1 March 2013 Investor Update March 2013 Investor Update Exhibit 99.1
2 Forward Looking Disclosures Forward-looking statements: Certain matters discussed in this presentation are “forward- looking statements.” The Private Securities Litigation Reform Act of 1995 has established that these statements qualify for safe harbors from liability. Forward-looking statements may include words like “believe,” “anticipate,” “target,” “expect,” “pro forma,” “estimate,” “intend,” “guidance” or words of similar meaning. Forward-looking statements describe future plans, objectives, expectations or goals. Although we believe expectations are based on reasonable assumptions, all forward-looking statements involve risk and uncertainty. The factors that could cause actual results to differ materially from these forward-looking statements include those discussed herein as well as (1) those discussed in the company’s Annual Report on Form 10-K for the year ended Dec. 31, 2012 (a) under the heading, “Forward-Looking Statements,” (b) in ITEM 1. Business, (c) in ITEM 1A. Risk Factors, (d) in ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, and (e) in ITEM 8. Financial Statements and Supplementary Data: Notes 13 and 15; and (2) other factors discussed in the company’s filings with the Securities and Exchange Commission. Any forward-looking statement speaks only as of the date such statement was made, and the company does not undertake any obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement was made. March 2013 Investor Update
3 • Yearend 2012 results $2.15 per share • Issued 2013 EPS guidance $2.00 to $2.15 • 3% increase to common dividend • 2013 – 2015 CapEx plan • Managing our costs • 2013 Regulatory calendar Recent Events March 2013 Investor Update
4 • Retail GWh sales decreased 1.5% – Milder weather than 2011 – Estimate ≈1% weather normalized retail sales growth • Implemented all planned price adjustments (annualized amounts): – Base rates -- $50 million in May – Transmission -- $25 million in January – Environmental -- $19 million in June – Energy Efficiency -- $1 million in November • Initiated cost controls latter half of the year • COLI proceeds of $17.4 million – ≈$3 million above 2012 guidance level • Issued $330 million additional First Mortgage Bonds – Refinanced ≈$250 million of long-term debt and preferred stock Yearend 2012 Results $2.15 vs. $1.95 for 2011 March 2013 Investor Update
5 • Planned prices adjustments via tracking mechanisms • Expect weather-adjusted retail sales to grow 50 to 100 bp • Combined O&M and SG&A increase ≈5% – YoY change is ≈1% decrease for all items without revenue offsets, i.e. • $30 million for SPP Transmission and Property Taxes • $19 million for pension and tree trimming expenses in base rates eff. May • Depreciation and amortization increase ≈$7 million • No change for AFUDC • COLI proceeds of ≈$14 million • Prairie Wind joint venture earnings increase ≈$4 million • Effective tax rate 31-33% • Debt used as primary source of external funding – Issue ≈2 million shares already priced under forward sale agreements 2013 Earnings Guidance Range $2.00 to $2.15 March 2013 Investor Update
6 $0.92 $1.00 $1.08 $1.16 $1.20 $1.24 $1.28 $1.32 $1.36 $0.80 $0.90 $1.00 $1.10 $1.20 $1.30 $1.40 2005 2006 2007 2008 2009 2010 2011 2012 2013 3% Dividend Increase • Long-standing dividend payout target of 60%-75% of earnings – 2013 guidance implies payout in middle of range – 9th consecutive annual increase Indicated annual rate March 2013 Investor Update
7 Forecast 2013 – 2015 Capital Investment of $2.3 Billion March 2013 Investor Update Generation 23% Air Quality Controls 13% La Cygne Environmental 15% Nuclear Fuel 4% Transmission 24% Distribution 18% Other 3%
8 Managing O&M and SG&A • O&M / SG&A increased at CAGR of 6% over last 5 years – Reduced impact to ≈1% excluding items with revenue offsets which include: • SPP transmission expenses • Property taxes • Pension and tree trimming expenses $300 $400 $500 $600 $700 $800 $900 2008 2009 2010 2011 2012 2013 Proj. M ill io ns CAGR 1% March 2013 Investor Update Portion of O&M and SG&A expense covered by revenue offsets and deferred accounting treatment
9 2013 Regulatory Calendar March 2013 Investor Update Transmission Delivery Charge (TDC) Environmental Cost Recovery Rider (ECRR) Energy Efficiency Rider (EER) Abbreviated Rate Case Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Approximate time between filing and implementation
10 Current Plans March 2013 Investor Update
11 Annualized Rate & Revenue Changes Actual and Estimated 2012 2013 (Estimated) 2014 (Estimated) Base rates ≈$50 million May ≈$34 million Jan Transmission rates (a) ≈$25 million Jan 1 ≈$18 million Jan 1 ≈$22 million Jan 1 ECRR ≈$19 million June 1 ≈$31 million June 1 ≈$13 million June 1 Energy Efficiency ≈$1 million November ≈$0.5million November ≈$0.6 million November March 2013 Investor Update Complete (a) Incremental transmission revenue is from FERC transmission formula rate and the retail Transmission Delivery Charge, net of the projected increase in SPP transmission costs. Plan to file abbreviated rate case in April to recover CWIP for La Cygne air quality project - Request should capture about $350 million of our estimated $610 million share of project
12 Major Construction Projects • Air Quality Improvements – Jeffrey Energy Center • SCR on single unit to be in-service late 2014 • Will satisfy site-wide NOx limits without an additional SCR – SNCR and low NOx systems – La Cygne Energy Center in-service mid 2015 • Scrubbers, fabric filters, common chimney, SCR and low NOx system • Transmission – Prairie Wind Transmission line (≈110 mile double circuit 345 kV) – In-service late 2014 March 2013 Investor Update
13 Capital Expenditure Forecast 2013 - 2015 Actual Forecast Forecast Forecast Forecast Method of Cost 2012 2013 2014 2015 2013 - 2015 Recovery Generation replacements and other 146.5$ 199.6$ 174.1$ 169.0$ 542.7$ GRC Westar environmental 195.1 118.7 130.0 44.3 293.0 ECRR La Cygne environmental 159.7 192.5 109.5 48.3 350.3 GRC Nuclear Fuel 29.6 7.2 52.8 29.1 89.1 RECA Transmission 140.2 207.5 167.1 186.0 560.6 FERC / TDC Distribution 103.5 134.0 128.3 145.2 407.5 Other 35.6 28.6 23.5 20.4 72.5 GRC Total 810.2$ 888.1$ 785.3$ 642.3$ 2,315.7$ Prairie Wind Transmission joint venture 8.3$ 4.3$ 17.9$ 0.1$ 22.3$ Not included in the table are Westar's planned investment in Prairie Wind Transmission joint venture March 2013 Investor Update
14 Capital Expenditure Forecast 2013 - 2015 $0 $100 $200 $300 $400 $500 $600 $700 $800 $900 $1,000 2012 2013 2014 2015 M illi on s $810 $888 $785 $642 Air Quality - ECRR Other Transmission 36% 38% 36% 41% La Cygne Bracketed segments represent the transmission and air quality control investments recovered through riders March 2013 Investor Update
15 Projected Rate Base 2012 – 2017 (in billions) 2012 2013 2014 2015 2016 2017 Base Air Quality Transmission $7.3 $7.0 $6.7 $6.4 $5.9 $5.3 $4.0 $4.5 $4.6 $4.8 $4.9 $5.0 March 2013 Investor Update $0.9 $1.0 $1.2 $1.3 $1.6 $1.8 $0.4 $0.4 $0.5 $0.6 $0.5 $0.5
16 Environmental March 2013 Investor Update
17 Cross-State Air Pollution Rule Mercury and Air Toxics Standards Water 316(b) Coal Combustion Waste SO2 National Ambient Air Quality Standard Status Uncertain (Vacated by DC Circuit Court) Final Rule December 2011 Proposed March 2011 Proposed June 2010 Final Rule 2010 Effective DC Court denied EPA rehearing April 2012 (4 years to comply) Final compliance likely by 2020 5 years after Final Rule 2014 – 2017 Emissions / Areas Covered NOx SO2 Mercury Acid gases Cooling water intake Coal waste SO2 Generation Sources Affected Coal Gas Coal Coal Nuclear Coal Coal Issue(s) Cost Allowances Cost Cost Cost Hazardous or non-hazardous designation Cost Clarity Environmental Regulation Summary March 2013 Investor Update
18 $0.0 $0.5 $1.0 $1.5 $2.0 $0 $50 $100 $150 $200 $250 $300 $350 $400 2005 2006 2007 2008 2009 2010 2011 2012 2013E 2014E 2015E Investment in Air Quality Controls $ M il li o n s A n n u a l In v estme n t $ B il li o n s C u m u lat iv e I n v estme n t $2.0 $1.5 $1.0 $0.5 $0.0 March 2013 Investor Update
19 0 10,000 20,000 30,000 40,000 50,000 60,000 70,000 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 Air Quality Improvement March 2013 Investor Update Actual Projected Sulfur Dioxide Nitrogen Oxide Emission Rates (lbs/MWh) Emission Levels (Tons) Project ≈90% reduction Project ≈75% reduction 0 20,000 40,000 60,000 80,000 100,000 120,000 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 Actual Projected 2005 2012 2015 0 1 2 3 4 5 6 7 0 1 2 3 4 2005 2012 2015
20 Westar Coal Fleet Emission Control Equipment Unit Scrubber Precipitator Fabric Filter Low NOx SCR/SNCR ACI DSI Jeffrey 1 Yes Yes No plans Yes SCR (a) Planned No plans Jeffrey 2 Yes Yes No plans Yes SNCR (a) Planned No plans Jeffrey 3 Yes Yes No plans Yes SNCR Planned No plans La Cygne 1 Yes (b) Yes (a) No SCR Planned No plans La Cygne 2 Yes (a) Yes Yes (a) Yes (a) SCR (a) Planned No plans Lawrence 3 No plans Yes (c) No plans Planned No plans Planned Planned Lawre ce 4 Yes n/a Yes Yes No plans Planned No plans Lawrence 5 Yes n/a Yes Yes No plans Planned No plans Tecumseh 7 No plans Yes No plans Yes No plans Planned Planned Tecumseh 8 No plans Yes (c) No plans Planned No plans Planned Planned (a) Equipment installation underway (b) PM removal integrated into scrubbers (c) Equipment upgrade planned 83% of MWs Currently Scrubbed March 2013 Investor Update We intend to meet site-wide NOx limits without an additional SCR at Jeffrey * *
21 • Westar does not view as problematic – No surprises in final rule – Have four years to comply – View as additive to current environmental plans • Incorporated anticipated rules in current compliance plans for Regional Haze and JEC Consent Decree – Largest fleet impact on smallest coal-fired units – MATS compliance investment estimated at < $16 million Mercury and Air Toxics Standards (MATS) March 2013 Investor Update
22 Air Quality Control Targeted Emission / Benefit Low NOx Burner Systems NOx Selective Non-Catalytic Reduction NOx Selective Catalytic Reduction NOx Scrubber SO2 Acid gases Small amount of mercury Baghouse Particulate matter Small amount of mercury Metals Electrostatic Precipitator Particulate matter Metals Activated Carbon Injection (ACI) Mercury Dry Sorbent Injection (DSI) SO2 Acid gases Air Quality Controls March 2013 Investor Update
23 Transmission March 2013 Investor Update
24 Major Transmission Investment • Prairie Wind Transmission • 50/50 JV with ETA • Siting approved June 2011 • Acquiring ROW and clearing • Began construction Aug 2012 • Approximately 110 miles • Estimated completion 2014 • Project cost ≈$180 million March 2013 Investor Update
25 $0.0 $0.5 $1.0 $1.5 $0 $50 $100 $150 $200 $250 2005 2006 2007 2008 2009 2010 2011 2012 2013E 2014E 2015E Investment in Transmission $ M il li o n s A n n u a l In v estme n t $ B il li o n s C u m u lat iv e I n v estme n t March 2013 Investor Update
26 Potential for High Voltage Transmission Growth A. JEC to Iatan Energy Center B. Wolf Creek to Swissvale C. Concordia to Salina D. Salina to Hays E. JEC to Swissvale F. Hutchinson to Spearville G. Wichita to Rose Hill H. JEC to Concordia F G A B C E D H March 2013 Investor Update Granted conditional notice to construct
27 Prairie Wind Transmission Regulation • Received FERC incentives – Recovery of pre-commercial development costs – CWIP recovery in rate base – Allowed ROE of 12.8% • KCC – Siting approved June 2011 • Southwest Power Pool – Regional cost allocation approved by FERC – PWT’s formula rate in effect March 2013 Investor Update
28 Profile March 2013 Investor Update
29 Strategic Approach • Embrace uncertainty – Acknowledge inability to predict the future • Value flexibility – Operational – Financial – Regulatory • Leverage actions and strategies around intrinsic advantages • Seek collaborative and constructive approaches to regulation • Value proposition – Protect against downside while growing investor returns March 2013 Investor Update Pure-play, vertically integrated, rate-regulated • ≈7,200 MW of generation • 6,200 miles transmission • ≈690,000 customers
30 Regulatory Approach • A sound regulatory and energy policy platform – KCC and FERC • Ultimately results in lower rates for customers March 2013 Investor Update
31 Favorable Supply Portfolio $33.29 $20.59 $7.28 Uranium Coal Gas Ave. Fuel Cost $19.65/MWh Fuel Mix Coal 47% Gas 36% Wind 9% Uranium 8% MW Capability 6.0¢ 7.0¢ 8.0¢ 9.0¢ 10.0¢ 11.0¢ Westar Energy Kansas City Power and Light (KS) Empire District Electric (KS) C e n ts p e r K W h National Average 8.3¢ 9.7¢ 10.5¢ Low Rates Source: Edison Electric Institute 07/01/2012 Uranium 15% Wind 5%Gas 9% Coal 71% Cost of Fuel March 2013 Investor Update
32 Diverse Energy Sales (MWh) Chemical & oil Food processing Aerospace Consumer manufacturing Other Commercial 38% Residential 34% Industrial 28% 39% 17% 16% 15% 13% 12% 18% 8% 7% 3% 4% 48% Other General merchandise Grocery/ Convenience Real estate Health care Government Education March 2013 Investor Update
33 Service Territory Economy 3 4 5 6 7 8 9 10 11 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec U ne m pl oy m en t % ’s Unemployment (latest 12 months) U.S. KS • Economy stronger than the nation – No big real estate crash – Unemployment remains 2+ pts favorable to nation • Economic development gains supports industrial stability – EcoDevo success: • Mars Chocolate opening M&M and Snickers factory in Topeka – Improving tax environment • Reduced personal tax rates for all • Eliminated income taxes for most small businesses March 2013 Investor Update
34 Liquidity and Capitalization Target ≈50/50 capital structure Debt 49% Equity 51% Dec 31, 2012 (a) (millions) Long-term, net $2,819 Common 2,896 Total Capitalization $5,715 (a) Capitalization excludes short-term debt and adjustments for VIEs March 2013 Investor Update • Solid investment grade credit • Total credit facility capacity $1 Billion • Active in Commercial Paper market • No bonds mature before 2014 • $250 million FMB due July 2014 Fitch Moody’s Ratings S&P Secured A3 A- A- Unsecured Baa2 BBB+ BBB CP P-2 F-2 A-2 Outlook Stable Stable Stable
35 $0.92 $1.00 $1.08 $1.16 $1.20 $1.24 $1.28 $1.32 $1.36 $0.80 $0.90 $1.00 $1.10 $1.20 $1.30 $1.40 2005 2006 2007 2008 2009 2010 2011 2012 2013 3% Dividend Increase • Long-standing dividend payout target of 60%-75% of earnings – 2013 guidance implies payout in middle of range – 9th consecutive annual increase Indicated annual rate March 2013 Investor Update
36 Westar’s Value Proposition • Solid, transparent business strategy • Strong, experienced utility management team • Thoughtful, disciplined approach to operations, capital planning and financing • Constructive regulatory and policy environment – Results in lower, more gradual price changes for customers – Preserves reliable infrastructure as base for economic growth – Provides investors clarity • Focus on containing risks and maintaining returns • Diverse customer base and stable service territory March 2013 Investor Update
37 Rates and Regulation March 2013 Investor Update
38 • Kansas Corporation Commission – Three-member board appointed by governor • Serve staggered four year terms • Current KCC commissioners – Mark Sievers (R), chairman • Term expires March 2015 – Thomas Wright (D) • Term expires March 2014 – Shari Feist Albrecht (I) • Term expires March 2016 Kansas Regulators March 2013 Investor Update
39 Regulatory Approach • A sound regulatory and energy policy platform – KCC and FERC • Ultimately results in lower rates for customers March 2013 Investor Update
40 Methods of Cost Recovery Revenue Requirement Method of Recovery Comment 1. Fuel, purchased power and environmental consumables Quarterly adjustment based on forecasted cost, with annual true-up Adjusts prices for actual costs, protecting both customers and investors from mispricing 2. Environmental capital, excluding La Cygne environmental project Environmental Cost Recovery Rider adjusts annually Allows annual price adjustment to reflect capital costs for investments in emission controls 3. Transmission rate recovery FERC formula rate adjusts annually; companion retail tariff to reflect current revenue requirement Timely recovery of transmission system operating and capital costs 4. General capital investments Traditional rate case, but with predetermination and CWIP Typical rate case reflects current level of operating expenses and most recent plant investment 5. Property taxes Annual adjustment to reflect current property taxes Allows timely recovery of actual property tax costs in current rates 6. Extraordinary storm damages Traditionally deferred accounting treatment as rate base Smoothes period expenses for extraordinary storm restoration costs 7. Pension expenses Deferred as a regulatory asset for subsequent recovery Smoothes period expenses in excess of amount in base rates 8. Energy efficiency programs Deferred as a regulatory asset for subsequent recovery Smoothes period expenses for energy efficiency programs March 2013 Investor Update
41 Retail Energy Cost Adjustment (RECA) • Provides timely price adjustments for fuel and purchased power costs • Retail rates based on forecast of fuel and purchased power costs and retail sales – Set quarterly – Difference between forecast and actual is deferred • Quarterly approach produces more stable prices • Annual settlement of deferred balance • RECA also used to rebate wholesale margins as a credit to retail cost of service – Energy Marketing (i.e., non-asset) margins continue to be excluded from rate setting March 2013 Investor Update
42 Pension Tracker • Defer as regulatory asset shortfall between funding of GAAP pension/OPEB expense and pension/OPEB currently authorized in rates • Maintain minimum funding level equal to GAAP pension/OPEB expense • Recover deferred expenses through multi-year amortization as part of next rate case March 2013 Investor Update
43 Environmental Cost Recovery Rider Mechanics • ECRR adjusts retail rates annually to reflect capital investments in emission controls – Investments as of December 31 recovered in rates subsequent June – Eliminates need to file a rate case to capture rate base additions • Return of and on capital that is in service December 31 • Return on capital not yet placed in service December 31 (i.e., CWIP) • ECRR reduces regulatory lag – Regulatory lag limited to months, rather than longer lag typically associated with traditional rate case filings March 2013 Investor Update
44 Illustrative ECRR Mechanics (1) Illustration reflects only the projects publicly announced and assumes one-half of annual investment in service at year end (2) Illustration uses ≈11.9% pretax return and 4% depreciation recovery (3) Annual ECRR Tariff is effective June 1; assume Jan-May at prior year revenue requirement and Jun-Dec at new revenue requirement March 2013 Investor Update Clean Air Investment (1) 2011 2012 2013 2014 2015 Year 1 Investment $ 165.2 Year 2 Investment $ 195.1 Year 3 Investment $ 118.7 Year 4 Investment $ 130.0 Year 5 Investment $ 44.3 Environmental Investment $ 165.2 $ 360.3 $ 479.0 $ 609.0 $ 653.3 Accumulated Depreciation Clean Air Investment Year 1 Investment $ 4.5 $ 6.6 $ 6.6 $ 6.6 $ 6.6 Year 2 Investment 3.9 7.8 7.8 7.8 Year 3 Investment 2.4 4.7 4.7 Year 4 Investment 2.6 5.2 Year 5 Investment 0.9 Annual Depreciation $ 4.5 $ 10.5 $ 16.8 $ 21.8 $ 25.2 Total Accum Depreciation for Environmental Investment $ 4.5 $ 15.0 $ 31.8 $ 53.6 $ 78.8 Environmental Investment, net of accum. Depreciation $ 160.7 $ 345.3 $ 447.2 $ 555.4 $ 574.5 Return on prior YE investment balance (2) $ 19.1 $ 41.0 $ 53.0 $ 65.9 Return of prior YE investments completed 4.5 10.5 16.8 21.8 Annual ECRR Revenue Requirement $ 23.6 $ 51.5 $ 69.8 $ 87.6 Estimated calendar year revenue recognition (3) $ 13.7 $ 39.8 $ 62.2 $ 80.2 Cumulative ECRR revenue recognition $ 13.7 $ 53.6 $ 115.8 $ 196.0
45 Transmission Cost Recovery • FERC formula transmission rate – Changes in cost of service reflected in annual update of FERC tariff • Update posted each October using projected test year – Capital expenditures – O&M – Tariff based on year-end consolidated capital structure • FERC transmission changes effective January 1 • Allowed ROE 11.3% • Annual true-up compares projected revenue requirement to actual, with difference incorporated into next update – Incentives on completed central Kansas line • 12.3% ROE • Accelerated book depreciation of 15 vs. 45 years • Transmission Delivery Charge (TDC) – Retail rates adjusted to match changes to FERC tariff March 2013 Investor Update
46 Transmission Formula Rate Mechanics • Fixed formula with changing inputs – Updated annually using Form 1 data – Established protocols for updates • Uses projected test year – Rate base (based on 13 month average) – O&M, depreciation and taxes – Cost of debt • Annual true-up incorporated in subsequent year’s formula inputs J a n. 1 A p r. 1 5 J un. 1 5 O c t. 1 5 J a n. 1 O c t. 1 5 Establish Proj. 2013 Rev. Req. Establish Proj. 2014 Rev. Req. Start of 2014 Rate Year Start of 2013 Rate Year FERC Form 1 Released True-up between ’12 Proj. Rev. Req. and Actual Rev. Req. Transmission Formula Rate Time Line March 2013 Investor Update
47 Energy Efficiency Initiatives • Deferred accounting for the cost of energy efficiency initiatives, such as – Smart thermostats – Customer educational programs – Demand response programs • SmartStar Lawrence smart grid project – Installed ≈48,000 “smart” meters – Advanced outage management system – Total project cost of ≈$40 million • Reduced by 50% DOE match – Focused rollout to other areas March 2013 Investor Update
48 • Obtain permission from KCC to file ARC – Request made in a general rate case (GRC) – Identify scope of proposed ARC • Must file within 12 months of final GRC order • Applicant must adopt from previous rate order: – All regulatory procedures – All regulatory principles – Established rate of return Abbreviated (Limited Scope) Rate Case (ARC) March 2013 Investor Update
49 Kansas’ Renewable Requirements • Renewable Portfolio Standard established – Installed capability standard in lieu of energy standard • 10% of peak load by 2011, 15% by 2016 and 20% after 2020 – If generated in Kansas, treated at 110% of requirement – Relief from standard possible if costs would increase prices >1% • Potential to offset with RECs for initial period • Limited net metering – Limited to 1% of peak demand – Customer’s net metered sales can’t produce net negative sales • Environmental predictability – Legislation precludes state air emission levels from being more stringent than federal standards March 2013 Investor Update
50 0 200 400 600 800 1,000 1,200 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 M W Westar Commitment REC Allowance Statuatory Requirement Westar Renewables Compliance Favorable pricing allowed for head start on 2016 statute requirements KCC allowed the 2011 statute requirement to be satisfied with Renewable Energy Credits March 2013 Investor Update
51 Statutes for Predetermination and CWIP • Predetermination – Utilities can obtain order establishing ratemaking principles that will apply over the life of the asset • Construction Work in Progress (CWIP) – Utilities can include CWIP in rate cases March 2013 Investor Update
52 Capital Structure for Ratemaking (Per Recent Orders) Capitalization Ratio Cost of Capital Weighted Cost of Capital Pre-tax Weighted Cost of Capital Long-term debt 46.97% 6.65% 3.12% 3.12% Preferred 0.40 4.55 .02 .03 Common 52.63 10.00 5.26 8.71 100.00% 8.40% 11.86% Capitalization Ratio Cost of Capital Weighted Cost of Capital Pre-tax Weighted Cost of Capital Long-term debt 47.20% 6.32% 2.98% 2.98% Preferred 0.41 4.52 .02 .03 Common 52.39 11.30 5.93 9.81 100.00% 8.92% 12.82% KCC FERC Transmission (1) Incentive ROE of 12.3% for applicable rate base (1) March 2013 Investor Update
53 Background March 2013 Investor Update
54 Westar Energy Legal Structure Kansas Gas and Electric Company Consolidated capital structure is used for ratemaking (Rate regulated utility) (Rate regulated utility) Westar Energy, Inc. Parent Subsidiary Combined company does business under the name “Westar Energy” March 2013 Investor Update
55 Westar’s Generating Resources March 2013 Investor Update
56 Westar’s Plants Westar's MW Operator Years Installed Pulverized coal Jeffrey Energy Center 1,983 Westar 1978, 1980, 1983 Lawrence Energy Center 534 Westar 1954, 1960, 1971 Tecumseh Energy Center 197 Westar 1957, 1962 LaCygne Station 711 KCPL 1973, 1977 Nuclear Wolf Creek 547 WCNOC (1) 1985 Gas steam turbine Gordon Evans Energy Center 524 Westar 1961, 1967 Hutchinson Energy Center 160 Westar 1965 Murray Gill Energy Center 268 Westar 1952, 1954, 1956, 1959 Gas combustion turbine Gordon Evans Energy Center 284 Westar 2000, 2001 Hutchinson Energy Center 232 Westar 1974, 1975 Spring Creek Energy Center 269 Westar 2001 Emporia Energy Center 646 Westar 2008, 2009 Gas combined cycle State Line 201 EDE Co. 2001 Wind Meridian Way 96 Horizon (2) 2008 Central Plains 99 Westar 2009 Flat Ridge 100 Westar (3) 2009 Ironwood 168 Duke Energy (2) 2012 Post Rock 201 Wind Capital (2) 2012 Available generation At Nov. 1, 2012 7,220 (1) Wolf Creek Nuclear Operating Company is a company formed specifically to operate Wolf Creek for its owners. WCNOC is governed by a board of directors consisting of the CEO of WCNOC and senior executives of the plant owners. (2) 100% of generation purchased under Power Purchase Agreement (PPA) (3) 50% owned and 50% of generation purchased under PPA from BP Alternative Energy Westar Energy 2012 Results NERC 5-Year Average Plant Performance 81.0% 85.4% 79.4% 89.3% 87.0% 90.1% 61.6% 73.7% 0% 20% 40% 60% 80% 100% Coal Capacity Factor Wolf Creek Capacity Factor Coal Availability Factor Wolf Creek Availability Factor March 2013 Investor Update
57 Low-Cost Coal Fleet • Very low fuel cost – PRB coal – Excellent rail arrangements – Proximity to mines • Low embedded capital cost • No high-heat rate obsolete plants $0 $150 $300 $450 $600 $750 $900 $1,050 $1,200 $1,350 JEC 3 JEC 2 JEC 1 LEC 5 LAC 1 LAC 2 TEC 8 LEC 4 TEC 7 LEC 3 Embedded Cost 5,000 7,000 9,000 11,000 13,000 Heat Rate $/ K W B tu /k W h LAC 2 subject to lease agreement March 2013 Investor Update
58 Westar Energy Coal Fleet Unit Capacity (MW) WR Share (MW) Age Heat Rate (Btu/kWh) Net Book Value (Millions) $/KW Jeffrey 3 722 664 30 11,193 329$ 495$ Jeffrey 2 715 658 33 11,139 253$ 384$ Jeffrey 1 718 661 35 11,289 255$ 386$ Lawrence 5 374 374 42 10,361 233$ 623$ La Cygne 1 736 368 40 10,936 155$ 421$ La Cygne 2 (a) 686 343 36 10,233 7$ 20$ Tecumseh 8 127 127 51 10,780 19$ 150$ Lawrence 4 109 109 53 11,737 145$ 1,330$ Tecumseh 7 70 70 56 12,000 33$ 471$ Lawrence 3 51 51 59 11,840 21$ 412$ 3,425 (a) Subject to lease agreement March 2013 Investor Update
59 Westar-operated plant fuel supply (80%) • JEC supply under contract through 2020 (10+ million tons/year) – 70% has no market openers – 30% reopened on price every 5 years • Most recent re-pricing effective January 2013 – All volumes have cost escalators – Rail contract through 2013 • LEC/TEC supply under contract through 2014 (3 million tons/year) – 100% at fixed price or capped through 2014 – Rail contract through 2013 Co-owned plant fuel supply managed by GXP (20%) • LAC supply (3 million tons/year) Coal Supply March 2013 Investor Update
