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-	amount, type and timing of capital expenditures,

-	earnings,

-	cash flow,

-	liquidity and capital resources,

-	litigation,

-	accounting matters,

-	possible corporate restructurings, acquisitions and dispositions,

-	compliance with debt and other restrictive covenants,

-	interest rates and dividends,

-	environmental matters,

-	regulatory matters,

-	nuclear operations, and

-	the overall economy of our service area and its impact on our customers' demand for electricity and their ability to pay for service.

-	the risk of operating in a heavily regulated industry subject to frequent and uncertain political, legislative, judicial and regulatory developments at any level of government that can affect our revenues and costs,

-	the difficulty of predicting the amount and timing of changes in demand for electricity,

-	weather conditions and their effect on sales of electricity as well as on prices of energy commodities,

-	equipment damage from storms and extreme weather,

-	economic and capital market conditions, including the impact of inflation or deflation, changes in interest rates, the cost and availability of capital and the market for trading wholesale energy,

-	the impact of changes in market conditions on employee benefit liability calculations, as well as actual and assumed investment returns on invested plan assets,

-	the impact of changes in estimates regarding our Wolf Creek Generating Station (Wolf Creek) decommissioning obligation,

-	the ability of our counterparties to make payments as and when due and to perform as required,

-	the existence or introduction of competition into markets in which we operate,

-	the impact of frequently changing laws and regulations relating to air emissions, water emissions, waste management and other environmental matters,

-	risks associated with execution of our planned capital expenditure program, including timing and receipt of regulatory approvals necessary for planned construction and expansion projects as well as the ability to complete planned construction projects within the terms and time frames anticipated,

-	cost, availability and timely provision of equipment, supplies, labor and fuel we need to operate our business,

-	availability of generating capacity and the performance of our generating plants,

-	changes in regulation of nuclear generating facilities and nuclear materials and fuel, including possible shutdown or required modification of nuclear generating facilities,

-	additional regulation due to Nuclear Regulatory Commission (NRC) oversight to ensure the safe operation of Wolf Creek, either related to Wolf Creek's performance, or potentially relating to events or performance at a nuclear plant anywhere in the world,

-	uncertainty regarding the establishment of interim or permanent sites for spent nuclear fuel storage and disposal,

-	homeland and information security considerations,

-	changes in accounting requirements and other accounting matters,

-	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,

-	regulatory limits, higher costs and/or reduced demand associated with coal-based energy because of concerns about environmental impact or the desire to advance alternate energy sources,

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-	conservation and energy efficiency measures which may reduce electricity sales,

-	current and future litigation, regulatory investigations, proceedings or inquiries,

-	other circumstances affecting anticipated operations, electricity sales and costs, and

-	other factors discussed elsewhere in this report, including in "Item 1A. Risk Factors" and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations," and in other reports we file from time to time with the Securities and Exchange Commission (SEC).

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(a)

Under a wholesale agreement that expires in May 2039, we provide base load capacity to the city of McPherson, Kansas, and in return the city provides peaking capacity to us. During 2012, we provided approximately 88 MW to, and received approximately 148 MW from, the city. The amount of base load capacity provided to the city is based on a fixed percentage of its annual peak system load. The city is a full requirements customer of Westar Energy. In addition, the agreement for the city to provide capacity to us is treated as a capital lease. See Note 18 of the Notes to Consolidated Financial Statements, "Leases," for additional information.

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•	reduce demand for our service;

•	increase delinquencies or non-payment by customers;

•	adversely impact the financial condition of suppliers, which may in turn limit our access to inventory or capital equipment or increase our costs; and

•	increase deductibles and premiums and result in more restrictive policy terms under insurance policies regarding risks we typically insure against, or make insurance claims more difficult to collect.

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•	the risks associated with storing, handling and disposing of radioactive materials and the current lack of a long-term off-site disposal solution for radioactive materials;

•	limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with nuclear operations;

•	uncertainties with respect to the technological and financial aspects of decommissioning Wolf Creek at the end of its life; and

•	costs of measures associated with public safety.

•	shortages, disruption in the delivery and inconsistent quality of equipment, materials and labor;

•	contractor or supplier non-performance;

•	delays in or failure to receive necessary permits, approvals and other regulatory authorizations;

•	impacts of new and existing laws and regulations, including environmental and health and safety laws, regulations and permit requirements;

•	adverse weather;

•	unforeseen engineering problems or changes in project design or scope;

•	environmental and geological conditions; and

•	unanticipated cost increases with respect to labor or materials, including basic commodities needed for our infrastructure such as steel, copper and aluminum.

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(a)	The 2009 amount represents income from continuing operations.

(b)	Includes long-term debt, net, current maturities of long-term debt, capital leases and, for 2010 through 2012, long-term debt of VIEs, net and current maturities of long-term debt of VIEs. See Note 17 of the Notes to Consolidated Financial Statements, "Variable Interest Entities," for additional information regarding VIEs.

(c)

The earnings per share (EPS) amount previously reported for 2008 was adjusted to reflect the use of the two-class method beginning in 2009. See Note 2 of the Notes to Consolidated Financial Statements, "Summary of Significant Accounting Policies—Earnings Per Share," for additional information regarding the two-class method. Additionally, we recorded basic EPS available for common stock from continuing operations of $1.28 in 2009.

(d)	In 2008, Westar Energy issued and sold approximately 12.8 million shares of common stock realizing proceeds of $293.6 million.

(e)	In 2010, Westar Energy issued and sold approximately 3.1 million shares of common stock realizing proceeds of $54.7 million.

(f)	In 2011, Westar Energy issued and sold approximately 13.6 million shares of common stock realizing proceeds of $294.9 million.

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•	weather conditions;

•	the economy;

•	customer conservation efforts;

•	the performance, operation and maintenance of our electric generating facilities and networks;

•	conditions in the fuel, wholesale electricity and energy markets;

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

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

•	capital market conditions.

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(a)	Increases or decreases due to changes in actuarial assumptions result primarily in changes to regulatory assets and liabilities.

(a)	Increases or decreases due to changes in actuarial assumptions result primarily in changes to regulatory assets and liabilities.

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(a)	Reflects revenue from an SPP network transmission tariff. In 2012 and 2011, our SPP network transmission costs were $166.5 million and $132.2 million, respectively. These amounts, less administration costs of $27.2 million and $18.6 million, were returned to us as revenue in 2012 and 2011, respectively.

(b)	Change greater than 1000%.

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(a)	Change less than 0.1%.

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•	higher SPP network transmission costs of $34.4 million, most of which is offset with higher revenues;

•	a $9.2 million increase in property taxes, most of which is offset in retail revenues;

•	higher costs for tree trimming and other electrical system reliability activities of $5.9 million; and

•	higher costs at Wolf Creek of $4.6 million, which were the result primarily of maintenance costs incurred during an unscheduled outage.

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•	our having reversed $22.0 million of previously accrued liabilities in 2011 as a result of settling litigation;

•	higher pension and other employee benefit costs of $20.2 million;

•	our having recorded $4.5 million of expense as a result of sustainable cost reduction activities; and

•	a $2.1 million increase in the amortization of previously deferred amounts associated with various energy efficiency programs, which we recover in retail revenues; however,

•	partially offsetting these increases was a $9.4 million decrease in legal fees that was the result principally of arbitration and litigation that occurred in 2011.

•	our having recorded a $7.2 million gain on the sale of a non-utility investment in 2011; however,

•	partially offsetting these items was our having recorded $4.5 million of additional gains on investments in a trust to fund retirement benefits and a $1.7 million increase in our share of the earnings of the Prairie Wind Transmission, LLC.

•	our having recorded an additional $17.4 million in COLI benefits;

•	a $6.2 million increase in equity AFUDC, which reflects more construction activity; and

•	our having recorded an additional $3.1 million related to the sale of oil inventory.

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(a)	Reflects revenue from an SPP network transmission tariff. In 2011 and 2010, our SPP network transmission costs were $132.2 million and $116.4 million, respectively. These amounts, less administration costs of $18.6 million and $14.4 million, respectively, were returned to us as revenue.

(b)	Cannot divide by zero.

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•	higher SPP network transmission costs of $15.7 million, most of which is recovered in revenues;

•	higher costs at Wolf Creek of $13.0 million, which was the result primarily of an increase in the amortization of deferred refueling and maintenance outage costs of $8.0 million and higher regulatory compliance costs;

•	a $7.0 million increase in property taxes, which was mostly offset in retail revenues;

•	our having recorded in 2010 a $5.0 million reduction in our liability for environmental remediation costs associated with assets we divested many years ago;

•	a $2.3 million increase related to the operation of our steam powered plants; and

•	higher costs for tree trimming and other distribution reliability activities of $1.4 million; however,

•	partially offsetting these increases was an $8.0 million decrease in the amortization of previously deferred storm costs.

•	the reversal of approximately $22.0 million of previously accrued liabilities as a result of the legal settlements discussed in Note 15 of the Notes to Consolidated Financial Statements, "Legal Proceedings"; and

•	our having recorded $7.1 million less for non-union, non-executive employee compensation that is at-risk to employees and payable only upon meeting pre-established operating and financial objectives.

•	a $3.6 million increase in the amortization of previously deferred amounts associated with various energy efficiency programs, which we recover in higher retail revenues; and

•	higher legal fees of $3.2 million related principally to the legal matters discussed in Note 15 of the Notes to Consolidated Financial Statements, "Legal Proceedings."

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•	a $2.4 million increase in equity AFUDC, which reflects increased construction activity; and

•	our having recorded gains on the sale of oil of $1.2 million, for which similar gains were not recorded in 2010.

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•	an $18.7 million decrease in deferred employee benefit costs;

•	a $15.3 million decrease in amounts previously deferred for fuel expense;

•	a $14.7 million decrease in previously deferred storm costs; and

•	a $10.9 million decrease in amounts deferred for the 2011 Wolf Creek outage; however,

•	partially offsetting decreases was a $15.2 million increase in amounts deferred for property taxes.

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(a)	In addition to amounts listed, we are investing in Prairie Wind Transmission. In 2012, we incurred $8.3 million of expenditures related to this investment. In 2013, 2014 and 2015, we plan to incur expenditures related to Prairie Wind Transmission of $4.3 million, $17.9 million and $0.1 million, respectively.

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(a)	See Note 9 of the Notes to Consolidated Financial Statements, "Long-Term Debt," for individual maturities.

(b)	We calculate interest on our variable rate debt based on the effective interest rates as of December 31, 2012.

(c)	Our contribution amounts for future periods are not yet known. See Notes 11 and 12 of the Notes to Consolidated Financial Statements, "Employee Benefit Plans" and "Wolf Creek Employee Benefit Plans," for additional information regarding pension and post-retirement benefits.

(d)	Includes principal and interest on capital leases.

(e)	Includes leases for operating facilities, operating equipment, office space, office equipment, vehicles and rail cars as well as other miscellaneous commitments.

(f)	See Note 17 of the Notes to Consolidated Financial Statements, “Variable Interest Entities,” for additional information on VIEs.

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

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

(i)	Includes obligations to SPP for transmission service payments. See Note 13 of the Notes to Consolidated Financial Statements, "Commitments and Contingencies," for additional information.

(j)	We have $1.7 million of unrecognized income tax benefits, including interest, that are not included in this table because we cannot reasonably estimate the timing of the cash payments to taxing authorities assuming those unrecognized income tax benefits are settled at the amounts accrued as of December 31, 2012.

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•	Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the company;

•	Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and

•	Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements.

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(a)	For the years ended December 31, 2012, 2011 and 2010, we had no antidilutive shares.

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Deferred employee benefit costs: Includes $485.5 million for pension and post-retirement benefit obligations and $56.7 million for actual pension expense in excess of the amount of such expense recognized in setting our prices. During 2013, we will amortize to expense approximately $44.2 million of the benefit obligations and approximately $9.8 million of the excess pension expense. As authorized in the April 2012 KCC order discussed below, we are amortizing the excess pension expense as of the time of our filing with the KCC over a five-year period. We do not earn a return on this asset.

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Amounts due from customers for future income taxes, net: In accordance with various orders, we have reduced our prices to reflect the income tax benefits associated with certain income tax deductions, thereby passing on these benefits to customers at the time we receive them. We believe it is probable that the net future increases in income taxes payable will be recovered from customers when these temporary income tax benefits reverse in future periods. We have recorded a regulatory asset, net of the regulatory liability, for these amounts on which we do not earn a return. We also have recorded a regulatory liability for our obligation to customers for income taxes recovered in earlier periods when corporate income tax rates were higher than current income tax rates. This benefit will be returned to customers as these temporary differences reverse in future periods. The income tax-related regulatory assets and liabilities as well as unamortized investment tax credits are also temporary differences for which deferred income taxes have been provided. These items are measured by the expected cash flows to be received or settled in future prices. We do not earn a return on this asset.

•	Depreciation: Represents the difference between regulatory depreciation expense and depreciation expense we record for financial reporting purposes. We earn a return on this asset and amortize the difference over the life of the related plant.

•	Debt reacquisition costs: Includes costs incurred to reacquire and refinance debt. These costs are amortized over the term of the new debt. We do not earn a return on this asset.

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Treasury yield hedges: Represents the effective portion of losses on treasury yield hedge transactions. This amount will be amortized to interest expense over the term of the related debt. See Note 4, "Financial and Derivative Instruments, Trading Securities, Energy Marketing and Risk Management—Derivative Instruments—Cash Flow Hedges," for additional information regarding our treasury yield hedge transactions. We do not earn a return on this asset.

•	Asset retirement obligations: Represents amounts associated with our AROs as discussed in Note 14, "Asset Retirement Obligations." We recover these amounts over the life of the related plant. We do not earn a return on this asset.

•	Ad valorem tax: Represents actual costs incurred for property taxes in excess of amounts collected in our prices. We expect to recover these amounts in our prices over a one-year period. We do not earn a return on this asset.

•	Energy efficiency program costs: We accumulate and defer for future recovery costs related to our various energy efficiency programs. We will amortize such costs over a one-year period. We do not earn a return on this asset.

•	Disallowed plant costs: In 1985, the Kansas Corporation Commission (KCC) disallowed certain costs associated with the original construction of Wolf Creek. In 1987, the KCC authorized KGE to recover these costs in prices over the useful life of Wolf Creek. We do not earn a return on this asset.

•	Wolf Creek outage: We defer the expenses associated with Wolf Creek's scheduled refueling and maintenance outages and amortize these expenses during the period between planned outages. We do not earn a return on this asset.

•	Storm costs: We accumulated and deferred for future recovery costs related to restoring our electric transmission and distribution systems from damages sustained during unusually damaging storms. We amortize these costs over periods ranging from three to five years and earn a return on a majority of this asset.

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Retail energy cost adjustment: We are allowed to adjust our retail prices to reflect changes in the cost of fuel and purchased power needed to serve our customers. This item represents the actual cost of fuel consumed in producing electricity and the cost of purchased power in excess of the amounts we have collected from customers. We expect to recover in our prices this shortfall over a one-year period. We have two retail jurisdictions, each with a separate cost of fuel. For the reporting period, this resulted in us simultaneously reporting both a regulatory asset and a regulatory liability for this item. We do not earn a return on this asset.

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•	Other regulatory assets: Includes various regulatory assets that individually are small in relation to the total regulatory asset balance. Other regulatory assets have various recovery periods. We do not earn a return on any of these assets.

•	Removal costs: Represents amounts collected, but not yet spent, to dispose of plant assets that do not represent legal retirement obligations. This liability will be discharged as removal costs are incurred.

•	Deferred regulatory gain from sale leaseback: Represents the gain KGE recorded on the 1987 sale and leaseback of its 50% interest in La Cygne Generation Station (La Cygne) unit 2. We amortize the gain over the lease term.

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Nuclear decommissioning: We have a legal obligation to decommission Wolf Creek at the end of its useful life. This amount represents the difference between the fair value of the assets held in a decommissioning trust and the fair value of our ARO. See Note 4, "Financial and Derivative Instruments, Trading Securities, Energy Marketing and Risk Management," Note 5, "Financial Investments" and Note 14, "Asset Retirement Obligations," for information regarding our nuclear decommissioning trust (NDT) and our ARO.

•	La Cygne dismantling costs: We are contractually obligated to dismantle a portion of La Cygne unit 2. This item represents amounts collected but not yet spent to dismantle this unit and the obligation will be discharged as we dismantle the unit.

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Retail energy cost adjustment: We are allowed to adjust our retail prices to reflect changes in the cost of fuel and purchased power needed to serve our customers. We bill customers based on our estimated costs. This item represents the amount we collected from customers that was in excess of our actual cost of fuel and purchased power. We will refund to customers this excess recovery over a one-year period. We have two retail jurisdictions, each with a separate cost of fuel. For the reporting period, this resulted in us simultaneously reporting both a regulatory asset and a regulatory liability for this item.

•	Kansas tax credits: Represents Kansas tax credits on investments in utility plant. Amounts will be credited to customers subsequent to their realization over the remaining lives of the utility plant giving rise to the tax credits.

•	Other post-retirement benefits costs: Represents the amount of other post-retirement benefits expense recognized in setting our prices in excess of actual other post-retirement benefits expense. We amortize the amount over a five-year period.

•	Gain on sale of oil: We discontinued the use of a certain type of oil in our plants. As a result, we sold this oil inventory for a gain. This item represents the remaining portion of the gain that will be refunded to customers over a three-year period.

•	Fuel supply and electricity contracts: We use fair value accounting for some of our fuel supply and electricity contracts. This represents the non-cash net gain position on fuel supply and electricity contracts that are recorded at fair value. Under the RECA, fuel supply contract market gains accrue to the benefit of our customers.

•	Other regulatory liabilities: Includes various regulatory liabilities that individually are relatively small in relation to the total regulatory liability balance. Other regulatory liabilities will be credited over various periods.

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•	$19.5 million effective in June 2012;

•	$10.4 million effective in June 2011; and

•	$13.8 million effective in June 2010.

•	$36.7 million effective in April 2012;

•	$17.4 million effective in April 2011; and

•	$6.4 million effective in March 2010.

•	$1.1 million effective in October 2012;

•	$4.9 million effective in November 2011; and

•	$5.8 million effective in November 2010.

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•	$38.2 million effective in January 2012;

•	$15.9 million effective in January 2011; and

•	$16.8 million effective in January 2010.

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•	Level 1 - Quoted prices are available in active markets for identical assets or liabilities. The types of assets and liabilities included in level 1 are highly liquid and actively traded instruments with quoted prices, such as equities listed on public exchanges and exchange-traded futures contracts.

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Level 2 - Pricing inputs are not quoted prices in active markets, but are either directly or indirectly observable. The types of assets and liabilities included in level 2 are typically measured at net asset value, comparable to actively traded securities or contracts, such as treasury securities with pricing interpolated from recent trades of similar securities, or priced with models using highly observable inputs, such as commodity options priced using observable forward prices and volatilities.

•	Level 3 - Significant inputs to pricing have little or no transparency. The types of assets and liabilities included in level 3 are those with inputs requiring significant management judgment or estimation, such as the complex and subjective models and forecasts used to determine the fair value of options, private equity and real estate securities and long-term electricity supply contracts.

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(a)	Unrealized gains and losses included in earnings are reported in revenues.

(b)	Includes changes in the fair value of certain fuel supply and electricity contracts.

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(a)	This investment is in two long-term private equity funds that do not permit early withdrawal. Our investments in these funds cannot be distributed until the underlying investments have been liquidated which may take years from the date of initial liquidation. One fund has begun making distributions and we expect the other to begin in 2013.

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(a)	Jointly owned with KCPL. Our 8% leasehold interest in JEC that is consolidated as a VIE is reflected in the net megawatts (MW) and ownership percentage provided above, but not in the other amounts in the table.

(b)	Jointly owned with KCPL and Kansas Electric Power Cooperative, Inc.

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(a)

Based on filed tax returns and amounts expected to be reported in current year tax returns (December 31, 2012), we had available federal general business tax credits of $39.3 million and state investment tax credits of $159.8 million. The federal general business tax credits were primarily generated from affordable housing partnerships in which we sold the majority of our interests in 2001. These tax credits expire beginning in 2020 and ending in 2032. The state investment tax credits expire beginning in 2013 and ending in 2028. As we do not expect to realize sufficient state taxable income in 2013, a valuation allowance of $1.3 million has been established for the state investment tax credits that expire in 2013 (see item (e) below).

(b)	As of December 31, 2012, we had a federal net operating loss carryforward of $276.9 million, which is available to offset federal taxable income. The net operating losses will expire beginning in 2030 and ending in 2032.

(c)	As of December 31, 2012, we had available an alternative minimum tax credit carryforward of $36.5 million, which has an unlimited carryforward period.

(d)	As of December 31, 2012, we had an unused capital loss carryforward of $29.1 million that is available to offset future capital gains. The capital losses will expire beginning in 2013 and ending in 2016.

(e)

As we do not expect to realize any significant capital gains in the future, we have established a valuation allowance of $11.5 million. In addition, we have established a valuation allowance of $2.3 million for certain deferred tax assets related to the write-down of other investments and state investment tax credits. The total valuation allowance related to the deferred tax assets was $13.8 million as of December 31, 2012, and $13.7 million as of December 31, 2011.

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(a)	In 2012 certain former employees received a one-time lump sum payment of their pension benefits totaling $26.1 million.

(b)	As of December 31, 2011, Other includes the $9.7 million reclassification of a contractual obligation related to the legal settlement with a former executive officer and $0.8 million of proceeds received as a result of the Early Retiree Reinsurance Program.

(c)

As of December 31, 2012 and 2011, pension benefits include non-qualified benefit obligations of $30.0 million and $29.4 million, respectively, which are funded by a trust containing assets of $43.5 million and $40.2 million, respectively, classified as trading securities as discussed in Notes 4 and 5, "Financial and Derivative Instruments, Trading Securities, Energy marketing and Risk Management" and "Financial Investments," respectively.

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(a)	The regulatory adjustment represents the difference between current period pension or post-retirement benefit expense and the amount of such expense recognized in setting our prices.

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(a)	In 2012 certain former employees received a one-time lump sum payment of their pension benefits. Our share of the payment totaled $4.9 million.

(b)	Includes proceeds received as a result of the Early Retiree Reinsurance Program.

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(a)	The regulatory adjustment represents the difference between current period pension or post-retirement benefit expense and the amount of such expense recognized in setting our prices.

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(a)	Items are computed independently for each of the periods presented and the sum of the quarterly amounts may not equal the total for the year.

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(a)	Items are computed independently for each of the periods presented and the sum of the quarterly amounts may not equal the total for the year.

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(a)	Result from write-offs of accounts receivable.

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