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Results of OperationsOverview of Drivers and Variances for 2003 and 2002Year Ended December 31, 2003 as Compared to December 31, 2002. For 2003, earnings available for common stockholders were a loss of $1,338 million, or a loss of $1.48 per basic and diluted share. For 2002, earnings available for common stockholders were $1,021 million, or earnings of $1.22 per basic and diluted share. For Duke Energy, 2003 was a year of transition and one of Duke Energy's key goals was to establish a platform for future growth by cutting costs, selling non-strategic assets and exiting businesses that were not profitable or were not part of the core business. As a result, Duke Energy incurred significant charges in 2003 related to these activities; including wind-down costs, asset impairments and other charges related to current market conditions and strategic actions taken by management. Significant charges that contributed to the lower results in 2003 included:
Partially offsetting these 2003 charges were net gains of $279 million on equity investment sales during the year, and when compared to 2002, $645 million of charges in 2002 related to severance, goodwill impairment for International Energy's European trading and marketing business, the termination of certain turbines on order, impairments of other uninstalled turbines, write-off of project and site development costs, demobilization costs related to deferred plants and a partial impairment of a merchant plant. (For additional information on goodwill impairments, other impairments and related charges, assets held for sale and discontinued operations, see Notes 9, 11 and 12 to the Consolidated Financial Statements) Other key drivers of the 2003 lower results included:
The above decreases in earnings were partially offset by additional earnings in 2003 from the Westcoast acquisition in March 2002. Year Ended December 31, 2002 as Compared to December 31, 2001. In 2002, earnings available for common stockholders were $1,021 million, or $1.22 per basic and diluted share, compared to $1,884 million, or $2.45 per basic share and $2.44 per diluted share, in 2001. The decrease was due primarily to:
The above drivers were partially offset by:
For additional information on specific business unit related items, see the segment discussions that follow. For a detailed discussion of interest, taxes and the change in accounting principles, see "Other Impacts on Earnings Available for Common Stockholders" at the end of this section. Consolidated Operating RevenuesYear Ended December 31, 2003 as Compared to December 31, 2002. Consolidated operating revenues for 2003 increased $6,340 million, compared to 2002. This change was driven by a $5,452 million increase in Non-regulated Electric, Natural Gas, Natural Gas Liquids and Other revenues, due primarily to increased NGL pricing, and due to the adoption of the final consensus on Emerging Issues Task Force (EITF) Issue No. 02-03, "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and for Contracts Involved in Energy Trading and Risk Management Activities," on January 1, 2003. As of that date, Duke Energy began to report revenues and expenses for certain derivative and non-derivative gas and other contracts on a gross basis instead of a net basis. Adopting the final consensus on EITF Issue No. 02-03 did not require a change to prior periods, which had already been changed in 2002 to report amounts on a net basis in accordance with earlier provisions of EITF Issue No. 02-03. Regulated Natural Gas revenues also increased $742 million due primarily to increased transportation, storage and distribution revenues from assets acquired or consolidated as a part of the acquisition of Westcoast in March 2002. Year Ended December 31, 2002 as Compared to December 31, 2001. Consolidated operating revenues for 2002 decreased $2,226 million, compared to 2001. The decrease was due primarily to decreased trading and marketing net margins (included in Non-regulated Electric, Natural Gas, Natural Gas Liquids, and Other revenues on the Consolidated Statements of Operations) as a result of the negative impacts of a prolonged economic weakness, low commodity prices, continued low volatility levels, reduced spark spreads and decreased market liquidity. The decrease was also a result of decreased revenues on the sale of natural gas, NGLs and other petroleum products. The decrease was partially offset by increased transportation, storage and distribution revenue from assets acquired or consolidated as part of the Westcoast acquisition in March 2002. For a more detailed discussion of operating revenues, see the segment discussions that follow. Consolidated Operating ExpensesYear Ended December 31, 2003 as Compared to December 31, 2002. Consolidated operating expenses for 2003 increased $9,672 million, compared to 2002. Changes in consolidated operating expenses were driven primarily by asset impairments and related charges, and by the same drivers that affected consolidated operating revenues: increased purchase costs for NGLs and the adoption of the final consensus on EITF Issue No. 02-03, and additional expenses due to the acquisition of Westcoast. Year Ended December 31, 2002 as Compared to December 31, 2001. Consolidated operating expenses for 2002 decreased $1,246 million, compared to 2001. The decrease was due primarily to a reduction in expenses related to the purchases of natural gas, NGLs and other petroleum products. The decrease was partially offset by increased operating expenses from assets acquired or consolidated as part of the Westcoast acquisition in March 2002, and various asset impairment and severance charges related to market conditions and strategic actions taken by management. For a more detailed discussion of operating expenses, see the segment discussions that follow. Consolidated (Losses) Gains on Sales of Other Assets, netConsolidated (losses) gains on sales of other assets, net was a loss of $199 million for 2003, a gain of $32 million for 2002, and a gain of $238 million for 2001. The loss for 2003 was comprised of a $208 million loss at DENA primarily related to charges on DETM contracts ($127 million) resulting from the wind-down of DETM's operations, and impairments recorded on assets held for sale, including a 25% undivided interest in the wholly-owned Duke Energy Vermillion facility ($18 million), and stored turbines and related equipment ($66 million). The gain for 2002 was primarily comprised of a $33 million gain on the sale of Duke Energy's remaining water operations. The gain for 2001 was primarily comprised of gains on sales of DENA's interests in several merchant energy facilities. Consolidated Operating IncomeYear Ended December 31, 2003 as Compared to December 31, 2002. For 2003, consolidated operating income decreased $3,563 million, compared to 2002. Lower operating income was driven by decreased operating income at DENA of $3,699 million, due primarily to asset impairments and related charges, as discussed above. Year Ended December 31, 2002 as Compared to December 31, 2001. Consolidated operating income for 2002 decreased $1,186 million, compared to 2001. The decrease was driven by a $1,430 million decrease at DENA due to decreased trading and marketing results (as previously described), decreased average prices realized on electric generation, and certain charges taken as a result of 2002 market conditions and strategic actions by management. Also contributing to the decrease was a $318 million decrease at Field Services due to decreased commodity prices such as NGLs and natural gas. Slightly offsetting these decreases was a $488 million increase at Natural Gas Transmission due primarily to the acquisition of Westcoast in March 2002. For a more detailed discussion of these variances, see segment discussions below. Consolidated Earnings Before Interest and Taxes From Continuing Operations (EBIT)Changes in consolidated EBIT were primarily driven by the same changes as consolidated operating income, as discussed above. Consolidated EBIT also includes Other Income and Expenses, which increased $177 million for the year ended December 31, 2003 and $68 million for the year ended December 31, 2002. The increase for 2003 was driven primarily by DENA's $178 million gain on the sale of its 50% ownership interest in Duke/UAE Ref-Fuel LLC (Ref-Fuel) in June 2003 and Natural Gas Transmission's $90 million gain on sales of various investments in 2003, offset by foregone earnings from the sale of those investments. The increase for 2002 was driven by Natural Gas Transmission's $32 million gain on the sale of a portion of its partnership interests in Northern Border Partners L.P. in 2002. For a more detailed discussion of EBIT, see segment discussions below. Consolidated EBIT is viewed as a non-Generally Accepted Accounting Principles (GAAP) measure under the rules of the Securities and Exchange Commission (SEC). Duke Energy includes consolidated EBIT in its disclosures because it is one of the measures used by management to evaluate total company and segment performance for continuing operations. On a segment basis, EBIT excludes discontinued operations and represents all profits from continuing operations (both operating and non-operating) before deducting interest and taxes, and is net of the minority interest expense related to those profits. Cash and cash equivalents are managed centrally by Duke Energy. Since the business units do not manage those items, the gains and losses on foreign currency remeasurement associated with cash balances, and third-party interest income on those balances, are generally excluded from the segments' EBIT. Management considers segment EBIT to be a good indicator of each segment's operating performance from its continuing operations, as it represents the results of Duke Energy's ownership interest in operations without regard to financing methods or capital structures. On a consolidated basis, EBIT is also used as a performance measure and represents the combination of operating income, and other income and expenses as presented on the Consolidated Statements of Operations. The use of EBIT on a consolidated basis follows its use for assessing segment performance, and Duke Energy believes its investors use consolidated EBIT as a supplemental measure to evaluate Duke Energy's consolidated results of operations from continuing operations. Components of EBIT and Reconciliation of Operating (Loss) Income to Net (Loss) Income
(a) Includes gains on sale of equity investments EBIT should not be considered an alternative to, or more meaningful than, net income or operating cash flow as determined in accordance with GAAP. Duke Energy's EBIT may not be comparable to a similarly titled measure of another company because other entities may not calculate EBIT in the same manner. Business segment EBIT is summarized in the following table, and detailed discussions follow. EBIT by Business Segment
(a) Other primarily includes certain unallocated corporate costs and elimination of intercompany profits. (b) Amounts relate to the elimination of intercompany EBIT that has been reclassified to discontinued operations. The amounts discussed below include intercompany transactions that are eliminated in the Consolidated Financial Statements. Franchised Electric
The following table shows the changes in GWh sales and average number of customers for Franchised Electric for the past two years.
(a) Major components of Franchised Electric's retail sales. (b) Consists of all components of Franchised Electric's sales, including retail sales, and wholesale sales to incorporated municipalities and to public and private utilities and power marketers. Year Ended December 31, 2003 as Compared to December 31, 2002 Operating Revenues. Operating revenues for 2003 decreased $5 million, compared to 2002. The decrease was driven primarily by:
Operating Expenses. Operating expenses for 2003 increased $204 million, compared to 2002. The increase was driven primarily by:
EBIT. EBIT for 2003 decreased $192 million, compared to 2002, due primarily to unfavorable weather, the one year South Carolina rate decrement and lower sales to industrial customers, coupled with increased depreciation and amortization expense, severance expenses and right-of-way maintenance costs. These changes were partially offset by increased wholesale power sales, continued growth in the number of residential and general service customers, and lower storm and purchased power expenses. Matters Impacting Future Franchised Electric's Results Franchised Electric continues to increase its customer base, maintain low costs and deliver high-quality customer service in the Piedmont Carolinas. The residential and general service sectors are expected to continue to grow, but this growth will be offset by a continuing decline in the industrial sector. Franchised Electric's compounded annual EBIT growth over the next three years is expected to be 0% to 2%, coupled with strong cash flows. Changes in weather, wholesale power market prices and changes to the regulatory environment could impact future financial results for Franchised Electric. In addition, Franchised Electric's results will be affected by Duke Energy's flexibility to vary the amortization expenses associated with the North Carolina clean air legislation as noted in "Operating Expenses" above. Year Ended December 31, 2002 as Compared to December 31, 2001 Operating Revenues. Operating revenues for 2002 increased $142 million, compared to 2001. The increase was driven primarily by:
Operating Expenses. Operating expenses for 2002 increased $144 million, compared to 2001. The increase was driven primarily by:
Other Income, net of expenses. Other income, net of expenses decreased $29 million in 2002, compared to 2001, due primarily to a $19 million charge resulting from the settlement agreements reached with the North Carolina Utilities Commission (NCUC) and the PSCSC. (See Note 4 to the Consolidated Financial Statements.) EBIT. EBIT for 2002 decreased $31 million, compared to 2001, primarily as a result of increased operating expenses, including costs associated with an ice storm in December 2002, severance costs related to workforce reductions, and charges resulting from the settlement agreements reached by Duke Energy with the NCUC and the PSCSC. The increase in operating expenses was offset by increases in revenues as discussed above. Natural Gas Transmission
(a) Trillion British thermal units. Revenues are not significantly impacted by pipeline throughput fluctuations since revenues are primarily composed of demand charges. Year Ended December 31, 2003 as Compared to December 31, 2002 Operating Revenues. Operating revenues for 2003 increased $733 million, compared to 2002. This increase was driven primarily by:
Operating Expenses. Operating expenses for 2003 increased $549 million, compared to 2002. This increase was driven primarily by:
For the year ended December 31, 2003, Natural Gas Transmission's operating expenses increased approximately 39% when compared to the same period in 2002, while operating revenues increased approximately 30%. The difference was due to the Westcoast operations that were acquired in March 2002. The operating expenses, as a percentage of operating revenues, of the acquired Westcoast natural gas distribution business, are greater than the previously owned natural gas transmission business. Gas commodity costs related to the Westcoast distribution business are recovered from customers by increasing revenues by the amount of gas commodity costs expensed (i.e. flowed through to customers with no incremental profit). Other Income, net of expenses. Other income, net of expenses decreased $23 million for 2003, compared to 2002. This decrease was driven primarily by:
Minority Interest Expense. Minority interest expense increased $12 million for 2003, compared to 2002. This resulted from the recognition of a full year of minority interest expense in 2003, versus only ten months during 2002, from less than 100% owned subsidiaries acquired in the March 2002 acquisition of Westcoast. EBIT. EBIT for 2003 increased $156 million, compared to 2002, due primarily to incremental EBIT related to assets acquired or consolidated as part of the March 2002 acquisition of Westcoast, gains on asset sales, and business expansion projects in the U.S. These items were partially offset by earnings in 2002 from operations that were sold in the fourth quarter of 2002 and during 2003, and 2003 severance charges in excess of 2002 amounts. Matters Impacting Future Natural Gas Transmission's Results Natural Gas Transmission plans to continue earnings growth through capital efficient expansions in existing markets, optimization of existing systems, and organizational efficiencies and cost control. Natural Gas Transmission expects modest annual EBIT growth over the next three years from its 2003 EBIT. The average contract life for the U.S. pipelines is nine years. Changes in the Canadian dollar, weather, throughput and the ability to renew service contracts would impact future financial results at Natural Gas Transmission. Year Ended December 31, 2002 as Compared to December 31, 2001 Operating Revenues. Operating revenues for 2002 increased $1,404 million, compared to 2001. This increase resulted primarily from increased transportation, storage, and distribution revenue of $1,380 million from assets acquired or consolidated as a part of the Westcoast acquisition in March 2002. Revenues also increased $35 million due to business expansion projects. Operating Expenses. Operating expenses for 2002 increased $916 million, compared to 2001. This increase was driven primarily by:
Other Income, net of expenses. Other income, net of expenses increased $97 million in 2002, compared to 2001, partly as a result of a $28 million construction fee from an unconsolidated affiliate related to the successful completion of the Gulfstream project in 2002 and associated incremental earnings of $19 million. Also contributing to the increase in other income was a $32 million gain in 2002 on the sale of a portion of Natural Gas Transmission's limited partnership units in Northern Border Partners, L.P. and an increase in allowance for funds used during construction related to capital projects. Minority Interest Expense. Minority interest expense for 2002 resulted from consolidating less than 100% owned subsidiaries acquired in the March 2002 acquisition of Westcoast. EBIT. EBIT for 2002 increased $554 million, compared to 2001. As discussed above, this increase resulted primarily from incremental EBIT related to assets acquired or consolidated as part of the acquisition of Westcoast in March 2002. EBIT was also impacted by a construction fee from an unconsolidated affiliate related to the successful completion of Gulfstream, and incremental earnings from Gulfstream which went into service in May 2002. EBIT was impacted, to a lesser extent, by the reversal of reserves as a result of the resolution of certain environmental issues during 2002 and the implementation of SFAS No. 142, resulting in the elimination of goodwill amortization. Field Services
(a) Trillion British thermal units per day (b) Thousand barrels per day (c) Million British thermal units (d) Does not reflect results of commodity hedges Year Ended December 31, 2003 as Compared to December 31, 2002 Operating Revenues. Operating revenues for 2003 increased $2,723 million, compared to 2002. The increase was due primarily to a $2.17 per MMBtu increase in average natural gas prices of approximately $2,250 million and a $0.15 per gallon increase in average NGL prices of approximately $1,195 million. Lower throughput and NGL production partially offset higher revenues by approximately $120 million related to natural gas volume and approximately $380 million related to lower NGL production. The results of cash flow hedging also partially offset higher revenues by approximately $179 million, as hedge contracts locked in an average MMBtu price below market. Operating Expenses. Operating expenses for 2003 increased $2,615 million, compared to 2002. The increase was due primarily to increased costs of raw natural gas and natural gas liquids supply of approximately $2,985 million, offset by lower throughput volumes of approximately $440 million. Other factors contributing to higher operating expenses included severance charges in 2003 and other employee related expenditure increases totaling approximately $36 million. Offsetting increases in operating expenses were 2002 charges related to Field Services internal review of balance sheet accounts of approximately $53 million ($37 million at Duke Energy's 70% share), which may be related to corrections of accounting errors in periods prior to 2002. These adjustments were made in the following five categories: operating expense accruals; gas inventory valuations; gas imbalances; joint venture and investment account reconciliations; and other balance sheet accounts and were immaterial to Duke Energy's reported results. Minority Interest Expense. Minority interest expense at Field Services increased $67 million in 2003, compared to 2002, due to increased earnings from Duke Energy Field Services, LLC (DEFS), Duke Energy's joint venture with ConocoPhillips. The increase in minority interest expense was not proportionate to the increase in Field Services' earnings as the Field Services segment includes the results of incremental hedging activities contracted at the Duke Energy corporate level that are not included in DEFS. EBIT. EBIT for 2003 increased $44 million compared to the same period in 2002, as a result of better pricing and other factors discussed above. Matters Impacting Future Field Services' Results Field Services has developed significant size and scope in natural gas gathering and processing and NGL marketing and plans to focus on organic growth. Field Services estimates 8% to 10% compounded annual EBIT growth over the next three years. However, Field Services' revenues and expenses are significantly dependent on prevailing commodity prices for NGLs and natural gas, and past and current trends in price changes of these commodities may not be indicative of future trends. In 2003, DEFS converted a portion of their keep whole contracts to add a minimum fee clause to the keep whole contract and/or converted the contracts to percent of proceeds contracts. This had the impact of reducing DEFS' exposure to natural gas prices and reducing the exposure to NGL prices on an unhedged basis. After considering the impacts of hedging, DEFS' exposure to a one cent per gallon change in the average price of NGLs is $6 million for 2004 and $7 million for 2003. Year Ended December 31, 2002 as Compared to December 31, 2001 Operating Revenues. Operating revenues for 2002 decreased $2,375 million, compared to 2001. The decrease was due primarily to a $1.05 per MMBtu decrease in average natural gas prices and a decrease in average NGL prices of approximately $0.07 per gallon. Other factors contributing to lower operating revenues were reduced levels of natural gas gathered and processed/transported (throughput) of 0.2 TBtu per day, and a lower trading and marketing net margin as a result of market conditions. Operating Expenses. Operating expenses for 2002 decreased $2,057 million, compared to 2001. The decrease was due primarily to a decrease in average natural gas prices of $1.05 per MMBtu, a $0.07 per gallon decrease in average NGL prices and lower throughput levels. Partially offsetting these decreases were increases in operating and maintenance costs and general administrative costs of $113 million, resulting from increased maintenance on equipment, pipeline integrity and core business process improvements. Additionally, Field Services recorded, as part of its internal review of balance sheet accounts, approximately $53 million of charges ($37 million at Duke Energy's 70% share) in 2002, as described above. Minority Interest Expense. Minority interest at Field Services decreased $116 million in 2002, compared to 2001, due primarily to decreased earnings from DEFS, Duke Energy's joint venture with ConocoPhillips. The decrease in minority interest expense was not proportionate to the decrease in Field Services' earnings as the Field Services segment includes the results of incremental hedging activities contracted at the Duke Energy corporate level that are not included in DEFS. EBIT. EBIT for 2002 decreased $187 million, compared to 2001, primarily as a result of the changes in commodity prices and increases in operating, and general and administrative costs. Duke Energy North America
(a) Includes plant production from plants accounted for under the equity method Year Ended December 31, 2003 as Compared to December 31, 2002 Operating Revenues. Operating revenues for 2003 increased $2,769 million, compared to 2002. The increase was driven primarily by:
Operating Expenses and Impairments. Operating expenses and impairments for 2003 increased $6,260 million, compared to 2002. The increase was driven primarily by:
Losses on Sales of Other Assets, net. Losses on sales of other assets for 2003 were $208 million due primarily to an $18 million loss on the anticipated sale of the 25% net interest in Vermillion, a $66 million loss on the anticipated sale of turbines and DETM charges related to the sale of contracts of $127 million. Other Income, net of expenses. Other income, net of expenses increased $125 million for 2003, compared to 2002. The increase was driven primarily by:
Minority Interest Expense. Minority interest benefit increased $64 million for 2003 compared to 2002, due to increased losses at DETM. EBIT. EBIT for 2003 decreased $3,510 million, compared to 2002. The decrease was due primarily to those factors discussed above: plant impairments, disqualification of certain hedges, the wind down of DETM, the write-off of goodwill, narrowed spark spreads, and increases in 2002 related to the appreciation of the fair value of the mark-to-market portfolio. Matters Impacting Future DENA Results Power generation oversupply in certain regions in the U.S. has resulted in reduced spark spread in many markets. In addition the reduction of major wholesale marketing and trading participants has resulted in a decrease in overall power and gas market liquidity. DENA has reduced its merchant exposure and has simplified its business strategy to reposition DENA to maximize the value of its assets focusing on natural gas and power. If negative market conditions persist over time and estimated cash flows over the lives of DENA's individual assets do not exceed the carrying value of those individual assets, asset impairments may occur in the future. Furthermore, a change in management's intent about the use of individual assets (held for use versus held for sale) or a change in fair value of assets held for sale could also impact an impairment analysis. As of December 31, 2003, DENA had written off all of its goodwill but had $4,386 million in total net property, plant and equipment (including the Southeastern U.S. plants), and $164 million in assets held for sale. Due to the current depressed spark spread environment and the resulting lack of opportunities to capture value in the marketplace above the power production already sold, DENA expects to incur an EBIT loss of approximately $300 million in 2004. Year Ended December 31, 2002 as Compared to December 31, 2001 Operating Revenues. Operating revenues for 2002 decreased $1,462 million, compared to 2001. Significant increases in the megawatt capacity of generation assets in operation were more than offset by decreases in the average price realized for electricity generated, resulting in a reduction in operating revenue of $415 million. In addition, revenues decreased $1,017 million as a result of a decrease in the trading and marketing net margin. DENA's results reflected the negative impacts of a prolonged economic weakness, low commodity prices, continued low volatility levels (measures of the fluctuation in the prices of energy commodities or products), reduced spark spreads, and decreased market liquidity. Operating Expenses and Impairments. Operating expenses for 2002 decreased $261 million, compared to 2001. The decrease was driven primarily by:
Gains on Sales of Other Assets, net. Gains on sales of other assets of $229 million in 2001 resulted from the sale of interests in several generating facilities. Other Income, net of expenses. Other income, net of expenses, increased $25 million in 2002 compared to 2001. The increase was due primarily to settlements received on disputed items at two generating facilities and interest income related to a note receivable associated with the sale of an interest in a generating facility. Minority Interest (Benefit) Expense. Minority interest benefit increased $87 million for 2002 compared to 2001, due to increased losses at DETM. EBIT. EBIT for 2002 decreased $1,318 million compared to 2001. The decrease was due primarily to those factors discussed above: decreased trading margins, a decrease in the average price realized on electric generation, a decrease in the number of generation facilities sold in 2002, and certain charges taken as a result of market conditions in 2002 and strategic actions taken by management. As a result of Duke Energy's findings in the course of its investigation related to the SEC inquiry on "round trip" trades (see Note 17 to the Consolidated Financial Statements), DENA identified accounting issues that justified adjustments which reduced its EBIT by $11 million during 2002. An additional $2 million charge was recorded in other Duke Energy business segments related to these findings. International Energy
Year Ended December 31, 2003 as Compared to December 31, 2002 Operating Revenues. Operating revenues for 2003 decreased $146 million, compared to 2002. The decrease was driven primarily by:
Operating Expenses. Operating expenses for 2003 decreased $310 million compared to 2002. The decrease was driven primarily by:
Other Income, net of expenses. Other income, net of expenses decreased $53 million compared to 2002. The decrease was primarily the result of:
EBIT. EBIT for 2003 increased $108 million, compared to 2002. This increase was due primarily to the absence of $75 million in project cancellations that occurred in 2002, favorable contract terms on the renewal of the initial contracts in Brazil, and increased volumes in Central America due to the completion of expansion projects. Other principal drivers included net increases of $40 million from the liquefied natural gas business, $17 million due to lower administrative expenses, and $11 million on the equity investment income for National Methanol Company, offset by changes in revenue recognition and operating results in Mexico, as noted above. Matters Impacting Future International Energy's Results International Energy's current strategy is focused on maximizing the returns and cash flow from its current portfolio of energy businesses by creating organic growth through its sales and marketing efforts in Latin America (primarily Brazil), optimizing the output and efficiency of its various facilities, controlling and reducing costs and actively managing its portfolio of assets. International Energy estimates 2% to 3% compounded annual EBIT growth over the next three years. If estimated cash flows over the lives of International Energy's individual assets do not exceed the carrying value of those individual assets, asset impairments may occur in the future under existing accounting rules. Furthermore, a change in management's intent about the use of individual assets (held for use versus held for sale) or a change in fair value of assets held for sale could also impact an impairment analysis. As of December 31, 2003, International Energy had $238 million in goodwill, $1,752 million in net property, plant and equipment, and $1,625 million in assets held for sale. EBIT results for International Energy are sensitive to short term translation impacts from fluctuations in exchange rates, most notably, the Brazilian Real and the Mexican Peso. Results could also be affected by significant changes in the Argentine Peso, the Peruvian Nuevo Sol, and the Bolivian Boliviano. Certain of International Energy's long-term sales contracts and long-term debt in Brazil contain inflation adjustment clauses. While this is favorable to revenue in the long run, as International Energy's contract prices are adjusted, there is an unfavorable impact on interest expense resulting from revaluation of International Energy's outstanding local currency debt. Following the 2002 devaluation of the Brazilian currency, 2003 inflation rates were significantly higher than in recent years impacting both revenue and interest expense. Current inflation levels are lower than they were on average for 2003. Regulatory changes in Brazil affecting the electric sector have been passed by the Brazil legislature. Implementation of the regulations are still being developed by the regulatory authority but could significantly affect the ability of International Energy's existing Brazilian plants to receive competitive market prices for their energy capacity and production. Year Ended December 31, 2002 as Compared to December 31, 2001 Operating Revenues. Operating revenues for 2002 increased $59 million, compared to 2001. The increase was driven primarily by:
Operating Expenses. Operating expenses for 2002 increased $258 million, compared to 2001. The increase was driven primarily by:
Other Income, net of expenses. Other income, net of expenses increased $61 million in 2002, compared to 2001. The increase was primarily the result of $48 million of income generated from certain assets in Mexico acquired with the Westcoast acquisition in March 2002, as well as a $9 million increase in the equity investment income from operations in Peru. EBIT. EBIT for 2002 decreased $134 million, compared to 2001. This decrease was due primarily to charges recorded as a result of the write-off of site development costs and the write-down of uninstalled turbines, primarily related to planned energy plants in Brazil and Bolivia. This decrease was partially offset by the positive effect of the Guatemala acquisition. Other Operations
Year Ended December 31, 2003 as Compared to December 31, 2002 Operating Revenues. Operating revenues for 2003 increased $1,305 million, compared to 2002. The increase was driven primarily by:
Operating Expenses. Operating expenses for 2003 increased $1,303 million, compared to 2002. The increase was driven primarily by:
Gains on Sales of Other Assets, net. Gains on sales of other assets for 2003 decreased $32 million, due primarily to a 2002 net gain of $33 million on the sale of Duke Energy's remaining water operations. Other Income, net of expenses. Other income, net of expenses decreased $51 million for 2003, compared to 2002. The decrease was due primarily to decreased equity earnings related to Duke/Fluor Daniel (D/FD). In 2002, D/FD completed a number of energy plants, most of which were constructed for DENA. Therefore, the related intercompany profit was eliminated within Other. EBIT. For 2003, EBIT decreased $86 million, compared to 2002. As discussed above, the decline in EBIT was primarily driven by the $32 million decrease due to the sale of assets and the $51 million decrease in other income due primarily to the decreased equity earnings related to D/FD, as discussed above. Matters Impacting Future Other Operations' Results In 2003, a significant portion of Other Operations was either sold or classified as held-for-sale. For 2004, Other Operations will be comprised mainly of Crescent, DEM, DukeNet Communications, LLC (DukeNet), and D/FD. Crescent plans sustained levels of earnings in its development activities, while generating additional cash flow through increased sales of developed and undeveloped land. Crescent estimates 0%-2% compounded annual EBIT growth rate over the next three years. DEM is still winding down its positions in ammonia, coal, hydrocarbon, and refined products. Earnings from DukeNet should remain relatively stable, while earnings from D/FD will continue to decrease as the partnership winds down. Year Ended December 31, 2002 as Compared to December 31, 2001 Operating Revenues. Operating revenues for 2002 decreased $323 million, compared to 2001. The decrease was driven primarily by:
Operating Expenses. Operating expenses for 2002 decreased $422 million, compared to 2001. The decrease was driven primarily by:
Gains on Sales of Other Assets, net. Gains on sales of other assets for 2002 was comprised primarily of a $33 million net gain on the sale of Duke Energy's remaining water operations. Other Income, net of expenses. Other income, net of expenses increased $78 million due primarily to increased equity earnings from D/FD, as a result of D/FD completing a number of energy plants. Most of the plants were constructed for DENA or Franchised Electric and therefore the related intercompany profit has been eliminated within the Other group. EBIT. EBIT for 2002 increased $213 million, compared to 2001. The increase was due primarily to gains on sales of other assets, as described above, increased equity in earnings at D/FD, earnings generated from EDS and the DEM write-off for Enron and Agrifos in 2001. OtherEBIT for Other improved $157 million in 2003, due primarily to decreased intercompany profits between Duke Energy's segments which are eliminated within Other. These intercompany profits are primarily a result of earnings at D/FD for energy plants it has under construction or completed for DENA, and profits on gas contracts between DENA and Natural Gas Transmission. Partially offsetting those decreases was a $51 million write-off in 2003 related to a corporate risk management information system that was no longer going to be used. EBIT for Other decreased $51 million in 2002, due primarily to increased intercompany profits between Duke Energy's segments which are eliminated within Other. Partially offsetting the decrease were the expenses associated with increased contributions in 2001 to the Duke Energy Foundation (an independent, Internal Revenue Code section 501(c)(3) entity that funds Duke Energy's charitable contributions) and mark-to-market losses in 2001 on corporately managed energy risk positions used to hedge exposure to commodity prices. Other Impacts on Earnings Available for Common StockholdersInterest expense increased $283 million in 2003 as compared to 2002. The increase was due primarily to a $136 million decrease in capitalized interest, resulting primarily from DENA's significantly lower plant construction activity in 2003, and expenses of $48 million related to certain financial instruments with characteristics of both liabilities and equity whose related distributions are now classified as interest expense instead of minority interest expense. Those instruments were classified as debt as of July 1, 2003, in accordance with SFAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity." Interest expense also increased $16 million as a result of a 2003 regulatory action by the PSCSC which required the write-off of a portion of regulatory assets related to debt issuance costs (see Note 4 to the Consolidated Financial Statements). The remaining increase was due primarily to higher debt balances, resulting mainly from debt assumed in, and issued with respect to, the acquisition of Westcoast, slightly offset by lower borrowing costs. In 2002 as compared to 2001, interest expense increased $337 million, due primarily to higher debt balances resulting from debt assumed in, and issued with respect to, the acquisition of Westcoast and increased financing throughout the corporation, partially offset by lower interest rates in 2002. Minority interest expense decreased $51 million in 2003 as compared to 2002, and decreased $212 million in 2002 as compared to 2001. Through June 30, 2003, minority interest expense included expense related to regular distributions on trust preferred securities of Duke Energy and its subsidiaries. As of July 1, 2003, those distributions were accounted for as interest expense on a prospective basis in accordance with the adoption of SFAS No. 150. As a result of this accounting change, and due to lower distributions related to Catawba River Associates, LLC (changes in its ownership structure as of October 2002 caused costs associated with this financing to be classified as interest expense from minority interest), minority interest expense decreased $75 million for 2003 and $31 million for 2002. Minority interest expense as shown and discussed in the preceding business segment EBIT sections includes only minority interest expense related to EBIT of Duke Energy's joint ventures. It does not include minority interest expense related to interest and taxes of the joint ventures. Total minority interest expense related to the joint ventures (including the portion related to interest and taxes) increased $24 million in 2003 as compared to 2002, and decreased $181 million in 2002 as compared to 2001. The 2003 change was driven by increased earnings at DEFS, and Natural Gas Transmission, offset by decreased earnings at DETM. The 2002 change was driven by decreased earnings at DETM and decreased earnings from DEFS. Income tax expense decreased $1,318 million for the year ending December 31, 2003, compared to the same period in 2002, due primarily to the large write-offs in 2003. Income tax expense decreased $539 million in 2002, compared to 2001, due primarily to a $1,243 decrease in earnings from continuing operations before income taxes, favorable foreign taxes due to the acquisition of regulated Westcoast entities, a benefit from a change in the federal tax law relating to the deduction of employee stock ownership plan dividends, and a state tax settlement finalized during 2002. Loss for discontinued operations was $156 million for 2003, $261 million for 2002 and $5 million for 2001. These amounts represent operating losses and net loss on dispositions related primarily to International Energy's Australian and European operations, Duke Capital Partners, LLC (DCP) and certain businesses at DEFS and DEM. (See Note 12 to the Consolidated Financial Statements.) The 2003 amount is primarily comprised of a $223 million after-tax charge for International Energy's impairment charges incurred as a result of classifying its Australian assets as held for sale and to exit the European market. The 2002 amount is primarily comprised of $194 million charge for the impairment of goodwill for International Energy's European trading and marketing business. During 2003, Duke Energy recorded a net-of-tax and minority interest cumulative effect adjustment for a change in accounting principles of $162 million, or $0.18 per basic share, as a reduction in earnings. The change in accounting principles included an after-tax and minority interest charge of $151 million, or $0.17 per basic share, related to the implementation of EITF Issue No. 02-03 and an after-tax charge of $11 million, or $0.01 per basic share, due to the implementation of SFAS No. 143, "Accounting for Asset Retirement Obligations." (See Note 1 to the Consolidated Financial Statements.) During 2001, Duke Energy recorded a one-time net-of-tax charge of $96 million related to the cumulative effect of a change in accounting principle for the January 1, 2001 adoption of SFAS No. 133. This charge related to contracts that either did not meet the definition of a derivative under previous accounting guidance or do not qualify as hedge positions under new accounting requirements. (See Notes 1 and 8 to the Consolidated Financial Statements.) |
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