ITEM 1. BUSINESS

GENERAL

Overview

We are the largest electric utility in Kansas. Unless the context otherwise indicates, all references in this Annual Report on Form 10-K to "the company," "we," "us," "our" and similar words are to Westar Energy, Inc. and its consolidated subsidiaries. The term "Westar Energy" refers to Westar Energy, Inc., a Kansas corporation incorporated in 1924, alone and not together with its consolidated subsidiaries.

We provide electric generation, transmission and distribution services to approximately 693,000 customers in Kansas. Westar Energy provides these services in central and northeastern Kansas, including the cities of Topeka, Lawrence, Manhattan, Salina and Hutchinson. Kansas Gas and Electric Company (KGE), Westar Energy's wholly owned subsidiary, provides these services in south-central and southeastern Kansas, including the city of Wichita. Both Westar Energy and KGE conduct business using the name Westar Energy. Our corporate headquarters is located at 818 South Kansas Avenue, Topeka, Kansas 66612.

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.

OPERATIONS

General

As noted above, we supply electric energy at retail to customers in Kansas. We also supply electric energy at wholesale to municipalities and electric cooperatives in Kansas, and have contracts for the sale or purchase of wholesale electricity with other utilities.

Following is the percentage of our revenues by customer classification. Classification of customers as residential, commercial and industrial requires judgment and our classifications may be different from other companies. Assignment of tariffs is not dependent on classification.

The percentage of our retail electricity sales by customer class was as follows.

In November, 2013 we entered into a renewable energy purchase agreement. Under the agreement, we plan to purchase an additional 200 MW of installed designed capacity to be delivered by the end of 2016.

Our aggregate 2013 peak system net load of 5,186 MW occurred in July 2013. Our net generating capacity, combined with firm capacity purchases and sales and potentially interruptible load, provided a capacity margin of 19% above system peak responsibility at the time of our 2013 peak system net load, which satisfied Southwest Power Pool (SPP) planning requirements.

Under wholesale agreements, we provide firm generating capacity to other entities as set forth below.

Fossil Fuel Generation

The effectiveness of a fuel to produce heat is measured in British thermal units (Btu). The higher the Btu content of a fuel, the smaller volume of fuel required to produce a given amount of electricity. We measure the quantity of heat consumed during the generation of electricity in millions of Btu (MMBtu).

Coal

Jeffrey Energy Center (JEC): The three coal-fired units at JEC have an aggregate capacity of 2,155 MW, of which we own or consolidate through a variable interest entity (VIE) a combined 92% share, or 1,983 MW. We have a long-term coal supply contract with Alpha Natural Resources, Inc. to supply coal to JEC from surface mines located in the Powder River Basin (PRB) in Wyoming. The contract contains a schedule of minimum annual MMBtu quantities. All of the coal used at JEC is purchased under this contract, which expires December 31, 2020. The contract provides for price escalation based on certain costs of production. The price for quantities purchased in excess of the scheduled annual minimum is subject to renegotiation every five years to provide an adjusted price for the ensuing five years that reflects the market prices at the time of renegotiation. The most recent price adjustment was effective January 1, 2013.

The BNSF Railway Company (BNSF) and Union Pacific Railroad Company transport coal to JEC under a long-term rail transportation contract. The contract term continues through December 31, 2020, at which time we plan to enter into a new contract. The contract price is subject to price escalation based on certain costs incurred by the railroads.

    

The average delivered cost of coal consumed at JEC during 2013 was approximately $1.77 per MMBtu, or $29.22 per ton.

La Cygne Generating Station (La Cygne): The two coal-fired units at La Cygne have an aggregate generating capacity of 1,418 MW, of which we own or consolidate, through a VIE a 50% share, or 709 MW. La Cygne uses primarily PRB coal but one of the two units also uses a small portion of locally-mined coal. The operator of La Cygne, Kansas City Power & Light Company (KCPL), arranges coal purchases and transportation services for La Cygne. Approximately 70%, 40% and 20% of La Cygne's PRB coal requirements are under contract for 2014, 2015 and 2016, respectively. About 80% of those commitments under contract for 2014 are fixed price and all of those commitments under contract are fixed price for 2015 and 2016. As the PRB coal contracts expire, we anticipate that KCPL will negotiate new supply contracts or purchase coal on the spot market.

All of the La Cygne PRB coal is transported under KCPL's rail transportation agreements with BNSF through 2018 and Kansas City Southern Railroad through 2020. During 2013 , our share of average delivered cost of coal consumed at La Cygne was approximately $2.06 per MMBtu, or $35.81 per ton.

Lawrence and Tecumseh Energy Centers: Lawrence and Tecumseh Energy Centers have an aggregate generating capacity of 732 MW. We purchase PRB coal for these energy centers under a contract with Arch Coal, Inc., which we expect to provide 100% of the coal requirements through 2014. BNSF transports coal for these energy centers under a contract that expires in December 2020, at which time we plan to enter into a new contract.

During 2013 , the average delivered cost of coal consumed in the Lawrence units was approximately $1.78 per MMBtu, or $31.43 per ton. The average delivered cost of coal consumed in the Tecumseh units was approximately $1.74 per MMBtu, or $30.96 per ton.

Natural Gas

We use natural gas as a primary fuel at our Gordon Evans, Murray Gill, Hutchinson, Spring Creek and Emporia Energy Centers, at the State Line facility and in the gas turbine units at Tecumseh Energy Center. We can also use natural gas as a supplemental fuel in the coal-fired units at Lawrence and Tecumseh Energy Centers. During 2013 , we consumed 19.0 million MMBtu of natural gas for a total cost of $83.8 million, or approximately $ 4.41 per MMBtu. Natural gas accounted for approximately 7% of the total MMBtu of fuel we consumed and approximately 16% of our total fuel expense in 2013 . From time to time, we may enter into contracts, including the use of derivatives, in an effort to manage the cost of natural gas. For additional information about our exposure to commodity price risks, see "Item 7A. Quantitative and Qualitative Disclosures About Market Risk."

We maintain a natural gas transportation arrangement for Hutchinson Energy Center with Kansas Gas Service. The agreement has historically expired on April 30 of each year and is renegotiated for an additional one year term. We meet a portion of our natural gas transportation requirements for Gordon Evans, Murray Gill, Lawrence, Tecumseh and Emporia Energy Centers through firm natural gas transportation capacity agreements with Southern Star Central Gas Pipeline (SSCGP ) . We meet all of the natural gas transportation requirements for the State Line facility through a firm transportation agreement with SSCGP. The firm transportation agreement that serves Gordon Evans and Murray Gill Energy Centers extends through April 1, 2020, and the agreement for Lawrence and Tecumseh Energy Centers expires April 1, 2030. The agreement for the State Line facility extends through July 30, 2017, while the agreement for Emporia Energy Center is in place until December 1, 2028, and is renewable for five-year terms thereafter. We meet all of the natural gas transportation requirements for Spring Creek Energy Center through an interruptible month-to-month transportation agreement with ONEOK Gas Transportation, LLC.

Diesel

We use diesel to start some of our coal generating stations, as a primary fuel in the Hutchinson No. 4 combustion turbine and in our diesel generators. We purchase No. 2 diesel in the spot market. We maintain quantities in inventory that we believe will allow us to facilitate economic dispatch of power and satisfy emergency requirements. We do not use significant amounts of diesel in our operations.

Nuclear Generation

General

Wolf Creek is a 1,164 MW nuclear power plant located near Burlington, Kansas. KGE owns a 47% interest in Wolf Creek, or 547 MW. Wolf Creek's operating license, issued by the NRC, is effective until 2045. Wolf Creek Nuclear Operating Corporation, an operating company owned by each of the plant's owners in proportion to their ownership share of the plant, operates the plant. The plant's owners pay operating costs proportionate to their respective ownership share.

Fuel Supply

Wolf Creek has on hand or under contract all of the uranium and conversion services needed to operate through September 2016 and approximately 70% of the uranium and conversion services needed after that date through March 2021. The owners also have under contract all of the uranium enrichment and fabrication services required to operate Wolf Creek through March 2027 and September 2025, respectively. All such agreements have been entered into in the ordinary course of business.

Operations and Regulation

Plant performance, including extended or unscheduled shutdowns of Wolf Creek, could cause us to purchase replacement power, rely more heavily on our other generating units and/or reduce amounts of power available for us to sell in the wholesale market. Plant performance also affects the degree of regulatory oversight and related costs. In early 2014, Wolf Creek will undergo a planned maintenance outage. Because the outage is not part of a refueling outage, the related costs will be expensed as incurred. We expect our share of the outage to be approximately $9.0 million .

Wolf Creek normally operates on an 18-month planned refueling and maintenance outage schedule. As authorized by our regulators, incremental maintenance costs of planned refueling and maintenance outages are deferred and amortized ratably over the period between planned outages. During outages at the plant, we meet our electric demand primarily with our other generating units and by purchasing power.

The NRC evaluates, monitors and rates various inspection findings and performance indicators for Wolf Creek based on safety significance. Although not expected, the NRC could impose an unscheduled plant shutdown due to security or safety concerns. Those concerns need not be related to Wolf Creek specifically, but could be due to concerns about nuclear power generally or circumstances at other nuclear plants in which we have no ownership.

See Note 13 of the Notes to Consolidated Financial Statements, "Commitments and Contingencies," for additional information regarding our nuclear operations.

 

Wind Generation

As discussed under "Environmental Matters—Renewable Energy Standard" below, Kansas law requires that our energy supply resources consist of a certain amount of renewable sources. For us, wind has been the primary source of renewable energy. As of December 31, 2013 , we owned approximately 149 MW of designed installed wind capacity and had under contract the purchase of wind energy produced from approximately 715 MW of designed installed wind capability. Of the 715 MW under contract, 200 MW are associated with an agreement pursuant to which a generation provider is scheduled to deliver power beginning in 2016.

Our wind production has no associated fuel costs and is, therefore, not included in the table above.

Purchased Power

In addition to generating electricity, we also purchase power.  Factors that cause us to purchase power include contractual arrangements, planned and unscheduled outages at our generating plants, favorable wholesale energy prices compared to our costs of production, weather conditions and other factors.  Transmission constraints may limit our ability to bring purchased electricity into our control area, potentially requiring us to curtail or interrupt our customers as permitted by our tariffs. In 2013 , purchased power comprised approximately 18% of our total fuel and purchased power expense. Our weighted average cost of purchased power per Megawatt hour (MWh) was $33.63 in 2013 , $26.41 in 2012 and $34.27 in 2011 .

Transmission

Regional Transmission Organization

The Federal Energy Regulatory Commission (FERC) requires owners of regulated transmission assets to allow third parties nondiscriminatory access to their transmission systems. We are a member of the SPP RTO and transferred the functional control of our transmission system, including the approval of transmission service, to the SPP. The SPP coordinates the operation of our transmission system within an interconnected transmission system that covers all or portions of nine states. The SPP collects revenues for the use of each transmission owner's transmission system. Transmission customers transmit power purchased and generated for sale or bought for resale in the wholesale market throughout the entire SPP system. Transmission capacity is sold on a first come/first served non-discriminatory basis. All transmission customers are charged rates applicable to the transmission system in the zone where energy is delivered, including transmission customers that may sell power inside our certificated service territory. The SPP then distributes as revenue to transmission owners the amounts it collects from transmission users less an amount it retains to cover administrative expenses.

Developing Forward Market in SPP

The SPP is scheduled to launch an Integrated Marketplace (IM) in March 2014. The SPP IM will be similar to other organized power markets currently operating in other RTOs. The SPP IM will change how we currently sell the output from our generation facilities and buy power to meet the needs of our customers. The SPP will have the authority to start and stop generating units participating in the market and will select the lowest cost resource mix to meet the needs of the various SPP customers while ensuring reliable operations of the transmission system. As with other organized markets, there will be additional market related products, revenues, and charges. Westar recently submitted the necessary regulatory filings seeking to recognize the associated revenues and charges in the prices we charge our customers, similar to our current retail energy cost adjustment tariff.

Regulation and Our Prices

Kansas law gives the Kansas Corporation Commission (KCC) general regulatory authority over our prices, extensions and abandonments of service and facilities, the classification of accounts, the issuance of some securities and various other matters. We are also subject to the jurisdiction of FERC, which has authority over wholesale electricity sales, including prices, the transmission of electric power, and the issuance of some securities. We are subject to the jurisdiction of the NRC for nuclear plant operations and safety. Regulatory authorities have established various methods permitting adjustments to our prices for the recovery of costs. For portions of our cost of service, regulators allow us to adjust our prices periodically through the application of formulae that track changes in our costs, which reduce the time between making expenditures or investments and reflecting them in the prices we charge customers. However, for the remaining portions of our cost of service, we must file a general rate review, which lengthens the period of time between when we make and recover expenditures and a return on our investments. See Note 3 of the Notes to Consolidated Financial Statements, "Rate Matters and Regulation," for information regarding our rate proceedings with the KCC and FERC.

Environmental Matters

General

We are subject to various federal, state and local environmental laws and regulations. Environmental laws and regulations affecting our operations are overlapping, complex, subject to changes, have become more stringent over time and are expensive to implement. Such laws and regulations 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. These laws and regulations require a lengthy and complex process for obtaining licenses, permits and approvals from governmental agencies for new, existing or modified facilities. If we fail to comply with such laws, regulations and permits, or fail to obtain and maintain necessary permits, we could be fined or otherwise sanctioned by regulators, and such fines or the cost of sanctions may not be recoverable in our prices. We have incurred and will continue to incur significant capital and other expenditures to comply with environmental laws and regulations. We are currently permitted to recover certain of these costs through the environmental cost recovery rider (ECRR), which, in comparison to a general rate review, reduces the amount of time it takes to begin collecting in retail prices the costs associated with capital expenditures for qualifying environmental improvements. However, there can be no assurance that the costs to comply with existing or future environmental laws and regulations will not have a material effect on our operations or consolidated financial results. Certain key environmental issues, laws and regulations facing us are described further below.

Air Emissions

We must comply with the federal Clean Air Act, state laws and implementing federal and state regulations that impose, among other things, limitations on emissions generated from our operations, including sulfur dioxide (SO ₂ ), particulate matter (PM), nitrogen oxides (NOx), carbon monoxide (CO), mercury and acid gases.

Emissions from our generating facilities, including PM, SO ₂ and NOx, have been determined by regulation to reduce visibility by causing or contributing to regional haze. Under federal laws, such as the Clean Air Visibility Rule, and pursuant to an agreement with the Kansas Department of Health and Environment (KDHE) and the Environmental Protection Agency (EPA), we are required to install, operate and maintain controls to reduce emissions found to cause or contribute to regional haze. In addition, our power plants that burn fossil fuels emit carbon dioxide, which is also regulated under the Clean Air Act and for which the EPA is presently developing regulations.

Sulfur Dioxide and Nitrogen Oxide

Through the combustion of fossil fuels at our generating facilities, we emit SO ₂ and NOx. Federal and state laws and regulations, including those noted above, and permits issued to us limit the amount of these substances we can emit. If we exceed these limits we could be subject to fines and penalties. In order to meet SO ₂ and NOx regulations applicable to our generating facilities, we use low-sulfur coal and natural gas and have equipped some of our generating facilities with equipment to control such emissions.

We are subject to the SO ₂ allowance and trading program under the federal Clean Air Act Acid Rain Program. Under this program, each unit must have enough allowances to cover its SO ₂ emissions for that year. In 2013, we had adequate SO ₂ allowances to meet planned generation and we expect to have enough to cover emissions under this program in 2014.

Cross-State Air Pollution Rule     

In 2011, the EPA finalized the Cross-State Air Pollution Rule (CSAPR) requiring 28 states, including Kansas, Missouri and Oklahoma, to further reduce power plant emissions of SO ₂ and NOx beginning January 2012, with further reductions required beginning January 2014. In August 2012, the U.S. Court of Appeals for the District of Columbia Circuit vacated CSAPR and remanded the rule to the EPA to promulgate a replacement. This decision is now under review by the U.S. Supreme Court. We cannot at this time predict the outcome of the U.S. Supreme Court's review; however, based on our current and planned environmental controls, if the regulations were to be reinstated or replaced, either in part or in whole, we do not believe the impact on our operations and consolidated financial results would be material.

National Ambient Air Quality Standards

Under the federal Clean Air Act, the EPA sets National Ambient Air Quality Standards (NAAQS) for certain emissions considered harmful to public health and the environment, including two classes of PM, NOx (a precursor to ozone), CO and SO ₂ , 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 the EPA at five-year intervals. KDHE, our state environmental regulatory agency, 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 SO ₂ . 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.

Mercury and Other Air Emissions

The operation of power plants results in emissions of mercury, acid gases and other air toxics. In 2012 , the EPA's Mercury and Air Toxics Standards (MATS) for power plants became effective, replacing the prior federal Clean Air Mercury Rule (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

Byproducts of burning coal and other fossil fuels include carbon dioxide (CO ₂ ) and other gases referred to as greenhouse gases (GHGs), which are believed by many to contribute to climate change. The EPA has proposed using the federal Clean Air Act to limit CO ₂ and other GHG emissions, and other measures are being imposed or offered by individual states, municipalities and regional agreements with the goal of reducing GHG emissions.

In January 2014, the EPA re-proposed a New Source Performance Standard (NSPS) that would limit CO ₂ emissions for new coal and natural gas fueled generating units. The re-proposal would limit CO ₂ 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 CO ₂ 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 best available control technology (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 cost of compliance with the regulations could be material.

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 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.

Regulation of Coal Combustion Byproducts

In the course of operating our coal generation plants, we produce coal combustion byproducts (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 at the federal level, 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.

Renewable Energy Standard

Kansas law mandates that we maintain a minimum amount of renewable energy sources. Through 2015 , net renewable generation capability 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 capcaity 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.

Environmental Costs

As discussed above, environmental laws and regulations affecting our operations are evolving and becoming more stringent. As a result, we are making and will continue to make significant capital and operating expenditures to reduce regulated emissions. The amount of these expenditures could change materially depending on the timing and nature of required investments, the specific outcomes resulting from existing regulations, new regulations, legislation and the manner in which we operate our plants. The degree to which we will need to reduce certain emissions and the timing of when such emissions controls may be required is uncertain. Additionally, our ability to access capital markets and the availability of materials, equipment and contractors may affect the timing and amount of these capital investments.

We are not allowed to use the ECRR to collect approximately $610.0 million of the projected capital investment associated with environmental upgrades at La Cygne. 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 . To change our prices to collect increased operating and maintenance costs, we must file a general rate review with the KCC.

Our estimated capital expenditures associated with environmental improvements for 2014-2016 appear in the following table. We prepare these estimates for planning purposes and revise them from time to time.

In addition to the capital investment, in the event we install new equipment, such equipment may cause us to incur significant increases in annual operating and maintenance expenses and may reduce the net production, reliability and availability of the plants. Furthermore, enhancements to our power plants, even if they result in greater efficiency, can trigger a new source review, which could require additional control equipment. In order to change our prices to recognize increased operating and maintenance costs, we must file a general rate review with the KCC.

EPA Consent Decree

As part of a 2010 settlement of a lawsuit filed by the Department of Justice on behalf of the EPA, we are installing selective catalytic reduction (SCR) equipment on one of three JEC coal units by the end of 2014 , which we estimate will cost approximately $230.0 million . We are installing less expensive NOx reduction equipment on the other two units to satisfy other terms of the settlement. We plan to complete these projects in 2014 and recover the costs to install these systems through our ECRR, but such recovery remains subject to the approval of our regulators.

Safety and Health Regulation

The safety and health of our employees is vital to our business. We are subject to a number of federal and state laws and regulations, including the Occupational Safety and Health Act of 1970. We believe we have appropriate measures in place to ensure the safety and health of our employees and to monitor compliance with such laws and regulations.

    

Information Technology

Safeguarding information technology networks and systems is important to our business. There are risks associated with the unauthorized access, theft or accidental release of electronic data, which may result in the misappropriation or corruption of our information or cause operational disruptions. We believe these risks are getting increasingly larger and more sophisticated. We believe that we have taken appropriate measures to secure our information infrastructure from attacks or breaches and from accidental release of information, but notwithstanding such measures, the increasing sophistication of potential attacks may result in remaining vulnerabilities. See Item 1A, "Risk Factors," for additional information.

SEASONALITY

Our electricity sales and revenues are seasonal, with the third quarter typically accounting for the greatest of each. Our electricity sales are impacted by weather conditions, the economy of our service territory and other factors affecting customers' demand for electricity.

EMPLOYEES

As of February 18, 2014 , we had 2,302 employees. In 2013, we negotiated a contract extension with Locals 304 and 1523 of the International Brotherhood of Electrical Workers that extends through June 30, 2017. The contract covers 1,256 employees as of February 18, 2014 .

ACCESS TO COMPANY INFORMATION

Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K are available free of charge either on our Internet website at www.westarenergy.com or through requests addressed to our investor relations

department. These reports are available as soon as reasonably practicable after such material is electronically filed with, or furnished to, the SEC. The information contained on our Internet website is not part of this document.

Executive officers serve at the pleasure of the board of directors. There are no family relationships among any of the executive officers, nor any arrangements or understandings between any executive officer and other persons pursuant to which he was appointed as an executive officer.