We have considered a number of risks and costs associated with the future contractual commitments included in our energy portfolio. These risks include credit risks associated with the financial condition of counterparties, product location (basis) differentials and other risks. Declines in the credit-worthiness of our counterparties could have a material adverse impact on our overall exposure to credit risk. We maintain credit policies with regard to our counterparties that, in management’s view, reduce overall credit risk. There can be no assurance that the employment of VaR, or other risk management tools we employ, will eliminate the risk of loss.

We are also exposed to commodity price changes outside of trading activities. We use derivatives for non-trading purposes and a mix of various fuel types primarily to reduce exposure relative to the volatility of market and commodity prices. The wholesale power market is extremely volatile in price and supply. This volatility impacts our costs of power purchased and our participation in power trades. If we were unable to generate an adequate supply of electricity for our native load customers, we would purchase power in the wholesale market to the extent it is available or economically feasible to do so and/or implement curtailment or interruption procedures as allowed for in our tariffs and terms and conditions of service. To the extent open positions exist in our power marketing portfolio, we are exposed to changing market prices that may adversely impact our financial position and results of operations. The increased expenses or loss of revenues associated with this could be material and adverse to our consolidated results of operations and financial condition.

From 2001 to 2002, we experienced a 10% decrease in the average price per MWh of electricity purchased for utility operations. Purchased power market volatility could be greater than the average price decrease indicates. If we were to have a 10% increase in our purchased power price from 2002 to 2003, given the amount of power purchased for utility operations during 2002, we would have exposure of approximately $3.5 million of operating income. Due to the volatility of the power market, past prices cannot be used to predict future prices.

We use a mix of various fossil fuel types, including coal, natural gas and oil, to operate our system, which helps lessen our risk associated with any one fuel type. A significant portion of our coal requirements are under long-term contract, which removes most of the price risk associated with this commodity type. During 2002, we experienced an approximate 2% increase, or $0.056 per MMBtu, in our average cost for natural gas purchased for utility operations. We decreased our gas usage by 1.9 million MMBtu compared to the amount burned in 2001. Due to the volatility of natural gas prices, we have begun to increasingly utilize our ability to switch to lower cost fuel types as the market allows. We expect that exposure to natural gas price changes will not be material in 2003 due to our natural gas hedge that has fixed the price of our gas through July 2004.

We use uranium to fuel our nuclear generating station and have on hand or under contract 100% of Wolf Creek’s uranium, uranium conversion and uranium enrichment needs for 2003. We have on hand or under contract 76% of the uranium and

uranium conversion and 80% of the uranium enrichment required for operation of Wolf Creek through March 2008. The balance is expected to be obtained through spot market and contract purchases, which means we will be exposed to the price risk associated with these components.

Additional factors that affect our commodity price exposure are the quantity and availability of fuel used for generation and the quantity of electricity customers will consume. Quantities of fossil fuel used for generation could vary dramatically from year to year based on the individual fuel’s availability, price, deliverability, unit outages and nuclear refueling. Our customers’ electricity usage could also vary dramatically year to year based on the weather or other factors.

Under SFAS No. 133, we are required to mark to market changes in the anticipated amount of the liability related to the portion of the $400 million in notes that have been retired so that our consolidated balance sheet reflects the current fair value of the free standing portion of the call option as discussed in Note 14 of the Notes to Consolidated Financial Statements, “Call Option.” The amount of our liability will increase or decrease approximately $5 million for every 10-basis point change in the 10-year forward treasury rate. Related to the call option, for the year ended December 31, 2002, we recorded a non-cash mark-to-market charge of $23.7 million, net of $15.7 million tax benefit, to reflect the fair value of the call option associated with the retired notes. We intend to repurchase or provide for the repayment of all or a portion of these notes on or prior to June 15, 2003. Any repurchase of these notes will require us to mark to market additional amounts of the call option. We cannot predict changes in the market value of the call option and therefore cannot estimate amounts of future mark-to-market non-cash charges associated with the call option or the impact on our earnings.