News Column

WESTAR ENERGY INC /KS - 10-K - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

February 26, 2014

Certain matters discussed in Management's Discussion and Analysis 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 we "believe," "anticipate," "target," "expect," "estimate," "intend" and words of similar meaning. Forward-looking statements describe our future plans, objectives, expectations or goals. See "Forward Looking Statements" above for additional information. EXECUTIVE SUMMARY Description of Business We are the largest electric utility in Kansas. We produce, transmit and sell electricity at retail to approximately 693,000 customers in Kansas under the regulation of the KCC. We also supply electric energy at wholesale to municipalities and electric cooperatives in Kansas under the regulation of FERC. We have contracts for the sale or purchase of wholesale electricity with other utilities. Earnings Per Share Following is a summary of our net income and basic EPS for the years ended December 31, 2013 and 2012. Year Ended December 31, 2013 2012 Change (Dollars In Thousands, Except Per Share Amounts)



Net income attributable to common stock $ 292,520 $ 273,530$ 18,990 Earnings per common share, basic

2.29 2.15 0.14 Net income attributed to common stock and basic EPS for the year ended December 31, 2013, increased due primarily to higher prices and lower selling, general and administrative expenses. Lower electricity sales as a result of cooler weather and reduced demand for electricity served to partially offset the aforementioned increases. See the discussion under "-Operating Results" below for additional information.



Key Factors Affecting Our Performance

The principal business, economic and other factors that affect our operations and financial performance include:

weather conditions; the economy;



customer conservation efforts;

the performance, operation and maintenance of our electric generating

facilities and network;

conditions in the fuel, wholesale electricity and energy markets;

rate and other regulations and costs of addressing public policy initiatives including environmental regulations;



the availability of and our access to liquidity and capital resources; and

capital market conditions.

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Strategy

We expect to continue operating as a vertically integrated, regulated, electric utility. Significant elements of our strategy include maintaining a flexible and diverse energy supply portfolio. In doing so, we continue to make environmental upgrades to our coal-fired power plants, develop renewable generation, build and upgrade our electrical infrastructure, and develop systems and programs with regard to how our customers use energy.



Current Trends

Environmental Regulation

Environmental laws and regulations affecting our operations, which relate primarily to air quality, water quality, the use of water, and the handling, disposal and clean-up of hazardous and non-hazardous substances and wastes, continue to evolve and have become more stringent and costly over time. We have incurred and will continue to incur significant capital and other expenditures, and may potentially need to limit the use of some of our power plants, to comply with existing and new environmental laws and regulations. While certain of these costs are recoverable through the ECRR and ultimately we expect all such costs to be reflected in the prices we are allowed to charge, we cannot assure that all such costs will be recovered or that they will be recovered in a timely manner. See Note 13 of the Notes to Condensed Consolidated Financial Statements, "Commitments and Contingencies," for additional information regarding environmental laws and regulations.



Air Emissions

The operation of power plants results in emissions of mercury, acid gases and other air toxics. In 2012, the EPA's MATS for power plants became effective, replacing the prior federal CAMR and requiring significant reductions in mercury, acid gases and other emissions. We expect to be compliant with the new standards by April 2016 as approved by KDHE. We continue to evaluate the new standards and believe that our related investment will be approximately $17.0 million. Greenhouse Gases In January 2014, the EPA re-proposed a NSPS that would limit CO2 emissions for new coal and natural gas fueled generating units. The re-proposal would limit CO2 emissions to 1,000 lbs per MWh generated for larger natural gas units and 1,100 lbs per MWh generated for smaller natural gas units and coal units. Final regulations are expected later in 2014. The EPA was also directed to issue proposed standards addressing CO2 emissions for modified, reconstructed and existing power plants by June 2014, issue final rules by June 2015, and require that states submit their implementation plans to the EPA no later than June 2016. We cannot at this time determine the impact of such proposals on our operations and consolidated financial results, but we believe the costs to comply could be material. Under regulations known as the Tailoring Rule, the EPA regulates GHG emissions from certain stationary sources. The regulations are being implemented pursuant to two federal Clean Air Act programs which impose recordkeeping and monitoring requirements and also mandate the implementation of BACT for projects that cause a significant increase in GHG emissions (defined to be more than 75,000 tons or more per year or 100,000 tons or more per year, depending on various factors). The EPA has issued guidance on what BACT entails for the control of GHGs and individual states are now required to determine what controls are required for facilities within their jurisdiction on a case-by-case basis. We cannot at this time determine the impact of these regulations on our future operations and consolidated financial results, but we believe the costs to comply with the regulations could be material.



Regulation of Coal Combustion Byproducts

In the course of operating our coal generation plants, we produce CCBs, including fly ash, gypsum and bottom ash. We recycle some of our ash production, principally by selling to the aggregate industry. In 2010, the EPA proposed a rule to regulate CCBs, which we believe might impair our ability to recycle ash or require additional CCB handling, processing and storage equipment, or both. The EPA has agreed, subject to court approval, to issue a final rule in 2014. While we cannot at this time estimate the impact and costs associated with future regulations of CCBs, we believe the impact on our operations and consolidated financial results could be material. 29



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National Ambient Air Quality Standards

Under the federal Clean Air Act, the EPA sets NAAQS for certain emissions considered harmful to public health and the environment, including two classes of PM, NOx (a precursor to ozone), CO and SO2, which result from fossil fuel combustion. Areas meeting the NAAQS are designated attainment areas while those that do not meet the NAAQS are considered nonattainment areas. Each state must develop a plan to bring nonattainment areas into compliance with the NAAQS. NAAQS must be reviewed by EPA at five-year intervals. KDHE proposed to designate portions of the Kansas City area nonattainment for the eight-hour ozone standard. The EPA has not acted on KDHE's proposed designation of the Kansas City area and it is uncertain when, or if, such a designation might occur. The Wichita area also exceeded the eight-hour ozone standard and could be designated nonattainment in the future potentially impacting our operations. In September 2011, the President instructed the EPA not to implement its more stringent 2008 Ozone Standard since a new NAAQS for ozone was due to be proposed in 2013 and finalized in 2014. We are waiting on this new standard and cannot at this time predict the impact it may have on our operations, but it could be material. In December 2012, the EPA strengthened an existing NAAQS for one class of PM. By the end of 2014, the EPA anticipates making final attainment/nonattainment designations under this rule and expects to issue a final implementation rule. We are currently evaluating the rule, however, we cannot at this time predict the impact it may have on our operations or consolidated financial results, but it could be material. In 2010, the EPA strengthened the NAAQS for both NOx and SO2. We continue to communicate with our regulators regarding these standards and are currently evaluating what impact this could have on our operations and consolidated financial results. If we are required to install additional equipment to control emissions at our facilities, the revised NAAQS could have a material impact on our operations and consolidated financial results.



Water

We discharge some of the water used in our operations. This water may contain substances deemed to be pollutants. Revised rules governing such discharges from coal-fired power plants are expected to be issued by the EPA in 2014. Although we cannot at this time determine the timing or impact of compliance with any new regulations, more stringent regulations could have a material impact on our operations and consolidated financial results. In 2011, the EPA issued a proposed rule that would increase the requirements for cooling water intake structures at power plants over concerns about impacts to aquatic life. We are currently evaluating the proposed rule as well as recent nationally-issued information requests from the EPA. The EPA is required to finalize the rule by April 2014; however, because the rule has yet to be finalized, we cannot predict the impact it may have on our operations or consolidated financial results, but it could be material.



Renewable Energy Standard

Kansas law mandates that we maintain a minimum amount of renewable energy sources. Through 2015, net renewable generation capacity must be 10% of the average peak retail demand for the three prior years, subject to limited exceptions. This requirement increases to 15% for years 2016 through 2019 and 20% for 2020 and thereafter. With our existing wind generation facilities, supply contracts and renewable energy credits, we are able to satisfy the net renewable generation requirement through 2015. With our agreement to purchase an additional 200 MW of installed design capacity from a wind generation facility beginning in late 2016, we expect to meet the increased requirements through 2020. If we are unable to meet future requirements, our operations and consolidated financial results could be adversely impacted.



Regulation of Nuclear Generating Station

Additional regulation of Wolf Creek resulting from NRC oversight of the plant's performance or from changing regulations generally, including those that could potentially result from natural disasters or any event that might occur at any nuclear power plant anywhere in the world, may result in increased operating and capital expenditures. We cannot estimate the cost associated with such increases, but they could be material to our operations and consolidated financial results. We expect future increases in operating costs due to increased NRC oversight and efforts to comply with new industry-wide regulations adopted by the NRC in 2012. Future extended or unscheduled shutdowns of Wolf Creek could cause us to 30



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purchase replacement power, rely more heavily on our other generating units and reduce amounts of power available for us to sell in the wholesale market.

Allowance for Funds Used During Construction

AFUDC represents the allowed cost of capital used to finance utility construction activity. We compute AFUDC by applying a composite rate to qualified construction work in progress. We credit other income (for equity funds) and interest expense (for borrowed funds) for the amount of AFUDC capitalized as construction cost on the accompanying consolidated statements of income as follows:

Year Ended December 31, 2013 2012 2011 (In Thousands) Borrowed funds $ 11,706$ 10,399$ 5,589 Equity funds 14,143 11,706 5,550 Total $ 25,849$ 22,105$ 11,139



Average AFUDC Rates 4.8 % 5.0 % 3.6 %

We expect AFUDC for both borrowed funds and equity funds to fluctuate over the next several years as we execute our capital expenditure program.

Interest Expense

We expect interest expense to increase over the next several years as we issue new debt securities to fund our capital expenditure program. We continue to believe this increase will be reflected in the prices we are permitted to charge customers, as cost of capital will be a component of future rate proceedings and is also recognized in some of the other rate adjustments we are permitted to make. In addition, short-term interest rates are extremely low by historical standards. We cannot predict to what extent these conditions will continue. See Note 9 of the Notes to Consolidated Financial Statements, "Long-Term Debt" for additional information regarding the issuance of long-term debt.



Outstanding Shares of Common Stock

We expect the number of outstanding shares of Westar Energy common stock to increase through 2015 as we issue additional shares previously priced through forward sales agreements to fund our capital expenditure program. See Note 16 of the Notes to Consolidated Financial Statements, "Common and Preferred Stock," for additional information regarding our share issuances.



Customer Growth and Usage

Residential customer additions have slowed and electricity demand is stable to slightly declining due principally to the effects of the economic downturn and energy efficiency measures. Absent an economic recovery to conditions similar to those preceding the downturn, we believe such customer additions will continue to be significantly lower than historical levels. In addition, with the numerous energy efficiency policy initiatives promulgated through federal, state and local governments, as well as industry, we believe customers will continue to adopt more energy efficiency and conservation measures which will suppress the rate of demand for electricity.



2014 Outlook

In 2014, we expect to maintain our current business strategy and regulatory approach. Subject to regulatory approvals, we anticipate annualized price increases of approximately $50.0 million from formulae that track changes in certain of our costs, as well as a $30.7 million general price increase authorized by the KCC in November 2013. Assuming normal weather in line with the historical average, we expect 2014 retail electricity sales to be between about 0.5% to 1.0% higher than weather-normalized 2013 sales. In addition, we anticipate increased operating and maintenance expenses, including maintenance costs for our power plants, and higher selling, general and administrative expenses. SPP transmission expense and property taxes are increasing at a much higher rate than inflation and are offset with higher revenues pursuant to our regulatory mechanisms. To help fund our 31



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capital spending as provided under "-Future Cash Requirements" below, we plan to utilize short-term borrowings and we expect to issue common stock to settle forward sale transactions.

In March 2014, the SPP is expected to launch an IM similar to other organized power markets currently operating in other RTOs. As a result, we expect an increase in revenues and a corresponding increase in fuel and purchased power expense. Further, additional products may result in increased derivative activity, currently presented in other assets and liabilities, for which we will receive regulatory treatment.



CRITICAL ACCOUNTING ESTIMATES

Our discussion and analysis of financial condition and results of operations are based on our consolidated financial statements, which have been prepared in conformity with Generally Accepted Accounting Principles (GAAP). Note 2 of the Notes to Consolidated Financial Statements, "Summary of Significant Accounting Policies," contains a summary of our significant accounting policies, many of which require the use of estimates and assumptions by management. The policies highlighted below have an impact on our reported results that may be material due to the levels of judgment and subjectivity necessary to account for uncertain matters or their susceptibility to change.



Regulatory Accounting

We currently apply accounting standards that recognize the economic effects of rate regulation. Accordingly, we have recorded regulatory assets and liabilities when required by a regulatory order or based on regulatory precedent. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery in our prices. Regulatory liabilities represent probable future reductions in revenue or refunds to customers. The deferral of costs as regulatory assets is appropriate only when the future recovery of such costs is probable. In assessing probability, we consider such factors as specific regulatory orders, regulatory precedent and the current regulatory environment. Were we to deem it no longer probable that we would recover such costs, we would record a charge against income in the amount of the related regulatory assets. As of December 31, 2013, we had recorded regulatory assets currently subject to recovery in future prices of approximately $755.4 million and regulatory liabilities of $329.6 million, as discussed in greater detail in Note 3 of the Notes to Consolidated Financial Statements, "Rate Matters and Regulation."



Pension and Post-retirement Benefit Plans Actuarial Assumptions

We and Wolf Creek calculate our pension benefit and post-retirement medical benefit obligations and related costs using actuarial concepts within the guidance provided by applicable GAAP.

In accounting for our retirement plans and post-retirement benefits, we make assumptions regarding the valuation of benefit obligations and the performance of plan assets. The reported costs of our pension plans are impacted by estimates regarding earnings on plan assets, contributions to the plan, discount rates used to determine our projected benefit obligation and pension costs, and employee demographics including age, compensation levels and employment periods. Changes in these assumptions result primarily in changes to regulatory assets, regulatory liabilities or the amount of related pension and post-retirement benefit liabilities reflected on our consolidated balance sheets. Such changes may also require cash contributions.



The following table shows the impact of a 0.5% change in our pension plan discount rate, salary scale and rate of return on plan assets.

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Table of Contents Annual Change Change in in Projected Projected Change in Benefit Pension Actuarial Assumption Assumption Obligation (a) Costs (a) (Dollars In Thousands) Discount rate 0.5% decrease $ 70,159$ 6,721 0.5% increase (63,319 ) (6,234 ) Salary scale 0.5% decrease (17,359 ) (3,392 ) 0.5% increase 17,686 3,491 Rate of return on plan assets 0.5% decrease - 3,359 0.5% increase - (3,359 ) _______________

(a) Increases or decreases due to changes in actuarial assumptions result primarily in changes to regulatory assets and liabilities. The following table shows the impact of a 0.5% change in the discount rate and rate of return on plan assets and a 1% change in the annual medical trend on our post-retirement benefit plans. Annual Change in Change in Projected Projected Change in Benefit Post-retirement Actuarial Assumption Assumption Obligation (a) Costs (a) (Dollars In Thousands) Discount rate 0.5% decrease $ 8,174 $ 436 0.5% increase (7,702 ) (446 ) Rate of return on plan assets 0.5% decrease - 521 0.5% increase - (519 ) Annual medical trend 1.0% decrease (1,804 ) (261 ) 1.0% increase 1,996 292 _______________ (a) Increases or decreases due to changes in actuarial assumptions result primarily in changes to regulatory assets and liabilities. 33



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Table of Contents Revenue Recognition Electricity Sales



We record revenue at the time we deliver electricity to customers. We determine the amounts delivered to individual customers through systematic monthly readings of customer meters. At the end of each month, we estimate how much electricity we have delivered since the prior meter reading and record the corresponding unbilled revenue.

Our unbilled revenue estimate is affected by factors including fluctuations in energy demand, weather, line losses and changes in the composition of customer classes. We recorded estimated unbilled revenue of $60.1 million as of December 31, 2013 and $62.5 million as of December 31, 2012.



Income Taxes

We use the asset and liability method of accounting for income taxes. Under this method, we recognize deferred tax assets and liabilities for the future tax consequences attributable to temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. We recognize the future tax benefits to the extent that realization of such benefits is more likely than not. We amortize deferred investment tax credits over the lives of the related properties as required by tax laws and regulatory practices. We recognize production tax credits in the year that electricity is generated to the extent that realization of such benefits is more likely than not. We record deferred tax assets to the extent capital losses, operating losses, or tax credits will be carried forward to future periods. However, when we believe based on available evidence that we do not, or will not, have sufficient future capital gains or taxable income in the appropriate taxing jurisdiction to realize the entire benefit during the applicable carryforward period, we record a valuation allowance against the deferred tax asset. The application of income tax law is complex. Laws and regulations in this area are voluminous and often ambiguous. Accordingly, we must make judgments regarding income tax exposure. Interpretations of and guidance surrounding income tax laws and regulations change over time. As a result, changes in our judgments can materially affect amounts we recognize in our consolidated financial statements. See Note 10 of the Notes to Consolidated Financial Statements, "Taxes," for additional detail on our accounting for income taxes. Asset Retirement Obligations Legal Liability We have recognized legal obligations associated with the disposal of long-lived assets that result from the acquisition, construction, development or normal operation of such assets. Concurrent with the recognition of the liability, the estimated cost of the asset retirement obligation (ARO) is capitalized and depreciated over the remaining life of the asset. We estimate our AROs based on the fair value of the AROs we incurred at the time the related long-lived assets were either acquired, placed in service or when regulations establishing the obligation became effective. We initially recorded AROs at fair value for the estimated cost to decommission Wolf Creek (our 47% share), retire our wind generating facilities, dispose of asbestos insulating material at our power plants, remediate ash disposal ponds and dispose of polychlorinated biphenyl contaminated oil. In determining our AROs, we make assumptions regarding probable future disposal costs. A change in these assumptions could have a significant impact on the AROs reflected on our consolidated balance sheets. As of December 31, 2013 and 2012, we have recorded AROs of $160.7 million and $152.6 million, respectively. For additional information on our legal AROs, see Note 14 of the Notes to Consolidated Financial Statements, "Asset Retirement Obligations."



Non-Legal Liability - Cost of Removal

We collect in our prices the costs to dispose of plant assets that do not represent legal retirement obligations. As of December 31, 2013 and 2012, we had $114.1 million and $129.0 million, respectively, in amounts collected, but not yet spent, for removal costs classified as a regulatory liability. 34



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Contingencies and Litigation

We are currently involved in certain legal proceedings and have estimated the probable cost for the resolution of these claims. These estimates are based on an analysis of potential results, assuming a combination of litigation and settlement strategies. It is possible that our future consolidated financial results could be materially affected by changes in our assumptions. See Notes 13 and 15 of the Notes to Consolidated Financial Statements, "Commitments and Contingencies" and "Legal Proceedings," for additional information.



OPERATING RESULTS

We evaluate operating results based on EPS. We have various classifications of revenues, defined as follows:

Retail: Sales of electricity to residential, commercial and industrial customers. Classification of customers as residential, commercial or industrial requires judgment and our classifications may be different from other companies. Assignment of tariffs is not dependent on classification.



Other retail: Sales of electricity for lighting public streets and highways, net of revenue subject to refund.

Wholesale: Sales of electricity to electric cooperatives, municipalities and other electric utilities, the prices for which are either based on cost or prevailing market prices as prescribed by FERC authority. Margins realized from these sales serve to offset retail prices through either the RECA or at the time of our next general rate case.



Transmission: Reflects transmission revenues, including those based on tariffs with the SPP.

Other: Miscellaneous electric revenues including ancillary service revenues and rent from electric property leased to others. This category also includes transactions unrelated to the production of our generating assets and fees we earn for services that we provide for third parties. Electric utility revenues are impacted by things such as rate regulation, fuel costs, technology, customer behavior, the economy and competitive forces. Changing weather also affects the amount of electricity our customers use as electricity sales are seasonal. As a summer peaking utility, the third quarter typically accounts for our greatest electricity sales. Hot summer temperatures and cold winter temperatures prompt more demand, especially among residential and commercial customers and, to a lesser extent, industrial customers. Mild weather reduces customer demand. Our wholesale revenues are impacted by, among other factors, demand, cost and availability of fuel and purchased power, price volatility, available generation capacity, transmission availability and weather. 35



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2013 Compared to 2012

Below we discuss our operating results for the year ended December 31, 2013, compared to the results for the year ended December 31, 2012. Significant changes in results of operations shown in the table immediately below are further explained in the descriptions that follow.

Year Ended December 31, 2013 2012 Change % Change (Dollars In Thousands, Except Per Share Amounts) REVENUES: Residential $ 728,852$ 714,562$ 14,290 2.0 Commercial 667,106 640,654 26,452 4.1 Industrial 374,825 368,909 5,916 1.6 Other retail 8,939 (5,845 ) 14,784 252.9 Total Retail Revenues 1,779,722 1,718,280 61,442 3.6 Wholesale 348,239 316,353 31,886 10.1 Transmission (a) 210,281 193,797 16,484 8.5 Other 32,412 33,040 (628 ) (1.9 ) Total Revenues 2,370,654 2,261,470 109,184 4.8 OPERATING EXPENSES: Fuel and purchased power 634,797 589,990 44,807 7.6 SPP network transmission costs 178,604 166,547 12,057 7.2 Operating and maintenance 359,060 342,055 17,005 5.0 Depreciation and amortization 272,593 270,464 2,129 0.8 Selling, general and administrative 224,133 226,012 (1,879 ) (0.8 ) Taxes other than income tax 122,282 104,269 18,013 17.3 Total Operating Expenses 1,791,469 1,699,337 92,132 5.4 INCOME FROM OPERATIONS 579,185 562,133 17,052 3.0 OTHER INCOME (EXPENSE): Investment earnings 10,056 7,411 2,645 35.7 Other income 35,609 35,378 231 0.7 Other expense (18,099 ) (19,987 ) 1,888 9.4 Total Other Income 27,566 22,802 4,764 20.9 Interest expense 182,167 176,337 5,830 3.3 INCOME BEFORE INCOME TAXES 424,584 408,598 15,986 3.9 Income tax expense 123,721 126,136 (2,415 ) (1.9 ) NET INCOME 300,863 282,462 18,401 6.5 Less: Net income attributable to noncontrolling interests 8,343 7,316 1,027 14.0 NET INCOME ATTRIBUTABLE TO WESTAR ENERGY, INC. 292,520 275,146 17,374 6.3 Preferred dividends - 1,616 (1,616 ) (100.0 ) NET INCOME ATTRIBUTABLE TO COMMON STOCK $ 292,520$ 273,530$ 18,990 6.9 BASIC EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING ATTRIBUTABLE TO WESTAR ENERGY $ 2.29$ 2.15$ 0.14 6.5 DILUTED EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING ATTRIBUTABLE TO WESTAR ENERGY $ 2.27$ 2.15$ 0.12 5.6 _______________



(a) Reflects revenue from an SPP network transmission tariff corresponding to our

SPP network transmission costs. These costs, less administration fees of

$39.1 million and $27.2 million, were returned to us as revenue in 2013 and

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Rate Case Agreement

In November 2013, the KCC issued an order allowing us to adjust our prices to include the additional investment in the La Cygne environmental upgrades, as discussed below, and to reflect cost reductions elsewhere. The new prices are expected to increase our annual retail revenues by approximately $30.7 million. In April 2012, the KCC issued an order authorizing higher revenues to recover higher expenses primarily for increased tree trimming to enhance reliability and increased pension costs resulting from the consequences of the 2008 financial crisis and subsequent low interest rate environment in accordance with the regulatory mechanism in place to account for such pension costs. As a result of this order, we expect selling, general and administrative expense to increase $32.1 million and the cost of operating and maintaining our distribution system to increase $10.9 million on an annualized basis. In addition, we revised our depreciation rates to reflect changes in the estimated useful lives of some of our assets. The change in estimate will decrease annual depreciation expense by $43.6 million. However, decreased depreciation expense as a result of lower depreciation rates will be offset by additional depreciation related to additions to property, plant and equipment. Because the aforementioned changes were implemented shortly after the KCC issued its order, our 2012 consolidated financial results do not reflect the full annual impact of the changes.



Gross Margin

Fuel and purchased power costs fluctuate with electricity sales and unit costs. As permitted by regulators, we adjust our retail prices to reflect changes in the costs of fuel and purchased power. Fuel and purchased power costs for wholesale customers are recovered at prevailing market prices or based on a predetermined formula with a price adjustment approved by FERC. As a result, changes in fuel and purchased power costs are offset in revenues with minimal impact on net income. In addition, SPP network transmission costs fluctuate due primarily to investments by us and other members of the SPP for upgrades to the transmission grid within the SPP RTO. As with fuel and purchased power costs, changes in SPP network transmission costs are mostly reflected in the prices we charge customers with minimal impact on net income. For these reasons, we believe gross margin is useful for understanding and analyzing changes in our operating performance from one period to the next. We calculate gross margin as total revenues, including transmission revenues, less the sum of fuel and purchased power costs and amounts billed by the SPP for network transmission costs. Accordingly, gross margin reflects transmission revenues and costs on a net basis. The following table summarizes our gross margin for the years ended December 31, 2013 and 2012. Year Ended December 31, 2013 2012 Change % Change (Dollars In Thousands) Revenues $ 2,370,654$ 2,261,470$ 109,184 4.8 Less: Fuel and purchased power expense 634,797 589,990 44,807 7.6 SPP network transmission costs 178,604 166,547 12,057 7.2 Gross Margin $ 1,557,253$ 1,504,933$ 52,320 3.5 The following table reflects changes in electricity sales for the years ended December 31, 2013 and 2012. No electricity sales are shown for transmission or other as they are not directly related to the amount of electricity we sell. Year Ended December 31, 2013 2012 Change % Change (Thousands of MWh) ELECTRICITY SALES: Residential 6,523 6,684 (161 ) (2.4 ) Commercial 7,480 7,581 (101 ) (1.3 ) Industrial 5,407 5,588 (181 ) (3.2 ) Other retail 86 85 1 1.2 Total Retail 19,496 19,938 (442 ) (2.2 ) Wholesale 8,593 7,719 874 11.3 Total 28,089 27,657 432 1.6 37



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Gross margin increased due primarily to higher retail revenues that were the result of higher prices offset partially by lower retail electricity sales. The lower retail electricity sales were attributable principally to cooler summer weather, which particularly impacted residential and commercial electricity sales. As measured by cooling degree days, 2013 was 23% cooler than the prior year. Contributing also to the decrease in retail sales was the reduced demand, primarily from several large industrial customers. Income from operations is the most directly comparable measure to our presentation of gross margin that is calculated and presented in accordance with GAAP in our consolidated statements of income. Our presentation of gross margin should not be considered in isolation or as a substitute for income from operations. Additionally, our presentation of gross margin may not be comparable to similarly titled measures reported by other companies. The following table reconciles income from operations with gross margin for the years ended December 31, 2013 and 2012. Year Ended December 31, 2013 2012 Change % Change (Dollars In Thousands) Gross margin $ 1,557,253$ 1,504,933$ 52,320 3.5 Less: Operating and maintenance expense 359,060 342,055 17,005 5.0 Depreciation and amortization expense 272,593 270,464 2,129 0.8 Selling, general and administrative expense 224,133 226,012 (1,879 ) (0.8 ) Taxes other than income tax 122,282 104,269 18,013 17.3 Income from operations $ 579,185$ 562,133$ 17,052 3.0



Operating Expenses and Other Income and Expense Items

Year Ended December 31, 2013 2012 Change %



Change

(Dollars in Thousands)



Operating and maintenance expense $ 359,060$ 342,055$ 17,005

5.0

Operating and maintenance expense increased due principally to:

higher costs for tree trimming, pursuant to authorized rate recovery, and other distribution reliability activities of $11.8 million; and higher costs at Wolf Creek of $5.0 million, due principally to higher amortization of refueling outage costs and recognition of costs incurred during an unscheduled maintenance outage in 2013. Year Ended December 31, 2013 2012 Change % Change (Dollars in Thousands)



Depreciation and amortization expense $ 272,593$ 270,464$ 2,129

0.8

Depreciation and amortization expense increased due to additional depreciation expense resulting primarily from increased plant additions at our power plants, including air quality controls, and the addition of transmission facilities. Partially offsetting this increase was a result of our having reduced depreciation rates in mid 2012 to reflect changes in the estimated useful lives of some of our assets. 38



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Table of Contents Year Ended December 31, 2013 2012 Change % Change (Dollars in Thousands)



Selling, general and administrative expense $ 224,133$ 226,012$ (1,879 ) (0.8 )

Selling, general and administrative expense decreased due primarily to:

lower post-retirement and other employee benefit costs of $8.6 million due principally to restructuring insurance contracts; and, lower labor cost of $2.3 million, which in part reflects expenses recorded in 2012 related to sustainable cost reduction



activities;

however, partially offsetting these decreases were higher pension costs of $12.3 million, most of which were offset with higher revenues. These increased pension cost were principally a consequence of the 2008 financial market downturn and the subsequent low interest rate environment. Year Ended December 31, 2013 2012 Change % Change (Dollars in Thousands)



Taxes other than income tax $ 122,282$ 104,269$ 18,013 17.3

Taxes other than income tax increased due primarily to an $18.2 million increase in property taxes, which are offset in retail revenues.

Year Ended December 31, 2013 2012 Change % Change (Dollars in Thousands)



Investment earnings $ 10,056$ 7,411$ 2,645 35.7

Investment earnings increased due principally to:

$1.2 million increase in earnings from our investment in Prairie Wind Transmission, LLC; and, $1.4 million of additional gains on investments in a trust to fund retirement benefits. Year Ended December 31, 2013 2012 Change % Change (Dollars in Thousands)



Interest expense $ 182,167$ 176,337$ 5,830 3.3

Interest expense increased due to our recording $10.5 million in interest principally related to additional debt issued to fund capital investment. Partially offsetting this increase was a $2.2 million decrease of interest expense on long-term debt of VIEs and a $1.3 million decrease for capitalized interest.

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2012 Compared to 2011

Below we discuss our operating results for the year ended December 31, 2012, compared to the results for the year ended December 31, 2011. Significant changes in results of operations shown in the table immediately below are further explained in the descriptions that follow.

Year Ended December 31, 2012 2011 Change % Change (Dollars In Thousands, Except Per Share Amounts) REVENUES: Residential $ 714,562$ 693,388$ 21,174 3.1 Commercial 640,654 604,626 36,028 6.0 Industrial 368,909 347,881 21,028 6.0 Other retail (5,845 ) (8,964 ) 3,119 34.8 Total Retail Revenues 1,718,280 1,636,931 81,349 5.0 Wholesale 316,353 346,948 (30,595 ) (8.8 ) Transmission (a) 193,797 154,569 39,228 25.4 Other 33,040 32,543 497 1.5 Total Revenues 2,261,470 2,170,991 90,479 4.2 OPERATING EXPENSES: Fuel and purchased power 589,990 630,793 (40,803 ) (6.5 ) SPP network transmission costs 166,547 132,164 34,383 26.0 Operating and maintenance 342,055 332,989 9,066 2.7 Depreciation and amortization 270,464 285,322 (14,858 ) (5.2 ) Selling, general and administrative 226,012 184,695 41,317 22.4 Taxes other than income tax 104,269 92,599 11,670 12.6 Total Operating Expenses 1,699,337 1,658,562 40,775 2.5 INCOME FROM OPERATIONS 562,133 512,429 49,704 9.7 OTHER INCOME (EXPENSE): Investment earnings 7,411 9,301 (1,890 ) (20.3 ) Other income 35,378 8,652 26,726 308.9 Other expense (19,987 ) (18,398 ) (1,589 ) (8.6 ) Total Other Income (Expense) 22,802 (445 ) 23,247 (b) Interest expense 176,337 172,460 3,877 2.2 INCOME BEFORE INCOME TAXES 408,598 339,524 69,074 20.3 Income tax expense 126,136 103,344 22,792 22.1 NET INCOME 282,462 236,180 46,282 19.6 Less: Net income attributable to noncontrolling interests 7,316 5,941 1,375 23.1 NET INCOME ATTRIBUTABLE TO WESTAR ENERGY. INC. 275,146 230,239 44,907 19.5 Preferred dividends 1,616 970 646 66.6 NET INCOME ATTRIBUTABLE TO COMMON STOCK $ 273,530$ 229,269$ 44,261 19.3 BASIC EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING ATTRIBUTABLE TO WESTAR ENERGY $ 2.15$ 1.95$ 0.20 10.3 DILUTED EARNINGS PER AVERAGE COMMON SHARE OUTSTANDING ATTRIBUTABLE TO WESTAR ENERGY $ 2.15$ 1.93$ 0.22 11.4 ______________



(a) Reflects revenue from an SPP network transmission tariff corresponding to our

SPP network transmission costs. These costs, less administration fees of

$27.2 million and $18.6 million, respectively, were returned to us as

revenue.

(b) Change greater than 1,000%.

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Gross Margin

The following table summarizes our gross margin for the years ended December 31, 2012 and 2011. Year Ended December 31, 2012 2011 Change % Change (Dollars In Thousands) Revenues $ 2,261,470$ 2,170,991$ 90,479 4.2 Less: Fuel and purchased power expense 589,990 630,793 (40,803 ) (6.5 ) SPP network transmission costs 166,547 132,164 34,383 26.0 Gross Margin $ 1,504,933$ 1,408,034$ 96,899 6.9 The following table reflects changes in electricity sales for the years ended December 31, 2012 and 2011. No electricity sales are shown for transmission or other as they are not directly related to the amount of electricity we sell. Year Ended December 31, 2012 2011 Change % Change (Thousands of MWh) ELECTRICITY SALES: Residential 6,684 6,986 (302 ) (4.3 ) Commercial 7,581 7,573 8 0.1 Industrial 5,588 5,589 (1 ) (a) Other retail 85 88 (3 ) (3.4 ) Total Retail 19,938 20,236 (298 ) (1.5 ) Wholesale 7,719 8,215 (496 ) (6.0 ) Total 27,657 28,451 (794 ) (2.8 ) (a) Change less than 0.1% Gross margin increased due primarily to higher retail revenues that were the result of higher prices offset partially by lower retail electricity sales. The lower retail electricity sales were attributable principally to moderate weather, which particularly impacted residential electricity sales. In 2012, cooling degree days were similar to 2011; however, cooling degree days during the third quarter of 2012 were 9% lower than the same period of 2011.



The following table reconciles income from operations with gross margin for the years ended December 31, 2012 and 2011.

Year Ended December 31, 2012 2011 Change % Change (Dollars In Thousands) Gross margin $ 1,504,933$ 1,408,034$ 96,899 6.9 Less: Operating and maintenance expense 342,055 332,989 9,066 2.7 Depreciation and amortization expense 270,464 285,322 (14,858 ) (5.2 ) Selling, general and administrative expense 226,012 184,695 41,317 22.4 Taxes other than income tax 104,269 92,599 11,670 12.6 Income from operations $ 562,133$ 512,429$ 49,704 9.7 41



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Operating Expenses and Other Income and Expense Items

Year Ended December 31, 2012 2011 Change %



Change

(Dollars in Thousands)



Operating and maintenance expense $ 342,055$ 332,989$ 9,066 2.7

Operating and maintenance expense increased due principally to:

higher costs for tree trimming, pursuant to authorized rate recovery, and other electrical system reliability activities of $5.9 million; and higher costs at Wolf Creek of $4.6 million, which were the result primarily of maintenance costs incurred during an unscheduled outage. Year Ended December 31, 2012 2011 Change % Change (Dollars in Thousands)



Depreciation and amortization expense $ 270,464$ 285,322$ (14,858 )

(5.2 )

Depreciation and amortization expense decreased as a result of our having reduced depreciation rates to reflect changes in the estimated useful lives of some of our assets. Partially offsetting this decrease was additional depreciation expense associated primarily with additions at our power plants, including air quality controls, and the addition of transmission facilities. Year Ended December 31, 2012 2011 Change % Change (Dollars in Thousands)



Selling, general and administrative expense $ 226,012$ 184,695$ 41,317 22.4

Selling, general and administrative expense increased due primarily to:

our having reversed $22.0 million of previously accrued



liabilities

in 2011 as a result of settling litigation; higher pension and other employee benefit costs of $20.2 million pursuant to authorized rate recovery; our having recorded $4.5 million of expense as a result of sustainable cost reduction activities; and a $2.1 million increase in the amortization of previously deferred amounts associated with various energy efficiency programs, which we recover in retail revenues; however, partially offsetting these increases was a $9.4 million



decrease in

legal fees that was the result principally of arbitration and litigation that occurred in 2011. Year Ended December 31, 2012 2011 Change % Change (Dollars in Thousands)



Taxes other than income tax $ 104,269$ 92,599$ 11,670 12.6

Taxes other than income tax increased due primarily to a $9.2 million increase in property taxes, which is offset in retail revenues.

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Table of Contents Year Ended December 31, 2012 2011 Change % Change (Dollars in Thousands) Investment earnings $ 7,411$ 9,301$ (1,890 ) (20.3 )



Investment earnings decreased due principally to:

our having recorded a $7.2 million gain on the sale of a



non-utility

investment in 2011; however, partially offsetting this item was our having recorded $4.5 million of additional gains on investments in a trust to fund



retirement

benefits and a $1.7 million increase in earnings from our



investment

in Prairie Wind Transmission, LLC. Year Ended December 31, 2012 2011 Change % Change (Dollars in Thousands)



Other income $ 35,378$ 8,652$ 26,726 308.9

Other income increased due principally to:

our having recorded an additional $17.4 million in COLI (corporate-owned life insurance) benefits; a $6.2 million increase in equity AFUDC, which reflects more construction activity; and our having recorded an additional $3.1 million related to the sale of oil inventory. Year Ended December 31, 2012 2011 Change % Change (Dollars in Thousands)



Income tax expense $ 126,136$ 103,344$ 22,792 22.1

Income tax expense increased due principally to higher income before income taxes.

Financial Condition

A number of factors affected amounts recorded on our balance sheet as of December 31, 2013, compared to December 31, 2012.

As of December 31, 2013 2012 Change % Change (Dollars in Thousands)



Fuel inventory and supplies $ 239,511$ 249,016$ (9,505 ) (3.8 )

Fuel inventory and supplies decreased due principally to a $16.7 million decrease in coal inventory, due to a price reduction in the cost of coal and reduced transportation costs. This decrease was partially offset by a $6.8 million increase in materials and supplies as a result of higher inventory replacement costs as well as materials purchased for spring 2014 outages.

As of December 31, 2013 2012 Change



% Change

(Dollars in Thousands)



Property, plant and equipment, net $ 7,551,916$ 7,013,765$ 538,151

7.7

Property, plant and equipment, net of accumulated depreciation, increased due primarily to additions at our power plants, including air quality controls, and the addition of transmission facilities. 43



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Table of Contents As of December 31, 2013 2012 Change % Change (Dollars in Thousands)



Property, plant and equipment of variable interest entities, net $ 296,626$ 321,975$ (25,349 ) (7.9 )

Property, plant and equipment of variable interest entities, net of accumulated depreciation, decreased due to deconsolidating a rail car lease as discussed in Note 17 of the Notes to Consolidated Financial Statements, "Variable Interest Entities," and normal depreciation of these assets. As of December 31, 2013 2012 Change % Change (Dollars in Thousands)



Regulatory assets $ 755,414$ 1,002,672$ (247,258 ) (24.7 ) Regulatory liabilities 329,556 323,175 6,381 2.0 Net regulatory assets $ 425,858$ 679,497$ (253,639 ) (37.3 )

Total regulatory assets decreased due primarily to the following reasons:

a $265.1 million decrease in deferred employee benefit costs, due primarily to decreased pension and post-retirement benefit obligations as a result of increases in the discount rates used to calculate our and Wolf Creek's benefits obligations;



a $9.6 million decrease in amounts previously deferred for storm costs;

a $5.3 million decrease in amounts due from customers for future income taxes; and a $4.4 million decrease in amounts deferred for energy



efficiency

costs; however, partially offsetting decreases were a $17.9 million, $14.9



million

and $12.7 million increase in amounts deferred for fuel



expense, for

the Wolf Creek outage and for property taxes, respectively. Regulatory liabilities increased due primarily to a $24.9 million increase in the fair value of the NDT and an $8.3 million increase in other post-retirement costs. Partially offsetting this increase was a $14.8 million decrease in amounts collected but not yet spent to dispose of plant assets. As of December 31, 2013 2012 Change % Change (Dollars in Thousands) Short-term debt $ 134,600$ 339,200$ (204,600 ) (60.3 ) Short-term debt decreased due to decreases in issuances of commercial paper. Proceeds from issuances of long-term debt were used to repay short-term debt, which had been used primarily to purchase capital equipment, to redeem bonds and for working capital and general corporate purposes. As of December 31, 2013 2012 Change



% Change

(Dollars in Thousands) Current maturities of long-term debt $ 250,000 $ - $ 250,000 Long-term debt, net 2,968,958 2,819,271 149,687 5.3 Total long-term debt $ 3,218,958$ 2,819,271$ 399,687 14.2



Total long-term debt increased due to the issuance of $500.0 million principal amount of first mortgage bonds. This increase was partially offset by our redemption of two pollution control bond issues with an aggregate principal amount of

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$100.0 million. Both the issuance and redemptions are further discussed in Note 9 of the Notes to Consolidated Financial Statements, "Long-Term Debt."

As of December 31, 2013 2012 Change



% Change

(Dollars in Thousands) Current maturities of long-term debt of variable interest entities $ 27,479$ 25,942$ 1,537 5.9 Long-term debt of variable interest entities 194,802 222,743 (27,941 ) (12.5 ) Total long-term debt of variable interest entities $ 222,281$ 248,685$ (26,404 ) (10.6 )



Total long-term debt of variable interest entities decreased due principally to the VIEs that hold the JEC and La Cygne leasehold interests having made principal payments totaling $25.4 million.

As of December 31, 2013 2012 Change



% Change

(Dollars in Thousands)



Deferred income tax liabilities $ 1,361,418$ 1,197,837$ 163,581

13.7

Long-term deferred income tax liabilities increased due primarily to the use of bonus and accelerated depreciation methods during the year.

As of December 31, 2013 2012 Change % Change (Dollars in Thousands)



Accrued employee benefits $ 331,558$ 564,870$ (233,312 ) (41.3 )

Accrued employee benefits decreased due primarily to lower pension and post-retirement benefit obligations as a result of increases in the discount rates used to calculate our and Wolf Creek's benefits obligations.

LIQUIDITY AND CAPITAL RESOURCES

Overview

Available sources of funds to operate our business include internally generated cash, short-term borrowings under Westar Energy's commercial paper program and revolving credit facilities, and access to capital markets. We expect to meet our day-to-day cash requirements including, among other items, fuel and purchased power, dividends, interest payments, income taxes and pension contributions, using primarily internally generated cash and short-term borrowings. To meet the cash requirements for our capital investments, we expect to use internally generated cash, short-term borrowings, and proceeds from the issuance of debt and equity securities in the capital markets. When such balances are of sufficient size and it makes economic sense to do so, we also use proceeds from the issuance of long-term debt and equity securities to repay short-term borrowings, which are principally related to investments in capital equipment and the redemption of bonds and for working capital and general corporate purposes. For additional information on our future cash requirements, see "-Future Cash Requirements" below. In 2014, we expect to continue our significant capital spending program and plan to contribute to our pension trust. We continue to believe that we will have the ability to pay dividends. Uncertainties affecting our ability to meet cash requirements include, among others, factors affecting revenues described in "-Operating Results" above, economic conditions, regulatory actions, compliance with environmental regulations and conditions in the capital markets. 45



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Capital Structure

As of December 31, 2013 and 2012, our capital structure, excluding short-term debt, was as follows: As of December 31, 2013 2012 Common equity 47% 49% Noncontrolling interests <1% <1% Long-term debt, including VIEs 53% 51%



Short-Term Borrowings

In 2011, Westar Energy entered into a commercial paper program pursuant to which it may issue commercial paper up to a maximum aggregate amount outstanding at any one time of $1.0 billion. This program is supported by Westar Energy's revolving credit facilities. Maturities of commercial paper issuances may not exceed 365 days from the date of issuance and proceeds from such issuances will be used to temporarily fund capital expenditures, to repay borrowings under Westar Energy's revolving credit facilities, for working capital and/or for other general corporate purposes. As of February 18, 2014, Westar Energy had issued $177.8 million of commercial paper. Westar Energy has two revolving credit facilities in the amounts of $730.0 million and $270.0 million. In July 2013, Westar Energy extended the term of the $730.0 million facility to September 2017, and in February 2014, Westar Energy extended the term of the $270.0 million credit facility to February 2017, provided that $20.0 million of this facility will terminate in February 2016. As long as there is no default under the facility, the $730.0 million facility may be extended an additional year and the aggregate amount of borrowings under the $730.0 million and $270.0 million facilities may be increased to $1.0 billion and $400.0 million, respectively, subject to lender participation. All borrowings under the facilities are secured by KGE first mortgage bonds. Total combined borrowings under the revolving credit facilities and the commercial paper program may not exceed $1.0 billion at any given time. As of February 18, 2014, no amounts were borrowed and $18.5 million of letters of credit had been issued under the $730.0 million facility. No amounts were borrowed and no letters of credit were issued under the $270.0 million facility as of the same date. A default by Westar Energy or KGE under other indebtedness totaling more than $25.0 million would be a default under both revolving credit facilities. Westar Energy is required to maintain a consolidated indebtedness to consolidated capitalization ratio of 65% or less at all times. At December 31, 2013, our ratio was 53%. See Note 8 of the Notes to Consolidated Financial Statements, "Short-Term Debt," for additional information regarding our short-term borrowings.



Long-Term Debt Financing

We have $250.0 million in outstanding aggregate principal amount of first mortgage bonds that are due July 1, 2014. We expect to issue additional long-term debt to redeem those bonds before the maturity date thereof.

In August 2013, Westar Energy issued $250.0 million principal amount of first mortgage bonds bearing stated interest of 4.625% and maturing in September 2043.

In June 2013, KGE redeemed two pollution control bond series with an aggregate principal amount of $100.0 million and stated interest rates of 5.60% and 6.00%.

In March 2013, Westar Energy issued $250.0 million principal amount of first mortgage bonds bearing stated interest of 4.10% and maturing in April 2043. Proceeds from these issuances were used to repay short-term debt, which had been used primarily to purchase capital equipment, to redeem bonds and for working capital and general corporate purposes.



As of December 31, 2013, we had $121.9 million of variable rate, tax-exempt bonds. While the interest rates for these bonds have been extremely low, we continue to monitor the credit markets and evaluate our options with respect to these bonds.

The Westar Energy and KGE mortgages each contain provisions restricting the amount of first mortgage bonds that can be issued by each entity. We must comply with such restrictions prior to the issuance of additional first mortgage bonds or other secured indebtedness. 46



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Under the Westar Energy mortgage, the issuance of bonds is subject to limitations based on the amount of bondable property additions. In addition, so long as any bonds issued prior to January 1, 1997, remain outstanding, the mortgage prohibits additional first mortgage bonds from being issued, except in connection with certain refundings, unless Westar Energy's unconsolidated net earnings available for interest, depreciation and property retirement (which as defined, does not include earnings or losses attributable to the ownership of securities of subsidiaries), for a period of 12 consecutive months within 15 months preceding the issuance, are not less than the greater of twice the annual interest charges on or 10% of the principal amount of all first mortgage bonds outstanding after giving effect to the proposed issuance. As of December 31, 2013, approximately $505.3 million principal amount of additional first mortgage bonds could be issued under the most restrictive provisions in the mortgage, except in connection with certain refundings. Under the KGE mortgage, the issuance of bonds is subject to limitations based on the amount of bondable property additions. In addition, the mortgage prohibits additional first mortgage bonds from being issued, except in connection with certain refundings, unless KGE's net earnings before income taxes and before provision for retirement and depreciation of property for a period of 12 consecutive months within 15 months preceding the issuance are not less than either two and one-half times the annual interest charges on or 10% of the principal amount of all KGE first mortgage bonds outstanding after giving effect to the proposed issuance. As of December 31, 2013, approximately $1.1 billion principal amount of additional KGE first mortgage bonds could be issued under the most restrictive provisions in the mortgage. Some of our debt instruments contain restrictions that require us to maintain leverage ratios as defined in the credit agreements. We calculate these ratios in accordance with the agreements and they are used to determine compliance with our various debt covenants. We were in compliance with these covenants as of December 31, 2013.



Impact of Credit Ratings on Debt Financing

Moody's Investors Service (Moody's), Standard & Poor's Ratings Services (S&P) and Fitch Ratings (Fitch) are independent credit-rating agencies that rate our debt securities. These ratings indicate each agency's assessment of our ability to pay interest and principal when due on our securities. In general, more favorable credit ratings increase borrowing opportunities and reduce the cost of borrowing. Under Westar Energy's revolving credit facilities and commercial paper program, our cost of borrowings is determined in part by credit ratings. However, Westar Energy's ability to borrow under the credit facilities and commercial paper program are not conditioned on maintaining a particular credit rating. We may enter into new credit agreements that contain credit rating conditions, which could affect our liquidity and/or our borrowing costs. Factors that impact our credit ratings include a combination of objective and subjective criteria. Objective criteria include typical financial ratios, such as total debt to total capitalization and funds from operations to total debt, among others, future capital expenditures and our access to liquidity including committed lines of credit. Subjective criteria include such items as the quality and credibility of management, the political and regulatory environment we operate in and an assessment of our governance and risk management practices. In January 2014, Moody's upgraded its ratings for Westar Energy and KGE first mortgage bonds to A2 from A3. In February 2013, S&P revised its criteria for rating utility first mortgage bonds and, as a result, upgraded its ratings for Westar Energy and KGE first mortgage bonds/senior secured debt to A- from BBB+. Additionally, in April 2013, S&P affirmed its ratings for Westar Energy and KGE and raised its outlook to positive from stable. As of February 18, 2014, our ratings with the agencies are as shown in the table below. Westar Energy KGE First First Mortgage Mortgage Bond Bond Rating Rating Rating Westar Energy Commercial Paper Outlook Moody's A2 A2 P-2 Stable S&P A- A- A-2 Positive Fitch A- A- F2 Stable 47



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Table of Contents Common and Preferred Stock Common Stock



Westar Energy's Restated Articles of Incorporation, as amended, provide for 275.0 million authorized shares of common stock. As of December 31, 2013, Westar Energy had 128.3 million shares issued and outstanding.

In September 2013, Westar Energy entered into two forward sale agreements with two banks. Under the terms of the agreements, the banks, as forward sellers, borrowed 8.0 million shares of Westar Energy's common stock from third parties and sold them to a group of underwriters for $31.15 per share. Pursuant to over-allotment options granted to the underwriters, the underwriters purchased in October 2013, an additional 0.9 million shares from the banks as forward sellers, increasing the total number of shares under the forward sale agreements to approximately 8.9 million. The underwriters received a commission equal to 3.5% of the sales price of all shares sold under the agreements. Westar Energy must settle such transactions within 24 months. In March 2013, Westar Energy entered into a new, three-year sales agency financing agreement and master forward sale confirmation with a bank, similar to the sales agency financing agreement and master forward sale confirmation entered into in April 2010. The maximum amount that Westar Energy may offer and sell under the March 2013 master agreements is the lesser of an aggregate of $500.0 million or approximately 25.0 million shares, subject to adjustment for share splits, share combinations and share dividends. Under the terms of the sales agency financing agreement, Westar Energy may offer and sell shares of its common stock from time to time. In addition, under the terms of the March 2013 sales agency financing agreement and master forward sale confirmation, Westar Energy may from time to time enter into one or more forward sale transactions with the bank, as forward purchaser, and the bank will borrow shares of Westar Energy's common stock from third parties and sell them through its agent. The agent receives a commission equal to 1% of the sales price of all shares sold under the agreements. Westar Energy must settle the forward sale transactions within 18 months of the date each transaction is entered. In April 2010, Westar Energy entered into a three-year Sales Agency Financing Agreement and forward sale agreement with a bank that was terminated in March 2013. The maximum amount that Westar Energy could offer and sell under the agreements was the lesser of an aggregate of $500.0 million or approximately 22.0 million shares, subject to adjustment for share splits, share combinations and share dividends. Under the terms of the Sales Agency Financing Agreement, Westar Energy could offer and sell shares of its common stock from time to time through the broker dealer subsidiary, as agent. The broker dealer received a commission equal to 1% of the sales price of all shares sold under the agreement. In addition, under the terms of the Sales Agency Financing Agreement and forward sale agreement, Westar Energy could from time to time enter into one or more forward sale transactions with the bank, as forward purchaser, and the bank will borrow shares of Westar Energy's common stock from third parties and sell them through its broker dealer. Westar Energy was required to settle the forward sale transactions within 18 months of the date each transaction was entered. In 2011 and 2010, Westar Energy entered into and settled forward sale transactions with respect to an aggregate of approximately 5.4 million shares of common stock for proceeds of approximately $118.3 million. During 2013 and 2012, Westar Energy entered into additional forward sale transactions with respect to an aggregate of approximately 2.5 million and 1.8 million shares of common stock respectively, under the March 2013 and April 2010 agreements. During 2013, Westar Energy settled 1.1 million shares, resulting in 3.1 million shares under the March 2013 and April 2010 agreements that had not settled as of December 31, 2013. In February 2014, Westar Energy settled 0.3 million shares with a physical settlement amount of approximately $9.2 million. The forward sale transactions are entered into at market prices; therefore, the forward sale agreements have no initial fair value. Westar Energy does not receive any proceeds from the sale of common stock under the forward sale agreements until transactions are settled. Upon settlement, Westar Energy will record the forward sale agreements within equity. Except in specified circumstances or events that would require physical share settlement, Westar Energy is able to elect to settle any forward sale transactions by means of physical share, cash or net share settlement, and is also able to elect to settle the forward sale transactions in whole, or in part, earlier than the stated maturity dates. Currently, Westar Energy anticipates settling the forward sale transactions through physical share settlement. The shares under the forward sale agreements are initially priced when the transactions are entered into and are subject to certain fixed pricing adjustments during the term of the agreements. Accordingly, assuming physical share settlement, Westar Energy's net proceeds from the forward sale transactions will represent the prices established by the forward sale agreements applicable to the time periods in which physical settlement occurs. 48



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Assuming physical share settlement of the approximately 12.1 million shares associated with all forward sale transactions as of December 31, 2013, Westar Energy would have received aggregate proceeds of approximately $358.3 million based on a weighted average forward price of $29.73 per share.



Westar Energy used the proceeds from the issuance of common stock to repay short-term borrowings, with such borrowed amounts principally related to investments in capital equipment, as well as for working capital and general corporate purposes.

Preferred Stock Redemption In May 2012, Westar Energy provided an irrevocable notice of redemption to holders of all of Westar Energy's preferred shares. Pursuant to Westar Energy's Articles of Incorporation, we deposited cash in a separate account to effect the redemption of all of our preferred stock outstanding. Payment was due to holders of the preferred shares effective July 1, 2012. The table below shows the redemption amounts for all series of preferred stock. Total Principal Call Cost Rate Shares Outstanding Price Premium to Redeem (Dollars in Thousands) 4.50% 121,613 $ 12,161 108.0% $ 973$ 13,134 4.25% 54,970 5,497 101.5% 82 5,579 5.00% 37,780 3,778 102.0% 76 3,854 214,363 $ 21,436$ 1,131$ 22,567 Summary of Cash Flows Year Ended December 31, 2013 2012 2011 (In Thousands) Cash flows from (used in): Operating activities $ 702,803$ 599,106$ 462,696 Investing activities (641,901 ) (797,337 ) (701,516 ) Financing activities (62,244 ) 200,521 241,431 Net (decrease) increase in cash and cash equivalents $ (1,342 )$ 2,290$ 2,611



Cash Flows from Operating Activities

Cash flows from operating activities increased $103.7 million in 2013 compared to 2012 due principally to our having received about $74.3 million more from retail and wholesale customers, our having paid approximately $40.9 million less for pension and post retirement contributions, our having paid $29.7 million in 2012 to settle treasury yield hedge transactions, and our receiving $9.6 million more in COLI death proceeds. Increases were offset partially by our having paid approximately $65.6 million more for the planned Wolf Creek refueling and maintenance outage. The $136.4 million increase in 2012 compared to 2011 was due principally to our having paid approximately $100.9 million less for fuel and purchased power, our having received about $96.3 million more from retail customers and our having paid $56.3 million in 2011 to settle litigation. Increases were offset partially by our having received approximately $42.0 million less from wholesale customers, our having paid $29.7 million in 2012 to settle treasury yield hedge transactions, our having received $13.1 million less in income tax refunds and our having contributed $10.3 million more to pension and post-retirement benefit plans.



Cash Flows used in Investing Activities

Cash flows used in investing activities decreased $155.4 million from 2012 to 2013 due primarily to increased proceeds from investment in corporate owned life insurance of $114.1 million and decreased investment in property, plant and equipment of $30.1 million. 49



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Cash flows used in investing activities increased $95.8 million from 2011 to 2012 due primarily to our having invested an additional $112.8 million in additions to property, plant and equipment, which was attributable principally to additions at our power plants, including air quality controls, and the addition of transmission facilities. The increased investment in 2012 was partially offset by our having received $32.2 million more in proceeds from our investment in COLI.



Cash Flows from (used in) Financing Activities

Cash flows from financing activities decreased $262.8 million in 2013 compared to 2012. The decrease was due primarily to our having borrowed $258.1 million less in short term debt and our having repaid $110.6 million more for borrowings against the cash surrender value of corporate owned life insurance. This decrease was partially offset by our having paid $120.6 million less to retire long-term debt. The $40.9 million decrease in 2012 compared to 2011 was due principally to our having received $287.9 million less in proceeds from the issuance of common stock, which was attributable principally to our having issued shares in 2011 to settle forward transactions, and our having retired $220.2 million more of long-term debt due to favorable conditions in the capital markets. Contributing to the decrease was our having repaid $31.4 million more for borrowings against the cash surrender value of COLI, our having established a $22.6 million restricted cash account to fund the redemption of preferred stock and our having paid $19.9 million more for dividends as a result principally of our having increased our common stock dividend from $1.28 per share in 2011 to $1.32 per share in 2012. Partially offsetting the decreases was our having received $541.4 million in proceeds from long-term debt issuances. The proceeds were used to repay short-term debt, which was used to purchase capital equipment, to redeem bonds, and for working capital and general corporate purposes.



Future Cash Requirements

Our business requires significant capital investments. Through 2016, we expect to need cash primarily for utility construction programs designed to improve and expand facilities related to providing electric service, which include, but are not limited to, expenditures for environmental projects at our coal-fired power plants, new transmission lines and other improvements to our power plants, transmission and distribution lines, and equipment. We expect to meet these cash needs with internally generated cash, short-term borrowings and the issuance of securities in the capital markets. We have incurred and expect to continue to incur significant costs to comply with existing and future environmental laws and regulations, which are subject to changing interpretations and amendments. Changes to environmental regulations could result in significantly more stringent laws and regulations or interpretations thereof that could affect us and our industry in particular. These laws, regulations and interpretations could result in more stringent terms in our existing operating permits or a failure to obtain new permits could cause a material increase in our capital or operational costs and could otherwise have a material effect on our operations and consolidated financial results.



Capital expenditures for 2013 and anticipated capital expenditures, including costs of removal, for 2014 through 2016 are shown in the following table.

Actual 2013 2014 2015 2016 (In Thousands) Generation: Replacements and other $ 201,395$ 181,600$ 173,100$ 136,800 Environmental 262,441 237,000 112,000 21,900 Nuclear fuel 4,129 52,900 28,600 30,200 Transmission (a) 168,662 179,100 186,900 203,400 Distribution 107,993 137,200 147,700 157,300 Other 35,478 26,200 30,700 41,400



Total capital expenditures $ 780,098$ 814,000$ 679,000$ 591,000

_______________

(a) In addition to amounts listed, we are investing in Prairie Wind

Transmission. In 2013, we incurred $4.0 million of expenditures related to

this investment. In 2014 we plan to incur expenditures related to Prairie

Wind Transmission of $6.7 million. We do not anticipate any further investment related to Prairie Wind Transmission in 2015 and 2016. 50



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We prepare these estimates for planning purposes and revise them from time to time. Actual expenditures will differ, perhaps materially, from our estimates due to changing regulatory requirements, changing costs, delays or advances in engineering, construction or permitting, changes in the availability and cost of capital, and other factors discussed in "Item 1A. Risk Factors." We and our generating plant co-owners periodically evaluate these estimates and this may result in possibly material changes in actual costs. In addition, these amounts do not include any estimates for potential new environmental requirements.



We will also need significant amounts of cash in the future to meet our long-term debt obligations. The principal amounts of our long-term debt maturities as of December 31, 2013, are as follows.

Long-term Year Long-term debt debt of VIEs (In Thousands) 2014 $ 250,000$ 27,479 2015 - 27,933 2016 - 28,309 2017 125,000 26,842 2018 300,000 28,538 Thereafter 2,549,440 82,581 Total maturities $ 3,224,440$ 221,682 Pension Obligation The amount we contribute to our pension plan for future periods is not yet known, however, we expect to fund our pension plan each year at least to a level equal to current year pension expense. We must also meet minimum funding requirements under the Employee Retirement Income Security Act, as amended by the Pension Protection Act. We may contribute additional amounts from time to time as deemed appropriate. We contributed $27.5 million to our pension trust in 2013 and $56.7 million in 2012. We expect to contribute approximately $30.8 million in 2014. In 2013 and 2012, we also funded $7.6 million and $13.9 million, respectively, of Wolf Creek's pension plan contributions. In 2014, we plan to contribute $5.4 million to fund Wolf Creek's pension plan contributions. See Notes 11 and 12 of the Notes to Consolidated Financial Statements, "Employee Benefit Plans" and "Wolf Creek Employee Benefit Plans," for additional discussion of Westar Energy and Wolf Creek benefit plans, respectively.



OFF-BALANCE SHEET ARRANGEMENTS

As discussed under "-Common Stock" above and in Note 16 of the Notes to Consolidated Financial Statements, "Common Stock," Westar Energy entered into several forward sale agreements with banks in 2013. The forward sale agreements are off-balance sheet arrangements. We also have off-balance sheet arrangements in the form of operating leases and letters of credit entered into in the ordinary course of business. We did not have any additional off-balance sheet arrangements as of December 31, 2013.



CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS

In the course of our business activities, we enter into a variety of contracts and commercial commitments. Some of these result in direct obligations reflected on our consolidated balance sheets while others are commitments, some firm and some based on uncertainties, not reflected in our underlying consolidated financial statements. 51



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Contractual Cash Obligations

The following table summarizes the projected future cash payments for our contractual obligations existing as of December 31, 2013.

Total 2014 2015 - 2016 2017 - 2018 Thereafter (In Thousands) Long-term debt (a) $ 3,224,440$ 250,000 $ - $ 425,000$ 2,549,440

Long-term debt of VIEs (a) 221,682 27,479 56,242 55,380 82,581 Interest on long-term debt (b) 2,698,143 173,875 317,749 308,093 1,898,426 Interest on long-term debt of VIEs 50,209 12,183 19,128 12,594 6,304 Long-term debt, including interest 6,194,474 463,537 393,119 801,067 4,536,751 Pension and post-retirement benefit expected contributions (c) 39,700 39,700 - - - Capital leases (d) 99,044 6,464 11,070 9,375 72,135 Operating leases (e) 65,588 14,384 22,212 13,631 15,361 Other obligations of VIEs (f) 14,980 1,038 3,626 10,316 - Fossil fuel (g) 1,287,180 199,289 350,411 347,846 389,634 Nuclear fuel (h) 282,569 42,196 39,303 44,806 39,443 156,264 Transmission service (i) 33,791 7,267 12,133 5,399 8,992 Unconditional purchase obligations 312,171 258,293 46,415 7,463 - Total contractual obligations (j) $ 8,329,497$ 1,032,168$ 878,289$ 1,239,903$ 5,179,137 _______________



(a) See Note 9 of the Notes to Consolidated Financial Statements, "Long-Term

Debt," for individual maturities.

(b) We calculate interest on our variable rate debt based on the effective

interest rates as of December 31, 2013.

(c) Our contribution amounts for future periods are not yet known. See Notes 11

and 12 of the Notes to Consolidated Financial Statements, "Employee Benefit

Plans" and "Wolf Creek Employee Benefit Plans," for additional information

regarding pension and post-retirement benefits.

(d) Includes principal and interest on capital leases.

(e) Includes leases for operating facilities, operating equipment, office space,

office equipment, vehicles and rail cars as well as other miscellaneous

commitments.

(f) See Note 17 of the Notes to Consolidated Financial Statements, "Variable

Interest Entities," for additional information on VIEs.

(g) Coal and natural gas commodity and transportation contracts.

(h) Uranium concentrates, conversion, enrichment, fabrication and spent nuclear

fuel disposal.

(i) Includes obligations to SPP for transmission service payments. See Note 13 of

the Notes to Consolidated Financial Statements, "Commitments and

Contingencies," for additional information.

(j) We have $1.9 million of unrecognized income tax benefits, including interest,

that are not included in this table because we cannot reasonably estimate the

timing of the cash payments to taxing authorities assuming those unrecognized

income tax benefits are settled at the amounts accrued as of December 31,

2013. Commercial Commitments Our commercial commitments as of December 31, 2013, consist of outstanding letters of credit that expire in 2014, some of which automatically renew annually. The letters of credit are comprised of $11.7 million related to new transmission projects, $3.3 million related to energy marketing and trading activities, $0.8 million related to workers' compensation, and $3.4 million related to other operating activities, for a total outstanding balance of $19.2 million. 52



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Table of Contents OTHER INFORMATION Changes in Prices KCC Proceedings We filed an application with the KCC in February 2014 to adjust our prices to include updated transmission costs as reflected in our transmission formula rate effective in January 2014 discussed below. If approved, we estimate that the new prices will increase our annual retail revenues by approximately $43.6 million. We expect the KCC to issue an order on our request in March 2014.



In December 2013, the KCC approved an order allowing us to adjust our prices to include costs incurred for property taxes. The new prices were effective in January 2014 and are expected to increase our annual retail revenues by approximately $12.7 million.

In November 2013, the KCC issued an order allowing us to adjust our prices to include the additional investment in the La Cygne environmental upgrades and to reflect cost reductions elsewhere. The new prices are expected to increase our annual retail revenues by approximately $30.7 million. In May 2013, the KCC issued an order allowing us to adjust our prices to include costs associated with 2012 investments in environmental projects. The new prices were effective in June 2013 and are expected to increase our annual retail revenues by approximately $27.3 million. In March 2013, we adjusted our prices to included updated transmission costs as reflected in the transmission formula rate discussed below. The KCC issued an order in July 2013 approving our adjustment which is expected to increase our annual retail revenues by approximately $11.8 million.



FERC Proceedings

In October 2013, we posted our updated transmission formula rate that includes projected 2014 transmission capital expenditures and operating costs. The updated rate was effective in January 2014 and is expected to increase our annual transmission revenues by approximately $44.3 million.

Our transmission formula rate that includes projected 2013 transmission capital expenditures and operating costs was effective in January 2013 and is expected to increase our annual transmission revenues by approximately $12.2 million. This updated rate provided the basis for our request with the KCC to adjust our retail prices to include updated transmission costs as discussed above.



Wolf Creek Outage

Wolf Creek normally operates on an 18-month planned refueling and maintenance outage schedule. However, as a result of an unscheduled maintenance outage at Wolf Creek in 2012 coupled with the longer than planned refueling and maintenance outage in 2011, we were able to defer the fall 2012 planned refueling and maintenance outage to the first quarter of 2013. The next planned refueling and maintenance outage will be in the first quarter of 2015. During the first quarter of 2014, Wolf Creek will undergo a planned maintenance outage. The outage is not part of a refueling outage and therefore will be expensed as incurred. We expect our share of the 2014 outage costs to be approximately $9.0 million. New Financial Regulation In 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) was signed into law. Although the Dodd-Frank Act is focused primarily on the regulation and oversight of financial institutions, it also calls for new regulation of the derivatives markets, including mandatory clearing of certain swaps, exchange trading, margin requirements and other transparency requirements, which could impact our operations and consolidated financial results. We do not expect compliance with related regulations to have a significant impact on our business. 53



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Stock-Based Compensation

We use two types of restricted share units (RSUs) for our stock-based compensation awards; those with service requirements and those with performance measures. See Note 11 of the Notes to Consolidated Financial Statements, "Employee Benefit Plans," for additional information. Total unrecognized compensation cost related to RSU awards with only service requirements was $4.4 million as of December 31, 2013, and we expect to recognize these costs over a remaining weighted-average period of 1.7 years. Total unrecognized compensation cost related to RSU awards with performance measures was $4.0 million as of December 31, 2013, and we expect to recognize these costs over a remaining weighted-average period of 1.7 years.


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