Risk and Accounting Policies

Duke Energy is exposed to market risks associated with commodity prices, credit exposure, interest rates, equity prices and foreign currency exchange rates. Management has established comprehensive risk management policies to monitor and manage these market risks. Duke Energy’s Risk Management Committee is responsible for the overall approval of market risk management policies and the delegation of approval and authorization levels. The Risk Management Committee is composed of senior executives who receive periodic updates from the Chief Risk Officer (CRO) and other members of management, on market risk positions, corporate exposures, credit exposures and overall risk management activities. The CRO is responsible for the overall management of credit risk and commodity price risk, including monitoring exposure limits.

See Critical Accounting Policies—Risk Management Activities for further discussion of the accounting of energy trading contracts and derivatives.

Commodity Price Risk

Duke Energy, substantially through its subsidiaries, is exposed to the impact of market fluctuations in the price of natural gas, electricity and other energy-related products marketed and purchased as a result of its ownership of energy related assets and proprietary trading activities. Duke Energy employs established policies and procedures to manage its risks associated with these market fluctuations using various commodity derivatives, including forward contracts, futures, swaps and options for trading purposes and for activity other than trading activity (primarily hedge strategies). (See Notes 1 and 7 to the Consolidated Financial Statements.)

Trading. The risk in the trading portfolio is measured and monitored on a daily basis utilizing a Value-at-Risk model to determine the potential one-day favorable or unfavorable Daily Earnings at Risk (DER) as described below. DER is monitored daily in comparison to established thresholds. Other measures are also used to limit and monitor risk in the trading portfolio (which includes all trading contracts not designated as hedge positions) on monthly and annual bases. These measures include limits on the nominal size of positions and periodic loss limits.

DER computations are based on historical simulation, which uses price movements over an eleven day period. The historical simulation emphasizes the most recent market activity, which is considered the most relevant predictor of immediate future market movements for natural gas, electricity and other energy-related products. DER computations use several key assumptions, including a 95% confidence level for the resultant price movement and the holding period specified for the calculation. Duke Energy’s DER amounts for instruments held for trading purposes are shown in the following table.

Daily Earnings at Risk

				Estimated  Average One-Day  Impact  on EBIT for 2002			Estimated  Average One-Day  Impact  on EBIT for 2001			High  One-Day Impact  on EBIT  for 2002			Low  One-Day Impact  on EBIT  for 2002
				(in millions)
		Calculated DER		$14			$21			$24			$8

DER is an estimate based on historical price volatility. Actual volatility can exceed assumed results. DER also assumes a normal distribution of price changes; thus, if the actual distribution is not normal, the DER may understate or overstate actual results. DER is used to estimate the risk of the entire portfolio, and for locations that do not have daily trading activity, it may not accurately estimate risk due to limited price information. Stress tests are employed in addition to DER to measure risk where market data information is limited. In the current DER methodology, options are modeled in a manner equivalent to forward contracts which may understate the risk.

Duke Energy’s exposure to commodity price risk is influenced by a number of factors, including contract size, length, market liquidity, location and unique or specific contract terms. The following table illustrates the movements in the fair value of Duke Energy’s trading instruments during 2002.

		Changes in Fair Value of Trading Contracts		(in millions)
		Fair value of contracts outstanding at the beginning of the year		$	1,069
		Contracts realized or otherwise settled during the year			(150	)
		Fair value of contracts when entered into during the year			133
		Net premiums received for new option contracts during the period			(14	)
		Changes in fair value amounts attributable to changes in valuation techniques (a)			73
		Other changes in fair values (b)			(622	)
		Fair value of contracts outstanding at the end of the year		$	489

When available, quoted market prices are used to record a contract’s fair value. However, market values for energy trading contracts may not be readily determinable because the duration of the contracts exceeds the liquid activity in a particular market. 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. Of these components, volatility and correlation are the most subjective. Internally developed valuation techniques include the use of interpolation, extrapolation, and fundamental analysis in the calculation of a contract’s fair value. All new and existing transactions are valued using approved valuation techniques and market data and discounted using a LIBOR-based interest rate. Valuation adjustments for performance and market risk, and administration costs are used to adjust the fair value of the contract to the gain or loss ultimately recognized in the Consolidated Statements of Income.

Validation of a contract’s fair value is performed by the Risk Management Group, an internal group independent of Duke Energy’s trading areas. This group performs pricing model validation, back testing and stress testing of valuation techniques, variables and price forecasts consistent with GAAP. Validation of a contract’s fair value may be by comparison to actual market activity and through negotiation of collateral requirements with third parties. 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.

The following table shows the fair value of Duke Energy’s trading portfolio as of December 31, 2002.

				Fair Value of Trading Contracts as of December 31, 2002
		Sources of Fair Value		Maturity in 2003				Maturity in 2004					Maturity in 2005					Maturity in 2006 and Thereafter				Total Fair Value
				(in millions)
		Prices supported by    quoted market    prices and other    external sources		$	46			$	99				$	(6	)			$	15			$	154
		Prices based on    models and    other valuation    methods			9				(15	)				29					312				335
		Total		$	55			$	84				$	23				$	327			$	489

The “prices supported by quoted market prices and other external sources” category includes Duke Energy’s New York Mercantile Exchange (NYMEX) futures positions in natural gas and crude oil. The NYMEX has currently quoted prices for the next 32 months. In addition, this category includes Duke Energy’s forward positions and options in natural gas and power and natural gas basis swaps at points for which over-the-counter (OTC) broker quotes are available. On average, OTC quotes for natural gas and power forwards and swaps extend 22 and 32 months into the future, respectively. OTC quotes for natural gas and power options extend 12 months into the future, on average. Duke Energy values these positions against internally developed forward market price curves that are constantly validated and recalibrated against OTC broker quotes. This category also includes “strip” transactions whose prices are obtained from external sources and then modeled to daily or monthly prices as appropriate.

The “prices based on models and other valuation methods” category includes (i) the value of options not quoted by an exchange or OTC broker, (ii) the value of transactions for which an internally developed price curve was constructed as a result of the long dated nature of the transaction or the illiquidity of the market point, and (iii) the value of structured transactions. In certain instances structured transactions can be decomposed and modeled by Duke Energy as simple forwards and options based on prices actively quoted. Although the valuation of the simple structures might not be different from the valuation of contracts in other categories, the effective model price for any given period is a combination of prices from two or more different instruments and therefore have been included in this category due to the complex nature of these transactions. Many of the contracts in the “prices based on models and other valuation methods” category, such as transportation and storage contracts, are not derivatives as defined by SFAS No. 133. As a result, following the adoption of EITF Issue No. 02-03 in January 2003, these contracts will be accounted for using the accrual method of accounting and a significant decrease in the reported fair value of trading contracts will occur.

Duke Energy’s trading portfolio valuation adjustments for performance, market risk and administration costs are reflected in the above amounts.

Hedging Strategies. Some Duke Energy subsidiaries are exposed to market fluctuations in the prices of energy commodities related to their power generating and natural gas gathering, processing and marketing activities. Duke Energy closely monitors the risks associated with these commodity price changes on its future operations and, where appropriate, uses various commodity instruments such as electricity, natural gas, crude oil and NGL forward contracts to hedge the value of its assets and operations from such price risks. In accordance with SFAS No. 133, Duke Energy’s primary use of energy commodity derivatives is to hedge the output and production of assets it physically owns. Contract terms are up to 15 years, and contracts with terms extending several years are generally valued using models and assumptions developed internally or by industry standards. These contracts are designated and qualify as effective hedge positions of future cash flows, or fair values of assets owned by Duke Energy.

Duke Energy also engages in the economic hedging of other contractual assets such as transportation and storage of gas. For the three years ended December 31, 2002, such hedging activity was not recorded pursuant to SFAS No. 133 because of the broad fair value accounting model in the FASB’s and the EITF’s rules during that period. The hedge and the hedged item were both accounted for using MTM accounting. However, in connection with the adoption of EITF Issue No. 02-03 in January 2003, Duke Energy anticipates that many of these former hedge relationships will be designated as hedges for accounting purposes in accordance with SFAS No. 133.

To the extent that the hedge instrument offsets the transaction being hedged, there is no impact to the Consolidated Statements of Income but changes in fair values will result in changes in the Consolidated Balance Sheets and the Consolidated Statements of Common Stockholders’ Equity and Comprehensive Income. Accordingly, assumptions and valuation techniques for these contracts have no impact on reported earnings or cash flows prior to settlement. The unrealized gains or losses on these contracts are deferred in Other Comprehensive Income (OCI) for cash flow hedges and included in Other Current or Noncurrent Assets or Liabilities on the Consolidated Balance Sheets for fair value hedges of firm commitments, in accordance with SFAS No. 133. Amounts deferred in OCI are realized in earnings concurrently with the transaction being hedged. (See Notes 1 and 7 to the Consolidated Financial Statements.) However, in instances where the hedging contract no longer qualifies for hedge accounting, amounts included in OCI through the date of de-designation remain in OCI until the underlying transaction actually occurs. The derivative contract (if continued as an open position) will be marked to market currently through earnings. Several factors influence the effectiveness of a hedge contract, including counterparty credit risk and using contracts with different commodities or unmatched terms. Hedge effectiveness is monitored regularly and measured each month. To the extent hedge contracts are deemed ineffective, as defined by SFAS No. 133, the impact may increase or decrease earnings.

In addition to the hedge contracts described above and recorded on the Consolidated Balance Sheets, Duke Energy enters into other contracts that qualify for the normal purchases and sales exemption described in Paragraph 10 of SFAS No. 133 and DIG Issue No. C15. These contracts, generally forward agreements to sell power, bear the same counterparty credit risk as the hedge contracts described above. Under the same credit risk reduction guidelines used for other contracts, normal purchases and sales contracts are also subject to collateral requirements. Income recognition and realization related to these contracts coincide with the physical delivery of power.

Based on a sensitivity analysis as of December 31, 2002, it was estimated that a difference of one cent per gallon in the average price of NGLs in 2003 would have a corresponding effect on EBIT of approximately $7 million (at Duke Energy’s 70% ownership), after considering the effect of Duke Energy’s commodity hedge positions. Comparatively, the same sensitivity analysis as of December 31, 2001 estimated that EBIT would have changed by approximately $6 million in 2002. Based on a sensitivity analysis performed on DENA’s managed merchant generation fleet and associated natural gas transportation contracts, with both modeled as options, a $1 change in spark spread (defined as the price realized for power less the cost of fuel for that power) would not be expected to have a material impact on EBIT for 2003 as of December 31, 2002, or 2002 as of December 31, 2001. The effect on EBIT for 2003 or 2002 was also not expected to be material as of December 31, 2002 or 2001 for exposures to other commodities’ price changes. These hypothetical calculations consider existing hedge positions and estimated production levels, but do not consider other potential effects that might result from such changes in commodity prices.

North American Merchant Generation

As of December 31, 2002, the merchant generation facilities in North America owned or operated by Duke Energy represented 12,734 net megawatts (MW), after considering other parties’ ownership interests. This excludes 1,423 net MW, associated with facilities which are not currently managed directly by DENA. Facilities scheduled for completion during 2003 represent an additional 1,860 net MW. The managed merchant generation fleet total of 14,594 net MW (inclusive of the 1,860 net MW related to facilities scheduled for completion during 2003), consists of 13 combined cycle units representing 10,361 net MW and seven simple cycle (peaker) units representing 4,233 net MW. For more information on the North American merchant generation facilities, see Part I, Item 2—Properties.

As of December 31, 2002, the estimated available production from the merchant generation fleet for 2003 was approximately 89 million megawatt hours (Mwh), which consists of approximately 70 million Mwh for the combined cycle units and approximately 19 million Mwh for the peaker units. As of December 31, 2002, estimated production from the merchant generation fleet for 2003 was approximately 27 million Mwh for the combined cycle units and approximately 1 million Mwh for the peaker units. As of December 31, 2002, the estimated production from the managed merchant generation fleet that was hedged was 102% for 2003, 79% for 2004 and 64% for 2005 at average prices per Mwh of $51 for 2003, $44 for 2004 and $39 for 2005.

Credit Risk

Duke Energy’s principal customers for power and natural gas marketing and transportation services are industrial end-users, marketers, local distribution companies and utilities located throughout the U.S., Canada, Asia Pacific, Europe and Latin America. Duke Energy has concentrations of receivables from natural gas and electric utilities and their affiliates, as well as industrial customers and marketers throughout these regions. These concentrations of customers may affect Duke Energy’s overall credit risk in that risk factors can negatively impact the credit quality of the entire sector. Where exposed to credit risk, Duke Energy analyzes the counterparties’ financial condition prior to entering into an agreement, establishes credit limits and monitors the appropriateness of those limits on an ongoing basis.

Duke Energy frequently uses master collateral agreements to mitigate certain credit exposures, primarily in its trading and marketing operations. The collateral agreements provide for a counterparty to post cash or letters of credit for exposure in excess of the established threshold. The threshold amount represents an unsecured credit limit, determined in accordance with the corporate credit policy. The collateral agreement also provides that the inability to post collateral is sufficient cause to terminate a contract and liquidate all positions.

Natural Gas Transmission and Field Services also obtain cash or letters of credit from customers, where appropriate, based on their financial analysis of the customer and the regulatory or contractual terms and conditions applicable to each transaction.

Collateral amounts held or posted may be fixed or may vary depending on the value of the underlying contracts and cover trading, normal purchases and normal sales, and hedging contracts outstanding. Duke Energy may be required to return certain held collateral and post additional collateral should price movements adversely impact the value of open contracts or positions. In many cases, Duke Energy’s and its counterparties’ publicly disclosed credit ratings impact the amounts of additional collateral to be posted. Recent downgrades in Duke Energy’s affiliates’ credit ratings resulted in Duke Energy posting more collateral with counterparties, and any further downgrade could require the posting of additional collateral. Likewise, downgrades in credit ratings of counterparties could require counterparties to post additional collateral to Duke Energy. (See Liquidity and Capital Resources—Financing Cash Flows and Liquidity for additional discussion of downgrades.)

The change in market value of NYMEX-traded futures and options contracts requires daily cash settlement in margin accounts with brokers. Financial derivatives are generally cash settled periodically throughout the contract term. However, these transactions are also generally subject to margin agreements with many of Duke Energy’s counterparties.

Following the bankruptcy of Enron, Duke Energy terminated substantially all contracts with Enron. As a result, in 2001 Duke Energy recorded, as a charge, a non-collateralized accounting exposure of $43 million. The $43 million non-collateralized accounting exposure was composed of charges of $24 million at Other Energy Services, $12 million at DENA, $3 million at International Energy, $3 million at Field Services and $1 million at Natural Gas Transmission. These amounts were stated on a pre-tax basis as charges against the reporting segment’s earnings in 2001.

Duke Energy’s claims made in the Enron bankruptcy case exceeded its non-collateralized accounting exposure. Bankruptcy claims that exceed this amount primarily relate to termination and settlement rights under normal purchases and normal sales contracts where Enron was the counterparty.

Substantially all contracts with Enron were completed or terminated prior to December 31, 2001. Duke Energy has continuing contractual relationships with certain Enron affiliates, which are not in bankruptcy. In Brazil, a power purchase agreement between a Duke Energy affiliate, Paranapanema, and Elektro Eletricidade e Servicos S/A (Elektro), a distribution company approximately 100% owned by Enron, will expire December 31, 2005. The contract was executed by Duke Energy’s predecessor in interest in Paranapanema, and obligates Paranapanema to provide energy to Elektro on an irrevocable basis for the contract period. In addition, a purchase/sale agreement expiring September 1, 2005 between a Duke Energy affiliate and Citrus Trading Corporation (Citrus), a joint venture between Enron and El Paso Corporation, continues to be in effect. The contract requires the Duke Energy affiliate to provide natural gas to Citrus. Citrus has provided a letter of credit in favor of Duke Energy to cover its obligations.

Interest Rate Risk

Duke Energy is exposed to risk resulting from changes in interest rates as a result of its issuance of variable-rate debt and commercial paper. Duke Energy manages its interest rate exposure by limiting its variable-rate and fixed-rate exposures to percentages of total capitalization and by monitoring the effects of market changes in interest rates. Duke Energy also enters into financial derivative instruments, including, but not limited to, interest rate swaps, swaptions and U.S. Treasury lock agreements to manage and mitigate interest rate risk exposure. (See Notes 1, 7, 11, 13 and 15 to the Consolidated Financial Statements.)

Based on a sensitivity analysis as of December 31, 2002, it was estimated that if market interest rates average 1% higher (lower) in 2003 than in 2002, earnings before income taxes would decrease (increase) by approximately $55 million. Comparatively, based on a sensitivity analysis as of December 31, 2001, had interest rates averaged 1% higher (lower) in 2002 than in 2001, it was estimated that earnings before income taxes would have decreased (increased) by approximately $57 million. These amounts include the effects of interest rate hedges and were determined by considering the impact of the hypothetical interest rates on the variable-rate securities outstanding as of December 31, 2002 and 2001. The decrease in interest rate sensitivity was primarily due to the decrease in outstanding variable-rate commercial paper. If interest rates changed significantly, management would likely take actions to manage its exposure to the change. However, due to the uncertainty of the specific actions that would be taken and their possible effects, the sensitivity analysis assumes no changes in Duke Energy’s financial structure.

Equity Price Risk

Duke Energy maintains trust funds, as required by the NRC, to fund certain costs of nuclear decommissioning. (See Note 12 to the Consolidated Financial Statements.) As of December 31, 2002 and 2001, these funds were invested primarily in domestic and international equity securities, fixed-rate, fixed-income securities and cash and cash equivalents. Per NRC and Internal Revenue Service mandates, these funds may be used only for activities related to nuclear decommissioning. Those investments are exposed to price fluctuations in equity markets and changes in interest rates. Because the accounting for nuclear decommissioning recognizes that costs are recovered through Franchised Electric’s rates, fluctuations in equity prices or interest rates do not affect consolidated results of operations or cash flows.

Duke Energy’s costs of providing non-contributory defined benefit retirement and postretirement benefit plans are dependent upon a number of factors, such as the rates of return on plan assets, discount rate, the rate of increase in health care costs and contributions made to the plans. The market value of Duke Energy’s defined benefit retirement plan assets has been affected by declines in the equity market since 2000. As a result, at September 30, 2002 (Duke Energy’s measurement date), Duke Energy’s pension plan obligation, excluding Westcoast, exceeded the value of the plan assets by $439 million and Duke Energy was therefore required to recognize a minimum liability as prescribed by SFAS No. 87 and SFAS No. 132, “Employers’ Disclosures about Pensions and Postretirement Benefits,” of approximately $772 million, excluding Westcoast. The $772 million pension liability was a combination of the $439 million excess obligation and $333 million in pre-paid pension assets. The net pension liability as of December 31, 2002 is included in Other Deferred Credits and Other Liabilities on the Consolidated Balance Sheets. The liability was recorded as a reduction to OCI, net of income taxes, and did not affect net income for 2002. When the fair value of the plan assets exceeds the accumulated benefit obligations on the measurement date, the recorded liability will be reduced and OCI will be restored in the Consolidated Balance Sheets. Also, Westcoast recorded a $22 million minimum pension liability as of December 31, 2002.

Pension cost and cash funding requirements could increase in future years without a substantial recovery in the equity markets. Funding requirements for defined benefit pension plans are determined by government regulations, not SFAS No. 87. Duke Energy anticipates that it will make a contribution to its defined benefit pension plan in 2004 of approximately $100 million for the 2003 plan year. Duke Energy anticipates that it will make a contribution of approximately $10 million to the Westcoast pension plans in 2003 for the 2003 plan year. Contributions for the 2004 plan year and beyond may vary based on the actual return on the defined benefit pension plan’s assets, as well as other factors.

Foreign Currency Risk

Duke Energy is exposed to foreign currency risk from investments in international affiliates and businesses owned and operated in foreign countries. To mitigate risks associated with foreign currency fluctuations, contracts may be denominated in or indexed to the U.S. dollar and/or local inflation rates, or investments may be hedged through debt denominated or issued in the foreign currency. Duke Energy may also use foreign currency derivatives, where possible, to manage its risk related to foreign currency fluctuations. To monitor its currency exchange rate risks, Duke Energy uses sensitivity analysis, which measures the impact of devaluation of the foreign currencies to which it has exposure.

As of December 31, 2002, Duke Energy’s primary foreign currency rate exposures were the Canadian dollar, the Brazilian real, the Peruvian nuevo sol, the Australian dollar, the El Salvadoran colon, the European euro and the Argentine peso. A 10% devaluation in the currency exchange rate in all of these foreign currencies would be immaterial to Duke Energy’s Consolidated Statements of Income. The Consolidated Balance Sheets would be negatively impacted by approximately $300 million currency translation through the cumulative translation adjustment in OCI.

In 1991, the Argentine peso was pegged to the U.S. dollar at a fixed 1:1 exchange ratio. In December 2001, the Argentine government imposed a restriction that limited cash withdrawals above a certain amount and foreign money transfers. Financial institutions were allowed to conduct limited activity, a holiday was announced, and currency exchange activity was essentially halted. The government also required that all dollar-denominated contracts be converted to pesos. In January 2002, the Argentine government announced the creation of a dual-currency system. Subsequently, however, the Argentine government changed to a managed free-floating currency.

Duke Energy’s investment in Argentina was U.S. dollar functional as of December 31, 2001. Once a functional currency determination has been made, that determination must be adhered to consistently, unless significant changes in economic factors indicate that the entity’s functional currency has changed. The events in Argentina required a change. In January 2002, the functional currency of Duke Energy’s investment in Argentina changed from the U.S. dollar to the Argentine peso. In compliance with SFAS No. 52, “Foreign Currency Translation,” the change in functional currency was made prospectively. Management believes that the events in Argentina will have no material adverse effect on Duke Energy’s future consolidated results of operations, cash flows or financial position.