1/10/2011 · 7.2 Supply-Side Activities IPL is committed to meeting the demands of its customers

ACTION PLAN 7.0 General

The resources needed to meet IPL’s system capacity and energy requirements come primarily

from three types of resources; demand-side, supply-side and renewable resources. During the

forthcoming years, IPL will continue to pursue DSM activities, investigate and pursue renewable

energy alternatives, consider all supply-side options and will only commit to resources that are in

IPL’s and IPL’s customers’ best interest. In addition, IPL is engaged in transmission and

environmental related activities which are also discussed below. The analysis of all options is

ongoing.

7.1 Demand-Side Management Activities

IPL’s current DSM programs have been aggressively pursued and are continuing to save

customers’ kilowatts and kilowatt-hours. In the next five years, the peak demand reduction per

year and the annual energy reduction per year due to DSM programs are projected to be relatively

constant. DSM activity is reported annually in all regulatory jurisdictions in which IPL serves

retail customers. These filings on DSM programs to various agencies are expected to continue.

For this filing, the impacts of adding new DSM programs and measures were analyzed. New

measures within the prescriptive rebate programs and new programs, such as commercial new

construction (CNC) were added as compared to the programs included in the DSM section of

IPL’s 2005 Electric Resource Plan. IPL will continue to analyze potential demand and energy

savings from future DSM activities.

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PUBLIC DOCUMENTTRADE SECRET DATA HAS BEEN EXCISED

7.2 Supply-Side Activities

IPL is committed to meeting the demands of its customers. In Section 5, the types of resources

required to meet IPL’s customer needs were identified. The proposed plan projects IPL to be

long on capacity through 2018. IPL plans to meet its resource needs consistent with the

regulations of the governing jurisdictions. Considering the next five years, the immediate

incremental capacity and energy needs through 2015 will most likely be met with existing

resources and MISO market energy as necessary. IPL’s future resource requirements will be

acquired taking Iowa Code § 476.53(4) and subsequent regulatory rate treatment into

consideration.

IPL is increasingly aware of the uncertainty created from potential unknown environmental

regulations. To help manage this uncertain future, IPL has subjectively ranked its coal units into

three tiers as outlined below:

! Tier 1 – Newer more efficient

- expect to survive the entire study period

- expect to fully control;

! Tier 2 – Mid-size, older, may be less efficient

- may not survive the entire study period due to new environmental

regulations

- explore low cost emission control options;

! Tier 3 – Smaller, older, less efficient

- cannot support additional emission control costs

- not likely to survive the entire study period due to new environmental

regulations.

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IPL’s tier ranking for each of its coal units can be found in Appendix 6B, IPL’s Existing

Generating Units, Purchases and Sales. In this Resource Plan, IPL analyzed the ongoing viability

of most IPL Tier 3 units and/or IPL units that are currently unavailable. The results, as discussed

in Section 6, support retiring Sixth Street (all units), Prairie Creek Unit 2, Dubuque Unit 2,

Lansing Units 2 and 3, Kapp Unit 1, Fox Lake Units 1, 2 and 4 (CT), Agency Street CTs (all

units), and Sutherland Unit 2 immediately. Of those units to retire immediately, only Lansing

Unit 3 and Fox Lake Unit 1 were operational at time of this analysis. The results also support

retiring Dubuque Units 3 and 4, and Sutherland Unit 1 effective 1/1/2015. These retirements are

a little further out and these units will remain operable in the immediate future. Retirements are

subject to approval from the MISO through the Attachment Y process.

IPL also evaluated capacity and efficiency improvements on two Tier 1 units, the Ottumwa

Generating Station and Lansing Unit 4. The analysis supports capacity and efficiency

improvements at both units. IPL will work toward implementing those improvements as soon as

practicable.

IPL is also currently trying to negotiate a favorable purchase power agreement for the output of

DAEC post the current purchase power agreement expiring in February 2014. Absent a new

purchase power agreement, the analysis shows there is enough lead time to replace the output

from DAEC post 2014 without compromising reliability. Negotiations are ongoing.

The proposed resource plan calls for very little new generation to be added over the study period

and most, if not all, being added in the back half of the study period. IPL will seek favorable

ratemaking principles for capital investments where Iowa Code § 476.53(4) is applicable and the

necessary regulatory and environmental approvals and permits will be obtained by the

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appropriate parties. IPL customers’ demands will be met, system reliability within the region will

be maintained, and customers’ rates will be kept as low as possible.

This action plan will continually be reviewed and revised, as new information with respect to

IPL’s resource needs becomes available. IPL’s resource planning process is a continuously

iterative and another complete electric resource plan will be publicly filed in Minnesota as

determined in this Minnesota docketed resource plan proceeding, and as needed in Iowa. In the

interim, all resource options will continue to be considered and evaluated.

7.3 Renewable Activities

IPL continues to consider renewable energy, especially wind energy, a viable option for future

resource needs. Currently, IPL purchases capacity and energy from approximately 250 MW of

wind turbines. Also, IPL’s 200 MW WWWF – East came online at the end of 2009. These

existing and new resources are expected to allow IPL to obtain a renewable energy portfolio in

the range of 6% to 8% over the next 15 years. As shown in Appendix 7A, IPL is projecting to be

surplus relative to Iowa’s current renewable energy requirements anywhere from approximately

800,000 MWh to 1,100,000 MWh depending on the year. Also shown in Appendix 7A, IPL has

a current “bank” of 44,000 renewable energy credits (“REC” / “RECs”) for Minnesota’s

Renewable Energy Objective / Renewable Energy Standard. Even with this REC bank, IPL will

fall short of Minnesota’s renewable requirements which increase to 25% by 2025. The

Minnesota shortfall is roughly:

! 40,000 RECs per year in 2013 to 2015



! 190,000 RECs per year in 2025

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When considering IPL collectively, IPL’s surplus in Iowa could be used to meet a deficit in

Minnesota and then all renewable energy requirements would be met system-wide for IPL.

Therefore, IPL in total is well positioned to meet both its Iowa and Minnesota renewable energy

requirements absent any purchases of Midwest Renewable Energy Tracking System (M-RETS)

Certificates. Furthermore, IPL’s Renewable Energy Production is shown in Appendix 7B and

IPL’s Annual Community-Based Energy Development (C-BED) Report is included in Appendix

7C. Since IPL’s C-BED tariff was approved, IPL has not received any proposals pursuant to its

C-BED tariff. In summary, IPL is well positioned to comply with both Iowa’s and Minnesota’s

renewable energy requirements.

7.4 Transmission Activities

On December 20, 2007, IPL sold its transmission assets to ITC Midwest. ITC Midwest is a

subsidiary of ITC Holdings. ITC Midwest is an independent transmission company which

provides non-discriminatory access to those entities who depend upon the transmission grid. The

transaction involved the acquisition of approximately 6,800 miles of 34.5 kV and higher voltage

transmission lines in Iowa, Minnesota, Illinois and Missouri. The transaction, Docket Number E-

001/PA-07-540, was approved by the Commission in a written order dated February 7, 2008,

with an effective date of December 18, 2007. As a result of the transaction IPL status has

changed from one of a Transmission Owner (TO) to a Transmission Dependent Utility (TDU).

As a TDU, IPL participates in the stakeholder processes of both MISO and ITC Midwest. In

addition, IPL participates in various ad hoc transmission activities such as the Upper Midwest

Transmission Development Initiative (UMTDI), as a TDU. IPL plans to remain active in

transmission planning activities as a TDU.

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7.5 Environmental Activities

Environmental activities impact many aspects of IPL's business, including our generation

planning and energy supply decision-making. IPL must develop plans to make major equipment

repairs and/or add new generation sources many years in advance to allow adequate time to

arrange financing, obtain necessary approvals and permits, accomplish engineering design, and

complete the actual construction. Our primary goal in evaluating regulatory developments is to

ensure compliance with applicable environmental requirements for air emissions, water and waste

management. Furthermore, IPL considers regulatory developments with an objective to select

appropriate emissions control technologies that will be highly efficient and cost-effective. Such

an approach will achieve environmental objectives while minimizing impacts on our customers’

energy costs.

7.5.1 Planning for Environmental Regulations

Environmental planning requires evaluating regulations and understanding associated impacts to

IPL's utility operations. The environmental regulatory framework governing air quality

requirements is a critical component to developing a flexible emissions strategy that can be

changed in response to revisions to existing regulations or issuance of new rules. The framework

for implementing rules issued under the authority of the Clean Air Act (CAA) is discussed in

Section 7.5.2. Section 7.5.3 provides an overview of the critical air quality regulatory

requirements that IPL is currently considering in its emissions planning efforts. In addition,

Section 7.5.4 provides a summary of water quality regulations that will impact IPL's power plant

operations and current actions being taken to prepare for compliance with these requirements.

Section 7.5.5 summarizes anticipated new or revised waste management regulations that could

affect current coal combustion byproduct re-use, ash handling or landfill practices at IPL.

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IPL monitors the status of environmental rules and regulations that may be subject to change.

Additional ambiguity and uncertainty enters the rulemaking process due to litigation of

environmental requirements. There is currently significant regulatory uncertainty with respect to

the various environmental rules and regulations discussed below. Until litigation on various

environmental rules is resolved in the courts or with further action by the EPA, IPL plans to

continue to implement its current multi-emissions compliance plan. This plan is outlined in IPL's

Emissions Plan and Budget (EPB) filing discussed in section 7.6.1. IPL will closely monitor the

future developments of emerging environmental rules as well as associated legal challenges to

these requirements and continue to review its multi-emissions compliance plans with regulators to

determine if any changes are necessary.

7.5.2 Framework Governing Issuance of Air Quality Rules

The federal CAA along with its various amendments provides the framework governing air

quality regulations, including emissions compliance requirements for the electric utility industry.

The CAA defines the role of federal government and state agencies. Under the CAA, the EPA

sets limits on how much of an air pollutant can be in the atmosphere anywhere in the United

States. This ensures that all Americans have the same basic health and environmental

protections.

The CAA and its amendments mandate preservation of air quality through existing regulations

and periodic reviews to ensure adequacy of these provisions based on scientific data. As part of

the basic regulatory framework under the CAA, the EPA is required to establish National

Ambient Air Quality Standards (NAAQS), which serve to protect public health and welfare.

These standards currently address six “criteria” pollutants, four of which are particularly relevant

to IPL’s electric utility operations, including nitrogen oxides (NOx), sulfur dioxide (SO2),

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particulate matter (PM), and ozone. In addition, NOx and SO2 emissions result in nitrates and

sulfates, respectively, that react as fine aerosols in the atmosphere to create fine particulate matter

also known as PM less than 2.5 microns in diameter (PM2.5). Ozone is not directly emitted from

power plants, but may result from the photochemical reaction of NOx emissions in the

atmosphere.

Under the CAA, EPA is also required to regulate emissions of 187 specific air toxics for industry

group sources that emit one or more of these federally-listed hazardous air pollutants (HAPs).

For major sources, those that have the potential to emit 10 tons per year or more of a single listed

HAP or 25 tons per year or more of a combination of HAPs, EPA develops standards that restrict

emissions to levels consistent with the lowest-emitting facilities. These standards are based on air

pollution reduction measures known as maximum achievable control technology (MACT).

State implementation plans (SIPs) document the collection of regulations that individual state

agencies will apply to maintain NAAQS and related CAA requirements. The EPA must approve

each SIP and if a SIP is not acceptable to the EPA or if a state chooses not to issue separate state

rules, then the EPA can assume enforcement of the CAA in that state by issuing a federal

implementation plan (FIP). Regulatory agencies implementing the CAA requirements for IPL

include the Iowa Department of Natural Resources (IDNR) and the Minnesota Pollution Control

Agency (MPCA). The CAA allows individual states to have stronger but not weaker pollution

controls than those required by the federal government. Deciding whether or not a state should

impose stronger requirements is determined at the state regulatory and legislative levels.

Areas that comply with NAAQS are considered to be in attainment, whereas routinely monitored

locations that do not comply with these standards may be classified by the EPA as non-attainment

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and require further actions to reduce emissions. The CAA regulatory framework allows for

further standards to preserve the environment beyond the NAAQS. Specifically, other federal

and state air emission regulations currently applicable to or anticipated to affect IPL's operations

include the following: Acid Rain Program, Clean Air Interstate Rule (CAIR), Clean Air Visibility

Rule (CAVR), Clean Air Transport Rule (CATR), MACT standards, and federal actions further

strengthening the NAAQS.

7.5.3 IPL Planning Considerations for Air Emissions Regulations

The following sections briefly discuss the primary CAA programs and associated air quality

regulatory requirements that IPL is currently considering for its multi-emissions control strategy,

including recent changes to the status of these rules since the most recent filing of the updated

IPL EPB.

Acid Rain Program

Congress created the Acid Rain Program in Title IV of the 1990 Clean Air Act Amendments. The

overall goal of the program is to achieve significant environmental and public health benefits

through reductions in emissions of SO2 and NOx, the primary causes of acid rain. Specifically,

for SO2 the program employs a market-based cap and trade approach that limits, or “caps,” SO2

emissions from power plants. Sources covered by the program receive authorizations to emit in

the form of emissions allowances, with the total amount of allowances limited by the cap. Each

source can design its own compliance strategy to meet the overall reduction requirement,

including sale or purchase of allowances, installation of pollution controls, implementation of

efficiency measures, among other options. Individual control requirements are not specified

under a cap and trade program, but each regulated source must surrender allowances equal to its

permitted actual emissions in order to comply.

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In January 2000, Phase II of the Acid Rain Program was implemented. The EPA currently allots

approximately 36,000 allowances annually to IPL. One allowance is equal to one ton of SO2. As

a general strategy to comply with the Acid Rain Program, IPL has switched to burning low-sulfur

Powder River Basins (PRB) coal. As a result of burning the low-sulfur PRB fuel, IPL has

‘banked’ early compliance SO2 credits during Phase I of the Acid Rain program. With its current

bank of SO2 allowances, IPL will be able to comply with the Acid Rain program many years into

the future at an effective “zero” cost to the consumers. The Acid Rain program also requires

certain coal-fired utility boilers to comply with NOx emissions rate standards (measured in

lbs/mmBtu of heat input), which IPL has achieved though implementation of combustion controls

and installation of low NOx burner technologies.

CAIR

CAIR was issued by the EPA in 2005 to further reduce emissions of SO2 and NOx from electric

generating units in the eastern United States (including Iowa and Minnesota), targeting units with

greater than 25 MW of capacity. CAIR establishes new SO2 (annual) and NOx (both annual and

ozone season) emission caps scheduled to begin in 2010 and 2009, respectively, with further

reductions in SO2 and NOx emission caps effective in 2015. The CAIR program requirements are

in addition to the existing Acid Rain Phase II requirements that also remain in effect.

In July 2008, the U.S. Court of Appeals for the D.C. Circuit vacated CAIR in its entirety and

remanded the rule to the EPA for reconsideration. On December 23, 2008, the U.S. Court of

Appeals for the District of Columbia issued an order that denied rehearing of the original court

decision and also remanded (rather than vacating) the CAIR to EPA for revision to address flaws

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identified in the July 2008 opinion in the case. The practical impact of the court’s remand is that

CAIR obligations became effective January 1, 2009.

Subsequently, in November 2009, the EPA also took final action to address one issue under

CAIR related to the inclusion of Minnesota in the CAIR program. At issue were claims that the

EPA had included Minnesota in the CAIR region based on inaccurate data and that use of better

data would result in Minnesota falling below the threshold impact level. Consistent with the

2008 court ruling, the EPA issued a final rule staying the application of the CAIR annual SO2 and

NOx programs for Minnesota. The final rule retired the annual 2009 NOx emission allowances

allocated to owners of Minnesota generating facilities, which essentially removed Minnesota

from the current CAIR program.

In addition, the EPA issued additional rulemaking to revise and replace the CAIR in accordance

with the remand as discussed below for the proposed Clean Air Transport Rule (CATR).

CAVR

CAVR was issued by the EPA in 2005 and requires states, including Iowa and Minnesota, to

develop and implement SIPs to address regional haze visibility impairment in designated national

parks and wilderness areas across the country with a national goal of no impairment by 2064.

Electric generating facility emissions of primary concern for visibility impairment include SO2,

NOx and particulate matter (PM). Affected states were required to submit a CAVR SIP to the

EPA by December 2007, which included Best Available Retrofit Technology (BART) air

pollution controls and other additional measures needed for reducing state contributions to

regional haze. Iowa submitted its CAVR SIP to address regional haze for EPA review and

approval in March 2008. There are pending obligations under the EPA’s CAVR to complete

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BART determinations that would evaluate control options to reduce these emissions at certain

IPL units that were built between 1962 and 1977.

IPL has identified the following four potentially affected BART-eligible units that are all located

in Iowa: Burlington Generating Station Unit 1; Prairie Creek Generating Station Unit 4; M.L.

Kapp Unit 2; and Lansing Generating Station Unit 4. The EPA allowed for BART obligations for

SO2 and NOx emissions to be fulfilled by the CAIR program and this compliance approach was

adopted by Iowa in its CAVR SIP submittal to EPA. Since the Iowa Department of Natural

Resources (IDNR) accepted EPA’s overall finding that CAIR “substitutes” for BART for electric

generating units (EGUs), a BART determination only needed to be completed for PM emissions.

The EGU PM emissions at each affected unit were evaluated and it was determined that existing

pollution controls qualified as BART, since IDNR modeling results concluded that EGU PM

emissions from Iowa BART sources will not cause or contribute to visibility impairment at

nearby designated national parks. The Minnesota CAVR SIP for regional haze was submitted to

EPA for review and approval in December 2009. IPL’s generating facilities operated in

Minnesota do not combust coal and therefore additional emissions controls were deemed

unnecessary for regional haze improvement by the MPCA.

In addition, the D.C. Circuit Court CAIR ruling in 2008 may have an indirect impact on the

CAVR SIP implementation approach for BART, because the EPA allowed for BART obligations

for SO2 and NOx emissions to be fulfilled by the CAIR program. As a result of the D.C. Circuit

Court CAIR ruling in December 2008 to revise CAIR, there are uncertainties in the applicability

of and compliance outcomes of BART control approaches that will be approved for inclusion in

CAVR SIPs. In addition, there are uncertainties whether additional emission reductions could be

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required to address regional haze impacts beyond BART. IPL is unable to predict the impact that

CAVR might have on the operations of existing electric generating facilities until EPA final

approval of the SIPs submitted for regional haze and also final issuance of CAIR replacement.

CATR

In August 2010, the EPA published its proposed CAIR replacement rule, now referred to as the

Clean Air Transport Rule (CATR) that requires emissions reductions in 31 states and the District

of Columbia. EPA estimates that by 2014, this proposed rule in combination with other federal

and state air quality regulations would reduce power plant SO2 emissions by 71 percent and NOx

emissions by 52 percent, respectively over 2005 levels. The rule proposal sets state emission

caps for SO2 and NOx beginning in 2012 that are further strengthened in 2014.

Specific to IPL operations, the SO2 emission cap will be lowered further in 2014 for Iowa, but not

Minnesota. The NOx emission cap set for 2012 remains the same for 2014 for IPL. However, the

EPA indicates that it will likely lower the NOx emission cap in the final version of the proposed

CATR or subsequent rulemakings to address additional ozone transport requirements.

EPA is proposing one approach and taking comment on two alternatives for the CATR. All three

approaches set a pollution limit (or budget) for each state and obtain the reductions from power

plants. EPA's preferred approach would allow in-state (i.e., intrastate) trading and limited

regional (i.e., interstate) trading among power plants. In the first alternative, trading is allowed

only among power plants within a state. In the second alternative, EPA specifies the allowable

emission limit for each power plant and allows some averaging of emission rates for power plants

that are part of the same electric generation fleet and located within the same state. All three

possible approaches include enforceable provisions to assure that each state meets its pollution

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control obligations to reduce statewide emissions and comply with allowed budgets. In addition,

EPA's proposed CATR would require issuance of new SO2 and NOx allowances for compliance

specific to this rule. Therefore, the SO2 and NOx allowances respectively used for Acid Rain and

CAIR program compliance could not be used for the emissions reductions required under the

proposed CATR.

EPA is proposing to reduce these emissions through Federal Implementation Plans (FIPs) for

each affected state. States may replace the FIPs with EPA approved State Implementation Plans

(SIPs). This proposal would affect IPL fossil fuel-fired electric generation units with greater than

25 MW of capacity in Iowa and Minnesota. The final CATR is expected to be issued by the EPA

in mid-2011. It is anticipated that the final CATR would replace and supersede the existing

CAIR program compliance requirements effective as of 2012. The proposed CATR does not

address EPA's prior decision related to the CAIR program being sufficient to meet compliance

obligations for units subject to BART emissions reduction requirements for SO2 and NOx under

the CAVR (often referred to as "CAIR equals BART"). The EPA's revised assessment of the

relationship for the CAVR's BART requirements and the proposed CATR remains pending,

including whether EPA's compliance approach and final rule will allow for "CATR equals

BART" for SO2 and NOx.

IPL is unable to predict the final outcome of the EPA’s further work on a replacement rule for

CAIR. IPL continues to implement their environmental compliance plans to meet the currently

effective CAIR requirements, which include investments in emission controls for electric

generating facilities as well as purchases of emission allowances. IPL will closely monitor future

developments relating to the proposed CATR replacement for the CAIR regulation and update

their environmental compliance plans as needed.

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Utility MACT

In March 2008, the U.S. Court of Appeals for the D.C. Circuit vacated and remanded the federal

Clean Air Mercury Rule (CAMR) to the EPA for reconsideration. The CAMR issued by EPA in

2005 would have required reductions of mercury emissions from existing and new U.S. coal-fired

EGUs with greater than 25 MW of capacity using a national cap-and-trade system. The first

phase of compliance was required to begin in 2010 and the second phase in 2018.

On February 6, 2009, EPA filed a motion to dismiss the agency's request for review of the D.C.

Circuit's decision vacating CAMR and also a related EPA rule delisting EGUs from regulation

under § 112 of the Clean Air Act that had enabled the CAMR cap-and-trade approach.

According to the motion to dismiss, EPA intends to develop MACT standards for electric

generating units pursuant to Clean Air Act § 112.

Therefore, the expected consequence of the court ruling vacating the CAMR is that EPA will

instead develop regulations for MACT standards for EGUs under § 112 of the CAA. The MACT

standards are expected to require reductions of mercury emissions from coal-fired EGUs greater

than 25 MW. EPA may also issue a determination to regulate other federally-listed HAP

emissions from coal-fired EGUs and/or issue MACT standards regulating HAPs from oil-fired

EGUs greater than 25 MW.

The Clean Air Act § 112 requires a command-and-control technology driven approach to develop

MACT standards. When developing a MACT standard for a particular source category, EPA

looks at the current level of emissions achieved by best-performing similar sources. These

emissions levels set a baseline, often referred to as the "MACT floor" for the new standard. At a

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minimum, a MACT standard must achieve, throughout the industry, a level of emissions control

that is at least equivalent to the MACT floor. EPA can establish a more stringent standard when

it makes economic, environmental, and public health sense to do so. Thus, in the first step of a

MACT rulemaking, EPA determines a “MACT floor” for new and existing units. The second

step in the MACT process requires EPA to determine if further “beyond the floor” limits are

warranted.

MACT is determined by taking into account the cost of emission reductions, non-air quality

health impacts, environmental impacts, and energy requirements. MACT standards typically

require compliance within 3-years from final rule issuance and are plant or unit-specific

emissions limits (percentage reduction or required stack concentration). MACT does not allow

for emissions trading or fleet wide system averaging.

The MACT floor differs for existing sources and new sources. For existing sources, the MACT

floor must equal the average current emissions limitations achieved by the best-performing 12

percent of sources in the source category, if there are 30 or more existing sources. If there are

fewer than 30 existing sources, the MACT floor must equal the average current emissions

limitation achieved by the best-performing five sources in the category. For new sources, the

MACT floor must equal the current level of emissions control achieved by the best-controlled

similar source. Note that prior to MACT rule issuance, this is to be determined on a case-by-case

basis as part of the air permitting process.

In January 2010, the EPA issued an information collection request for coal- and oil-fired electric

utility steam generating units over 25 MW in order to develop a proposed Utility MACT standard

for the control of mercury and other federal HAPs. The purpose of the information collection

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request is to collect data necessary to identify affected categories of electric generation units that

will be subject to a Utility MACT standard and to define the MACT floor. IPL received and

responded to the EPA information collection request in April 2010.

In February 2010, the EPA entered into a consent decree that requires the agency to propose

Utility MACT standards for coal- and oil-fired electric generating units no later than March 2011

and promulgate final standards no later than November 2011. There is uncertainty until EPA

reconsiders and issues new federal EGU MACT standards. The level of MACT is anticipated to

be equal to or more stringent than what IPL had been planning for CAMR and plant-specific

mercury emissions limitations. At this time, other impacts such as regulation of other HAPs or

oil-fired EGUs cannot be assessed until EPA issues proposed regulations in the Federal Register

for public comment.

Industrial Boiler and Process Heater MACT

The EPA’s Industrial Boiler and Process Heater MACT rule became effective in 2004 and

compliance with these new emission requirements for hazardous air pollutants was required by

September 2007. This rule applies to fossil fuel electric generating units with less than 25 MW

capacity as well as certain auxiliary boilers and process heaters operated at electric generating

facilities. In June 2007, a court decision vacated this rule. In June 2010, the EPA published a

revised Industrial Boiler and Process Heater MACT rule proposal for public comment. A final

rule is expected to be issued by the EPA in 2011.

Until the EPA issues a revised Industrial Boiler and Process Heater MACT rule, the federal CAA

generally requires affected facilities to submit to state permitting authorities an application for a

case-by-case MACT determination for all potentially affected units under this rule. Case-by-case

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MACT determinations are effective compliance measures until revised final federal regulations

can replace these interim requirements. IPL submitted case-by-case permit application

information in 2009. The outcome of the case-by-case MACT determinations by the IDNR are

uncertain at this time. Furthermore, IPL is unable to predict the impact of any potential Industrial

Boiler and Process Heater MACT standard changes until the EPA issues a final rule.

NAAQS

Further strengthening of NAAQS as required pursuant to CAA regulations could result in more

stringent air emissions requirements. NAAQS for ozone, NOx, SO2 and fine PM are under

continuing revision and/or under legal challenge. These NAAQS changes are not discussed

within detail due to the pending nature of these issues. In addition, many of the revised NAAQS

will require updated ambient monitoring and measurement methodologies. IPL is currently

unable to predict the potential impact of NAAQS revisions on its operations until final

designations are issued. Depending on the level and location of potential non-attainment areas,

IPL may be subject to additional emissions reduction requirements.

7.5.4 IPL Planning Considerations for Water Quality Regulations

The Federal Clean Water Act (CWA) requires the EPA to regulate cooling water intake structures

to assure that these structures reflect the “best technology available” for minimizing adverse

environmental impacts to fish and other aquatic life. In 2004, the second phase of this EPA rule

became effective and is generally referred to as “316(b)” of the CWA. Section 316(b) applies to

existing cooling water intake structures at large steam-electric generating facilities. This rule

requires existing electric generating stations with design cooling water intake rates of 50 million

gallons per day or more to demonstrate how they currently meet or will meet national

performance standards to reduce entrainment and impingement mortality of fish and shellfish.

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Cooling water intake can adversely impact aquatic organisms in two basic ways. The first is

entrainment, which is the taking in of organisms with the cooling water. As these entrained

organisms pass through the plant, they are subjected to numerous sources of damage. The second

way is through entrapment-impingement. This is the blocking of larger entrained organisms that

enter the cooling water intake by some type of physical barrier. Most electric generating plants

have screening equipment installed in the cooling water flow to protect downstream equipment

such as pumps and condensers from damage or clogging. Larger organisms, such as fish, which

enter the system and cannot pass through the screening equipment, are trapped ahead of it.

Eventually, if a fish cannot escape or is not removed, it will tire and become impinged on the

screening equipment. If impingement continues for a long time period, the fish may suffocate

because the water current prevents gill covers from opening. If the fish is impinged for a short

time period and removed, it may survive; however, it may still suffer from delayed mortality due

to the resulting stress.

In January 2007, a court opinion invalidated aspects of the 316(b) rule that allowed for

consideration of cost-effectiveness when determining the appropriate compliance measures. In

July 2007, the EPA formally suspended the 316(b) rule for further reconsideration. Prior to

suspension of the rule, IPL identified the following coal-fired generating stations as being

affected by the rule:

! Fox Lake;

! Lansing;

! Dubuque;

! M.L. Kapp;

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! Burlington; and,

! Prairie Creek.

Of these, the Fox Lake power plant is located in Minnesota with the others all located in Iowa.

Electric generating stations with cooling towers, including Ottumwa and Sutherland in Iowa, are

not anticipated to have additional compliance requirements under Section 316(b).

In April 2009, the U.S. Supreme Court granted the EPA authority to use a cost-benefit analysis

when setting technology-based requirements under Section 316(b). A revised Section 316(b) rule

reflecting the U.S. Supreme Court’s decision is anticipated to be proposed by the EPA in 2011

and a final rule is expected in 2012. EPA has not indicated what the changed rule requirements

may be and it is uncertain how any revised or new requirements may impact IPL electric

generating stations. At this time, IPL is conducting necessary engineering evaluations and

biological studies to prepare for determination of the best approach for compliance for each

facility. IPL’s planning for Section 316(b) compliance is subject to change pending the EPA's

issuance of the revised rule.

To date, IPL has completed impingement and Section 122.21(r) studies at all of the generating

stations affected by the original rule. Section 122.21(r) studies provide characterization of the

water body (ex. size, drainage area, water elevations) as well as data for evaluation of cooling

water system design alternatives. In addition, IPL has conducted an entrainment study at Prairie

Creek. The purpose of these studies is to determine and quantify the impingement and

entrainment mortality of fish and other aquatic life associated with the operation of each

generating station’s cooling water intake structure as well as collect source water physical,

cooling water intake structure, and cooling water system data. The impingement, entrainment

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and Section 122.21(r) data will be used to develop the calculation baseline for each affected

generating station once EPA revises the rule.

Currently IPL anticipates that installation of wedge-wire screens at the cooling water intake

structures of numerous IPL generating stations could be necessary to comply with 316(b)

requirements. Installing wedge-wire screens will reduce velocity of the cooling intake water

withdrawals at a power plant and therefore provides for less entrainment and impingement of fish

and other aquatic life. Wedge-wire screens are bullet shaped devices placed on the bottom of a

river that allows water to be withdrawn from a river through small diameter holes in the screen.

The device allows water to be withdrawn at a rate of less than 0.5 feet per second. However, the

adequacy of this compliance approach is based on analysis of the Phase II rule suspended by the

EPA in 2007 and IPL will need to re-evaluate the adequacy of this approach for meeting the

compliance requirements of the EPA's revised Section 316(b) rule when issued.

7.5.5 IPL Planning Considerations for Solid Waste Management Regulations

Coal combustion residuals (CCR) are what remain after the direct combustion of coal in power

plants to generate electricity. There are different types of CCR:

! Fly ash is a very fine powder-like particle, ranging in color from tan to black. It is

collected by emission controls, such as electrostatic precipitators (ESP) and baghouses,

which prevent it from being released through the stacks of the plant.

! Bottom ash is a brown sand-like material collected in the bottom of the boilers.

! Boiler slag is black, shiny and angular. It is coarser than bottom ash and also collected in

the bottom of boilers.

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CCR are comprised of melted sand and lime with smaller amounts of oxides containing

aluminum, iron, magnesium, sulfur and trace metals. These same components are also found in

mud, silt, and soil. Coal ash also contains unburned carbon residue that that tends to give it a

dark color.

Passage of the Resource Conservation and Recovery Act (RCRA) in 1976 delegated the

regulation of “non-hazardous” waste to each respective state. CCR’s met the definition of a non-

hazardous waste; hence, each state developed specific regulations for CCR management for their

respective jurisdictions. RCRA was amended in 1980 to include what is referred to as the “Bevill

Amendment”, which specifically exempted CCR from hazardous waste regulation until further

study could be completed by EPA. At this time, CCR remain classified as exempt non-hazardous

wastes under RCRA.

IPL currently manages CCR to prevent harmful emissions or releases into the environment in

accordance with state programs. Landfills have been constructed and are operated to manage the

disposal of CCRs in compliance with state regulations. CCR sampling, ground water sampling,

landfill management plans, landfill permits and monitoring reports are examples of activities

required to comply with disposal regulations. IPL strives to minimize land disposal of CCR by

finding and participating in acceptable beneficial use alternatives for the materials.

In December 2008, national attention was turned to CCR management when a breach in a coal

ash impoundment pond occurred at the Tennessee Valley Authority plant located in Kingston,

Tennessee. This breach released 1.1 billion gallons of coal ash slurry to the immediate

surrounding area and flooded more than 300 acres. In March 2009, EPA declared its intent to

move forward with new regulations to address the management of CCRs and potential

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environmental risks from the disposal of CCRs generated by electric utilities, such as pollution

from impoundment and landfills leaching into ground water and structural failures of

impoundments. In April 2009, IPL and other utility companies received an EPA Information

Collection Request to provide information to inform EPA's rulemaking effort on all current and

past surface impoundments in which CCR had been placed.

In June 2010, the EPA issued a proposed rule for all CCR generated by electric utilities that

potentially may impact future management of this material. This proposal included two possible

options for CCR management under either Subtitle C or Subtitle D of RCRA. In the first option,

the EPA would reverse its previous classification of CCRs as being a "non-hazardous waste" and

would define the material as a special waste managed under the Subtitle C provision of the EPA

Hazardous Waste rules for the specific case where the CCR was destined for disposal in landfills

or surface impoundments. If the material was instead destined to be used for beneficial reuse, it

would be managed as a non-hazardous waste material. Under the second option, CCRs would

continue being managed as a non-hazardous waste in all uses under Subtitle D of RCRA, but

EPA would establish national performance standards for landfills and surface impoundments.

Beneficial reuse applications for CCRs would continue under both options, especially for

encapsulated uses such as concrete, asphalt, wallboard, roofing materials, and bricks. However,

restrictions for unencapsulated CCR beneficial reuses are being considered. The public comment

period ends in November 2010 and EPA final regulations are anticipated in 2011. Further

assessment of CCR management compliance plans will be evaluated after EPA's final rule has

been issued.

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7.6 Environmental Regulatory and Related Initiatives

The following section describes IPL's significant on-going environmental regulatory initiatives.

7.6.1 Emissions Plan and Budget (EPB)

IPL is responsible for developing and managing an Emissions Plan and Budget (EPB) filing

within the State of Iowa, consistent with the requirements of Iowa Code § 476.6(22). In

accordance with this code section, each rate-regulated public utility that is an owner of one or

more electric generating facilities fueled by coal and located in the State of Iowa is required to

file an EPB at least every two years. An EPB provides a utility’s compliance plan and related

budget to meet applicable federal and state environmental requirements. IUB approval

demonstrates that IPL’s EPB is expected to reasonably achieve cost-effective compliance with

applicable environmental requirements.

The IPL EPB update was last filed in March 2010 for the period of 2011-2012. This biennial

filing was deemed complete and approved by the IUB on October 1, 2010. The complete filing

can be obtained from the IUB (http://www.iowa.gov/iub/). The EPB includes specific details of

IPL's multi-emissions plan to be implemented during the 2011 to 2015 timeframe, including:

1) IPL's evaluation of emission control technologies and alternatives to achieve compliance

with anticipated environmental requirements; and

2) IPL's specific emission reduction activities and budgets.

IPL's approved EPB includes environmental activities at regulated electric generating stations to

reduce emissions of SO2, NOx, mercury and other HAPs as well as compliance preparation efforts

for 316(b) requirements to minimize adverse impacts from cooling water intake structures. The

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http://www.iowa.gov/iub/

EPB also reviews IPL's approach to emission allowance management for SO2 and NOx as this

relates to the two applicable market-based cap-and-trade programs under Acid Rain and CAIR,

which permit the purchase or sale of allowances to comply with emission reductions required

under these regulations.

The March 2010 EPB filing outlines approximately $374 million in environmental capital

investments to existing coal-fired generating units during the Budget Update period from January

1, 2011 through December 31, 2015. IPL’s share of these capital investments is approximately

$211 million, with the other joint owner of Ottumwa, MidAmerican Energy Company

(MidAmerican), responsible for the remaining investments.

Related to this EPB filing, IPL announced plans in 2008 to install a selective catalytic reduction

(SCR) system and baghouse at Lansing Unit 4 to reduce NOx and mercury emissions,

respectively, at the generating station. The SCR system for Lansing Unit 4 was included in IPL’s

Amended EPB approved by the IUB in November 2007. The baghouse for Lansing Unit 4 was

included in IPL’s EPB approved by the IUB in October 2008. In July 2010, IPL completed the

installation of the SCR system and baghouse at Lansing Unit 4. As of June 30, 2010, IPL had

incurred capitalized expenditures of $90 million and recognized $6 million of allowance for funds

used during construction (AFUDC) for the SCR system and had incurred capitalized expenditures

of $86 million and recognized $3 million of AFUDC for the baghouse at Lansing Unit 4.

IPL plans to continue to execute a long-term, staged environmental compliance strategy that

incorporates current and emerging environmental rules and regulations and proactively manages

the timing, cost and customer rate impact of the actions it entails. IPL will continue to monitor

pending rules and regulations. IPL will maintain sufficient flexibility to respond, as necessary, to

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the outcomes of these pending rules and regulations while ensuring future environmental

compliance requirements are met and being sensitive to the resulting impact on customer rates.

IPL manages emissions in the context of its overall strategic planning process and these outcomes

are reflected in the company's EPB filing. The multi-emissions strategy is dynamic and considers

both increasingly stringent environmental requirements and growing electricity demand on the

electric generating units. IPL's multi-emissions strategy assesses the current status of its plants,

evaluates technical and economic feasibility of air pollution control scenarios and proposes a

flexible plan prioritizing options. These evaluations consider integration of control scenarios

with uncertainties of regulation, as well as, integration of existing generation with additional

renewable energy and demand-side savings programs, in a manner that ensures reliable power

supply and maximizes cost-effectiveness.

At this time, IPL is not subject to any mandatory cap and trade regulations to reduce greenhouse

gas (GHG) emissions including carbon dioxide (CO2). Therefore, due to the absence of a real

market, no related allowances or credits for CO2 currently exist and predictions of future

allowance prices will continue to be highly speculative due to the uncertainties of what a

mandatory program could ultimately require. IPL's ongoing consideration of potential

greenhouse gas regulation risk is further discussed in Section 7.6.2 below.

Future evaluations of IPL's multi-emissions strategy development will be on-going, evolving with

regulatory status and technology advancement. More recent outcomes of IPL's multi-emissions

plan evaluation will be updated periodically in the EPB filing discussed above. IPL financial

investments for installation of air pollution control technologies discussed in its EPB filing are

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further updated based on known commitments for engineering, procurement and construction in

disclosures to the Securities and Exchange Commission (SEC), Forms 10K and 10Q.

7.6.2 Potential Greenhouse Gas Regulation Risk

Climate change continues to garner public attention along with support for policymakers to take

action to mitigate global warming. There is considerable debate regarding the public policy

response that the U.S. should adopt, involving both domestic actions and international efforts.

Proposed legislation to regulate green-house gas (GHG) emissions, primarily targeting reductions

of CO2 emissions, continues to be reviewed but has not gained sufficient support to pass into law.

Initiatives to address GHG emissions in the Midwest region have concluded and are pending

further action pending federal GHG action. In addition, efforts are underway by the EPA to

respond to a court ruling that could require rules to reduce GHG emissions, including assessment

of whether or how the agency should regulate GHG emissions. Given the highly uncertain

outcome and timing of future regulations regarding the control of GHG emissions, IPL currently

cannot predict the financial impact of any future climate change regulations on their operations

but believe the expenditures to comply with any new emissions regulations could be significant.

Climate Change Legislative Developments

Federal - The U.S. Congress is currently debating various forms of legislation to regulate GHG

emissions with the most support gained for the American Clean Energy and Security Act of 2009

(ACES Act), H.R. 2454, which passed the U.S. House of Representatives passed by a vote of 219

to 212 on June 26, 2009. This comprehensive national climate and energy legislation would

establish an economy-wide, cap-and-trade system and additional measures towards clean energy

technological development. Similar legislation has been under consideration in the U.S. Senate at

the committee level only. IPL is not able to determine what, if any, GHG legislation will finally

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be enacted, or the impact of such legislation.

Midwestern Greenhouse Gas Reduction Accord

The Midwestern Greenhouse Gas Reduction Accord (GHG Accord) was announced in November

2007. The governors of Illinois, Iowa, Kansas, Michigan, Minnesota, and Wisconsin and the

Manitoba premier signed onto the plan.

In May 2010, the Advisory Group Final Recommendations were issued for the Midwestern GHG

Accord. This report outlines the following reduction targets and design principles related to

implementation of climate change policy in the Midwest.

Midwest GHG Accord Final Recommendations

Reduction Targets:

! 2020 Target - The Advisory Group recommends a target of 20 percent below 2005 levels

by 2020.

! 2050 Target - The Advisory Group recommends an 80 percent reduction below 2005

levels by 2050.

Design Principles:

! Ensure that the system is equitable, administratively simple for government and private

participants, minimizes administrative costs, and has a clear compliance path;

! Cover as many sources as practical, while encouraging emissions reductions beyond the

capped sources and sectors;

! Assure a transparent and robust data gathering and accounting system that will measure

and report emissions accurately and consistently across all sectors and throughout the

region;

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! Ensure distribution of allowance value supports the goals of the program, including

compensating for disparities and impacts caused by the program;

! Enable linkage to systems in other jurisdictions with similarly rigorous accounting in

order to create economies of scale and to increase market efficiencies, diversity, and

liquidity, while reducing costs;

! Maximize economic, employment, energy diversity, environmental and public health

benefits, while minimizing any transitional job losses, energy, and other cost impacts;

! Reduce the potential for emissions leakage, including the shifting of economic activity to

non-covered sources and to non-participating jurisdictions;

! Stimulate investment, especially in low-carbon technologies, and reward innovations that

will lead to near- and long-term, permanent greenhouse gas reductions;

! Credit qualified past and present actions to reduce GHG emissions;

! Require any offsets to be real, surplus/additional, verifiable, permanent, and enforceable;

! Allow flexibility for participating jurisdictions to meet specific policy needs and

objectives, while maintaining regional program uniformity;

! Demonstrate leadership toward, and enable transition to or harmonization with, any

future federal program, while ensuring the capability of the regional program to stand on

its own, if necessary; and

! Reduce the potential for and scale of unintended economic consequences of the policy,

while maintaining an appropriate price signal.

Reference: Midwestern Greenhouse Gas Reduction Accord: Final Recommendations of the

Advisory Group issued May, 2010.

http://www.midwesternaccord.org/Accord_Final_Recommendations.pdf

Issuance of this final report was prefaced with the following introduction, "The Advisory Group

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makes these final recommendations at this time in order for the Midwest to have regional

influence on the national debate in Washington, D.C., regarding a federal cap-and-trade climate

policy. Any future federal program must recognize the particular resources and special economic

circumstances of the Midwest region. These design recommendations provide a platform for

those Midwestern concerns and priorities. Midwestern Governors and the Manitoba Premier

strongly prefer the implementation of an effective cap-and-trade program at the federal level in

both countries, rather than a regional program. This preference for a federal system is shared by

stakeholders participating in this Advisory Group. However, the Governors and the Premier have

tasked the Advisory Group with providing recommendations for a regional cap-and-trade system,

should efforts toward implementing a federal system fail to proceed."

Furthermore, any adoption of any cap-and-trade or other GHG reduction proposals will have to

be adopted by member states subject to the approval of their legislatures and governors. No

specific GHG legislation is currently being considered in Iowa or Minnesota.

EPA GHG Regulations

In April 2007, the U.S. Supreme Court concluded in Massachusetts v. EPA that GHGs meet the

CAA definition of an air pollutant. In response to this court decision, the EPA has subsequently

issued proposed and final regulations for GHGs under the CAA. These regulations are described

in greater detail below, reflecting the complexity and magnitude of the question of whether and

how greenhouse gases could be effectively controlled under the CAA. Furthermore, significant

uncertainty exists surrounding the final implementation of these regulations, all of which are

subject to legal challenge in the D.C. Circuit Court. The outcome of these challenges will

determine if GHG stationary sources, including electric utility operations, will be regulated under

the CAA. IPL is currently unable to predict the timing and nature of stationary source rules for

GHG emissions including future issuance of regulations that would mandate reductions of GHGs

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at electric utilities.

Mandatory GHG Reporting Rule - In December 2009, the final EPA Mandatory GHG Reporting

rule became effective. The final rule does not require control of GHG emissions, rather it

requires that sources above certain threshold levels monitor and report emissions. The EPA

anticipates that the data collected by this rule will improve the U.S. government’s ability to

formulate a set of climate change policy options. The GHG emissions covered by the final EPA

reporting rule include CO2, methane (CH4), nitrous oxide (N2O), sulfur hexafluoride (SF6),

hydrofluorocarbons (HFCs), perfluorocarbons and other fluorinated gases. Emissions of GHG

will be reported at the facility level in CO2-equivalent (CO2e) and include those facilities that

emit 25,000 metric tons or more of CO2e annually. The final rule applies to electric utility and

natural gas distribution operations at IPL. The annual reporting compliance requirement begins

for the calendar year 2010, with the first GHG emissions reports due by March 31, 2011. IPL is

currently updating its emissions monitoring methodologies to capture all the GHG emissions data

required to comply with the EPA’s mandatory GHG reporting rule.

GHG Endangerment and Cause or Contribute Finding - In April 2009, the EPA issued a

“Proposed Endangerment and Cause or Contribute Findings for GHG under the CAA.” This

proposal includes two distinct findings regarding GHG emissions under the CAA. First, the

current and projected concentrations of GHG emissions in the atmosphere threaten the public

health and welfare of current and future generations. This is referred to as the endangerment

finding and includes the six key GHG emissions identified in the EPA’s proposed reporting rule.

Second, the combined emissions of CO2, CH4, N2O, and HFCs from new motor vehicles and

motor vehicle engines contribute to the atmospheric concentrations of these key GHG emissions

and hence to the threat of climate change. This is referred to as the cause or contribute finding.

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In December 2009, the EPA published the final rule for this finding with an effective date of

January 2010.

EPA Rulemaking Governing GHG Emissions from Motor Vehicles - In April 2010, the EPA,

under authority from the GHG Endangerment and Cause or Contribute Finding, issued a final rule

that regulates GHG emissions from motor vehicles as a pollutant under the CAA. The EPA’s

issuance of this rule under the CAA enables it to regulate other GHG stationary sources,

including electric utility operations.

GHG Tailoring Rule - In June 2010, the EPA issued the GHG Tailoring Rule. This final rule

tailors the applicability criteria that determine which stationary sources and modification projects

become subject to permitting requirements for GHG emissions under the Prevention of

Significant Deterioration (PSD) Construction Permit and Title V Operation Permit programs of

the CAA. The Tailoring Rule establishes a two-step process for implementing regulation of

GHGs under the PSD and Title V programs. This final rule is amending, for GHG purposes, the

CAA statutorily-prescribed major source threshold of 100 tons per year (tpy) for Title V

operating permits and the 100 or 250 tpy major source threshold for the PSD construction

permits. The final rule establishes a major source threshold for GHG emissions of 100,000 tpy of

CO2e. The final rule also establishes a significance level of 75,000 tpy CO2e for PSD purposes.

Existing major sources making physical or operational changes that would result in an increase in

emissions above the significance level would be required to obtain a PSD permit and meet Best

Available Control Technology (BACT) emission limits for GHGs. GHG permitting requirements

for large facilities that are already obtaining CAA permits for other (non-GHG) pollutants will

begin in January 2011. In July 2011, GHG permitting requirements will expand to cover all new

facilities that meet the 100,000 CO2e tpy major source threshold and modifications at existing

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major sources of GHGs that would increase GHG emissions by at least 75,000 tpy for CO2e.

GHG Tailoring Federal Implementation Rule - In September 2010, the EPA published in the

Federal Register the two proposed rules designed to ensure that GHG permitting requirements for

stationary sources are implemented in all states starting January 2, 2011. The EPA has proposed

these two additional rules in order to enable and implement the GHG Tailoring Rule. The two

actions are intended to fill the gap for any state that cannot make the necessary changes to its

permitting program by January 2011. EPA states that without these proposals industrial sources

of GHGs in some states would not be able to begin construction as of January 2, 2011, the earliest

GHG permitting requirements become effective.

In the first rule, EPA is asking states to review their GHG permitting authority and inform EPA if

their PSD programs do not apply to GHG sources. Pending the outcome of this notification, then

each state may be added to a formal SIP call listing, which would require states to revise their

SIPs to ensure that their PSD programs cover GHG emissions. In the second rule, EPA is

proposing a FIP that would apply in any state that is unable to submit, by its specified SIP-call

deadline, a SIP revision to ensure that the state has authority to issue permits under the PSD

program for GHG sources. Any source that requires a PSD permit for its GHGs located in an

area that is subject to this FIP would be issued a permit by EPA. The FIP would assure that PSD

permitting for GHGs can continue until the state's required SIP revision is complete. The agency

is working to finalize these rules prior to January 2, 2011, which is the earliest that the GHG

permitting requirements will be effective. Related state actions are as follows:

! Iowa - On July 20, 2010 the Iowa Environmental Protection Commission (EPC) approved

publication of a Notice of Intended Action (NOIA) proposing changes to air quality rules that

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would implement the EPA federal Tailoring Rule.

! Minnesota - Minnesota is a delegated state for the PSD program and this means that the new

federal PSD permit requirement is effective immediately. No rule changes are needed to

begin incorporating GHGs into PSD permits. However, Minnesota’s Part 70 permit rule for

Title 5 operating permits refers to the Clean Air Act for applicability. The current rule also

lists the permit threshold as 100 tpy. Minnesota is proposing to revise the existing rule

language to conform with the new threshold in the federal rule.

Alliant Energy GHG Initiatives

Alliant Energy Corporation (Alliant Energy), which is the public utility holding company for the

subsidiary IPL, remains committed to its adopted climate change position and guiding principles

shown below that support the development of a national climate change policy.

Alliant Energy's Position on Climate Change

It is in the best interest of Alliant Energy’s shareowners and customers that future efforts to reduce greenhouse gas (GHG) emissions be guided by an effective, mandatory policy that is national in scope, applies to multiple sectors, provides planning certainty, and allows flexible compliance actions consistent with national energy policy requirements. Alliant Energy will continue to invest in energy efficiency and renewable energy. Alliant Energy will continue to participate in collaborative efforts to further the development of technological advancements in emissions controls and generation performance.

Guiding Principles Sufficient scientific evidence exists to support GHG emissions reduction efforts. Technology solutions based on sound science are critical and should be developed; continued research and demonstration studies must be supported. GHG reduction efforts should not be targeted at any one industry, but rather at all sectors. Alliant Energy is part of the solution; but, global efforts are needed requiring international cooperation. Economic growth and sustainable development is possible while also reducing GHG emissions.

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Alliant Energy continues to take voluntary measures to reduce CO2 and other GHG emissions as

prudent steps to address potential climate change regulation. Strategically, Alliant Energy

focuses on the following areas to reduce emissions including GHG emissions:

1) Installation of commercially proven controls for air emissions and continued operational

excellence to achieve further generating facility efficiency improvements;

2) Implementation of DSM including energy conservation programs;

3) Expansion of company-owned renewable energy sources;

4) Continued use of purchase power agreements and investments that focus on lower or

non-emitting generation resources; and

5) Development of technology solutions through funding of collaborative research programs

for advanced clean coal generation as well as potential options for carbon sequestration.

Chicago Climate Exchange (CCX)

The Chicago Climate Exchange (CCX) is a voluntary market-based emissions cap and trade

program for reducing GHG emissions, including CO2. Alliant Energy is a committed Phase I and

II member of CCX. The CCX defined baseline is determined from the CO2 emissions over the

1998-2001 period for electric generating units with a boiler nameplate capacity of 25 MW or

greater. CCX defined reductions from the approved baseline are as follows:

Phase Year Reduction from Baseline

2003 1%

2004 2%

2005 3%

Phase I

2006 4%

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2007 4.25%

2008 4.50%

2009 5%

Phase II

2010 6%

Information on CCX is available at the following: http://www.chicagoclimatex.com/

Figure 1 below presents the total annual CO2 for 1998 through 2008 from the power plants owned

by IPL in the States of Iowa and Minnesota that are currently subject to the Acid Rain Program

regulations under the Clean Air Act. These units have the ability to serve a turbine with capacity

greater than 25 MW and are equipped with continuous emissions monitors (CEMs) for CO2.

Levels shown in Figure 1 represent IPL's ownership share. Review of Figure 1 indicates that

IPL's historical CO2 emissions remain relatively constant with an average annual rate of

approximately 13 million tons per year for this time period.

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Figure 1. IPL Historical CO2 Emissions

12.8 13.5 13.8 13.1 13.0 13.1 13.3 13.6 13.3 14.012.2

10.2

-1.02.03.04.05.06.07.08.09.0

10.011.012.013.014.015.0

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

Year

CO

2 (M

illio

ns o

f Ton

s)

CO2 EmissionsAverage

Alliant Energy believes it is prudent to analyze the impact of future climate change regulation to

the company's operations as part of its strategic planning process. Alliant Energy does evaluate

the potential impact of future climate change regulation using sensitivity studies that incorporate

possible outcomes of these future regulations. However, performing such studies is challenging

given the significant uncertainty in the timing and design of future climate change regulations.

As part of its strategic planning process, Alliant Energy does analyze the net effect that future

climate change regulation may have on our energy supply and resource mix. This includes

changes to the dispatch of existing power plants and changes to the technologies selected for

future new power plants. Unlike other criteria air emissions, commercially available back-end

CO2 emissions control technologies do not currently exist. This limits IPL’s options for CO2

emissions control to changes to the dispatch and fuel sources of existing power plants and

changes to the technologies selected for future new power sources.

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The highly dynamic nature and complex changing provisions of future regulatory proposals to

reduce greenhouse gas emissions, including CO2, result in challenges to analyze them with a

straightforward side-by-side comparison. However, such information does provide a general

guide to support the relative extent of potential impacts that could result from such climate

change policies. In addition, there is no way to speculate with certainty the final outcome of

climate change policy at any level, including “when” or “how” future legislation or rules could

impact IPL. Thus, such evaluations should be considered within the context as a means to better

understand how the various policies under consideration could impact IPL's future energy supply

options and resource mix.

Alliant Energy’s Board of Directors has assigned oversight of environmental policy and planning

issues for IPL, including Climate Change, to its Environmental, Nuclear, Health and Safety

(ENHS) Committee. The ENHS committee is comprised solely of independent directors. The

ENHS Committee reports on its reviews and, as appropriate, makes recommendations to Alliant

Energy’s Board of Directors. Given the highly uncertain outcome and timing of future

regulations regarding the control of GHG emissions, IPL currently cannot predict the financial

impact of any future climate change regulations on operations. IPL believes that its climate

change approach is balanced and assures that strategic plans are subject to executive review by

Alliant Energy’s Board of Directors.

7.6.3 Environmentally Beneficial Related Initiatives

As was first reported in IPL’s 2003-2018 Electric Resource Plan, IPL has a number of

environmentally beneficial programs, including:

! Seeking renewable energy alternatives like wind and biomass above and beyond what is

required in individual states, and helping provide customers the option to subscribe

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directly through IPL’s Second Nature program;

! Protecting land and wildlife with our Riverland Conservancy land trust;

! Encouraging energy conservation through customer programs like Performance Edge and

Shared Savings; and

! Sponsoring Operating ReLeaf, Branching out and other tree planting programs.

7.7 Other Actions

As in the past, IPL will continue to evaluate the service needs of its customers, the costs of

various resources, the applicability of new technologies, and other factors related to resource

planning. IPL expects to be adequately flexible so as to accommodate future uncertainties.

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Documents

ACTION PLAN - Plains Justiceplainsjustice.org/files/IPL Action Plan 11-1-10.pdf · 1/10/2011 · 7.2 Supply-Side Activities IPL is committed to meeting the demands of its customers