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Critical Accounting Policies

The selection and application of accounting policies is an important process that continues to evolve as Duke Energy's operations change and accounting guidance evolves. Duke Energy has identified a number of critical accounting policies that require the use of significant estimates and judgments and have a material impact on its consolidated financial position and results of operations. Management bases its estimates and judgments on historical experience and on other various assumptions that they believe are reasonable at the time of application. The estimates and judgments may change as time passes and more information about Duke Energy's environment becomes available. If estimates and judgments are different than the actual amounts recorded, adjustments are made in subsequent periods to take into consideration the new information. Duke Energy discusses its critical accounting policies and other significant accounting policies with senior members of management and the audit committee, as appropriate. Duke Energy's critical accounting policies are listed below.

Risk Management Activities

Duke Energy uses two comprehensive accounting models for its risk management activities in reporting its consolidated financial position and results of operations as required by GAAP: a fair value model and an accrual model. For the three years ended December 31, 2003, the determination as to which model was appropriate was primarily based on accounting guidance issued by the Financial Accounting Standards Board (FASB) and the EITF. Effective January 1, 2003, Duke Energy adopted EITF Issue No. 02-03. While the implementation of such guidance changed the accounting model used for certain of Duke Energy's transactions, the overall application of the models remains the same.

The fair value model incorporates the use of mark-to-market (MTM) accounting. Under this method, an asset or liability is recognized at fair value on the Consolidated Balance Sheets and the change in the fair value of that asset or liability is recognized in Non-regulated Electric, Natural Gas, Natural Gas Liquids and Other in the Consolidated Statements of Operations during the current period. While DENA is the primary business segment that uses this accounting model, International Energy, Field Services, Other Operations and Franchised Electric also have certain transactions subject to this model. For the year ended December 31, 2003, Duke Energy applied MTM accounting to its derivative contracts, unless subject to hedge accounting or the normal purchase and normal sale exemption (as described below). For the years ended December 31, 2002 and 2001, Duke Energy also applied MTM accounting to energy trading contracts, as defined by EITF Issue No 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities."

MTM accounting is applied within the context of an overall valuation framework. All new and existing transactions are valued using approved valuation techniques and market data, and discounted using a London Interbank Offered Rate (LIBOR) based interest rate. When available, quoted market prices are used to measure a contract's fair value. However, market quotations for energy trading contracts may not be available for illiquid periods or locations. If no active trading market exists for a commodity or for a contract's duration, holders of these contracts must calculate fair value using internally developed valuation techniques or models. Key components used in these valuation techniques include price curves, volatility, correlation, interest rates and tenor. While volatility and correlation are the most subjective components, the price curve is generally the most significant component affecting the ultimate fair value for a contract subject to mark-to-market accounting after implementation of EITF 02-03 due to the discontinuation of mark-to-market accounting for certain energy trading contracts, such as transportation agreements. Prices for illiquid periods or locations are established by extrapolating prices for correlated products, locations or periods. These relationships are routinely re-evaluated based on available market data, and changes in price relationships are reflected in price curves prospectively. Consideration may also be given to the analysis of market fundamentals when developing illiquid prices. A deviation in any of the components affecting fair value may significantly affect overall fair value.

Valuation adjustments for performance and market risk, and administration costs are used to arrive at the fair value of the contract and the gain or loss ultimately recognized in the Consolidated Statements of Operations. While Duke Energy uses common industry practices to develop its valuation techniques, changes in Duke Energy's pricing methodologies or the underlying assumptions could result in significantly different fair values and income recognition.

Validation of a contract's calculated fair value is performed by the Risk Management Group. This group performs pricing model validation, back testing and stress testing of valuation techniques, prices and other variables. Validation of a contract's fair value may be done by comparison to actual market activity and negotiation of collateral requirements with third parties.

Often for a derivative instrument that is initially subject to MTM accounting, Duke Energy applies either hedge accounting or the normal purchase and normal sales exemption in accordance with SFAS No. 133. The use of hedge accounting and the normal purchase and normal sales exemption provide effectively for the use of the accrual model. Under this model, there is generally no recognition in the Consolidated Statements of Operations for changes in the fair value of a contract until the service is provided or the associated delivery period occurs (settlement).

Hedge accounting treatment is used when Duke Energy contracts to buy or sell a commodity such as natural gas at a fixed price for future delivery corresponding with anticipated physical sales or purchase of natural gas (cash flow hedge). In addition, hedge accounting treatment is used when Duke Energy holds firm commitments or asset positions and enters into transactions that "hedge" the risk that the price of natural gas or electricity may change between the contract's inception and the physical delivery date of the commodity (fair value hedge). To the extent that the fair value of the hedge instrument offsets the transaction being hedged, there is no impact to the Consolidated Statements of Operations prior to settlement of the hedge. However, as not all of Duke Energy's hedges relate to the exact location being hedged, a certain degree of hedge ineffectiveness may be realized in the Consolidated Statements of Operations.

The normal purchases and normal sales exemption, as provided in SFAS No. 133 as amended and interpreted by Derivative Implementation Group (DIG) Issue C15, "Scope Exceptions: Normal Purchases and Normal Sales Exception for Option-Type Contracts and Forward Contracts in Electricity," and amended by SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities," indicates that no recognition of the contract's fair value in the Consolidated Financial Statements is required until settlement of the contract (in Duke Energy's case, the delivery of power). Previously, Duke Energy applied this exemption for certain contracts involving the sale of power in future periods. SFAS No. 149 includes certain modifications and changes to the applicability of the normal purchase and normal sales scope exception for contracts to deliver electricity. As a result, Duke Energy reevaluated its policy for accounting for forward power sale contracts and determined that substantially all forward contracts to sell power entered into after July 1, 2003 will be designated as cash flow hedges. To the extent that the hedge is perfectly effective, income statement recognition for the contract will be the same under either method. The unrealized loss associated with power forward sales contracts designated under the normal purchases and normal sales exemption as of December 31, 2003 was approximately $700 million. This unrealized loss represents the difference in the normal purchases and normal sales contract prices compared to the forward market prices of power as of December 31, 2003 and is partially offset by unrealized gains on natural gas positions of approximately $400 million which are recorded on the Consolidated Balance Sheet in Unrealized Gains and Losses on Mark-to-Market and Hedging Transactions. Duke Energy intends to fulfill these contractual obligations with production from its power generation fleet and, assuming that occurs, the above unrealized gains and losses would not be recognized in DENA's EBIT.

Regulatory Accounting

Duke Energy accounts for its regulated operations (primarily Franchised Electric and Natural Gas Transmission) under the provisions of SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation." As a result, Duke Energy records assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for non-regulated entities. Regulatory assets generally represent incurred costs that have been deferred because such are probable of future recovery in customer rates. Regulatory liabilities generally represent obligations to make refunds to customers for previous collections for costs that are not likely to be incurred. Management continually assesses whether the regulatory assets are probable of future recovery by considering factors such as applicable regulatory changes, recent rate orders applicable to other regulated entities and the status of any pending or potential deregulation legislation. Based on this continual assessment, management believes the existing regulatory assets are probable of recovery. This determination reflects the current political and regulatory climate at the state, provincial and federal levels, and is subject to change in the future. If future recovery of costs ceases to be probable, the asset write-offs would be required to be recognized in operating income. Total regulatory assets were $2,016 million as of December 31, 2003 and $1,421 million as of December 31, 2002. (See Note 4 to the Consolidated Financial Statements.)

Long-Lived Asset Impairments and Assets Held For Sale

Duke Energy evaluates the carrying value of long-lived assets, excluding goodwill, when circumstances indicate the carrying value of those assets may not be recoverable. For long-lived assets, an impairment exists when the carrying value exceeds the sum of estimates of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the asset is impaired, the asset's carrying value is adjusted to its estimated fair value. When alternative courses of action to recover the carrying amount of a long-lived asset are under consideration, a probability-weighted approach is used for developing estimates of future cash flows.

Duke Energy uses the best information available to estimate fair value of its long-lived assets and may use more than one source. Judgment is exercised to estimate the future cash flows, the useful lives of long-lived assets and to determine management's intent to use the assets. The sum of undiscounted cash flows is primarily dependent on forecasted commodity prices for sales of power, natural gas or natural gas liquids and costs of fuel over periods of time consistent with the useful lives of the assets. Management's intent to use or dispose of assets is subject to re-evaluation and can change over time.

A change in Duke Energy's plans regarding, or probability assessments of, holding or selling an asset could have a significant impact on the estimated future cash flows. Duke Energy considers various factors when determining if impairment tests are warranted, including but not limited to:

• Significant adverse changes in legal factors or in the business climate;
• A current-period operating or cash flow loss combined with a history of operating or cash flow losses, or a projection or forecast that demonstrates continuing losses associated with the use of a long-lived asset;
• An accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of a long-lived asset;
• Significant adverse changes in the extent or manner in which an asset is used or in its physical condition or a change in business strategy;
• A significant change in the market value of an asset; and
• A current expectation that, more likely than not, an asset will be sold or otherwise disposed of before the end of its estimated useful life.

Judgment is also involved in determining the timing of meeting the criteria for classification as an asset held for sale under SFAS No. 144.

Duke Energy intends to dispose of certain other assets in addition to the assets classified as held for sale at December 31, 2003. Negotiations for dispositions of these other assets, in addition to those classified as held for sale, are at various stages with prospective buyers. Based on current market conditions in the merchant energy industry, it is reasonably possible that Duke Energy's estimate of fair value of the long-lived assets impaired in 2003 could change and the change would impact the consolidated results of operations.

Impairment of Goodwill

Duke Energy evaluates the impairment of goodwill under SFAS No. 142. The majority of Duke Energy's goodwill relates to the acquisition of Westcoast in March 2002 and was not impaired as of December 31, 2003. The remainder relates to Field Services and International Energy's Latin America operations. As required by SFAS No. 142, Duke Energy performs an annual goodwill impairment test and updates the test if events or circumstances occur that would more likely than not reduce the fair value of a reporting unit below its carrying amount. As a result of the 2003 impairment test, Duke Energy recorded a $254 million goodwill impairment charge in the third quarter 2003 to write off all DENA goodwill, most of which related to certain aspects of DENA's trading and marketing business. This impairment charge reflects the reduction in scope and scale of DETM's business and the continued deterioration of market conditions affecting DENA during 2003. Duke Energy used a discounted cash flow analysis to perform the assessment. Key assumptions in the analysis included the use of an appropriate discount rate, estimated future cash flows and an estimated run rate of general and administrative costs. In estimating cash flows, Duke Energy incorporated current market information as well as historical factors and fundamental analysis as well as other factors into its forecasted commodity prices.

As the challenging market conditions continue into 2004, in addition to performing the annual goodwill impairment analysis required by SFAS No. 142, management will remain alert for any indicators that the fair value of a reporting unit could be below book value and assess goodwill for impairment as appropriate.

As of the acquisition date, Duke Energy allocates goodwill to a reporting unit. Duke Energy defines a reporting unit as an operating segment or one level below.

Revenue Recognition

Unbilled and Estimated Revenues.     Revenues on sales of electricity, primarily at Franchised Electric, are recognized when the service is provided. Unbilled revenues are estimated by applying an average revenue/kilowatt hour for all customer classes to the number of kilowatt hour delivered but not billed. Differences between actuals and estimates are immaterial and are a result of customer mix.

Revenues on sales of natural gas, natural gas transportation, storage and distribution as well as sales of petroleum products, primarily at Natural Gas Transmission and Field Services, are recognized when either the service is provided or the product is delivered. Revenues related to these services provided or products delivered but not yet billed are estimated each month. These estimates are generally based on contract data, regulatory information, estimated distribution usage based on historical data adjusted for heating degree days, commodity prices and preliminary throughput and allocation measurements. Final bills for the current month are billed and collected in the following month.

Trading and Marketing Revenues.     The recognition of income in the Consolidated Statements of Operations for derivative activity is primarily dependent on whether the accrual method or mark-to-market method of accounting is applied. Prior to January 1, 2003, Duke Energy applied the mark-to-market accounting method to certain derivative contracts and certain contracts classified as energy trading pursuant to EITF Issue 98-10. With the implementation of EITF Issue 02-03, the use of mark-to-market accounting has been restricted to contracts classified as derivatives pursuant to SFAS No. 133. Contracts classified previously as energy trading that do not meet the definition of a derivative are subject to the accrual method of accounting. While the mark-to-market method of accounting is the default method of accounting for all SFAS No. 133 derivatives, SFAS No. 133 allows for the use of accrual accounting for derivatives designated as hedges and certain scope exceptions, including the normal purchase and normal sale exception. Duke Energy designates a derivative as a hedge or a normal purchase or normal sale contract in accordance with internal hedge guidelines and the requirements provided by SFAS No. 133. For further information regarding the accrual or mark-to-market method of accounting, see Risk Management Activities above. For further information regarding the presentation of gains and losses or revenue and expense in the Consolidated Statements of Operations, see Note 1 to the Consolidated Financial Statements.

Pension

Duke Energy and its subsidiaries maintain a non-contributory defined benefit retirement plan. It covers most U.S. employees using a cash balance formula. Under a cash balance formula, a plan participant accumulates a retirement benefit consisting of pay credits that are based upon a percentage (which may vary with age and years of service) of current eligible earnings and current interest credits.

Westcoast and its subsidiaries maintain contributory and non-contributory defined benefit (DB) and defined contribution (DC) retirement plans covering substantially all employees. The DB plans provide retirement benefits based on each plan participant's years of service and final average earnings. Under the DC plans, company contributions are determined according to the terms of the plan and based on each plan participant's age, years of service and current eligible earnings.

Duke Energy accounts for its defined benefit pension plans using SFAS No. 87, "Employers' Accounting for Pensions." Under SFAS No. 87, pension income/expense is recognized on an accrual basis over employees' approximate service periods. For Duke Energy's U. S. defined benefit pension plans, it recognized expense of $2 million in 2003 and income of $27 million and $9 million in 2002 and 2001, respectively. Duke Energy expects its U.S. pension income to be less than $1 million in 2004. The Westcoast retirement plans recognized pension expense of $13 million in 2003 and $4 million in 2002 and has expected pension expense of $14 million in 2004.

The fair value of Duke Energy's U.S. plan assets increased to $2,477 million as of September 30, 2003 from $2,120 million as of September 30, 2002. Higher 2003 investment returns, net of ongoing benefit payments and declining interest rates have decreased Duke Energy's plan's calculated under-funded status to $286 million as of September 30, 2003 from $551 million as of September 30, 2002. Funding requirements for defined benefit plans are determined by government regulations, not SFAS No. 87. Duke Energy made a voluntary contribution of $181 million to its U.S. defined benefit retirement plan in 2003. No contributions to the Duke Energy plan were necessary in 2002 or 2001. No decision on 2004 contributions has been reached due to significant uncertainty around pending U.S. Congressional action over required interest rates used to determine minimum funding requirements. Duke Energy made contributions to the Westcoast pension plans of approximately $11 million in 2003 and $9 million dollars in 2002. Duke Energy anticipates that it will make contributions of approximately $27 million to the Westcoast plans in 2004.

The calculation of pension expense and Duke Energy's pension liability requires the use of assumptions. Changes in these assumptions can result in different expense and reported liability amounts, and future actual experience can differ from the assumptions. Duke Energy believes that the two most critical assumptions are the expected long-term rate of return on plan assets and the assumed discount rate.

Duke Energy assumed that its U.S. plan's assets would generate a long-term rate of return of 8.5% as of September 30, 2003 and 2002, and 9.25% as of September 30, 2001. The assets for Duke Energy's U.S. pension plan are maintained by a master trust. The investment objective of the master trust is to achieve reasonable returns on trust assets, subject to a prudent level of portfolio risk, for the purpose of enhancing the security of benefits for plan participants. The asset allocation target was set after considering the investment objective and the risk profile with respect to the trust. U.S. equities are held for their high expected return. Non-U.S. equities, debt securities, and real estate are held for diversification. Investments within asset classes are to be diversified to achieve broad market participation and reduce the impact of individual managers or investments. Duke Energy regularly reviews its actual asset allocation and periodically rebalances its investments to its targeted allocation when considered appropriate.

The long-term rate of return of 8.5% for the Duke Energy U.S. assets was developed using a weighted average calculation of expected returns based primarily on future expected returns across asset classes considering the use of active asset managers. The weighted average returns expected by asset classes were 4.18% for U.S. equities, 1.92 % for Non U.S. equities, 2.21 % for fixed income securities, and 0.24% for real estate. A premium of 0.36% was added for the higher returns expected for the plan's use of active asset managers. If Duke Energy had used a long-term rate of 8.0% in 2003, pre-tax pension expense would have been higher by approximately $16 million.

The long-term rate of return for the Westcoast plan assets was 7.5% as of September 30, 2003 and 7.75% in 2002. The Westcoast plan assets for registered pension plans are maintained by a master trust. The investment objective of the master trust is to achieve reasonable returns on trust assets, subject to a prudent level of portfolio risk, for the purpose of enhancing the security of benefits for plan participants. The asset allocation target was set after considering the investment objective and the risk profile with respect to the trust. Canadian equities are held for their high expected return. Non-Canadian equities are held for their high expected return as well as diversification relative to Canadian equities and debt securities. Debt securities are also held for diversification.

The long-term rate of return of 7.5% for the Westcoast assets was developed using a weighted average calculation of expected returns based primarily on future expected returns across asset classes considering the use of active asset managers. The weighted average returns expected by asset classes were 3.15% for Canadian equities, 1.27% for U.S. equities, 1.41% for Europe, Australasia and Far East equities, and 1.79% for fixed income securities. If the Westcoast plan had used a long-term rate of 7.00% in 2003, pre-tax pension expense would have been higher by less than $2 million.

Duke Energy discounted its future U.S. pension obligations using a rate of 6.0% as of September 30, 2003, compared to 6.75% as of September 30, 2002 and 7.25% as of September 30, 2001. Duke Energy determines the appropriate discount based on the current rates earned on long-term bonds that receive one of the two highest ratings given by a recognized rating agency. For 2003, the discount rate used to calculate pension expense was 6.75%. Lowering the discount rate by 0.25% (from 6.75% to 6.5%) would have decreased Duke Energy's 2003 pension expense by approximately $5 million, before income taxes.

Westcoast discounted its future pension obligations using a rate of 6.0% as of September 30, 2003, compared to 6.5% as of September 30, 2002. For Westcoast the discount rate used to determine the pension obligation is prescribed as the yield on Canadian corporate AA bonds at the measurement date of September 30. The yield is selected based on bonds with cash flows that match the timing and amount of the expected benefit payments under the plan. For 2003, the discount rate used to calculate pension expense was 6.5%. Lowering the discount rate by 0.25% (from 6.5% to 6.25%) would have increased Duke Energy's 2003 pension expense by less $2 million, before income taxes.

Future changes in plan asset returns, assumed discount rates and various other factors related to the participants in Duke Energy's pension plans will impact Duke Energy's future pension expense and liabilities. Management cannot predict with certainty what these factors will be in the future.