Wells Fargo Pipeline, MLP and Utility Symposium December 7, 2016

Transcription

1 Wells Fargo Pipeline, MLP and Utility Symposium December 7, 2016

2 Safe Harbor This presentation contains statements that may be considered forward looking statements, such as management s expectations of financial objectives and projections, capital expenditures, earnings growth, electric and gas margins, return on equity, rate base, allowance for funds used during construction rates, emissions, plant retirements, rate base, construction work in progress, electric sales, and new generation plans. These statements speak of the Company s plans, goals, beliefs, or expectations, refer to estimates or use similar terms. Actual results could differ materially, because the realization of those results is subject to many uncertainties including regulatory approvals and results, unanticipated construction costs or delays, economic conditions in our service territories, and other factors, some of which are discussed in more detail in the Company s Form 10-K for the year ended December 31, 2015 and 10-Q for the quarter ended September 30, All forward looking statements included in this presentation are based upon information presently available and the Company assumes no obligation to update any forward looking statements. 2

3 Investment Considerations Future strategic investments focused on renewable and gas generation, as well as electric and gas distribution investments Attractive total return Projected earnings growth rate of 5 7% using 2015 temperature normalized non GAAP base of $1.79 per share post split Target dividend payout of 60 70% of consolidated earnings. Currently forecasting a dividend of $1.26 per share for 2017, a 7% increase over 2016 Supportive regulatory environments Strong balance sheet and liquidity 3

4 Regulated Utility Profile 2015 data IPL WPL Total Electric Customers 489, , ,978 Electric Sales (GWh) 15,914 14,437 30,351 Summer Peak Demand (MW) 3,005 2,564 Iowa IPL Wisconsin WPL WISCONSIN WPL Gas Customers 225, , ,032 Gas Sales (000 s Dths) 61,006 61, ,797 Operating Revenues (millions) $1,775 $1,435 $3,210 Service Territory Advantages Favorable commission rankings Economic diversity High quality renewable resources Access to ANR, Northern Border, and Northern Natural Gas pipelines Access to Powder River Basin coal 4

5 Transitioning our Energy Resources Data as of August 2016 Sustainability Report 5

6 Reducing our Environmental Impact Data as of August 2016 Sustainability Report 6

7 10 Years Estimated Capital Expenditures $6.6 billion $4.7 billion Renewable Projects Gas Distribution Other Renewable Projects Other New Gas Generation New Gas Generation Gas Distribution Other Generation Electric Distribution Other Generation Electric Distribution 7

8 Capital Expenditures Drive Rate Base Growth (excluding AFUDC) $6.6 billion over 5 years in millions $1,600 $1,400 $1,200 $1,000 $800 $600 $400 $200 $0 $1,380 $1,415 $1,280 $1,285 $1, Other $105 $155 $120 $100 $100 Renewable Projects $100 $140 $345 $340 $325 Riverside Energy Center Expansion $75 $295 $180 $85 $5 Marshalltown Generating Station $185 $20 $0 $0 $0 Other Generation $270 $235 $185 $180 $160 Gas Distribution $170 $110 $145 $100 $220 Electric Distribution $305 $425 $440 $475 $475 Depreciation $410 $450 $495 $530 $575 8

9 Iowa Wind Expansion Approved Expect to place approximately 250 MW in service in 2019 and 250 MW in service in 2020 Advanced Ratemaking Principles approved by the IUB: The ratemaking principles apply to any new wind facility constructed as part of IPL s New Wind Project that qualifies for 100% of the federal Production Tax Credits, regardless of its location in Iowa, up to 500 megawatts. Cost cap: $1,830/kilowatt, including allowance for funds used during construction (AFUDC) and transmission costs Return on common equity: 11.0%, with the exception of certain transmission facilities classified as intangible assets, which shall earn the rate of return on equity authorized by the Iowa Utilities Board in a future rate case Return on common equity used in calculating the AFUDC rate to be the higher of the outcome of the next rate case or 10.0% Depreciable life of 40 years, unless changed as a result of a contested case before the Iowa Utilities Board Alliant Energy s Iowa customers shall be entitled to the full value of any environmental attributes, beyond those needed for compliance with applicable regulatory requirements, associated with investment included in IPL's Iowa jurisdictional rate base Alliant Energy is permitted to include in Iowa rates the actual cost of the wind project up to the cost cap without need to establish prudence, but required to establish the prudence of any cost in excess of the cost cap Cancellation costs: recovery of prudently incurred and unreimbursed costs, if applicable, amortized over 10 years Docket RPU

10 Renewable Energy Projects: Owned Wind MW of Owned Wind Resources Cedar Ridge 68 MW Whispering Willow-East 200 MW Bent Tree 200 MW Iowa Wind Expansion Up to 500 MW In Service In Service In Service Approved In Service WPL IPL Non regulated Franklin County 100 MW Owned Wind Currently In Service 568 MW of high capacity factor sites IPL 200 MW Whispering Willow In service in 2009, $350 million WPL 200 MW Bent Tree In service 2010, $402 million WPL 68 MW Cedar Ridge In-service in 2008, $122 million Resources 100 MW Franklin County In-service in 2012, $130 million Q asset valuation charge of $86 million reduced value to $33 million FERC filing to transfer to IPL in Q Note: All book values above are as of December 31, 2015 and include AFUDC or capitalized interest. Approved Wind Projects IPL 500 MW Wind Expansion Approved by IUB October 2016 Owned Wind Sites - Not Yet Developed Whispering Willow (Franklin County IA) Up to 400 MW of available sites Bent Tree (Freeborn County MN) Up to 120 MW of available sites 10

11 Gas Generation Investments Drive Growth IPL s Marshalltown Generating Station WPL s Riverside Expansion Need resulting from retirements and modest load growth An approximate 650 MW combined cycle naturalgas facility Cost cap $920 million, including the facility, pipeline, transmission costs, owners costs and AFUDC Approved by the Iowa Utilities Board (IUB) November 2013 KBR selected as engineering, procurement and construction contractor Siemens SGT6-5000F5ee combustion turbines Contractual guarantee heat rate ~6,650 BTU/kWhr In-service by second quarter 2017 Need resulting from long term energy and capacity due to planned coal and gas retirements An approximate 700 MW combined-cycle natural gas facility Estimated cost $700 million for facility, excluding transmission costs and AFUDC Approved by Public Service Commission of Wisconsin (PSCW) May 2016 AECOM selected as engineering, procurement and construction contractor GE Frame 7FA.05 combustion turbines In-service by early

12 Riverside Expansion Option Agreements WPL will provide book-value purchase options for partial ownership of the facility. Utilities and electric cooperatives Purchase option amount Option timing (a) Adams Columbia Electric Cooperative (ACEC) Rock Energy Cooperative (REC) Central Wisconsin Electric Cooperative (CWEC) approximately 60 megawatts November 1, 2016 letter of intent was exercised option subject to PSCW approval Wisconsin Public Service Corporation (WPS) up to 200 megawatts Madison Gas and Electric Company (MGE) up to 50 megawatts (a) Assumes an in-service date of early ACEC, REC, and CWEC options during construction The Co-ops ownership interests tied to wholesale power-supply agreements extending out to at least Co-ops will buy in during construction phase of approximately 60 megawatts. Payments will commence upon PSCW approval. WPS and MGE options when project is in-service and subject to approval of PSCW WPS may acquire up to 200 megawatts over the course of four years, with no more than 100 megawatts in the first two years. MGE may acquire up to 50 megawatts over five years, with no more than 25 megawatts in the first two years. If WPS exercises its options, WPL may exercise reciprocal options to purchase up to 200 megawatts of any natural-gas combined-cycle plant that either WPS or WEPCO, places in service before approximately WPL will also work cooperatively with WPS and WEPCO in developing utility-scale renewable resources (greater than 50 megawatts) located in Wisconsin over the next 10 years. Columbia Energy Center capital expenditures (PSCW docket 5-BS-214 approved in October 2016) WPS and MGE have negotiated contracts under which they may forgo certain capital expenditures at Columbia Energy Center, which WPL would then incur in exchange for a proportional increase in its ownership share. The Columbia Energy Center arrangement will expire when the Riverside Expansion project is placed in-service. The arrangement excludes capital expenditures related to the selective catalytic reduction system at Columbia Energy Center Unit 2. 12

13 Electric Distribution Strategy Grid Enhancements and Customer Need Reliability Distributed Generation/Renewable integration Integrate planning with generation and transmission Increase remote monitoring and control Eliminate lower voltage systems Increase life extension and rebuild rate Customer Focused Customer data availability Utility as trusted advisor for technical solutions 13

14 Natural Gas Strategy Reliability and Customer Growth Reliability Preparing for increased pipeline inspections under expected PHMSA rules Modifying existing pipes for enhanced inspection and verification requirements Replacing aging gas transmission lines Increasing remote monitoring Replacing bare steel Customer Growth Add capacity to areas of growth potential Modify tariffs to promote growth Utility as trusted advisor for natural gas solutions 14

15 Key Regulatory Initiatives IPL Estimated Key Dates IUB Clinton Lateral Natural Gas Pipeline Permit decision Decision regarding Advanced Rate Making (RPU) for additional wind generation (RPU ) Decision regarding Emissions Plan and Budget (EPB ) Q File Retail Electric Base Rate Case test year 2016 Q File Retail Gas Base Rate Case test year 2016 Q FERC Filing to transfer Franklin County Wind Farm from AER to IPL (EC17 40) Decision regarding authorized return on equity (ROE) amounts for MISO transmission owners first complaint Decision regarding authorized return on equity (ROE) amounts for MISO transmission owner s second complaint Q WPL PSCW Decision regarding Retail Electric and Gas Base Rate Case test years 2017 and 2018 (6680 UR 120) FERC Decision regarding authorized return on equity (ROE) amounts for MISO transmission owner s first complaint Decision regarding authorized return on equity (ROE) amounts for MISO transmission owner s second complaint Q

16 Wisconsin Power and Light Test Year Rate Case Oral Decision Oral decision on November 18 th consistent with revenue requirement settlement which resulted from collaboration with the Citizens Utility Board (CUB), Wisconsin Industrial Energy Group (WEIG), and PSCW Staff which was announced in May 2016 $9.4 million electric rate increase in 2017 $63.5 million base revenue increase ($54.1) million monitored fuel cost decrease $9.2 million gas base rate increase 10.0% authorized return on equity Continue ROE sharing mechanism 10.0% % no sharing 10.25%-11.00% 50/50 sharing >11.0% 100% customer Common equity 52.23% in 2017, 52.20% in 2018 Electric and gas retail rate base of $3.0 billion in 2017, $3.1 billion in 2018 Use of transmission escrow and continued use of the conservation escrow to offset base rate increases Deferral of revenue requirement impacts of Columbia ownership changes AFUDC treatment for 100% of Riverside Energy Center Expansion CWIP balances AFUDC treatment for 100% of CWIP balances for new CA/CPCNs not reflected in rate case, deferral of related incremental depreciation. Changes in depreciation rates Transfer of ATC investment out of WPL consistent with Docket 6680-AU-118 Docket 6680-UR

17 Incremental Growth Opportunity ATC 16% equity ownership interest Authorized ROE on 50% equity FERC base ROE decision of 10.32% for first complaint ROE under FERC review for second complaint, FERC ALJ recommended 9.70% base ROE ATC qualifies for 50 basis point adder Annual true-up mechanism Current return on construction work-in-progress Transmission siting under state jurisdiction ATC forecasted capex of $3.6 to $4.4 billion over 10 years; excludes potential transmission projects outside ATC s traditional footprint ATC 13-month average rate base for 2016 is projected to be approximately $3.3 billion Established Joint Venture with Duke Energy DATC Ownership split 50/50 between Duke and ATC Zephyr under development - deliver wind energy generated in eastern Wyoming to California and the southwestern U.S. between 500 and 850 miles 3,000 MW capacity $2.5B to $3.5B Path 15 DATC owns 72 percent of 84 mile transmission line in central California. FERC approved $25.9 million revenue requirement 17

18 Planned Financings, Strong Liquidity 2017 Financings Up to $250 million long term debt at IPL Up to $300 million long term debt at WPL Up to $150 million of common equity through one or more offerings and the shareholder direct program Long-term Debt Maturities Liquidity as of 10/31/2016 Credit Facility(a) (in millions) Limit Available Cash A/R Sales Total IPL $300 $300 $38 $149 $487 WPL AEC / Other Total $1,000 $973 $40 $149 $1,162 (a) Credit facilities expire

19 Growth in Earnings and Dividends Post stock split Adjusted (non-gaap) Earnings per Share from continuing operations $1.53 $1.66 $1.74 $1.75 $1.88 Dividends per Share $1.18 $1.10 $1.02 $0.90 $0.94 $1.26 (a) E Midpoint E 2017E (a) Annual common stock dividend target. Payment of the quarterly dividends is subject to the actual dividend declaration by the Board of Directors 19

20 Appendix 20

21 A Respected, Veteran Leadership Team Our top executives have over 180 combined years of creating shareholder value in the energy industry. Pat Kampling Chairman, President and CEO Doug Kopp Sr. Vice President and IPL President John Larsen Sr. Vice President and WPL President Tom Hanson Sr. Vice President and CFO Jim Gallegos Sr. Vice President, General Counsel and Corporate Secretary Barbara Tormaschy Vice President, Finance Robert Durian Vice President, CAO and Treasurer 21

22 2013, 2014 and 2015 Non-GAAP Temperature Normalized EPS versus Midpoint of 2016 EPS Guidance Post stock split $2.00 $1.80 $1.60 $1.57 (a) 8% increase $1.79 (c) 5% increase $1.88 $1.70 (b) 5% increase $1.40 $1.20 $1.00 $0.80 $0.60 $0.40 $0.20 $ Non GAAP temperature normalized 2014 Non GAAP temperature normalized 2015 Non GAAP temperature normalized 2016E (a) 2013 GAAP earnings were $1.65. Non-GAAP EPS adjustments were $0.09 for temperature and ($0.01) for other adjustments. (b) 2014 GAAP earnings were $1.74. Non-GAAP EPS adjustment was $0.04 for temperature. (c) 2015 GAAP earnings are $1.69. Non-GAAP EPS adjustments were ($0.04) for temperature and ($0.06) for losses from sales of Minnesota distribution assets and voluntary employee separation charges. The 2016 earnings guidance does not include the impacts of any material non cash valuation adjustments (such as asset valuation charges of $0.23 per share for Franklin County wind farm), regulatory related charges or credits, reorganizations or restructurings, discontinued operations, further impacts from anticipated changes to ATC s authorized return on equity, future changes in laws or regulations, adjustments made to deferred tax assets and liabilities from valuation allowances and organizational structure changes, pending lawsuits and disputes, federal and state incom tax audits and other Internal Revenue Service proceedings or changes in GAAP and tax methods of accounting that may impact the results. 22

23 2015 to 2016 Consolidated Earnings Guidance Walk Issued in November 2015 Post stock split Utilities, ATC and Corp. Services Non Reg./ Parent 2015 Non GAAP EPS $1.72 $0.03 $1.75 Adjust for temperature impacts Forecasted Temperature Normalized Non GAAP EPS Electric and Gas Margins: Lower base rate freeze settlement credits at IPL Other (primarily higher temperature normalized sales) Lower energy efficiency cost recovery amortizations at WPL Higher transmission expense at WPL (0.03) (0.03) Higher retirement plan expense (0.02) (0.02) Higher depreciation expense (0.03) (0.03) Higher utility interest expense (0.02) (0.02) Higher AFUDC (primarily Marshalltown) Lower income tax expense (flow through benefits) Equity dilution (0.02) (0.02) Other (0.02) (0.02) 2016 Forecasted EPS $1.85 $0.03 $1.88 AEC 23

24 IPL and WPL Capital Expenditures (in millions) $700 $600 $675 $650 $795 $745 $675 IPL $500 $400 $300 $200 $100 $ Other $35 $40 $35 $25 $25 Renewable Projects $70 $175 $325 $270 $115 Marshalltown Generating Station $185 $20 $0 $0 $0 Other Generation $90 $115 $105 $105 $80 Gas Distribution $120 $70 $75 $60 $160 Electric Distribution $175 $230 $255 $285 $295 Depreciation $205 $220 $255 $280 $300 $700 $600 $500 $400 $300 $665 $545 $545 $485 $470 WPL $200 $100 $ Other $20 $15 $10 $10 $10 Renewable Projects $30 $0 $20 $70 $210 Riverside Energy Center Expansion $75 $295 $180 $85 $5 Other Generation $180 $120 $80 $75 $80 Gas Distribution $50 $40 $70 $40 $60 Electric Distribution $130 $195 $185 $190 $180 Depreciation $190 $200 $205 $210 $230 24

25 IPL s Marshalltown Generating Station (MGS) Approved Rate Making Principles Cost cap of $920 million, including the facility, pipeline, transmission costs, owner s costs and AFUDC. Facility, owner s cost, and pipeline costs estimate is $700 million. The allowed rate of return on common equity capital on the portion of the MGS project to be included in Iowa electric rate base is 11%. ROE of 10.3% will be used in calculating the AFUDC rate. Depreciable life of MGS is 35 years. IPL permitted to include in rates the actual cost of the MGS project up to the cost cap, excluding transmission upgrades, without the need to establish prudence or reasonableness. IPL required to establish the prudence and reasonableness of any cost in excess of the cost cap. Note: ITC Midwest has elected to fund the cost of the Network Upgrades as allowed in Article 11.3 of the Generator Interconnection Agreement (GIA). ITC Midwest will recover its return on and of the actual capital cost of the Network Upgrades from IPL under a separate service agreement between ITC Midwest and IPL. 25

26 IPL and WPL Base Rate Settlements Stabilized Retail Electric Base Rates through 2016 Over $700 million of rate base additions $135 million DAEC PPA capacity payments in 2009 test year New DAEC PPA flows through energy adjustment clause Customer credits of $72 million in 2014, $24 million in 2015 and $9 million in 2016, flow through energy adjustment clause Credits represent difference between DAEC capacity in rates and impact of rate base additions Continuation of energy and transmission adjustment clauses Continuation of tax benefit rider Electric rate base increase of $90 million in 2015, $120 million in 2016 Utilizing ~$50 million in energy efficiency cost recovery liability Escrow treatment for major transmission charges Continuation of +/- 2% fuel band Return on common equity of 10.4% with sharing mechanism If return falls below 8.5% WPL can file for base rate change If return falls between 8.51% and 10.65% WPL retains If return falls between 10.65% and 11.4% WPL retains 50% excess, defers other 50% If return greater than 11.4% WPL defers 100% excess 26

27 Projected 13-Month Average IPL Rate Base for (a) (d) (a) CWIP is not included in retail and wholesale rate base (b) FERC formula rates (c) SERVCO assets not reflected in rate base for IPL retail or wholesale rates, but rather return on and of SERVCO assets are reflected in revenue requirement (d) IPL s next electric base rate case filings (test year 2016) anticipated to be filed in 2017 is expected to include 2016 rate base amounts plus certain post test year rate base additions including Marshalltown 27

28 Projected 13-Month Average WPL Rate Base for (a) (a) CWIP is not included in retail and wholesale rate base (b) FERC formula rates (c) SERVCO assets not reflected in rate base for WPL retail or wholesale rates, but rather return on and of SERVCO assets are reflected in revenue requirement 28

29 Earning AFUDC on Investments under Construction 13-Month Average Forecasted CWIP Balances (in millions) Projected AFUDC rates for 2017 IPL ~7.5% WPL ~7.6% $1,000 $900 $900 $1,085 $1,105 $800 $755 $700 In millions $600 $500 $400 $300 $200 $100 $0 $ WPL $235 $330 $575 $625 $300 IPL $665 $425 $510 $480 $235 CWIP balances include AFUDC eligible CWIP and, in the case of WPL, portions of CWIP that earn a current return in rate making processes (typically 50% of CWIP, except Riverside Expansion and certain large projects that had not received PSCW approval prior to the applicable rate case). 29

30 Meeting or Exceeding Expectations Construction Projects ($ in millions, excluding AFUDC, September 2016): Project Approved Budget (a) Current Estimate Progress (% Complete) Edgewater 5 SCR $154 $ % Columbia Scrubber/Baghouse (b) $627 $ % Ottumwa Scrubber/Baghouse (b) $345 $ % Ottumwa Efficiency Upgrades (b) $154 $ % Lansing 4 Scrubber $ 58 $ % Performance Columbia Efficiency Upgrades (b) $158 $142 80% TBD Columbia 2 SCR (b) $150 $107 33% TBD Edgewater 5 Scrubber/Baghouse $300 $242 99% TBD Marshalltown Generating Station and Pipeline $700 $700 94% TBD Sutherland CT Fuel Conversion $38 $38 77% TBD Riverside Energy Center Expansion $700 $700 1% TBD Ottumwa SCR $150 $150 0% TBD (a) Projects and related budgets have received appropriate regulatory approvals., with the exception of the Ottumwa SCR. (b) Budget and estimate amounts are for 100% of project, including co-owner s share 30

31 Rate Base and Return on Equity Rate Base in effect in 2016, information based on approved rate orders Rate Base $ s in millions % Common Equity Authorized ROE IPL (Iowa) Retail Electric Service Settlement approved by the IUB does not specify rate base, % common equity nor authorized ROE IPL (Iowa) Gas Service $ % 9.56%(a) WPL (Wisconsin) Retail Electric Service $2, % 10.40% Gas Service $ % 10.40% FERC WPL Wholesale $ % 10.90% IPL Wholesale $ % 10.97% (a) Reflecting application of double leveraging 31

32 Credit Ratings CREDIT RATINGS Moody s S&P AEC Unsecured long term debt Baa1 (Stable) N/A AEC Commercial Paper P 2 A 2 IPL Unsecured long term debt Baa1 (Stable) A (Stable) IPL Commercial Paper P 2 A 2 WPL Unsecured long term debt A2 (Stable) A (Stable) WPL Commercial Paper P 1 A 1 32

33 Renewable Energy Standards Wisconsin Iowa Current Standards ~5% by 2010 ~9% by MW total state IPL is 50MW 33

34 Wisconsin Fuel Rules Effective January 1, 2011 Annually, utilities will file a proposed fuel cost plan as an application to open or reopen a general rate case proceeding or, as part of a proceeding limited to fuel costs. After a hearing, the commission will approve the plan and establish the utilities rates accordingly, subject to a reconciliation. Utilities will automatically defer electric fuel-related costs that fall outside a symmetrical cost tolerance deadband and reflect the over/under recovery of these deferred costs in future billings to its retail customers. Annually, but no later than 90 days after the end of the plan year, the utility will file an application for the reconciliation of actual costs compared to items in the fuel cost plan. Refunds or charges resulting from the reconciliation will include interest at short-term debt rate. Fuel Cost Definition expanded to include: Emission allowances, including allowances for sulfur dioxide and carbon dioxide Cost for chemicals used to control emissions Deadband still at 2% bandwidth Approximately $5-$6 million pre-tax positive or negative exposure for WPL Excess revenues - If revenues in a plan year provide a utility with a greater return on common equity than authorized, the deferral of excess fuel costs will be adjusted by the excess revenues. 34

35 State Commission Overview Iowa Wisconsin Commissioners 3 3 Elected / Appoint Appointed Appointed Term (years) 6 6 Commissioners Term Expiration Dates Huser April 2021 Jacobs - April 2017 Wagner - April 2019 Nowak - March 2019 Huebsch March 2021 Montgomery - March 2017 Party Affiliation D: 1 R: 2 R:3 Rate Case Test Year Historical w/ post test year adjustments Forecasted Fuel Pass Through Fuel Band Financial Parameters for New Generation Iowa Code Wisconsin Statute

36 Constructive Regulatory Framework Expenses Recovered under Riders IPL Iowa Retail WPL Wisconsin Retail Electric production fuel and energy purchases Emission allowances and chemicals to reduce emissions Transmission service (a) Emission Allowances Only +2% Included in + 2% starting in 2012 Energy efficiency (b) Cost of gas % of 2015 utility operating expenses flowing through riders ~61% ~59% Test Year (a) Escrow accounting for WPL in 2015 and 2016 (b) Escrow accounting for WPL Historical, with interim rates implemented 10 days after filing Two Year Forward Looking 36

37 FERC Jurisdiction AEC investment in American Transmission Company 16% equity interest 2015 equity income $47 million Authorized ROE (annual true up) FERC base ROE decision of 10.32% for the first complaint Base ROE under FERC review for the second complaint, FERC ALJ recommended 9.70%, ATC qualifies for 50 basis point adder ATC forecasted capex of $3.6 $4.4 billion over 10 years, excludes investments outside of state of Wisconsin Established Joint Venture with Duke Energy anticipate additional capex WPL wholesale customers ~19% of WPL s MWh sales (~13% of electric revenue) in 2015 WPL s wholesale load is served via power supply agreements that extend through at least May 2017, with 70% extending through 2022, and 25% extending through WPPI Energy terminating contract May 31, Represents 6% of WPL total electric sales. Great Lakes Utilities terminating contract December 31, Represents 2% of WPL total electric sales wholesale revenues $165 million Return on equity at 10.9% Capital structure consisting of 55% equity and 45% long term debt Formula rates that true up capacity costs annually and adjust energy costs monthly Current recovery of 50% of construction work in progress except for new fossil fuel plants IPL wholesale customers ~5% of IPL s MWh sales (~4% of electric revenue) in 2015 New wholesale agreement started July 31, 2015 with SMEC 2015 wholesale revenues $56 million Jo Carroll terminating contract April 1, Represents 3% of IPL total electric sales. Return on equity 10.97%. Average capital structure adjusts annually (48% equity, 47% long term debt, 5% preferred) Formula rates that true up capacity costs annually and adjust energy costs monthly 37

38 Completed and Anticipated Plant Retirements IPL Nameplate Capacity (MW) Expected Retirement Dubuque 66 By Dec Units 3 and 4 (a) Fox Lake Unit 1 11 By Dec Fox Lake Unit 3 (a)(b) 82 By Dec Other (b) Approx. 195 By Dec Sutherland 119 By Dec Units 1 and 3 (b) Prairie Creek Units 64 By Dec and 3 (c) Total 537 WPL Nameplate Capacity (MW) Actual/Expected Retirement Edgewater 69 Dec Unit 3 Nelson Dewey Units Dec and 2 Edgewater 239 By Dec Unit 4 (d) Rock River Combustion Turbine Units 3 6 (d) 169 By Dec Sheepskin Combustion Turbine Unit 1 (d) Total By Dec (a) Contingent on transmission network upgrades (b) Contingent on Marshalltown Generating Station construction (c) Retire or fuel switch by Dec (d) Contingent on Riverside Expansion construction 38

39 2015 Capacity Based on summer capacity contribution to MISO Resource Adequacy calculations. Prior to 2014, DSM was used to reduce peak load. MISO changed the tariffs and moved DSM to supply side. IPL Wind 1% WPL Purchased Power Nuclear 13% Gas 53% Gas 37% Coal 38% Coal 39% DSM 11% Total 2015 MW 3,217 Total 2015 MW 2,888 Hydro 1% Emery generating station is 516 MW of total 1,210 MW gas capacity (42% of total gas) DSM 5% Wind 1% Sheboygan Falls, Neenah and Riverside generating stations are 1,095 MW of total 1,386 MW gas capacity (79% of total gas) 39

40 Name Plate Capacity (as of December 31, 2015) IPL WPL Wind 6% Other 11% $375 Gas 50% Coal 44% $690 Gas 39% Coal 40% Wind 9% Hydro 1% Total 2015 MW 3,215 Total 2015 MW 2,925 Sheboygan Falls 347 MW nameplate capacity is not included in the WPL gas percentage since it is not owned by the utility. WPL leases Sheboygan Falls from Alliant Energy non-regulated generation. 40

41 Adjusted Retail MWH Sales - Historical & Long-Term Forecast (a) (a) Historical sales are net of energy conservation and are weather normalized. Forecasted sales are net of energy conservation and assume normal weather. IPL Historical sales exclude MN retail sales 41

42 IPL Electric Sales (Calendar Year 2015) Electric Sales MWh Commercial 26% Residential 24% Sales For Resale / Other 7% 2015 US Avg.: 38% Residential, 36% Commercial, 26% Industrial Industrial 43% 489,632 customers $1.5 billion revenue IPL 43% Industrial Customer Usage by Segment Agricultural / Food Processing 29% Other Manufacturing 19% Chemicals 6% Fabrication & Machinery 9% Government, Trade, 5% Transportation & Utilities Health & Educational Services 7% Paper/Timber 4% Finance, Professional, Business 2% and Other Services Leisure & Hospitality 1% Other 18% 63% 42

43 WPL Electric Sales (Calendar Year 2015) Electric Sales MWh Residential 24% Commercial 16% Sales For Resale / Other 27% Industrial 33% 2015 US Avg.: 38% Residential, 36% Commercial, 26% Industrial 463,346 customers $1.3 billion revenue WPL 33% Industrial Customer Usage by Segment Chemicals 21% Fabrication & Machinery 12% Agricultural / Food Processing 9% Paper / Timber 5% Other Manufacturing 13% Gov t, Trade, Transportation & 7% Utilities Health & Educational Services 7% Finance, Professional, Business 2% and Other Services Leisure & Hospitality 4% Other 20% 60% 43

44 Electric Rate Comparison Dollars per kwh (Revenue $/kwh Sales) Residential Commercial Industrial Retail Avg. US average $0.13 $0.11 $0.07 $0.11 Iowa: MidAmerican $0.09 $0.07 $0.05 $0.07 IPL $0.14 $0.10 $0.06 $0.09 Wisconsin: MGE $0.17 $0.12 $0.08 $0.13 WE $0.15 $0.12 $0.08 $0.12 WPS $0.13 $0.10 $0.06 $0.09 WPL $0.13 $0.11 $0.08 $0.10 Source: EEI Typical Bills & Average Rates Report, Summer 2016 ed., Average rates 12 months ending June 30,