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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

[X] ANNUAL REPORT PURSUANT TO SECTION 13 or 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2010

OR

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the transition period from                      to                     

Commission File Number 1-3523

WESTAR ENERGY, INC.

(Exact name of registrant as specified in its charter)

Securities registered pursuant to section 12(b) of the Act:

Securities registered pursuant to section 12(g) of the Act:

Preferred Stock, 4-1/2% Series, $100 par value

(Title of Class)

Indicate by check mark whether the registrant is a well-known seasoned issuer (as defined in Rule 405 of the Act).     Yes    X       No          

Indicate by check mark whether the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.     Yes              No    X  

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes    X       No          

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes    X      No          

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  [ X ]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company (as defined in Rule 12b-2 of the Act). Check one:

Large accelerated filer    X      Accelerated filer            Non-accelerated filer              Smaller reporting company          

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).  Yes              No    X  

The aggregate market value of the voting common equity held by non-affiliates of the registrant was approximately $2,391,619,392 at June 30, 2010.

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date.

DOCUMENTS INCORPORATED BY REFERENCE:

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GLOSSARY OF TERMS

The following is a glossary of frequently used abbreviations or acronyms that are found throughout this report.

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FORWARD-LOOKING STATEMENTS

Certain matters discussed in this Annual Report on Form 10-K 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. Such statements address future events and conditions concerning matters such as, but not limited to:

What happens in each case could vary materially from what we expect because of such things as:

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These lists are not all-inclusive because it is not possible to predict all factors. This report should be read in its entirety. No one section of this report deals with all aspects of the subject matter. The reader should not place undue reliance on any forward-looking statement, as forward-looking statements speak only as of the date such statements were made. We undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement was made.

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PART I

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 687,000 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. We strive to optimize flexibility in our planning and operations to be able to respond to uncertain and changing conditions. Working constructively with our regulators and public officials is also an important part of our strategy.

Significant elements of our strategy include maintaining a flexible and diverse energy supply portfolio. In doing so, presently we are making environmental upgrades to our coal-fired power plants, developing more wind generation and building and upgrading transmission facilities, in addition to developing systems and programs to help our customers use energy more efficiently. Following is a summary of recent progress we have made on significant elements of our strategy.

Our plans and expectations for 2011 and beyond include:

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OPERATIONS

General

Westar Energy supplies electric energy at retail to approximately 369,000 customers in central and northeast Kansas and KGE supplies electric energy at retail to approximately 318,000 customers in south-central and southeastern Kansas. We supply electric energy at wholesale to municipalities and electric cooperatives in Kansas. We also have contracts for the sale, purchase or exchange of wholesale electricity with other utilities. In addition, we engage in energy marketing and purchase and sell electricity in areas outside our retail service territory.

We have a retail energy cost adjustment (RECA) under which we are permitted to recover in our prices the cost of fuel consumed in generating electricity and purchased power needed to serve our retail customers. Through the RECA, we bill our customers for fuel and purchased power costs based on a quarter-ahead estimate. The RECA provides for an annual review by the Kansas Corporation Commission (KCC) to reconcile estimated and actual fuel and purchased power costs. The KCC uses this same method as the means by which we refund to retail and cost-based wholesale customers the margins we realize from market-based wholesale sales.

Generation Capacity

We have 6,756 MW of accredited generating capacity in service, 2,518 MW of which KGE owns or leases from variable interest entities (VIEs). See “Item 2. Properties” for additional information on our generating units. While we also own wind generation facilities with an installed design capacity of 149 MW, the intermittent nature of this type of production does not create any appreciable amount of accredited capacity. Our capacity and net generation by fuel type is summarized below.

In addition to owning and leasing generating capacity, we also have two agreements under which we purchase renewable energy from third parties that own wind generation facilities with a combined installed design capacity totaling 146 MW.

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Our aggregate 2010 peak system net load of 5,485 MW occurred on August 12, 2010. This included 137 MW of potentially interruptible load. Our net generating capacity, combined with firm capacity purchases and sales and potentially interruptible load, provided a capacity margin of 20% above system peak responsibility at the time of our 2010 peak system net load.

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

Generation Mix

The effectiveness of a fuel to produce heat is measured in British thermal units (Btu). The higher the Btu content of a fuel, the less fuel it takes to produce electricity. We measure the quantity of heat consumed during the generation of electricity in millions of Btu (MMBtu).

Based on MMBtu, our 2010 fuel mix was 78% coal, 15% nuclear and 7% natural gas, with diesel and oil making up less than 1%. Our generation mix fluctuates with the operation of Wolf Creek, variations in fuel costs, plant availability, customer demand, and the cost and availability of power in the wholesale market.

Fossil Fuel Generation

Coal

Jeffrey Energy Center (JEC): The three coal-fired units at JEC have an aggregate capacity of 2,165 MW, of which we own or lease a combined 92% share, or 1,992 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 delivery 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 then current market prices. The next re-pricing for those quantities over the scheduled annual minimum will occur in 2013.

The Burlington Northern Santa Fe Railway (BNSF) and Union Pacific Railroad transport coal from the PRB to JEC under a long-term rail transportation contract. The contract term continues through December 31, 2013. The contract price is subject to price escalation based on certain costs incurred by the railroads. We expect increases in the cost of transporting coal due to higher prices for the items subject to contractual escalation.

The average delivered cost of coal consumed at JEC during 2010 was approximately $1.60 per MMBtu, or $26.39 per ton.

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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 lease a 50% share, or 709 MW. La Cygne unit 1 uses a blended fuel mix containing approximately 90% PRB coal and 10% Kansas/Missouri coal, the latter of which is purchased from time to time from Kansas and Missouri producers. La Cygne unit 2 uses PRB coal. The operator of La Cygne, Kansas City Power & Light Company (KCPL), arranges coal purchases and transportation services for La Cygne. Approximately 80% of La Cygne unit 1 and unit 2 PRB coal requirements is under contract for 2011. Approximately 50% of the requirements for 2012 and 2013 and 40% of the 2014 requirements are also under contract. Up to 75% of those commitments are fixed price contracts. All of the La Cygne PRB coal is transported under KCPL’s rail transportation agreements with BNSF through 2013 and Kansas City Southern Railroad through 2020. As the PRB coal contracts expire, we anticipate that KCPL will negotiate new supply contracts or purchase coal on the spot market.

During 2010, the average delivered cost of our share of coal consumed at La Cygne unit 1 was approximately $1.38 per MMBtu, or $23.23 per ton. The average delivered cost of our share of coal consumed at La Cygne unit 2 was approximately $1.24 per MMBtu, or $20.91 per ton.

Lawrence and Tecumseh Energy Centers: The units located at Lawrence and Tecumseh Energy Centers have an aggregate generating capacity of 773 MW. We purchase PRB coal for these two energy centers under a contract with Arch Coal, Inc., which we expect to provide 100% of the coal requirements for the energy centers through 2012. BNSF transports coal for these energy centers under a contract that expires in December 2013.

During 2010, the average delivered cost of coal consumed in the Lawrence units was approximately $1.69 per MMBtu, or $29.78 per ton. The average delivered cost of coal consumed in the Tecumseh units was approximately $1.66 per MMBtu, or $29.34 per ton.

Natural Gas

We use natural gas as a primary fuel at our Gordon Evans, Murray Gill, Neosho, Abilene, 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 2010, we consumed 21.3 million MMBtu of natural gas for a total cost of $109.0 million. Natural gas accounted for approximately 7% of our total MMBtu of fuel consumed during 2010 and approximately 21% of our total fuel expense. From time to time, we may enter into contracts, including the use of derivatives, in an effort to manage the overall 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 natural gas transportation arrangements for Abilene and Hutchinson Energy Centers with Kansas Gas Service, a division of ONEOK, Inc. (ONEOK). Abilene Energy Center is covered under a standard tariff as a large industrial transportation customer while Hutchinson Energy Center is covered under a rate agreement that expires on April 30, 2011. We plan to renegotiate the agreement for Hutchinson Energy Center prior to its expiration. 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 natural gas transportation agreement with SSCGP. The firm transportation agreement that serves Gordon Evans and Murray Gill Energy Centers extends through April 1, 2020. The agreement for the State Line facility extends through April 9, 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 natural gas transportation agreement with ONEOK Gas Transportation, LLC.

Diesel and Oil

Once started with natural gas, the steam units at our Gordon Evans, Murray Gill, Neosho and Hutchinson Energy Centers have the capability to burn No. 6 oil or natural gas. We may use No. 6 oil when natural gas is unavailable. During 2010, we did not use No. 6 oil.

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We also use No. 2 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, satisfy emergency requirements and protect against reduced availability of natural gas for limited periods.

During 2010, we consumed 0.2 million MMBtu of diesel at a total cost of $3.8 million. Diesel accounted for less than 1% of our total MMBtu of fuel consumed during 2010 and approximately 1% of our total fuel expense.

Nuclear Generation

General

Wolf Creek is a 1,158 MW nuclear power plant located near Burlington, Kansas. KGE owns a 47% interest in Wolf Creek, or 544 MW, which represents 8% of our total generating capacity. Wolf Creek’s operating license is effective until 2045 and Wolf Creek Nuclear Operating Corporation operates the plant for its owners. The plant’s owners pay operating costs equal to their respective ownership in Wolf Creek.

Fuel Supply

The owners of Wolf Creek have on hand or under contract all of the uranium and conversion services needed to operate through March 2014 and approximately 68% of the uranium and conversion services needed after that date through March 2020. The owners also have under contract 100% of the uranium enrichment and fabrication services required to operate Wolf Creek through March 2026. All such agreements have been entered into in the ordinary course of business.

Spent Nuclear Fuel and High-Level Radioactive Waste

Under the Nuclear Waste Policy Act of 1982, the DOE is responsible for the permanent disposal of spent nuclear fuel. Wolf Creek pays into a federal Nuclear Waste Fund administered by the DOE a quarterly fee for the future disposal of spent nuclear fuel. Our share of the fee, calculated as one-tenth of a cent for each kilowatt-hour of net nuclear generation delivered to customers, was $4.0 million in 2010, $3.7 million in 2009 and $3.5 million in 2008. We include these costs in fuel and purchased power expense on our consolidated statements of income.

In March 2010, the DOE filed a motion to withdraw its application with the Nuclear Regulatory Commission (NRC) to construct a national repository for the disposal of spent nuclear fuel and high-level radioactive waste at Yucca Mountain, Nevada, which would end the licensing process. An NRC board denied the DOE’s motion to withdraw its application in June 2010 and the DOE appealed that decision to the full NRC in early July 2010. The NRC has not yet decided that appeal. The question of the DOE’s legal authority to withdraw its license application also is pending in multiple lawsuits filed with a federal appellate court. Oral argument to the court is set for late March 2011. Wolf Creek has an on-site storage facility designed to hold all spent fuel generated at the plant through 2025 and believes it will be able to expand on-site storage as needed past 2025. We cannot predict when, or if, an alternative disposal site will be available to receive Wolf Creek’s spent nuclear fuel and will continue to monitor this activity.

Low-Level Radioactive Waste

Wolf Creek disposes of most of its low-level radioactive waste at an existing third-party repository in Utah, which we expect will remain available to Wolf Creek. Wolf Creek also contracts with a waste processor to process, take title and store in another state most of the remainder of Wolf Creek’s low-level radioactive waste. Should on-site waste storage be needed in the future, Wolf Creek has storage capacity on site adequate for about four years of plant operations.

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Outages

Wolf Creek operates on an 18-month planned refueling and maintenance outage schedule. Wolf Creek did not have such an outage in 2010 and the next outage is scheduled for spring 2011. During outages at the plant, we meet our electric demand primarily with our other generating units and by purchasing power. As authorized by regulators, we defer and amortize to expense ratably over an 18-month operating cycle the incremental maintenance costs incurred for planned refueling and maintenance outages.

An extended or unscheduled shutdown of Wolf Creek could cause us to purchase replacement power, rely more heavily on our other generating units and reduce amounts of power available for us to sell at wholesale.

The NRC evaluates, monitors and rates various inspection findings and performance indicators for Wolf Creek based on their 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.

Nuclear Decommissioning

Nuclear decommissioning is a nuclear industry term for the permanent shutdown of a nuclear power plant and the removal of radioactive components in accordance with NRC requirements. The NRC will terminate a plant’s license and release the property for unrestricted use when a company has reduced the residual radioactivity of a nuclear plant to a level mandated by the NRC. The NRC requires companies with nuclear plants to prepare formal financial plans to fund nuclear decommissioning. These plans are designed so that sufficient funds required for nuclear decommissioning will be accumulated prior to the expiration of the license of the related nuclear power plant. Wolf Creek files a nuclear decommissioning site study with the KCC every three years.

The KCC reviews nuclear decommissioning plans in two phases. Phase one is the approval of the revised nuclear decommissioning study including the estimated costs to decommission the plant. Phase two involves the review and approval by the KCC of a “funding schedule” prepared by the owner of the nuclear facility detailing how it plans to fund the future-year dollar amount of its pro rata share of the decommissioning costs.

The KCC approved Wolf Creek’s most recent nuclear decommissioning site study in August 2009. Based on the study, our share of decommissioning costs, including decontamination, dismantling and site restoration, is estimated to be $279.0 million. This amount compares to the prior site study estimate of $243.3 million. The site study cost estimate represents the estimate to decommission Wolf Creek as of the site study year. The actual nuclear decommissioning costs may vary from the estimates because of changes in regulations and technologies as well as changes in costs for labor, materials and equipment.

We are allowed to recover nuclear decommissioning costs in our prices over a period equal to the operating license of Wolf Creek, which is through 2045. The NRC requires that funds sufficient to meet nuclear decommissioning obligations be held in trust. We believe that the KCC approved funding level will also be sufficient to meet the NRC requirement. Our consolidated financial results would be materially adversely affected if we were not allowed to recover in our prices the full amount of the funding requirement.

We recovered in our prices and deposited in an external trust fund for nuclear decommissioning approximately $3.1 million in 2010 and $2.9 million in both 2009 and 2008. We record our investment in the nuclear decommissioning trust (NDT) fund at fair value, which approximated $127.0 million as of December 31, 2010, and $112.3 million as of December 31, 2009.

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Wind Generation

As discussed under “Environmental Matters – Renewable Energy Standard” below, the State of Kansas has enacted legislation mandating that more energy be derived from renewable sources. For us, wind has been the primary source of renewable energy. During 2010, our wind generation facilities produced 453,049 megawatt hours (MWh) of electricity and we purchased an additional 423,673 MWh of renewable energy through purchase power agreements. On December 14, 2010, we announced that we reached two separate agreements with third parties, subject to regulatory approval, to purchase under 20-year supply contracts the renewable energy produced from approximately 370 MW of wind generation beginning in late 2012.

Other Fuel Matters

The table below provides our weighted average cost of fuel, including transportation costs.

Our wind production has no fuel costs and is therefore excluded from the table above.

Purchased Power

We purchase electricity in addition to generating it. Factors that cause us to make such purchases include contractual arrangements, planned and unscheduled outages at our generating plants, prices for wholesale energy compared to our own 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 2010, purchased power comprised approximately 14% of our total fuel and purchased power expense. The weighted average cost of purchased power per MWh was $36.23 in 2010, $35.62 in 2009 and $58.96 in 2008.

Energy Marketing Activities

We engage in both financial and physical trading with the goal of managing our commodity price risk, enhancing system reliability and increasing profits. We trade electricity and other energy-related products using financial instruments, including futures contracts, options and swaps, and physical energy commodity contracts.

Competition and Deregulation

The Federal Energy Regulatory Commission (FERC) requires owners of regulated transmission assets to allow third parties nondiscriminatory access to their transmission systems. FERC also requires us to provide transmission services to others on the same basis as we use those assets ourselves. Furthermore, FERC issued an order encouraging the formation of RTOs under which transmission service is aggregated and coordinated across broad regions to better enable competitive wholesale power markets.

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Regional Transmission Organization

We are a member of the Southwest Power Pool (SPP), the RTO in our region. 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, less an administrative charge, the amounts it collects from transmission users.

Real-Time Energy Imbalance Market

The SPP utilizes a real-time energy imbalance market to accommodate financial settlement of energy imbalances within the SPP region. The objective of the real-time market is to permit an efficient balancing of energy production and consumption through the use of a least-cost economic dispatch system. It also provides a ready market for the purchase and sale of electricity to balance production with demand. We participate in this market.

Regulation and Our Prices

Kansas law gives the 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 sales of electricity, 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 certain costs. For portions of our cost of service, regulators allow us to adjust our prices periodically by formulae, which reduce the time between making expenditures and reflecting them in the prices we charge customers. However, for the remaining portions of our cost of service, we must file a formal rate case, which lengthens the period of time between making and recovering expenditures.

KCC Proceedings

In February 2011, we filed an application with the KCC to adjust our prices to include updated transmission costs as reflected in our transmission formula rate discussed below. If approved, we estimate that the new prices will increase our annual retail revenues by $14.6 million. We expect the KCC to issue an order on our request in March 2011.

On January 27, 2011, the KCC opened a docket seeking additional information from us and KCPL regarding planned environmental upgrades. The docket is focused on determining how required environmental upgrades may affect generating capabilities of the two companies and establishing criteria to be used when evaluating retrofit, decommission or replacement decisions. We are not able to determine the timing or outcome of this docket.

On October 29, 2010, the KCC issued an order, effective November 2010, allowing us to recover in our prices $5.8 million of previously deferred amounts associated with various energy efficiency programs.

On June 11, 2010, the KCC issued a final order approving an adjustment to our prices that we made earlier in 2010. The adjustment included updated transmission costs as reflected in our transmission formula rate discussed below. The new prices were effective March 16, 2010, and are expected to increase our annual retail revenues by $6.4 million.

On May 25, 2010, the KCC issued an order allowing us to adjust our prices to include costs associated with environmental investments made in 2009. The new prices were effective June 1, 2010, and are expected to increase our annual retail revenues by $13.8 million.

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On January 27, 2010, the KCC issued an order allowing us to adjust our prices to include costs associated with investments in natural gas and wind generation facilities. The new prices were effective February 2010 and are expected to increase our annual retail revenues by $17.1 million.

FERC Proceedings

On October 15, 2010, we posted our updated transmission formula rate which includes projected 2011 transmission capital expenditures and operating costs. The updated rate was effective January 1, 2011, and is expected to increase our annual transmission revenues by $15.9 million.

Our transmission formula rate that includes projected 2010 transmission capital expenditures and operating costs became effective January 1, 2010, and was expected to increase our annual transmission revenues by $16.8 million. The transmission formula rate provides the basis for our annual request with the KCC to adjust our retail prices to include updated transmission costs as noted above.

On January 12, 2010, FERC issued an order accepting our request to implement a cost-based formula rate for electricity sales to wholesale customers. The use of a cost-based formula rate allows us to annually adjust our prices to reflect changes in our cost of service. The cost-based formula rate was effective December 1, 2009.

Environmental Matters

General

We are subject to various federal, state and local environmental laws and regulations. Environmental laws and regulations affecting power plants are overlapping, complex, subject to changes in interpretation and implementation, and have become more stringent over time. These laws and regulations relate primarily to discharges into the air, air quality, discharges of effluents into water, 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 our 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 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 permitted to recover certain of these costs through the environmental cost recovery rider (ECRR), which allows for the more timely inclusion in retail prices the costs of capital expenditures associated with environmental improvements, including those required by the Federal Clean Air Act. However, there can be no assurance that the costs to comply with existing or future environmental laws and regulations will not have a material adverse effect on our 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 regulations that impose, among other things, limitations on pollutants generated during our operations, including sulfur dioxide (SO₂), particulate matter, nitrogen oxides (NOx) and mercury. In addition, we must comply with the provisions of the Federal Clean Air Act Amendments of 1990 that require reductions in SO₂ and NOx.

Emissions from our generating facilities, including particulate matter, SO₂ 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), we are required to install and maintain controls to reduce emissions found to cause or contribute to regional haze.

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Sulfur Dioxide

Through the combustion of fossil fuels at our generating facilities, we emit SO₂ and NOx. Federal and state laws and regulations limit the amount of SO₂ that we can emit. If we exceed these limits we could be subject to fines and penalties. In order to meet KDHE SO₂ 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 SO₂ allowance and trading program under the Federal Clean Air Act. Under this program, the Environmental Protection Agency (EPA) allocates annual SO₂ emissions allowances to emitting units subject to the program. Each unit must have enough allowances to cover its SO₂ emissions for that year. Allowances are tradable so that operators of affected units that are anticipated to emit SO₂ in excess of their allowances may purchase additional allowances from others. In 2010, we had SO₂ allowances adequate to meet planned generation and we expect to have enough in 2011. In the future if we need to purchase additional air emission allowances our operating costs would increase. We recover, and expect to continue to recover, the cost of such allowances through the RECA.

Clean Air Transport Rule

In July 2010, the EPA proposed the Clean Air Transport Rule (CATR), which would require the District of Columbia and 31 states, including Kansas, to issue regulations and develop a plan by which power plants in their respective jurisdictions will further reduce emissions of SO₂ and NOx. Reductions would be required beginning in 2012, with further reductions likely to be required in 2014. The EPA expects CATR to be finalized in the spring of 2011, but it is unclear when the states would issue implementing regulations. There are a number of uncertainties relating to this proposed rule, including whether it will be finalized and how the states will implement the requirements. As a result, we cannot determine the impact this rule will have on our operations or consolidated financial results, but it could be material.

National Ambient Air Quality Standards

Under the Federal Clean Air Act, the EPA sets National Ambient Air Quality Standards (NAAQS) for six criteria pollutants considered harmful to public health and the environment, including particulate matter, NOx, ozone and SO₂, which result from coal combustion. Areas meeting the NAAQS are designated attainment areas while those that do not meet the NAAQS are considered nonattainment areas. In 2009, KDHE proposed to designate portions of the Kansas City area nonattainment for the 8-hour ozone standard, which has the potential to impact our operations. 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.

In 2010, the EPA strengthened the NAAQS for both NOx and SO₂. We are currently evaluating what impact this could have on our operations. 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.

Particulate matter, principally ash, is a byproduct of coal combustion. In 2011, the particulate matter NAAQS are scheduled for their required five-year review, at which time the EPA could issue more stringent standards. We cannot at this time predict the impact of any new standards on our operations or consolidated financial results, but it could be material.

The EPA is currently in the process of revising the NAAQS for ozone. The EPA has requested additional time to finalize the ozone NAAQS, which are expected to be issued in July 2011. If these revisions result in more stringent standards, we could be required to place additional NOx pollution control measures on our facilities. Without knowing the new ozone standards, we cannot determine the impact they may have on our operations or consolidated financial results, but it could be material.

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Mercury Emissions

Coal contains mercury. When we combust coal at our generating facilities, we emit mercury into the air. The federal Clean Air Mercury Rule (CAMR) permanently caps and reduces nationwide mercury emissions from new and existing coal-fired power plants. In 2008, the U.S. Court of Appeals for the District of Columbia Circuit vacated CAMR. In lieu of CAMR, the EPA has announced that it intends to propose air toxics standards under the Clean Air Act, including mercury standards, for coal and oil-fired electric generating units by March 2011 and to finalize a rule by November 2011. Without knowing what the rule will require, we cannot estimate the impact to us. However, our costs to comply with future mercury emission requirements could have a material impact on our operations and consolidated financial results.

Carbon Dioxide and Greenhouse Gases

One byproduct of burning coal and other fossil fuels is the emission of carbon dioxide (CO₂), which is believed by many to contribute to climate change. Legislators, including the U.S. Congress, have at times considered the passage of laws to limit the emission of CO₂ and other gases referred to as greenhouse gases (GHGs). In 2009 the U.S. House of Representatives passed, and the U.S. Senate considered but did not pass, legislation that proposed, among other things, a nationwide cap on CO₂ and other GHG emissions and a requirement that major sources, including coal-fueled power plants, obtain emission allowances to meet that cap. It is possible that federal legislation related to GHG emissions will be considered by legislators in the future. The EPA has also proposed using the Federal Clear Air Act to limit CO₂ and other GHG emissions, and other measures are being imposed or offered by individual states, municipalities and regional agreements, such as the Midwestern Greenhouse Gas Reduction Accord, with the goal of reducing GHG emissions.

Under EPA regulations finalized in May 2010, known as the tailoring rule, the EPA began regulating GHG emissions from certain stationary sources in January 2011. The regulations are being implemented pursuant to two Federal Clear Air Act programs: the Title V Operating Permit program and the program requiring a permit if undergoing construction or major modifications, which is referred to as the Prevention of Significant Deterioration program (PSD). Obligations relating to Title V permits will include recordkeeping and monitoring requirements. With respect to PSD permits, projects that cause a significant increase in GHG emissions (currently defined to be more than 75,000 tons or more per year or 100,000 tons or more per year, depending on various factors), will be required to implement best available control technology (BACT). 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 new regulations on our operations and consolidated financial results, but we believe the cost of compliance with new regulations could be material.

In December 2010, the EPA announced it will be proposing GHG New Source Performance Standard (NSPS) rules for power plants and refineries. The rules for power plants will be proposed by July 2011, and finalized by May 2012. These rules would apply to new and existing facilities, including ours. Because these regulations have yet to be proposed, we cannot predict the impact they may have on our generating facilities or consolidated financial results, but it could be material.

In the absence of further federal legislation or regulation, certain states, regions and local authorities have developed their own GHG initiatives. In November 2007, the governors of Illinois, Indiana, Iowa, Kansas, Michigan, Minnesota, Ohio, South Dakota and Wisconsin and the Premier of Manitoba signed the Midwestern Greenhouse Gas Reduction Accord to develop and implement steps to reduce GHG emissions. In May 2010, the Midwestern Greenhouse Gas Reduction Accord Advisory Group finalized their recommendations for emissions reductions targets and targeted sectors for GHG reductions in their jurisdiction. These include a recommended reduction in GHG emissions of 20% below 2005 emissions levels by 2020. These recommendations are from the advisory committee only and have not been endorsed by the respective states or provinces. If Kansas were to implement the recommended or any other targets, the impact on our operations and consolidated financial results could be material.

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Wastewater Effluent

Some water used in our operations is discharged as wastewater effluent. This wastewater may contain heavy metals and other substances deemed to be pollutants. The EPA plans to propose revisions to the rules governing such wastewater effluent from coal-fired power plants by July 2012 with final action on the proposed rules expected to occur by January 2014. Although we cannot at this time determine the impact of any new regulations, more stringent regulations could have a material impact on our operations and consolidated financial results.

Regulation of Coal Combustion Byproducts

In the course of operating our coal generation plants, we produce coal combustion byproducts (CCBs), including fly ash and bottom ash, which we must handle, dispose, recycle or process. We recycle approximately 45% of our fly ash and bottom ash production, principally by selling to the aggregate industry. This is referred to as “beneficial use.” On June 21, 2010, the EPA published in the Federal Register a proposed rule to regulate CCBs under the Resource Conservation and Recovery Act (RCRA). The proposed rule provides two possible options for CCB regulation, both of which technically would allow for the continued beneficial use of CCBs, but we believe might actually curtail or impair beneficial use to the extent we are able to recycle it today. The first option would subject CCBs to regulation as special waste under Subtitle C of RCRA. The second option would regulate CCBs as non-hazardous solid waste under Subtitle D of RCRA and impose national criteria applicable to CCBs disposed of in landfills and surface impoundments. While we cannot at this time estimate the impact and cost associated with future regulations of CCBs, we believe the impact on our operations and consolidated financial results could be material.

Agreement with Regulators

We entered into an agreement with the EPA and Department of Justice (DOJ) to resolve alleged violations of the Federal Clean Air Act at JEC. The terms of the agreement require us to install additional equipment as well as perform environmental mitigation projects to further reduce air emissions. See “—EPA Lawsuit” below for further information regarding the terms of the agreement.

Renewable Energy Standard

In May 2009, Kansas enacted legislation that mandates, among other requirements, that more energy be derived from renewable sources. In years 2011 through 2015 net renewable generation capacity must be 10% of the average peak 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. We have worked with third parties to develop approximately 300 MW of qualifying wind generation facilities, which together with the use of renewable energy credits, we expect to meet the 2011 requirement. On December 14, 2010, we announced that we reached two separate agreements with third parties, subject to regulatory approval, to purchase under 20-year supply contracts the renewable energy produced from approximately 370 MW of wind generation beginning in late 2012. We expect these agreements, along with our prior development of wind generation facilities, will satisfy our net renewable generation requirement through 2015 and contribute toward meeting the increased requirement beginning in 2016.

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Environmental Costs

We will continue to make significant capital expenditures and incur operating expenses at our power plants 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 interpretation of existing regulations, new regulations, legislation and the manner in which we operate our plants. The degree to which we will need to reduce 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. The ECRR allows for the more timely inclusion in retail prices the costs of capital expenditures associated with environmental improvements, including those required by the Federal Clean Air Act.

A recent order of the KCC indicated that it may be more appropriate to recover environmental costs at La Cygne through the filing of a general rate case as opposed to the ECRR. This could increase the time between making these investments and having them reflected in the prices we charge our customers, as well as the amount we charge our customers. Estimated capital expenditures associated with environmental improvements for 2011-2013 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 expense and may reduce the net production, reliability and availability of the plants. In order to change our prices to recognize increased operating and maintenance costs, we must file a general rate case with the KCC.

Manufactured Gas Sites

We have been identified as being partially responsible for remediating a number of former manufactured gas sites located in Kansas. We and the KDHE entered into a consent agreement governing all future work at these sites. Under terms of the consent agreement, we agreed to investigate and, if necessary, remediate these sites. Pursuant to an environmental indemnity agreement with ONEOK, the current owner of some of the sites, ONEOK assumed total liability for remediation of seven sites and we share liability for remediation with ONEOK for five sites. Our total liability for the five shared sites is capped at $3.8 million.

Our environmental liability for remediation of former manufactured gas sites in Missouri associated with assets we divested many years ago had been limited to $7.5 million by the terms of an environmental indemnity agreement with the purchaser of those assets. In June 2010, the purchaser agreed to reduce our maximum liability to $2.5 million, which reflects our share of the purchaser’s expected remediation costs. We have settled this liability.

EPA Lawsuit

Under Section 114(a) of the Federal Clean Air Act, the EPA is conducting investigations nationwide to determine whether modifications at coal-fired power plants are subject to the New Source Review permitting program or NSPS. These investigations focus on whether projects at coal-fired plants were routine maintenance or whether the projects were substantial modifications that could reasonably have been expected to result in a significant net increase in emissions. The New Source Review program requires companies to obtain permits and, if necessary, install control equipment to address emissions when making a major modification or a change in operation if either is expected to cause a significant net increase in emissions.

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In January 2004, the EPA notified us that certain projects completed at JEC violated certain requirements of the New Source Review program. In February 2009, the DOJ, on behalf of the EPA, filed a lawsuit against us in U.S. District Court in the District of Kansas asserting substantially the same claims. On January 25, 2010, we announced a settlement of the lawsuit. The settlement was filed with the court, seeking its approval, and on March 26, 2010, the court entered an order approving the settlement. The settlement requires that we install a selective catalytic reduction (SCR) on one of the three JEC coal units by the end of 2014. We estimate the cost of this to be approximately $240.0 million. This amount could change materially depending on final engineering and design. Depending on the NOx emission reductions attained by the single SCR and attainable through the installation of other controls on the other two JEC coal units, we may have to install an SCR on another JEC unit by the end of 2016, if needed to meet NOx reduction targets. Recovery of costs to install these systems is subject to the approval of our regulators. We believe these costs are appropriate for inclusion in the prices we are allowed to charge our customers. We will also invest $5.0 million over six years in environmental mitigation projects that we will own. In 2009, we recorded as part of the settlement $1.0 million for environmental mitigation projects that will be owned by a qualifying third party and a $3.0 million civil penalty.

SEASONALITY

As a summer peaking utility, our revenues are seasonal. The third quarter typically accounts for our greatest revenues. Our electricity sales are affected by weather conditions, the economy of our service territory and other factors affecting customers’ demand for electricity.

EMPLOYEES

As of February 15, 2011, we had 2,409 employees. Our current contract with Local 304 and Local 1523 of the International Brotherhood of Electrical Workers extends through June 30, 2011. We expect to negotiate a new contract with the Electrical Workers. The contract covered 1,326 employees as of February 15, 2011.

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 through our Internet website at www.westarenergy.com or by responding to 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.

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EXECUTIVE OFFICERS OF THE COMPANY

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.

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We operate in market and regulatory environments that involve significant risks, many of which are beyond our control. In addition to other information in this Form 10-K, including “Item 1. Business” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and in other documents we file with the SEC from time to time, the following factors may affect our results of operations and cash flows and the market prices of our publicly traded securities. These factors may cause results to differ materially from those expressed in any forward-looking statements made by us or on our behalf. The factors listed below are not intended to be an exhaustive discussion of all such risks, and the statements below must be read together with factors discussed elsewhere in this document and in our other filings with the SEC.

Weather conditions, including mild and severe weather, may adversely impact our consolidated financial results.

Weather conditions directly influence the demand for electricity. Our customers use electricity for heating in winter months and cooling in summer months. Because of air conditioning demand, typically we produce our highest revenues in the third quarter. Milder temperatures reduce demand for electricity and have a corresponding affect on our revenues. Unusually mild weather in the future could adversely affect our consolidated financial results.

In addition, severe weather conditions can produce storms that can inflict extensive damage to our equipment and facilities that can require us to incur additional operating and maintenance expense and additional capital expenditures. Our prices may not always be adjusted timely and adequately to reflect these higher costs. Additionally, because many of our power plants use water for cooling, severe drought conditions could result in limited power production.

Our prices are subject to regulatory review and may not prove adequate.

We must obtain from state and federal regulators the authority to establish terms and prices for our services. The KCC and, for most of our wholesale customers, FERC, use a cost-of-service approach that takes into account operating expenses, fixed obligations and recovery of and return on capital investments. Using this approach, the KCC and FERC set prices at levels calculated to recover these costs and a permitted return on investment. Except for wholesale transactions for which the price is not so regulated, and except to the extent the KCC and FERC permit us to modify our prices by using approved formulae, our prices generally remain fixed until changed following a rate review. Further, the adjustments and formulae may be modified, limited or eliminated by regulatory or legislative actions. We may apply to change our prices or intervening parties may request that our prices be reviewed for possible adjustment.

Rate proceedings through which our prices and terms of service are determined typically involve numerous parties including electricity consumers, consumer advocates and governmental entities, some of whom frequently take positions adverse to us. The decision making process used in these proceedings may or may not be subject to statutory timelines, and in any event regulators’ decisions may be appealed to the courts by us or other parties to the proceedings. These factors may lead to uncertainty and delays in implementing changes to our prices or terms of service. There can be no assurance that our regulators will find all of our costs to have been prudently incurred. A finding that costs have been imprudently incurred can lead to disallowance of recovery for those costs. The prices approved by the applicable regulatory body may not be sufficient for us to recover our costs and to provide for an adequate return on and of capital investments.

We cannot predict the outcome of any rate review or the actions of our regulators. The outcome of rate proceedings, or delays in implementation of new prices regarding costs that we have already incurred, could have a significant affect on our ability to recover costs and could have a material adverse affect on our consolidated financial results.

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Significant decisions about capital investments are based on forecasts of long-term demand for energy incorporating assumptions about multiple, uncertain factors. Our actual experience may differ significantly from our assumptions, which may adversely impact our consolidated financial results.

We attempt to forecast demand to determine the timing and adequacy of our energy and energy delivery resources. Long-term forecasts involve risks because they rely on assumptions we make concerning uncertain factors including weather, technological change, economic conditions, regulatory requirements, social pressures and the responsiveness of customers’ electricity demand to conservation measures and prices. Actual future demand depends on these and other factors and may vary materially from our forecasts. If our actual experience varies significantly from our forecasts, our consolidated financial results may be adversely affected.

Our ability to fund our capital expenditures and meet our working capital and liquidity needs may be limited by conditions in the bank and capital markets or by our credit ratings or the market price of Westar Energy’s common stock.

To fund our capital expenditures and for working capital and liquidity, we rely on access to capital markets and to short-term credit. Disruption in capital markets, deterioration in the financial condition of the financial institutions on which we rely, any credit rating downgrade or any decrease in the market price of Westar Energy’s common stock may make capital more difficult and costly for us to obtain, may restrict liquidity available to us, may require us to defer or limit capital investments or impact operations, or may reduce the value of our financial assets. These and other related affects may have an adverse impact on our business and consolidated financial results, including our ability to pay dividends and to make investments or undertake programs necessary to meet regulatory mandates and customer demand.

Our planned capital investment for the next few years is large in relation to our size, subjecting us to significant risks.

Our anticipated capital expenditures for 2011 through 2013 are approximately $2.4 billion. In addition to risks discussed above associated with recovering capital investments through our prices, and risks associated with our reliance on the capital markets and short-term credit to fund those investments, our capital expenditure program poses risks, including, but not necessarily limited to:

These and other factors, or any combination of them, could cause us to defer or limit our capital expenditure program and could adversely impact our consolidated financial results.

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Capital market conditions can cause fluctuations in the values of assets set aside for employee benefit obligations and the Wolf Creek NDT and may increase our funding requirements related to these obligations.

We have significant future financial obligations with respect to employee benefit obligations and the Wolf Creek NDT. The value of the assets needed to meet those obligations are subject to market fluctuations and will yield uncertain returns, which may fall below our expectations, upon which we plan to meet our obligations. Additionally, changes in interest rates affect the value of future liabilities. While the KCC has recently allowed us to implement a regulatory accounting mechanism to track certain of our employee benefit plan expenses, this mechanism does not allow us to make automatic price adjustments. Only in future rate proceedings may we be allowed to adjust our prices to reflect changes in our funding requirements for these benefit plans. Further, the tracking mechanism for these benefit plan expenses is part of our overall rate structure, and as such it is subject to KCC review and may be modified, limited or eliminated in the future. If these assets are not managed successfully, our consolidated financial results could be adversely affected.

Adverse economic conditions could adversely impact our operations and our consolidated financial results.

Our operations are affected by economic conditions. Adverse general economic conditions including a prolonged recession or capital market disruptions may:

Any of these events, and others we may not be able to identify, could have an adverse impact on our consolidated financial results.

Deliveries of fuel for our plants may be interrupted or slowed, which may adversely impact our consolidated financial results.

We purchase fuel, including coal, natural gas and uranium, from a number of suppliers. Disruption in the delivery of fuel or environmental regulations affecting any of our fuel suppliers could limit our ability to operate our facilities. In addition, the markets for coal, natural gas and uranium are subject to price fluctuations, availability restrictions and counterparty default. It is not possible to predict the cost or availability of these commodities. Such costs, if not recovered in our prices, could have a material adverse affect on our consolidated financial results.

We are subject to complex governmental regulation that could require us to incur additional expenses or subject us to penalties.

Our operations are subject to extensive regulation and require numerous permits, approvals and certificates from various governmental agencies. New laws or regulations, the revision or reinterpretation of existing laws or regulations, or penalties imposed for non-compliance with existing laws or regulations may require us to incur additional expenses, which could have a material adverse affect on our consolidated financial results.

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We could be subject to penalties as a result of mandatory reliability standards, which could adversely affect our consolidated financial results.

As a result of the Energy Policy Act of 2005, owners and operators of the bulk power transmission system, including Westar Energy and KGE, are subject to mandatory reliability standards promulgated by the North American Electric Reliability Corporation and enforced by FERC. If we are found not to be in compliance with the mandatory reliability standards, we could be subject to sanctions, including substantial monetary penalties, which we may not be able to recover in the prices we charge our customers. This could have a material adverse affect on our consolidated financial results.

Our costs of compliance with environmental laws are significant, and the future cost of compliance with environmental laws could adversely affect our consolidated financial results.

We are subject to extensive federal, state and local environmental statutes, rules and regulations relating to discharges into the air, air quality, discharges of effluents into water, water quality, the use of water, the handling, disposal and clean up of hazardous and non-hazardous substances and wastes, natural resources, and health and safety. Compliance with these legal requirements, which change frequently and often become more restrictive, requires us to commit significant capital and operating resources toward permitting, emission fees, environmental monitoring, installation and operation of pollution control equipment and purchases of air emission allowances and/or offsets.

Costs of compliance with environmental regulations, if not recovered in our prices, could adversely affect our consolidated financial results, especially if emission and/or discharge limits are tightened, more extensive permitting requirements are imposed, additional substances become regulated and the number and types of assets we operate increases. We cannot estimate our compliance costs with certainty due to our inability to predict the requirements and timing of implementation of environmental rules or regulations.

We may be subject to legislative and regulatory responses to concerns about climate change, which could require us to incur substantial costs.

We emit large amounts of CO₂ and other gases through the operation of our power plants. Federal legislation has been in the past and may in the future be introduced in Congress to regulate the emission of GHGs and numerous states have adopted programs to stabilize or reduce GHG emissions.

Additionally, the EPA is proceeding with regulation of GHGs under the Clean Air Act. Under EPA regulations finalized in May 2010, the EPA began regulating GHG emissions from certain stationary sources, such as power plants, in January 2011. Under the regulations, any source that emits at least 75,000 tons per year of GHGs will be required to have a Title V operating permit under the Clean Air Act. Sources that already have a Title V permit would have GHG provisions added to their permit upon renewal. Additionally, PSD permits for new major sources of GHG emissions and GHG sources that undergo major modifications on or after January 2, 2011, will require the implementation of the BACT for the control of GHG emissions. 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. These regulations could have a material impact on our operations or require us to incur substantial costs.

Furthermore, in December 2010, the EPA announced it will be proposing GHG NSPS rules for power plants and refineries. The rules for power plants will be proposed by July 2011, and finalized by May 2012. These rules would apply to new and existing facilities, including ours. Because these regulations have yet to be proposed, we cannot predict the impact they may have on our generating facilities or consolidated financial results, but it could be material.

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Our cost of compliance with future federal regulations relating to the disposal of CCBs could require us to incur substantial costs.

In the course of operations, many of our facilities generate CCBs, including fly ash and bottom ash, requiring disposal or processing. On June 21, 2010, the EPA published in the Federal Register a proposed rule to regulate CCBs under RCRA. The proposed rule provides two possible options for CCB regulation, one of which would subject CCBs to increased regulation as special waste under Subtitle C of RCRA. While the impact and cost associated with the potential future regulation of CCBs cannot be established until such regulations are finalized, such regulations could have a material impact on our operations and/or require us to incur substantial costs.

Our risk management policies cannot eliminate price volatility and counterparty credit risks associated with our energy marketing activities.

We engage in energy marketing transactions with the goal of managing our commodity price risk, enhancing system reliability and increasing profits. We operate in active wholesale markets that expose us to price volatility for electricity and fuel and other commodities. The prices we use to value these transactions reflect our best estimates of the fair value of these contracts. Results actually achieved from these activities could vary materially from intended results and could cause significant earnings variability. In addition, we are exposed to credit risks of our counterparties and the risk that one or more counterparties may fail to perform their obligations to make payments or deliveries. Defaults by suppliers or other counterparties may adversely affect our consolidated financial results.

We attempt to manage our exposure to price volatility and counterparty credit risk through application of established risk limits and risk management procedures. These risk limits and risk management procedures may not work as planned and cannot eliminate all risks associated with these activities.

We are exposed to various risks associated with the ownership and operation of Wolf Creek, any of which could adversely impact our consolidated financial results.

Through KGE’s ownership interest in Wolf Creek, we are subject to the risks of nuclear generation, which include:

The NRC has authority to impose licensing and safety-related requirements for the operation of nuclear generation facilities. In the event of non-compliance, the NRC has authority to impose fines or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Revised safety requirements enacted by the NRC could necessitate substantial capital expenditures at Wolf Creek. In addition, the Institute of Nuclear Power Operations (INPO) reviews Wolf Creek operations and facilities. Compliance with INPO recommendations could result in substantial capital expenditures or a substantial increase in operating expenses at Wolf Creek being passed through to KGE.

If an incident did occur at Wolf Creek, it could have a material adverse affect on our consolidated financial results. Furthermore, the non-compliance of other nuclear facilities operators with applicable regulations or the occurrence of a serious nuclear incident at other facilities could result in increased regulation of the industry as a whole, which could in turn increase Wolf Creek’s compliance costs and impact our consolidated financial results.

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In addition, in the event of an extended or unscheduled outage at Wolf Creek, we would be required to generate power from more costly generating units, purchase power in the open market to replace the power normally produced at Wolf Creek and have less power available for sale into the wholesale markets. If we were unable to recover these costs from customers, such events would likely have an adverse impact on our consolidated financial results.

Events could occur that would change the accounting principles for regulated utilities currently applicable to our business, which would have an adverse impact on our consolidated financial results.

We currently apply accounting principles that are unique to regulated entities. As of December 31, 2010, we had recorded regulatory assets of $861.1 million and regulatory liabilities of $164.0 million. In the event we determined that we could no longer apply these principles, either as: (i) a result of the establishment of retail competition in our service territory; (ii) a change in the regulatory approach for setting our prices from cost-based ratemaking to another form of ratemaking; (iii) a result of other regulatory actions that restrict cost recovery to a level insufficient to recover costs; or (iv) a change from current generally accepted accounting principles (GAAP) to another set of standards that does not recognize regulatory assets and/or liabilities, then we may be required to record a charge against income in an amount up to the remaining unamortized regulatory assets. Such an action would materially reduce our shareholders’ equity. We review these criteria to ensure that the continuing application of these principles is appropriate each reporting period. Based upon our most current evaluation of the various factors that are expected to impact future cost recovery, we believe that our regulatory assets are probable of recovery.

Equipment failures and other events beyond our control may cause extended or unplanned plant outages, which may adversely impact our consolidated financial results.

The generation, distribution and transmission of electricity requires the use of expensive and complicated equipment, much of which is aged, and all of which requires significant ongoing maintenance. Although we maintain our power plants and equipment, they are still subject to extended or unplanned outages because of equipment failure, weather, transmission system disruption, operator error, contractor or subcontractor failure and other factors largely beyond our control. In such events, we must either produce replacement power from our other units, which may be less efficient or more expensive to operate, or purchase power from others at unpredictable and potentially higher costs in order to meet our sales obligations. Such events could also limit our ability to make sales to customers. Therefore, the occurrence of extended or unplanned outages could adversely affect our consolidated financial results.

None.

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We own and have in service approximately 6,300 miles of transmission lines, approximately 23,800 miles of overhead distribution lines and approximately 4,300 miles of underground distribution lines.

Substantially all of our utility properties are encumbered by first priority mortgages pursuant to which bonds have been issued and are outstanding.

Information on other legal proceedings is set forth in Notes 3, 13 and 15 of the Notes to Consolidated Financial Statements, “Rate Matters and Regulation,” “Commitments and Contingencies – EPA Lawsuit – FERC Investigation” and “Legal Proceedings,” respectively, which are incorporated herein by reference.

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PART II

STOCK PERFORMANCE GRAPH

The following graph compares the performance of Westar Energy’s common stock during the period that began on December 31, 2005, and ended on December 31, 2010, to the Standard & Poor’s 500 Index (S&P 500) and the Standard & Poor’s Electric Utility Index (S&P Electric Utilities). The graph assumes a $100 investment in Westar Energy’s common stock and in each of the indices at the beginning of the period and a reinvestment of dividends paid on such investments throughout the period.