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•	federal and state regulatory or governmental actions, including the impact of energy, tax, financial and health care legislation, and of regulatory agency orders;

•	IPL’s and WPL’s ability to obtain adequate and timely rate relief to allow for, among other things, the recovery of fuel costs, operating costs, transmission costs, deferred expenditures, capital expenditures, and remaining costs related to EGUs that may be permanently closed, earning their authorized rates of return, and the payments to their parent of expected levels of dividends;

•	the ability to continue cost controls and operational efficiencies;

•	the impact of IPL’s retail electric base rate freeze in Iowa during 2015 and 2016;

•	the impact of WPL’s retail electric and gas base rate freeze in Wisconsin during 2015 and 2016;

•	weather effects on results of utility operations, including impacts of temperature changes in IPL’s and WPL’s service territories on customers’ demand for electricity and gas;

•	the impact of the economy in IPL’s and WPL’s service territories and the resulting impacts on sales volumes, margins and the ability to collect unpaid bills;

•	the impact of customer- and third party-owned generation, including alternative electric suppliers, in IPL’s and WPL’s service territories on system reliability, operating expenses and customers’ demand for electricity;

•	the impact of energy efficiency, franchise retention, customer- and third party-owned generation and customer disconnects on sales volumes and margins;

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developments that adversely impact the ability to implement the strategic plan, including unanticipated issues with new emission controls equipment for various coal-fired EGUs of IPL and WPL, IPL’s construction of Marshalltown, WPL’s proposed Riverside expansion, various replacements and expansion of IPL’s and WPL’s natural gas distribution systems, Resources’ electricity output and selling price of such output from its Franklin County wind project, the potential decommissioning of certain EGUs of IPL and WPL, and the anticipated sales of IPL’s electric and gas distribution assets in Minnesota;

•	issues related to the availability and operations of EGUs, including start-up risks, breakdown or failure of equipment, performance below expected or contracted levels of output or efficiency, operator error, transmission constraints, compliance with mandatory reliability standards and risks related to recovery of resulting incremental costs through rates;

•	disruptions in the supply and delivery of coal, natural gas and purchased electricity;

•	changes in the price of delivered coal, natural gas and purchased electricity due to shifts in supply and demand caused by market conditions and regulations, and the ability to recover and to retain the recovery of related changes in purchased power, fuel and fuel-related costs through rates in a timely manner;

•	the impact that price changes may have on IPL’s and WPL’s customers’ demand for electric, gas and steam services and their ability to pay their bills;

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issues associated with environmental remediation and environmental compliance, including compliance with the Consent Decree between WPL, the Sierra Club and the EPA, future changes in environmental laws and regulations, including the EPA’s recently issued proposed regulations for CO2 emissions reductions from new and existing fossil-fueled EGUs and the final CCR rule, and litigation associated with environmental requirements;

•	the ability to defend against environmental claims brought by state and federal agencies, such as the EPA, state natural resources agencies or third parties, such as the Sierra Club, and the impact on operating expenses of defending and resolving such claims;

•	the ability to recover through rates all environmental compliance and remediation costs, including costs for projects put on hold due to uncertainty of future environmental laws and regulations;

•	impacts that storms or natural disasters in IPL’s and WPL’s service territories may have on their operations and recovery of, and rate relief for, costs associated with restoration activities;

•	the direct or indirect effects resulting from terrorist incidents, including physical attacks and cyber attacks, or responses to such incidents;

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•	the impact of penalties or third-party claims related to, or in connection with, a failure to maintain the security of personally identifiable information, including associated costs to notify affected persons and to mitigate their information security concerns;

•	the direct or indirect effects resulting from breakdown or failure of equipment in the operation of natural gas distribution systems, such as leaks, explosions and mechanical problems, and compliance with natural gas distribution safety regulations, such as those that may be issued by the Pipeline and Hazardous Materials Safety Administration;

•	risks associated with deployment and integration of a new customer billing and information system expected in 2015;

•	impacts of IPL’s future tax benefits from Iowa rate-making practices, including deductions for repairs expenditures and allocation of mixed service costs, and recoverability of the associated regulatory assets from customers, when the differences reverse in future periods;

•	any material post-closing adjustments related to any past asset divestitures, including the sale of RMT, which could result from, among other things, warranties, parental guarantees or litigation;

•	continued access to the capital markets on competitive terms and rates, and the actions of credit rating agencies;

•	inflation and interest rates;

•	changes to the creditworthiness of counterparties with which Alliant Energy, IPL and WPL have contractual arrangements, including participants in the energy markets and fuel suppliers and transporters;

•	issues related to electric transmission, including operating in Regional Transmission Organization energy and ancillary services markets, the impacts of potential future billing adjustments and cost allocation changes from Regional Transmission Organizations and recovery of costs incurred;

•	changes made by FERC to ATC’s authorized return on equity;

•	current or future litigation, regulatory investigations, proceedings or inquiries;

•	Alliant Energy’s ability to sustain its dividend payout ratio goal;

•	employee workforce factors, including changes in key executives, collective bargaining agreements and negotiations, work stoppages or restructurings;

•	access to technological developments;

•	changes in technology that alter the channels through which electric customers buy or utilize power;

•	material changes in retirement and benefit plan costs;

•	the impact of performance-based compensation plans accruals;

•	the effect of accounting pronouncements issued periodically by standard-setting bodies, including a new revenue recognition standard, which is currently expected to be adopted in 2017;

•	the impact of changes to production tax credits for wind projects;

•	the impact of adjustments made to deferred tax assets and liabilities from state apportionment assumptions;

•	the ability to utilize tax credits and net operating losses generated to date, and those that may be generated in the future, before they expire;

•	the ability to successfully complete tax audits and changes in tax accounting methods, including changes required by new tangible property regulations with no material impact on earnings and cash flows; and

•	factors listed in MDA and Item 1A Risk Factors.

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(a)	The average cost of natural gas includes commodity and transportation costs as well as realized gains and losses from swap and option contracts used to hedge the price of natural gas volumes expected to be used by IPL’s and WPL’s natural gas-fired EGUs.

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(a)	Cooling degree days are calculated using a simple average of the high and low temperatures each day compared to a 65 degree base. Normal degree days are calculated using a rolling 20-year average of historical cooling degree days. Refer to “Gas Utility Operations” below for details of heating degree days.

(b)	2013 MWhs include replacement energy provided under the Kewaunee PPA after Kewaunee was shut down in May 2013.

(c)	All or some of the renewable energy attributes associated with generation from these sources may be used in future years to comply with renewable energy standards or other regulatory requirements, or sold to third parties in the form of renewable energy credits or other environmental commodities.

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(a)	Cooling degree days are calculated using a simple average of the high and low temperatures each day compared to a 65 degree base. Normal degree days are calculated using a rolling 20-year average of historical cooling degree days. Refer to “Gas Utility Operations” below for details of heating degree days.

(b)	All or some of the renewable energy attributes associated with generation from these sources may be used in future years to comply with renewable energy standards or other regulatory requirements, or sold to third parties in the form of renewable energy credits or other environmental commodities.

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(a)	Cooling degree days are calculated using a simple average of the high and low temperatures each day compared to a 65 degree base. Normal degree days are calculated using a rolling 20-year average of historical cooling degree days. Refer to “Gas Utility Operations” below for details of heating degree days.

(b)	2013 MWhs include replacement energy provided under the Kewaunee PPA after Kewaunee was shut down in May 2013.

(c)	All or some of the renewable energy attributes associated with generation from these sources may be used in future years to comply with renewable energy standards or other regulatory requirements, or sold to third parties in the form of renewable energy credits or other environmental commodities.

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(a)	Heating degree days are calculated using a simple average of the high and low temperatures each day compared to a 65 degree base. Normal degree days are calculated using a rolling 20-year average of historical heating degree days.

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(a)	Heating degree days are calculated using a simple average of the high and low temperatures each day compared to a 65 degree base. Normal degree days are calculated using a rolling 20-year average of historical heating degree days.

(a)	Heating degree days are calculated using a simple average of the high and low temperatures each day compared to a 65 degree base. Normal degree days are calculated using a rolling 20-year average of historical heating degree days.

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(a)	Base load EGUs (BL) are designed for nearly continuous operation at or near full capacity to provide the system base load. Intermediate EGUs (IN) follow system load changes with frequent starts and curtailments of output during low demand. Peak load EGUs (PK) are generally low efficiency, quick response units that run primarily when there is high demand.

(b)	Based on the accredited generating capacity of the EGUs included in MISO’s resource adequacy process for the planning period from June 2014 through May 2015.

(c)	Represents IPL’s 48% ownership interest in this 726 MW (nameplate capacity) / 659 MW (generating capacity) EGU, which is operated by IPL.

(d)	Refer to “Strategic Overview” in MDA for discussion of EGUs that may be retired or changed from coal-fired to an alternative fuel source in the next few years.

(e)	Represents IPL’s 25.695% ownership interest in this 696 MW (nameplate capacity) / 620 MW (generating capacity) EGU, which is operated by MidAmerican Energy Company.

(f)	Represents IPL’s 28% ownership interest in this 584 MW (nameplate capacity) / 479 MW (generating capacity) EGU, which is operated by MidAmerican Energy Company.

(g)	Represents IPL’s 4% ownership interest in this 812 MW (nameplate capacity) / 728 MW (generating capacity) EGU, which is operated by MidAmerican Energy Company.

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(h)	Generating capacity represents 0% of the capacity of this wind project based upon the MISO resource adequacy process, which is determined separately for each wind site, during the planning period from June 2014 through May 2015. The 0% allocation resulted from the lack of firm transmission at this wind site during the planning period from June 2014 through May 2015.

(a)	BL are designed for nearly continuous operation at or near full capacity to provide the system base load. IN follow system load changes with frequent starts and curtailments of output during low demand. PK are generally low efficiency, quick response units that run primarily when there is high demand.

(b)	Based on the accredited generating capacity of the EGUs included in MISO’s resource adequacy process for the planning period from June 2014 through May 2015.

(c)	Represents WPL’s 46.2% ownership interest in this 1,112 MW (nameplate capacity) / 1,070 MW (generating capacity) EGU, which is operated by WPL.

(d)	Represents WPL’s 68.2% ownership interest in this 351 MW (nameplate capacity) / 292 MW (generating capacity) EGU, which is operated by WPL.

(e)	Refer to “Strategic Overview” in MDA for discussion of EGUs that may be retired in the next few years.

(f)	Represents Units 2 and 3, which WPL owns. WPL also operates South Fond du Lac Combustion Turbines Units 1 and 4.

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(g)	Rock River Combustion Turbine Unit 6 was not operating during the testing period for MISO’s resource adequacy process for the planning period from June 2014 through May 2015, resulting in no capacity being accredited to the EGU for that planning period.

(h)	Generating capacity represents 0% of the capacity of this wind project based upon the MISO resource adequacy process, which is determined separately for each wind site, during the planning period from June 2014 through May 2015. The 0% allocation resulted from the lack of firm transmission at this wind site during the planning period from June 2014 through May 2015.

(i)	Generating capacity represents 12% of the capacity of this wind project based upon the MISO resource adequacy process, which is determined separately for each wind site, during the planning period from June 2014 through May 2015.

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(a)	All shares were purchased on the open market and held in a rabbi trust under the DCP. There is no limit on the number of shares of Alliant Energy common stock that may be held under the DCP, which currently does not have an expiration date.

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(a)	Refer to “Alliant Energy’s Results of Operations” in MDA for discussion of the 2014, 2013 and 2012 results of operations.

(b)	Represents the sum of income from continuing operations before income taxes plus interest expense, divided by interest expense.

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(a)	Refer to “IPL’s Results of Operations” in MDA for a discussion of the 2014, 2013 and 2012 results of operations.

(a)	Refer to “WPL’s Results of Operations” in MDA for a discussion of the 2014, 2013 and 2012 results of operations.

•	Executive Summary

•	Strategic Overview

•	Rate Matters

•	Environmental Matters

•	Legislative Matters

•	Alliant Energy’s Results of Operations

•	IPL’s Results of Operations

•	WPL’s Results of Operations

•	Liquidity and Capital Resources

•	Other Matters

•	Market Risk Sensitive Instruments and Positions

•	New Accounting Pronouncements

•	Critical Accounting Policies and Estimates

•	Other Future Considerations

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(a)	In September 2013, IPL signed definitive agreements to sell its Minnesota electric and natural gas distribution assets. Refer to Note 3 for further discussion of these anticipated sales.

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•	$0.70 per share of lower purchased electric capacity expense related to the previous DAEC PPA recorded in 2014 compared to 2013;

•	$0.33 per share of purchased electric capacity expense related to the Kewaunee PPA that expired in 2013;

•	$0.06 per share of lower income tax expense at IPL in 2014 compared to 2013 due to Iowa rate-making practices; and

•	$0.06 per share of charges related to preferred stock redemptions at IPL and WPL in 2013.

•	$0.39 per share of retail electric customer billing credits at IPL in 2014 related to an approved settlement agreement for its Iowa retail electric base rates;

•	$0.11 per share of higher energy efficiency cost recovery amortizations at WPL in 2014 compared to 2013;

•	$0.08 per share of higher generation, distribution and customer service operation and maintenances expenses in 2014 compared to 2013;

•	an estimated $0.08 per share of net decreases in revenues from lower electric and gas sales in 2014 compared to 2013 due to weather conditions;

•	$0.08 per share of higher depreciation expense in 2014 compared to 2013;

•	$0.06 per share of higher interest expense in 2014 compared to 2013;

•	$0.05 per share from changes in the revenue requirement adjustment related to certain IPL tax benefits in 2014 compared to 2013;

•	$0.05 per share of higher electric transmission service expense, net of recoveries, in 2014 compared to 2013; and

•	$0.05 per share of lower electric margins related to changes in the recovery of fuel-related expense at WPL.

•	January 2014 - WPL received an order from the PSCW approving a request for generation maintenance and performance improvements at Columbia Units 1 and 2. WPL expects to begin construction in the first half of 2015 and place the projects in service by the end of 2017.

•	April 2014 - The scrubber and baghouse at WPL’s Columbia Unit 2 were placed in service. In addition, the scrubber and baghouse at WPL’s Columbia Unit 1 were placed in service in July 2014.

•	May 2014 - The scrubber and baghouse at IPL’s George Neal Unit 3 were placed in service.

•	June 2014 - After receiving the final necessary regulatory approvals and permits in the second quarter of 2014, IPL began constructing Marshalltown, an approximate 650 MW natural gas-fired combined-cycle EGU. IPL currently expects to place Marshalltown in service in the second quarter of 2017.

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November 2014 - WPL announced plans to file a CPCN application with the PSCW in early 2015 for approval to construct an approximate 650 MW natural gas-fired combined-cycle EGU in Beloit, Wisconsin, referred to as the Riverside expansion. A decision from the PSCW on WPL’s request is currently expected by mid-2016. Construction of the Riverside expansion is also subject to the receipt of various approvals and permits necessary to construct and operate the EGU. Subject to such approvals, construction is currently expected to begin in 2016 and be completed by early 2019. Capital expenditures are currently estimated to be approximately $725 million to $775 million to construct the EGU and a pipeline to supply natural gas to the EGU. The estimated capital expenditures exclude transmission network upgrades and AFUDC.

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December 2014 - The MPUC issued an order approving the proposed sale of IPL’s Minnesota natural gas distribution assets. IPL currently expects to complete the sale in 2015 pending completion of various other contingencies. Proceeds from the sale of the natural gas distribution assets, which approximate the carrying value of such assets, are expected to be approximately $10 million, subject to customary closing adjustments.

•	December 2014 - The scrubber and baghouse at IPL’s Ottumwa Unit 1 were placed in service.

•	January 2015 - WPL received an order from the PSCW approving WPL’s CA application to install an SCR system at Columbia Unit 2 to reduce NOx emissions at the EGU. WPL’s portion of the capital expenditures for the SCR system, excluding AFUDC, is currently estimated to be between $60 million and $80 million. WPL currently expects to place the project in service in 2018.

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July 2014 - WPL received an order from the PSCW authorizing WPL to maintain retail electric base rates at their current levels through the end of 2016. The retail electric base rate case included a return of and a return on costs for emission controls projects at Columbia Units 1 and 2 and Edgewater Unit 5, generation performance and reliability improvements at Columbia Units 1 and 2, other ongoing capital expenditures, and an increase in electric transmission service expense. The additional revenue requirement for these cost increases was offset by the impact of changes in the amortization of regulatory liabilities associated with energy efficiency cost recoveries and increased sales volumes. The order also authorized WPL to implement a $5 million decrease in annual retail gas base rates effective January 1, 2015 followed by a freeze of such gas base rates through the end of 2016.

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September 2014 - The IUB approved a settlement agreement, which extends IPL’s Iowa retail electric base rates authorized in its 2009 test year case through 2016 and provides retail electric customer billing credits of $105 million in aggregate, including targeting $70 million in 2014 (beginning May 2014), $25 million in 2015 and $10 million in 2016. In 2014, IPL recorded $72 million of such retail electric customer billing credits. IPL will make adjustments to future billing credits to provide retail electric customer billing credits of $105 million in aggregate. The settlement agreement included the continuation of the energy adjustment clause, transmission cost rider and electric tax benefit rider credits; the ability for IPL to seek rate relief if a significant event occurs; and the ability for parties to the DAEC PPA proceeding to request show cause action if IPL’s Iowa retail electric return on common equity exceeds 11% for 2014, 2015 or 2016.

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December 2014 - WPL received an order from the PSCW authorizing an annual retail electric rate increase of $39 million, or approximately 4%, effective January 1, 2015. The increase includes $39 million of anticipated increases in retail electric fuel-related costs in 2015 attributable to $25 million for higher retail electric fuel-related costs per MWh anticipated in 2015 and $14 million from the impact of increased sales volumes approved in the retail electric base rate case for 2015.

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December 2014 - The IUB issued an order authorizing $75 million of regulatory liabilities from tax benefits to be credited to IPL’s retail electric customers’ bills in Iowa during 2015 through the electric tax benefit rider. In December 2014, the IUB also authorized IPL to reduce the $75 million of billing credits on customers’ bills by $15 million in 2015 to recognize the revenue requirement impact of the changes in tax accounting methods.

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June 2014 - The EPA issued proposed standards to reduce CO2 emissions from existing fossil-fueled EGUs. The EPA is proposing a two-part goal structure: an “interim goal” that each state meets an average threshold over the period from 2020 through 2029, and a “final goal” based on a three-year rolling average that each state meets beginning in 2030. State plans that provide details of how these guidelines are to be met would be required by June 30, 2016. The EPA’s proposal allows for a one-year extension to submit state-only plans and a two-year extension if a state elects to join a regional multi-state program. In August 2014, the EPA’s legal authority to issue the proposed standards was challenged. The EPA is currently expected to issue final standards in 2015.

•	August 2014 - The EPA published a final rule related to Section 316(b) of the Federal Clean Water Act rule to regulate cooling water intake structures and minimize adverse environmental impacts to fish and other aquatic life. Compliance with this final rule will be incorporated during periodic facility permit renewal cycles, with final compliance anticipated by 2022.

•	December 2014 - The EPA issued the final CCR rule, which regulates CCR as a non-hazardous waste. The final rule establishes minimum criteria for disposing of CCR in landfills and surface impoundments (ash ponds), and allows for continued operation of ash ponds if they meet certain location and performance criteria. The rule is currently anticipated to become effective in 2015.

•	January 2015 - CSAPR replaced CAIR. Compliance with CSAPR emissions limits began in 2015, with additional emissions limits reductions beginning in 2017.

•	December 2014 - The FTIP Act was enacted. The most significant provisions of the FTIP Act for Alliant Energy, IPL and WPL relate to the extension of bonus depreciation deductions for certain expenditures for property that were incurred through December 31, 2014.

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•	March 2014 - IPL extended through March 2016 the purchase commitment from the third party to which it sells its receivables.

•	October 2014 - WPL issued $250 million of 4.1% debentures due 2044. The proceeds from the issuance were used by WPL to reduce commercial paper and for general corporate purposes.

•	October 2014 - Alliant Energy entered into a $250 million variable-rate term loan credit agreement and used the proceeds from borrowings under this agreement to retire its $250 million, 4% senior notes. The term loan credit agreement expires in October 2016.

•	November 2014 - IPL issued $250 million of 3.25% senior debentures due 2024. The proceeds from the issuance were used by IPL to reduce cash proceeds received from its sales of accounts receivable program, reduce commercial paper classified as long-term debt by $60 million and for general corporate purposes.

•	November 2014 - WPL received authorization from the PSCW to issue up to $500 million of long-term debt securities during 2015 and 2016, with no more than $300 million to be issued in either year.

•	November 2014 - Alliant Energy, IPL and WPL announced their future financing plans. IPL currently expects to issue up to $300 million of additional long-term debt in 2015. IPL’s $150 million, 3.3% senior debentures mature in 2015. Alliant Energy currently expects to issue approximately $150 million of common stock in 2015 through one or more offerings and its Shareowner Direct Plan.

•	November 2014 - Alliant Energy announced an increase in its targeted 2015 annual common stock dividend to $2.20 per share, which is equivalent to a quarterly rate of $0.55 per share, beginning with the February 2015 dividend payment.

•	December 2014 - Franklin County Holdings LLC, Resources’ wholly-owned subsidiary, entered into a $60 million variable-rate term loan credit agreement and used the proceeds to retire its borrowings under a term loan credit agreement that matured in December 2014. The latest term loan credit agreement expires December 2016.

•	December 2014 - At December 31, 2014, Alliant Energy and its subsidiaries had $859 million of available capacity under the revolving credit facilities, $128 million of available capacity at IPL under its sales of accounts receivable program and $57 million of cash and cash equivalents.

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October 2014 - FERC issued an order on a complaint against the MISO transmission owners. The order established hearing and settlement procedures on the return on equity component of the complaint, and established a refund period back to November 12, 2013. FERC also denied a request to limit the regulatory capital structure to 50% of common equity, among other items. Settlement discussions between the parties were held and no agreement was reached. The complaint is now subject to hearing procedures and an initial decision from FERC on the complaint is currently expected in late 2015. Alliant Energy, IPL and WPL are currently unable to determine what, if any, impact the October 2014 FERC order, subsequent hearing procedures and a new methodology FERC established for determining the return on equity may have on the returns authorized by FERC for MISO transmission owners, including ITC and ATC.

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January 2015 - FERC issued an order accepting a request from a group of MISO transmission owners, including ITC and ATC, to implement a 50 basis point incentive adder to their return on equity based on participation in MISO. The implementation of the adder is effective January 2015, subject to certain conditions. Alliant Energy, IPL and WPL are currently unable to determine any resulting changes to future electric transmission service charges.

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Natural gas - purchasing, constructing and/or converting to natural gas-fired EGUs. IPL is currently constructing Marshalltown, an approximate 650 MW natural gas-fired combined cycle EGU, and M.L. Kapp Unit 2 is expected to switch from coal to natural gas as its only fuel type in 2015. WPL currently plans to file a CPCN application with the PSCW in early 2015 for approval to construct an approximate 650 MW natural gas-fired combined cycle EGU referred to as the Riverside expansion.

•	Coal - implementing emission controls and generation performance and reliability improvements at newer, larger and more efficient coal-fired EGUs, and fuel switching at, and retirement of, certain older, smaller and less efficient coal-fired EGUs.

•	PPAs - purchasing electricity to meet a portion of customer demand for electricity, including wind power PPAs and a nuclear generation PPA related to DAEC for a term of February 22, 2014 through December 31, 2025.

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Renewables - operating hydroelectric generators and current wind projects, as well as evaluating the development of future wind sites and solar projects. IPL and WPL currently have up to 400 MW and 200 MW of undeveloped wind sites, respectively, available for future wind projects. Alliant Energy, IPL and WPL are also exploring opportunities to integrate solar projects into the portfolio of energy resources as the cost to produce solar energy continues to decline.

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•	A cost cap of $920 million, including costs to construct Marshalltown, a pipeline to supply natural gas to Marshalltown and transmission network upgrades to transmit electricity from Marshalltown, as well as AFUDC. Any costs incurred in excess of the cost cap are expected to be incorporated into rates if determined to be reasonable and prudent.

•	An 11% return on common equity for the 35-year depreciable life of Marshalltown and a 10.3% return on common equity for the calculation of AFUDC related to the construction of Marshalltown.

•	The application of double leverage is deferred until IPL’s next retail electric base rate case or other proceeding.

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(a)	Nameplate capacity represents the nominal amount of electricity an EGU is designed to produce. Each EGU is also assessed a generating capacity amount from MISO through its annual resource adequacy process. The generating capacity amount assessed by MISO is subject to change each year and is based upon the current performance capability of the EGU and is based on historical forced outages.

(b)	As of December 31, 2014, the aggregate net book value of EGUs that may be retired in the future in the table above was $57 million for IPL and $88 million for WPL.

(c)

IPL received approval from MISO to retire Dubuque Units 3 and 4, contingent on completion of transmission network upgrades necessary for system reliability. Final MISO studies could indicate that the retirement of Fox Lake Unit 3 may result in reliability issues and that transmission network upgrades for system reliability are necessary to enable such retirements. Under the current MISO tariff, the specific timing for the retirement of these EGUs could depend on the timing of the required transmission network upgrades as well as various operational, market and other factors.

(d)	The retirements of Fox Lake Unit 3, Sutherland Units 1 and 3, and other units are contingent on the construction of Marshalltown as well as various operational, market and other factors.

(e)	WPL received approval from MISO to retire Edgewater Unit 3, and Nelson Dewey Units 1 and 2, contingent on completion of transmission network upgrades necessary for system reliability.

(f)	Reflects WPL’s 68.2% ownership interest in Edgewater Unit 4.

(g)	The retirements of Edgewater Unit 4 and the Rock River and Sheepskin Combustion Turbine Units are contingent on the construction of the Riverside expansion as well as various operational, market and other factors.

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(a)	Scrubber is a post-combustion process that injects lime or lime slurry into the stream of gases leaving the EGU boiler to remove SO2 and other acid gases (including hydrochloric acid) and capture them in a solid or liquid waste by-product. A scrubber typically removes more than 90% of the SO2 emissions.

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(a)

In Iowa, IPL’s interim rates can be implemented 10 days after the filing date, without regulatory review and are subject to refund, pending determination of final rates. In Minnesota, IPL’s interim rates can be implemented 60 days after the filing date, with regulatory review and are subject to refund, pending determination of final rates. The amount of the interim rates is replaced by the amount of final rates once the final rates are effective.

(b)	Base rate changes reflect both returns on additions to infrastructure and recovery of changes in costs incurred or expected to be incurred. Given that a portion of the rate changes will offset changes in costs, revenues from rate changes should not be expected to result in an equal change in net income for either IPL or WPL.

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(a)	Authorized returns on common equity may not be indicative of actual returns earned or projections of future returns.

(b)	Authorized returns on common equity and after-tax WACC reflect application of double leverage pursuant to a January 2011 IUB order. Prior to the application of double leverage, authorized returns on common equity were: Emery-12.23%, Whispering Willow-East-11.7% and Other-10.0%, and after-tax WACC were: Emery-9.16%, Whispering Willow-East-8.91% and Other-8.09%.

(c)	Average rate base is calculated using a 13-month average adjusted for post-test year capital additions placed in service by September 30 following the end of the test year.

(d)	Authorized returns on common equity and after-tax WACC reflect application of double leverage pursuant to the unanimous settlement agreement approved in the IUB’s November 2012 order. Prior to the application of double leverage, authorized return on common equity was 10.0% and after-tax WACC was 8.0%.

(e)	Average rate base amounts do not include Whispering Willow - East capital costs, which are currently being recovered through a temporary renewable energy rider approved by the MPUC. Refer to Note 3 for details of the final recovery amount of the Whispering Willow - East capital costs.

(f)	Average rate base is calculated using a 13-month average adjusted for certain post-test year capital additions.

(g)	IPL’s wholesale formula rates reflect annual changes in CE, PE, LD, WACC and rate base.

(h)	IPL’s wholesale average rate base reflects production-related rate base calculated as the simple average of the beginning of year and end of year balances in accordance with IPL’s approved formula rates.

(i)	Average rate base amounts do not include CWIP or a cash working capital allowance and are calculated using a 13-month average. The PSCW provides a return on selected CWIP and a cash working capital allowance by adjusting the percentage return on rate base.

(j)	WPL’s wholesale formula rates reflect annual changes in WACC and rate base.

(k)	WPL’s wholesale average rate base reflects production-related rate base calculated as the simple average of the beginning of year and end of year balances in accordance with WPL’s approved formula rates.

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(a)	An additional year for compliance can be requested, which may be granted on a case-by-case basis by state permitting authorities or the EPA.

(a)	M.L. Kapp Unit 2 is expected to switch from coal to natural gas as the only fuel type in 2015, contingent on approval from MISO.

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(a)	CO2e emissions reported to the EPA represent all emissions from the facilities operated by IPL and WPL and do not reflect their share of co-owned facilities operated by other companies.

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(a)	Reflects the % change from 2013 to 2014. (b) Reflects the % change from 2012 to 2013.

(c)	Includes $85 million, $79 million and $83 million of credits on IPL’s Iowa retail electric customers’ bills for 2014, 2013 and 2012, respectively, resulting from the electric tax benefit rider. The electric tax benefit rider resulted in reductions in electric revenues that were offset by reductions in income tax expense for 2014, 2013 and 2012.

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(a)	Higher transmission rider revenues were offset by higher electric transmission service expense.

(b)	Billing credits began in May 2014 related to the approved settlement agreement for IPL’s Iowa retail electric rates. Refer to “Rate Matters - IPL’s Iowa Retail Electric Rate Settlement Agreement” for further discussion.

(c)	Primarily due to lower nuclear capacity costs in 2014 which are included in the rates charged to wholesale customers.

(d)	Refer to Note 2 for further discussion of IPL’s revenue requirement adjustment and electric tax benefit rider.

(e)	Includes increases in weather-normalized retail sales volumes at WPL in 2014 and 2013. Refer to “Sales Trends” below for more information.

(a)	HDD and CDD are calculated using a simple average of the high and low temperatures each day compared to a 65 degree base. Normal degree days are calculated using a rolling 20-year average of historical HDD and CDD.

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(a)	Reflects the % change from 2013 to 2014. (b) Reflects the % change from 2012 to 2013.

(c)	Includes $12 million and $11 million of credits on IPL’s Iowa retail gas customers’ bills for 2014 and 2013, respectively, resulting from the gas tax benefit rider. The gas tax benefit rider resulted in reductions in gas revenues that were offset by reductions in income tax expense for 2014 and 2013.

(a)	Changes in energy efficiency revenues were mostly offset by changes in energy efficiency expense included in other operation and maintenance expenses.

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(a)	Changes in utility other revenues related to coal sales were largely offset by changes in utility other operation and maintenance expenses related to coal sales.

(b)

Approximately 50% of all margins earned from IPL’s sharing mechanism relating to optimizing gas capacity contracts flow through the purchased gas adjustment clause to reduce retail gas customer bills in Iowa. The remaining margins are retained by IPL and recorded in utility other revenues. Due to the extreme cold temperatures causing natural gas price fluctuations in the first quarter of 2014, margins were higher than normal in 2014.

(c)	WPL recognized capacity revenues in 2014 and 2013 related to a PPA with a third party for the sale of a portion of Riverside’s capacity assumed by WPL with the acquisition of Riverside in December 2012. The PPA expired in May 2014. These capacity revenues were mostly offset by contract amortization expense included in utility other operation and maintenance expenses.

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(a)	Primarily due to increased electric transmission service rates.

(b)

IPL is currently recovering the Iowa retail portion of its increased electric transmission service costs from its retail electric customers in Iowa through a transmission cost rider approved by the IUB in January 2011 and extended as part of the rate settlement approved in September 2014. The difference between electric transmission services expense and amounts collected from customers as electric revenues results in temporary costs (credits) recorded in electric transmission service expense until the amounts are reflected in future customer billings.

(a)	The July 2012 PSCW order for WPL’s 2013/2014 test period electric and gas base rate case authorized changes in energy efficiency cost recovery amortizations for 2013 and 2014. Regulatory amortizations at WPL related to energy efficiency costs were $42 million, $22 million and $42 million in 2014, 2013 and 2012, respectively.

(b)	Refer to Note 3 for details of a regulatory-related credit recorded by IPL in 2013 due to decisions by the MPUC regarding recovery of costs for IPL’s Whispering Willow - East wind project.

(c)	Primarily due to the timing and extent of maintenance projects at IPL’s and WPL’s EGUs. The increase in 2013 was also due to additional operation and maintenance expenses related to Riverside, which was acquired in December 2012.

(d)	Primarily due to increased customer billing and customer assistance-related expenses.

(e)	Primarily due to a decrease in retirement plan costs, partially offset by an increase in other employee benefits-related costs and the reversal of a previously recorded reserve related to the Cash Balance Plan in 2013. Refer to Note 12(a) for details of the Cash Balance Plan reserve.

(f)	Changes in expense related to coal sales at WPL were largely offset by changes in coal sales revenue at WPL.

(g)	Primarily due to increases in other administrative and general and distribution system expenses.

(h)	Performance-based compensation expense is largely based on the achievement of specific operational and financial performance measures compared to targets established within the performance-based compensation plans.

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(i)	Primarily due to increased maintenance of the electric and gas distribution systems at IPL and WPL.

(j)	Higher bad debt expense at IPL in 2013 was largely due to increases in past due accounts receivable during 2013.

(k)	Refer to Notes 2 and 3 for details of regulatory-related charges and credits recognized in 2012.

(l)	Corporate Services bills IPL and WPL cost of capital charges in accordance with a service agreement. The 2013 increase was primarily due to increased property additions at Corporate Services in 2013.

(m)	Resulting from the amortization of capacity rights related to a PPA with a third party for the sale of a portion of Riverside’s capacity WPL assumed with the acquisition of Riverside. The PPA expired in May 2014. These amortization expenses were largely offset by capacity revenues included in utility other revenues.

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(a)	Reflects the % change from 2013 to 2014. (b) Reflects the % change from 2012 to 2013.

(c)	Includes $85 million, $79 million and $83 million of credits on Iowa retail electric customers’ bills for 2014, 2013 and 2012, respectively, resulting from the electric tax benefit rider. The electric tax benefit rider resulted in reductions in electric revenues that were offset by reductions in income tax expense for 2014, 2013 and 2012.

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(a)	Reflects the % change from 2013 to 2014. (b) Reflects the % change from 2012 to 2013.

(c)	Includes $12 million and $11 million of credits on Iowa retail gas customers’ bills for 2014 and 2013, respectively, resulting from the gas tax benefit rider. The gas tax benefit rider resulted in reductions in gas revenues that were offset by reductions in income tax expense for 2014 and 2013.

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(a)	Reflects the % change from 2013 to 2014. (b) Reflects the % change from 2012 to 2013.

(a)	Reflects the % change from 2013 to 2014. (b) Reflects the % change from 2012 to 2013.

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(a)	Cost estimates represent IPL’s or WPL’s estimated portion of total escalated construction expenditures and exclude AFUDC, if applicable. Refer to “Strategic Overview” for further discussion of key projects impacting construction and acquisition plans related to the utility business.

(b)	Cost estimates represent total escalated construction and acquisition expenditures and exclude capitalized interest.

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•	Long-term Debt - IPL currently expects to issue up to $300 million of additional long-term debt in 2015. IPL’s $150 million, 3.3% senior debentures mature in 2015.

•	Common Stock Issuances and Capital Contributions - Alliant Energy currently expects to issue approximately $150 million of common stock in 2015 through one or more offerings and its Shareowner Direct Plan. IPL currently expects to receive capital contributions of $175 million from its parent company in 2015.

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Common Stock Dividends - In November 2014, Alliant Energy announced an increase in its targeted 2015 annual common stock dividend to $2.20 per share, which is equivalent to a quarterly rate of $0.55 per share, beginning with the February 2015 dividend payment. The timing and amount of future dividends is subject to an approved dividend declaration from its Board of Directors, and is dependent upon earnings expectations, capital requirements, and general financial business conditions, among other factors. In addition, IPL and WPL currently expect to pay common stock dividends of approximately $140 million and $127 million, respectively, to their parent company in 2015.

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(a)

Purchased power and fuel commitments represent normal business contracts used to ensure adequate purchased power, coal and natural gas supplies, and to minimize exposure to market price fluctuations. Alliant Energy, through its subsidiary Corporate Services, entered into system-wide coal contracts on behalf of IPL and WPL that include minimum future commitments. These commitments were assigned to IPL and WPL based on information available as of December 31, 2014 regarding expected future usage, which is subject to change.

(b)	Other operating expense purchase obligations represent individual commitments incurred during the normal course of business that exceeded $1 million at December 31, 2014.

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(a)	In 2012, the PSCW issued an order approving the implementation of updated depreciation rates for WPL effective January 1, 2013 as a result of a recently completed depreciation study. In 2013, the PSCW and FERC issued orders approving WPL’s requests to revise depreciation rates associated with the acquisition of Riverside effective January 1, 2013.

(a)	In 2013, the IUB issued an order establishing rate-making principles for Marshalltown that requires a 10.3% return on common equity for the calculation of AFUDC related to the construction of such facility.

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(a)	Includes various emission controls projects placed in service in 2014, which are discussed in “Emission Controls Projects” below.

(b)

In 2013, WPL received approval from MISO to retire Edgewater Unit 3, and Nelson Dewey Units 1 and 2. WPL currently anticipates retiring these EGUs by December 31, 2015, contingent on completion of transmission network upgrades needed for system reliability. WPL is recovering the remaining net book value of these EGUs over a 10-year period beginning January 1, 2013 pursuant to a May 2012 PSCW order.

(c)	Less accumulated amortization of $59.1 million and $52.9 million for WPL as of December 31, 2014 and 2013, respectively.

(d)	Less accumulated depreciation of $49.5 million and $40.0 million for Alliant Energy as of December 31, 2014 and 2013, respectively.

(e)	Less accumulated depreciation of $229.1 million and $214.2 million for Alliant Energy as of December 31, 2014 and 2013, respectively.

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(a)	Changes in cash proceeds are presented in “Sales of accounts receivable” in operating activities in Alliant Energy’s and IPL’s cash flows statements.

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(a)	Alliant Energy and WPL have the ability to exercise significant influence over ATC’s financial and operating policies through their participation on ATC’s Board of Directors. Refer to Note 18 for information regarding related party transactions with ATC.

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(a)	In 2014, IPL issued $250.0 million of 3.25% senior debentures due 2024. The proceeds from the issuance were used by IPL to reduce cash proceeds received from its sales of accounts receivable program, reduce commercial paper classified as long-term debt by $60 million and for general corporate purposes.

(b)	In 2014, WPL issued $250.0 million of 4.1% debentures due 2044. The proceeds from the issuance were used by WPL to reduce commercial paper and for general corporate purposes.

(c)	In 2014, WPL retired $8.5 million of its 5% pollution control revenue bonds.

(d)	In 2014, IPL retired its $38.4 million, 5% pollution control revenue bonds.

(e)	In 2014, Alliant Energy entered into a $250.0 million variable-rate term loan credit agreement and used the proceeds from borrowings under this agreement to retire its $250.0 million, 4% senior notes due 2014.

(f)	In 2014, Franklin County Holdings LLC, Resources’ wholly-owned subsidiary, entered into a $60.0 million variable-rate term loan credit agreement and used the proceeds to retire its borrowings under a term loan credit agreement that matured in December 2014.

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(a)	At December 31, 2014, Alliant Energy’s state net operating losses carryforwards had expiration dates ranging from 2018 to 2033 with 98% expiring after 2024.

(b)	At December 31, 2014, IPL’s state net operating losses carryforwards had expiration dates ranging from 2018 to 2031 with 96% expiring after 2024.

(c)	At December 31, 2014, WPL’s state net operating losses carryforwards had expiration dates ranging from 2018 to 2031 with 99% expiring after 2024.

(a)	In 2012, the reductions for tax positions of prior years were due to the finalization of Alliant Energy’s federal income tax return audits for calendar years 2005 through 2009.

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(a)	These federal tax returns are effectively settled as a result of participation in the IRS Compliance Assurance Program, which allows Alliant Energy and the IRS to work together to resolve issues related to Alliant Energy’s current tax year before filing its federal income tax return. The statute of limitations for these federal tax returns expires three years from each filing date.

(b)	The statute of limitations for these Iowa tax returns expires three years from each filing date.

(c)	The statute of limitations for these Wisconsin combined tax returns expires four years from each filing date.

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(a)	The expected return on plan assets is based on the expected rate of return on plan assets and the fair value approach to the market-related value of plan assets.

(b)	Unrecognized prior service costs (credits) for the OPEB plans are amortized over the average future service period to full eligibility of the participants of each plan.

(c)	Unrecognized net actuarial gains or losses in excess of 10% of the greater of the plans’ benefit obligations or assets are amortized over the average future service lives of plan participants, except for the Cash Balance Plan where gains or losses outside the 10% threshold are amortized over the time period the participants are expected to receive benefits.

(d)

In 2013, Alliant Energy filed a stipulation agreement with the Court related to the class-action lawsuit against the Cash Balance Plan. As a result, Alliant Energy recognized $9.0 million of additional benefits costs in 2013 related to the agreement. IPL recognized $5.5 million ($2.6 million directly assigned and $2.9 million allocated by Corporate Services) and WPL recognized $2.8 million ($0.6 million directly assigned and $2.2 million allocated by Corporate Services) of additional benefits costs in 2013 related to the agreement.

(e)	Settlement losses related to payments made to retired executives of Alliant Energy.

(a)	Refer to IPL’s and WPL’s “Net Periodic Benefit Costs (Credits)” tables above for additional benefits costs related to the Cash Balance Plan allocated to IPL and WPL by Corporate Services in 2013.

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(a)	Refer to Note 2 and Alliant Energy’s common equity statements for amounts recognized in “Regulatory assets” and “AOCL,” respectively, on Alliant Energy’s balance sheets. At December 31, 2014 and 2013, $1.1 million and $5.1 million, respectively, of regulatory liabilities were recognized related to Alliant Energy’s OPEB plans.

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(a)	Refer to Note 2 for amounts recognized in “Regulatory assets” on IPL’s balance sheets. At December 31, 2014 and 2013, $0 and $1.0 million, respectively, of regulatory liabilities were recognized related to IPL’s OPEB plans.

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(a)	Refer to Note 2 for amounts recognized in “Regulatory assets” on WPL’s balance sheets. At December 31, 2014 and 2013, $1.1 million and $1.1 million, respectively, of regulatory liabilities were recognized related to WPL’s OPEB plans.

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(a)

Alliant Energy sponsors several non-qualified defined benefit pension plans that cover certain current and former key employees of IPL and WPL. Alliant Energy allocates pension costs to IPL and WPL for these plans. In addition, IPL and WPL amounts reflect funding for their non-bargaining employees who are participants in the Alliant Energy and Corporate Services sponsored qualified and non-qualified defined benefit pension plans.

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(a)	IPL’s and WPL’s amounts include allocated costs associated with Corporate Services employees.

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(a)	Share amounts represent the target number of performance shares. Each performance share’s value is based on the closing market price of one share of Alliant Energy’s common stock at the end of the performance period. The actual number of shares that will be paid out upon vesting is dependent upon actual performance and may range from zero to 200% of the target number of shares.

(b)	Forfeitures were primarily caused by retirements and voluntary terminations of participants.

(a)	Unit amounts represent the target number of performance units. Each performance unit’s value is based on the average price of one share of Alliant Energy’s common stock on the grant date of the award. The actual payout for performance units is dependent upon actual performance and may range from zero to 200% of the target number of units.

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(a)	In 2014, 45,612 and 45,235 performance contingent restricted shares granted in 2012 and 2011, respectively, vested because the specified performance criteria for such shares were met. In 2012, 65,172 performance-contingent restricted shares granted in 2010 vested because the specified performance criteria for such shares were met.

(b)	In 2013 and 2012, 101,822 and 65,516 performance-contingent restricted shares granted in 2009 and 2008, respectively, were forfeited because the specified performance criteria for such shares were not met. The remaining forfeitures during 2014 and 2012 were primarily caused by retirements and terminations of participants.

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(a)	In 2014, 34,766 and 20,751 performance contingent cash awards granted in 2012 and 2011 vested, resulting in cash payouts valued at $1.9 million and $1.1 million, respectively. In 2012, 21,605 performance contingent cash awards granted in 2010 vested, resulting in cash payouts valued at $0.9 million.

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(a)	Markets for similar assets and liabilities became inactive and observable market inputs became unavailable for transfers into Level 3. The transfers were valued as of the beginning of the period.

(b)	Observable market inputs became available for certain commodity contracts previously classified as Level 3 for transfers out of Level 3. The transfers were valued as of the beginning of the period.

(c)	Settlements related to deferred proceeds are due to the change in the carrying amount of receivables sold less the allowance for doubtful accounts associated with the receivables sold and cash proceeds received from the receivables sold.

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(a)	Includes payments required by PPAs for capacity rights and minimum quantities of MWhs required to be purchased. Refer to Note 18 for additional information on purchased power transactions.

(b)	Includes commitments incurred under a PPA, which grants IPL rights to purchase up to 431 MWs of capacity and the resulting energy from DAEC for a term through December 31, 2025. If energy delivered is less than the targeted energy amount, an adjustment payment will be made to IPL, which will be reflected in IPL’s fuel adjustment clause.

(c)	Corporate Services entered into system-wide coal contracts on behalf of IPL and WPL that include minimum future commitments. These commitments were assigned to IPL and WPL based on information available as of December 31, 2014 regarding expected future usage, which is subject to change.

(d)	Refer to Note 2 for discussion of $34 million of charges recognized by Alliant Energy and IPL in 2011 for forward contracts to purchase SO2 emission allowances.

(e)	Includes individual commitments incurred during the normal course of business that exceeded $1 million at December 31, 2014.

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•	SCR system at Edgewater Unit 5 by May 1, 2013 (placed in service in 2012);

•	Scrubbers and baghouses at Columbia Units 1 and 2 by December 31, 2014 (placed in service in 2014);

•	Scrubber and baghouse at Edgewater Unit 5 by December 31, 2016; and

•	SCR system at Columbia Unit 2 by December 31, 2018.

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•

Utility - includes the operations of IPL and WPL, which serve customers in Iowa, Wisconsin and Minnesota. The utility business has three reportable segments: a) utility electric operations; b) utility gas operations; and c) utility other, which includes steam operations and the unallocated portions of the utility business. Various line items in the following tables are not allocated to the electric and gas segments for management reporting purposes, and therefore, are included only in “Total Utility.”

•	Non-regulated, Parent and Other - includes the operations of Resources and its subsidiaries, Corporate Services, the Alliant Energy parent company, and any Alliant Energy parent company consolidating adjustments. Resources’ businesses include Transportation, Non-regulated Generation and other non-regulated investments described in Note 1(a).

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(a)

Represents performance shares granted under the OIP. The performance shares may be paid out in shares of Alliant Energy’s common stock, cash, or a combination of cash and stock and are adjusted by a performance multiplier, which ranges from zero to 200%, based on the performance criteria. The performance shares included in column (A) of the table reflect an assumed payout in the form of Alliant Energy’s common stock at the maximum performance multiplier of 200% for the 2014 and 2013 grants and at the actual performance multiplier of 168% for the 2012 grants.

(b)

All of the available shares under the OIP may be issued as awards in the form of restricted stock, restricted stock units, performance shares, performance units and other stock-based awards. As of December 31, 2014, there were performance shares and restricted stock awards outstanding under the OIP. Excludes 98,812 shares of non-vested restricted common stock previously issued and outstanding under the OIP at December 31, 2014.

(c)	As of December 31, 2014, there were 238,935 shares of Alliant Energy’s common stock outstanding under the DCP, which is described in Note 12(c).

(d)	There is no limit on the number of shares of Alliant Energy’s common stock that may be held under the DCP.

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(1)	Consolidated Financial Statements - Refer to Item 8 Financial Statements and Supplementary Data.

(2)	Financial Statement Schedules -

(3)	Exhibits Required by SEC Regulation S-K - Exhibits for Alliant Energy, IPL and WPL are listed in the Exhibit Index, which is incorporated herein by reference.

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(a)	Accumulated provision for uncollectible accounts: In accordance with its regulatory treatment, certain amounts provided by WPL are recorded in regulatory assets.

(b)	Deductions are of the nature for which the reserves were created. In the case of the accumulated provision for uncollectible accounts, deductions from this reserve are reduced by recoveries of amounts previously written off.

(c)	Refer to Note 5(b) for discussion of IPL’s sales of accounts receivable program.

(d)	Other reserves are largely related to injury and damage claims arising in the ordinary course of business.

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