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 endedDecember 31, 20092010

OR

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

SECURITIES EXCHANGE ACT OF 1934

For the transition period fromto                    

Commission File Number1-3523

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 $2,040,718,228$2,391,619,392 at June 30, 2009.2010.

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:

TABLE OF CONTENTS

GLOSSARY OF TERMS

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

OTC		Over-the-counter
PCB		Polychlorinated Biphenylbiphenyl
PRB		Powder River Basin
Protection One		Protection One, Inc.
PSD		Prevention of Significant Deterioration program
RCRA		Resource Conservation and Recovery Act
RECA		Retail Energy Cost Adjustmentenergy cost adjustment
RSU		Restricted Share Unit

		share unit
RTO		Regional Transmission Organization
S&P		Standard & Poor’s Ratings Group
S&P 500		Standard & Poor’s 500 Index
S&P Electric Utilities		Standard & Poor’s Electric Utility Index
SCR		Selective catalytic reduction
SEC		Securities and Exchange Commission
SO2		Sulfur dioxide
SPP		Southwest Power Pool
SSCGP		Southern Star Central Gas Pipeline
SO2		Sulfur Dioxide
VaR		Value-at-Risk
VIE		Variable interest entity
WCNOC		Wolf Creek Nuclear Operating Corporation
Wolf Creek		Wolf Creek Generating Station

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,” “pro forma,” “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:

-

changes in the energy markets in which we participate resulting from the development and implementation of real time and next day trading markets, and the effect of the retroactive repricing of transactions in such markets following execution because of changes or adjustments in market pricing mechanisms by regional transmission organizations (RTOs) and independent system operators,

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.

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 685,000687,000 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. KGE owns a 47% interest in Wolf Creek, a nuclear power plant located near Burlington, Kansas. 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

Our strategy isWe expect to remaincontinue operating as a vertically integrated, regulated, electric utility meeting the energy needs of our customers reliably at reasonable prices.utility. We strive to optimize flexibility in our planning and operations to be able to respond quickly to the uncertain and changing energy and environmental policies, economic conditions, regulations and technologies currently affecting or related to our business.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, the ability to usedeveloping more natural gas-fired generation, the development of wind generation and the building and upgrading of transmission facilities. We also planfacilities, in addition to invest significant resourcesdeveloping systems and programs to enhancehelp our distribution system and to developcustomers use energy efficiency programs.more efficiently. Following is a summary of some of therecent progress we have made on these significant elements.elements of our strategy.

Our plans and expectations for 2010 and beyond include:

SIGNIFICANT BUSINESS DEVELOPMENTSOur plans and expectations for 2011 and beyond include:

Weather

Our electricity sales and revenues are significantly impacted by the weather, mostly

OPERATIONS

General

Westar Energy supplies electric energy at retail to approximately 368,000369,000 customers in central and northeast Kansas and KGE supplies electric energy at retail to approximately 317,000318,000 customers in south-central and southeastern Kansas. We also supply electric energy at wholesale to the electric distribution systems of 31 cities in Kansasmunicipalities and four 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 KCCKansas 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 6,8076,756 MW of accredited generating capacity in service, 2,518 MW of which 2,586 MW is ownedKGE owns or leased by KGE.leases from variable interest entities (VIEs). See “Item 2. Properties” for additional information on our generating units. While we also own 149 MW of 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. TheOur capacity and net generation by fuel type is summarized below.

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

Our aggregate 20092010 peak system net load of 4,5455,485 MW occurred on June 23, 2009.August 12, 2010. This included 132137 MW of potentially interruptible load. Our net generating capacity, combined with firm capacity purchases and sales and the ability to interrupt 132 MW ofpotentially interruptible load, provided a capacity margin of 26.0%20% above system peak responsibility at the time of our 20092010 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 20092010 fuel mix was 78% coal, 14%15% nuclear and 7% natural gas, with diesel and oil making up less than 1%. In 2010 we expect to use a higher percentage of nuclear fuel because Wolf Creek will not have a scheduled refueling and maintenance outage. Wolf Creek had such an outage in the fall of 2009. Additionally, 2009 was the first year our new wind generation facilities produced a significant amount of wind energy as discussed under “—Wind Generation” below. Our generation mix fluctuates with the operation of Wolf Creek, fluctuationsvariations 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:Center (JEC): The three coal-fired units at Jeffrey Energy CenterJEC have an aggregate capacity of 2,1642,165 MW, of which we own andor lease a combined 92% share, or 1,9911,992 MW. We have a long-term coal supply contract with Foundation Coal WestAlpha Natural Resources, Inc. to supply coal to Jeffrey Energy CenterJEC 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 Jeffrey Energy CenterJEC is purchased under this contract. The 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 railroadsRailroad transport coal for Jeffrey Energy Center from Wyomingthe 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 Jeffrey Energy CenterJEC during 20092010 was approximately $1.59$1.60 per MMBtu, or $26.37$26.39 per ton.

La Cygne Generating Station:Station (La Cygne): The two coal-fired units at La Cygne Generating Station (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. AllApproximately 80% of the La Cygne unit 1 and unit 2 PRB coal requirements is supplied throughunder 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 through 2010 andcontracts. All of the La Cygne PRB coal is transported under KCPL’s Omnibus Rail Transportation Agreementrail transportation agreements with the BNSF through 2013 and Kansas City Southern Railroad through 2010.2020. As the PRB coal contracts expire, we anticipate that KCPL will negotiate new supply contracts or purchase coal on the spot market.

During 2009,2010, the average delivered cost of our share of coal consumed at La Cygne unit 1 was approximately $1.39$1.38 per MMBtu, or $22.91$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 $20.48$20.91 per ton.

Lawrence and Tecumseh Energy Centers: The coal-fired units located at the Lawrence and Tecumseh Energy Centers have an aggregate generating capacity of 731773 MW. We purchase PRB coal for these two energy centers under a contract with Arch Coal, Inc. Our current contract is expected, which we expect to provide 100% of the coal requirementrequirements for thesethe energy centers through 2012.

BNSF transports coal for these energy centers from Wyoming under a contract that expires in December 2013.

During 2009,2010, the average delivered cost of coal consumed in the Lawrence units was approximately $1.47$1.69 per MMBtu, or $25.93$29.78 per ton. The average delivered cost of coal consumed in the Tecumseh units was approximately $1.45$1.66 per MMBtu, or $25.67$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 the Lawrence and Tecumseh Energy Centers. During 2009,2010, we consumed 21.721.3 million MMBtu of natural gas for a total cost of $91.7$109.0 million. Natural gas accounted for approximately 7% of our total MMBtu of fuel consumed during 20092010 and approximately 19%21% of our total fuel expense. From time to time, we may purchase derivativeenter into contracts, including the use of derivatives, in an effort to mitigatemanage the effectoverall cost of high natural gas prices.gas. For additional information onabout our exposure to commodity price risks, see “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”

We maintain natural gas transportation arrangements for the Abilene and Hutchinson Energy Centers with Kansas Gas Service, a division of ONEOK, Inc. (ONEOK). The Abilene Energy Center is covered under a standard tariff as a large industrial transportation customer while the Hutchinson Energy Center is covered under a rate agreement that expires on April 30, 2010.2011. We plan to renegotiate the agreement for the Hutchinson Energy Center prior to its expiration. We meet a portion of our natural gas transportation requirements for the 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 the 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 the 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 the 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 2009,2010, we did not use No. 6 oil.

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 2009,2010, we consumed 0.30.2 million MMBtu of diesel at a total cost of $4.1$3.8 million. Diesel accounted for less than 1% of our total MMBtu of fuel consumed during 20092010 and approximately 1% of our total fuel expense.

Nuclear Generation

General

Wolf Creek is a 1,1601,158 MW nuclear power plant located near Burlington, Kansas. KGE owns a 47% interest in Wolf Creek, or 545544 MW, which represents 8% of our total generating capacity. KCPL owns an equal 47% interestWolf Creek’s operating license is effective until 2045 and KEPCo holdsWolf Creek Nuclear Operating Corporation operates the remaining 6% interest.plant for its owners. The co-ownersplant’s owners pay operating costs equal to their percentagerespective ownership in Wolf Creek.

In November 2008, the Nuclear Regulatory Commission (NRC) approved Wolf Creek Nuclear Operating Corporation’s (WCNOC) request for a 20-year extension of Wolf Creek’s operating license until 2045. WCNOC operates Wolf Creek for its owners.

Fuel Supply

The owners of Wolf Creek hashave on hand or under contract all of the uranium and conversion services needed to operate Wolf Creek through March 2014 and approximately 80%68% of the uranium and conversion services needed after that date through September 2018.March 2020. The owners also have under contract 100% of the uranium enrichment and fabrication services required to operate Wolf Creek through March 2026.

WCNOC has All such agreements have been entered into all uranium, uranium conversion and uranium enrichment arrangements, as well as the fabrication agreements, 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 and $4.4 million in 2007.2008. We include these costs in fuel and purchased power expense.expense on our consolidated statements of income.

The NRC continuesIn March 2010, the DOE filed a motion to withdraw its technical licensing review of a DOE application for authoritywith 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. In February 2010, the DOE announced its intent to withdraw the application,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. WeUtah, which we expect that this site will remain available to Wolf Creek. In late 2009, Wolf Creek contractedalso contracts with a waste processor that willto 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.

Outages

Wolf Creek operates on an 18-month planned refueling and maintenance outage schedule. Wolf Creek was shut downdid not have such an outage in 2010 and the next outage is scheduled for 43 days in 2009 for refueling and maintenance.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 outages. Wolf Creek’s next refueling and maintenance outage is scheduled for spring of 2011.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 the 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 plant.

In August 2009, theThe KCC approved Wolf Creek’s updatedmost recent nuclear decommissioning site study.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.

In the prices we charge, weWe are allowed to recover nuclear decommissioning costs in our prices over a period equal to the lifeoperating 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 each ofboth 2009 2008 and 2007.2008. We record our investment in the nuclear decommissioning trust (NDT) fund at fair value. The fair value, which approximated $127.0 million as of December 31, 2010, and $112.3 million as of December 31, 2009, and $85.6 million as of December 31, 2008.2009.

Wind Generation

Our newAs 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 began operation in 2009. We produced 288,254453,049 megawatt hours (MWh) of electricity at our wind generation facilities and we purchased an additional 308,498423,673 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 through purchase power agreements during the year. We expect to continue to produce and purchase significant amounts of wind generationbeginning in the future. In January 2010, we reached an agreement with a third party to acquire the development rights for a site we believe is capable of supporting up to 500 MW of wind generation. We expect to develop the site in phases with the initial phase potentially completed by the end of 2012, subject to regulatory approvals and the pace of development of new transmission facilities in western Kansas.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 ourselves.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 generationour own costs extremeof 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 2009,2010, purchased power comprised approximately 11%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 and $61.04 in 2007.2008.

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 futurefutures contracts, options and swaps, and we tradephysical energy commodity contracts.

Competition and Deregulation

FERCThe 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 how 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.

Regional Transmission Organization

We are a member of the SPP,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. We record in other revenue amounts we receive for providing transmission service.

Real-Time Energy Imbalance Market

The SPP implementedutilizes a real-time energy imbalance market as required by FERC to accommodate financial settlement of energy imbalances within the SPP region. The objective of thisthe real-time market system 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 formula,formulae, which reducesreduce 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

OnIn February 2, 2010,2011, 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, by regulators, we estimate that thisthe new prices will increase our annual retail revenues by $6.4$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.

On January 27, 2010, the KCC issued an order allowing us to adjust our prices to include costs associated with our investments in natural gas and wind generation facilities that were not included in the price increase approved by the KCC in its January 21, 2009, order discussed below.facilities. The new prices were effective February 2010 and are expected to increase our annual retail revenues by $17.1 million.

On September 11, 2009, the KCC issued an order, effective January 1, 2009, allowing us to establish a regulatory asset or liability to track the cumulative difference between current year pension and post-retirement benefits expense and the amount of such expense recognized in setting our prices. At the time of a future rate case, we expect to amortize such regulatory asset or liability as part of resetting base rates.

On May 29, 2009, the KCC issued an order allowing us to adjust our prices to include costs associated with environmental investments made in 2008. This change went into effect on June 1, 2009, and is expected to increase our annual retail revenues by $32.5 million.

On March 6, 2009, the KCC issued an order allowing us to adjust our prices to include updated transmission costs. This change went into effect on March 13, 2009, and is expected to increase our annual retail revenues by $31.8 million.

On January 21, 2009, the KCC issued an order expected to increase our annual retail prices by $130.0 million to reflect investments in natural gas generation facilities, wind generation facilities and other capital projects, costs to repair damage to our electrical system, which were previously deferred as a regulatory asset, higher operating costs in general and an updated capital structure. The new prices became effective on February 3, 2009.

FERC Proceedings

Requests for Changes in Rates

On October 15, 2009,2010, we filedposted our updated transmission formula rate which includes projected 20102011 transmission capital expenditures and operating costs. OurThe updated transmission formula rate was effective January 1, 2010,2011, 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. This filingThe transmission formula rate provides the basis for requesting a change in our annual request with the KCC to adjust our retail prices forto include updated transmission costs under the jurisdiction of the KCC as noted above.

In July and August 2009, FERC approved our requests to implement a cost-based formula rate for two of our wholesale customers. The use of a cost-based formula rate allows us to adjust our prices to reflect changes in our cost of service. On January 12, 2010, FERC issued an order accepting our request to implement a cost-based formula rate similar to that described above that would be applicable for electricity sales to other 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 as of December 1, 2009.

Request for Increase in Revolving Credit Facility

On January 27, 2010, FERC approved our request for authority to issue short-term securities and pledge KGE mortgage bonds in order to increase the size of Westar Energy’s revolving credit facility from $750.0 million to $1.0 billion. We have not yet exercised our authority to increase the size of the facility.

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 tended to 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. CertainWe are permitted to recover certain of these costs are recoverable through the environmental cost recovery rider (ECRR), which allows for the more timely inclusion in retail prices the costs of costscapital expenditures associated with capital expenditures tied directly to environmental improvements, including those required by the Federal Clean Air Act. However, there can be no assurance that we will be able to recover all such costs from our customers or 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

TheWe 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, and 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.

CertainEmissions 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.

Sulfur Dioxide

Through the combustion of fossil fuels at our generating facilities, we emit SO₂and 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, prohibit the emission of SO₂ in excess of prescribed levels. In order to meet these standards, we use low-sulfur coal and natural gas and have equipped some of our generating facilities with pollutionequipment to control equipment.such emissions.

In addition, we must comply withWe are subject to the provisions of the Clean Air Act Amendments of 1990 that require a reduction in SO₂ and NOx. We have installed continuous emissions monitoring and reporting equipment in order to meet these requirements.

Title IV of the Clean Air Act created an SO₂ allowance and trading program as part ofunder the federal acid rain program.Federal Clean Air Act. Under the allowance and tradingthis program, the Environmental Protection Agency (EPA) allocatedallocates annual SO₂ emissions allowances for each affected unit. An SO₂ allowance is a limited authorization to emit one ton of SO₂ during a calendar year. Atemitting units subject to the end of each year, each emittingprogram. 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 in the market in which such allowances are traded.from others. In 2009,2010, we had SO₂ allowances adequate to meet planned generation and we expect to have enough in 2010.2011. In the future if we need to purchase additional air emission allowances our operating costs would increase. We recover, and would expect to continue to recover, the cost of such allowances through the RECA. The price of air emission allowances is determined by regulations and market forces and changes over time.

Clean Air Transport Rule

We have an agreement withIn July 2010, the KDHE to implement a plan to install new equipment to reduce regulated emissions from our generating fleet. The projects are designed to meet requirements ofEPA proposed the Clean Air VisibilityTransport Rule (CATR), which would require the District of Columbia and significantly reduce plant emissions.

While an earlier issued EPA rule on mercury was vacated31 states, including Kansas, to issue regulations and develop a plan by a U.S. Court of Appeals ruling, the Obama administration has indicated that it intends to enact stricter, technology-based regulations on mercury emissions. Our costs to comply with mercury emission requirements could be material.

Environmental requirements have been changing substantially and have become more stringent over time. Accordingly, we may be required towhich power plants in their respective jurisdictions will further reduce emissions of presently regulated gasesSO₂ and substances, such asNOx. 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 and mercury, andNAAQS 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 maycould be required to reduceplace 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 limitconsolidated financial results, but it could be material.

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 gasesAppeals 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 substances not presently regulated (e.g.,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). Proposals and bills in those respects include:

If enacted, the impact of these proposed laws and regulations on our consolidated financial results cannot be accurately predicted because of various factors outside our control including, but not limited to, the specific terms of such laws or regulations, the amount and timing of required capital expenditures, the cost of any emission allowances or credits we may be required to purchase and our ability to recover additional capital and operating expenses in prices. Based on currently available information, we cannot estimate our costs to comply with these proposed laws and regulations, but we believe such costs could be material.

Environmental Legislation

On June 26,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 bill which, if passed by the Senate and signed into law by the President, would require reductions in greenhouse gas (GHG) emissions and, even beyond that, would impose additional expense for virtually all such emissions, even those below the stated targeted emission levels. The bill identifies seven gasses, includingnationwide cap on CO₂, as GHGs, and introduces a target to reduceother GHG emissions 3% below 2005 levelsand 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 2012, 17% below 2005 levels by 2020, 42% below 2005 levels by 2030 and 83% below 2005 levels by 2050. The bill also mandates that retail electric utilities receive 6% of their power from renewable sources by 2012, with this requirement increasing to 20% by 2020; in certain circumstances, a portion of this requirement could be satisfied through energy efficiency measures. On September 30, 2009, similar legislation was introducedlegislators in the U.S. Senate.future. The targets forEPA has also proposed using the Federal Clear Air Act to limit CO₂ and other GHG emission reductions underemissions, and other measures are being imposed or offered by individual states, municipalities and regional agreements, such as the Senate bill are 3% below 2005 levels by 2012, 20% below 2005 levels by 2020, 42% below 2005 levels by 2030 and 83% below 2005 levels by 2050.Midwestern Greenhouse Gas Reduction Accord, with the goal of reducing GHG emissions.

On April 17, 2009,Under EPA regulations finalized in May 2010, known as the Administrator oftailoring rule, the EPA issued a proposed finding thatbegan regulating GHG emissions from mobilecertain 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 contribute to air pollution that endangers the public health and welfare. The endangerment finding was proposed in response to a U.S. Supreme Court’s ruling in April 2007 that GHGs are pollutants as defined in the Clean Air Act. If the EPA proposal becomes final, the EPAmore per year or 100,000 tons or more per year, depending on various factors), will be required to enactimplement 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 emission standardsNew Source Performance Standard (NSPS) rules for mobile sources.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.

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 September 15, 2009,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 the U.S. Department of Transportation released a proposed joint rule that would regulate GHG emissions from passenger cars and light trucks. IfJustice (DOJ) to resolve alleged violations of the rule becomes final, it may render GHG,s including CO₂, “subject to regulation” under the Clean Air Act. On September 22, 2009, the EPA released its final rule requiring mandatory reporting of GHG emissions from all economic sectors. Our generating facilities are subject to these new reporting requirements. In addition, on September 30, 2009, the EPA issued a proposed rule under theFederal Clean Air Act and indicated its expectation that it would enact regulationsat JEC. The terms of the agreement require us to control GHGinstall additional equipment as well as perform environmental mitigation projects to further reduce air emissions.

There is substantial uncertainty with respect to whether U.S. federal GHG legislation will be enacted into law or whether the See “—EPA will regulate GHG emissions, and there is additional uncertaintyLawsuit” below for further information regarding the final provisions and implementation of any potential U.S. federal GHG legislation or EPA rules regulating GHG emissions. We cannot predict with certainty the outcometerms of the legislative and rulemaking processes or a specific related impact on our generating facilities.agreement.

The EPA may develop new regulations, and Congress may pass new legislation, that impose additional requirements on facilities that store or dispose of non-hazardous fossil fuel combustion materials, including coal ash. If so, we may be required to change our current practices and incur additional capital expenditures and/or operating expenses to comply with these regulations.Renewable Energy Standard

OnIn May 22, 2009, the State of Kansas enacted legislation that mandates, among other requirements, that more energy be derived from renewable sources. According to the law, inIn years 2011 through 2015 net renewable generation capacity must be 10% of the average peak demand for the three prior years.years, subject to limited exceptions. This requirement increases to 15% for years 2016 through 2019 and 20% for 2020 and thereafter. A further provision of the law is that the KCC may elect not to enforce these requirements if they result in more than a 1% increase in our prices. AlongWe have worked with third parties we developedto develop approximately 300 MW of qualifying wind generation facilities, that began producingwhich together with the use of renewable energy in late 2008 and early 2009. We estimate thatcredits, we may need to add about 150 to 200 MW of additional renewable generating capacityexpect to meet the 2011 deadline. In Januaryrequirement. On December 14, 2010, we announced that we reached an agreementtwo separate agreements with a third partyparties, subject to acquireregulatory approval, to purchase under 20-year supply contracts the development rights for a site we believe is capable of supporting up to 500renewable energy produced from approximately 370 MW of wind generation.generation beginning in late 2012. We expect to develop the site in phasesthese agreements, along with the initial phase potentially completed by the end of 2012, subject to regulatory approvals and the pace ofour prior development of new transmissionwind generation facilities, will satisfy our net renewable generation requirement through 2015 and contribute toward meeting the increased requirement beginning in western Kansas.2016.

Environmental Costs

We will continue to make significant capital expenditures and incur operating expenses at our power plants to reduce undesirableregulated emissions. The amount of these expenditures could change materially increase or decrease 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 the plants. 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 theour 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 ultimate amount of these capital investments. Our estimated capital expenditures associated with environmental improvements for 2010-2012 are as shown in the following table. We prepare these estimates for planning purposes and revise them from time to time.