Amendment No.1 to Form 10-K
Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-K/A

 

Amendment No. 1

 

FOR ANNUAL AND TRANSITION REPORTS

PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

 

(Mark One)

x

   ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
     For the fiscal year ended December 31, 2003 or

¨

   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
     For the transition period from                          to                         
     Commission file number 1-4928

 

DUKE ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

 

North Carolina   56-0205520
(State or other jurisdiction of incorporation or organization)   (I.R.S. Employer Identification No.)
526 South Church Street, Charlotte, North Carolina   28202-1803
(Address of principal executive offices)   (Zip Code)

 

704-594-6200

(Registrant’s telephone number, including area code)

 

Securities registered pursuant to Section 12(b) of the Act:

 

Title of each class

  

Name of each exchange on

which registered


Common Stock, without par value

   New York Stock Exchange, Inc.

6.375% Preferred Stock A, 1993 Series, par value $25

   New York Stock Exchange, Inc.

7.20% Quarterly Income Preferred Securities issued by Duke Energy Capital
Trust I and guaranteed by Duke Energy Corporation

   New York Stock Exchange, Inc.

7.20% Trust Preferred Securities issued by Duke Energy Capital
Trust II and guaranteed by Duke Energy Corporation

   New York Stock Exchange, Inc.

Preference Stock Purchase Rights

   New York Stock Exchange, Inc.

Series C 6.60% Senior Notes Due 2038

   New York Stock Exchange, Inc.

Corporate Units

   New York Stock Exchange, Inc.

 

Securities registered pursuant to Section 12(g) of the Act:

 

Title of class

Preferred Stock, par value $100

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K/A or any amendment to this Form 10-K/A. x

 

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yes x No ¨

 

Estimated aggregate market value of the common equity held by nonaffiliates of the registrant at June 30, 2003

   $ 18,018,000,000

Number of shares of Common Stock, without par value, outstanding at March 2, 2004

     912,888,377

 

Documents incorporated by reference:

The registrant is incorporating herein by reference certain sections of the proxy statement relating to the 2004 annual meeting of shareholders to provide information required by Part II, portions of Item 5, and Part III, Items 10, 11, 12,13 and 14 of this annual report.



Table of Contents

Explanatory Note

 

This Amendment No. 1 to the Annual Report on Form 10-K of Duke Energy Corporation (Duke Energy) for the fiscal year ended December 31, 2003 is being filed for the purpose of amending and revising Items 1, 2, 3, 6, 7, 8, 9A and 15. This Form 10-K/A is being filed in order to (1) present Duke Energy’s real estate operations, Crescent Resources, LLC (Crescent), as a separate reportable segment (see Note 3 to the Consolidated Financial Statements), (2) to present the effects of additional discontinued operations as a result of the change within the Field Services reportable segment (see Note 12 to the Consolidated Financial Statements), (3) to revise certain financial statement captions related to Crescent (see Note 24 to the Consolidated Financial Statements), (4) to provide updates to significant litigation matters since the original filing date of March 15, 2004 (see Note 17 to the Consolidated Financial Statements), (5) to remove the presentation of consolidated earnings before interest and taxes (EBIT) pursuant to the Securities and Exchange Commission’s rules on presentation of non-GAAP financial measures, and (6) to update for material subsequent events occurring since the original filing date of March 15, 2004 (see Note 23 to the Consolidated Financial Statements). These revisions did not affect consolidated net income, total assets, liabilities or stockholders’ equity.


Table of Contents

DUKE ENERGY CORPORATION

FORM 10-K/A FOR THE YEAR ENDED DECEMBER 31, 2003

TABLE OF CONTENTS

 

Item

        Page

     PART I.     
1.    Business    3
    

General

   3
    

Franchised Electric

   7
    

Natural Gas Transmission

   12
    

Field Services

   14
    

Duke Energy North America

   16
    

International Energy

   19
    

Crescent

   20
    

Other

   21
    

Environmental Matters

   22
    

Geographic Regions

   22
    

Employees

   22
    

Executive Officers of Duke Energy

   24
2.    Properties    25
3.    Legal Proceedings    28
4.    Submission of Matters to a Vote of Security Holders    28
     PART II.     
5.    Market for Registrant’s Common Equity and Related Stockholder Matters    29
6.    Selected Financial Data    30
7.    Management’s Discussion and Analysis of Results of Operations and Financial Condition    31
7A.    Quantitative and Qualitative Disclosures About Market Risk    81
8.    Financial Statements and Supplementary Data    82
9.    Changes in and Disagreements with Accountants on Accounting and Financial Disclosure    175
9A.    Controls and Procedures    175
     PART III.     
10.    Directors and Executive Officers of the Registrant    176
11.    Executive Compensation    176
12.    Security Ownership of Certain Beneficial Owners and Management    176
13.    Certain Relationships and Related Transactions    177
14.    Principal Accounting Fees and Services    177
     PART IV.     
15.    Exhibits, Financial Statement Schedule, and Reports on Form 8-K.    178
     Signatures    179
     Exhibit Index     

 

SAFE HARBOR STATEMENT UNDER THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

 

Duke Energy Corporation’s reports, filings and other public announcements may contain or incorporate by reference statements that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. You can typically identify forward-looking statements by the use of forward-looking words, such as “may,” “will,” “could,” “project,” “believe,” “anticipate,” “expect,” “estimate,” “continue,” “potential,” “plan,” “forecast” and other similar words. Those statements represent Duke Energy’s intentions, plans, expectations, assumptions and beliefs about future events and are subject to risks, uncertainties and other factors. Many of those factors are outside Duke Energy’s control and could cause actual results to differ materially from the results expressed or implied by those forward-looking statements. Those factors include:

 

    State, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rate structures, and affect the speed at and degree to which competition enters the electric and natural gas industries

 

1


Table of Contents
    The outcomes of litigation and regulatory investigations, proceedings or inquiries

 

    Industrial, commercial and residential growth in Duke Energy’s service territories

 

    The weather and other natural phenomena

 

    The timing and extent of changes in commodity prices, interest rates and foreign currency exchange rates

 

    General economic conditions, including any potential effects arising from terrorist attacks and any consequential hostilities or other hostilities

 

    Changes in environmental and other laws and regulations to which Duke Energy and its subsidiaries are subject or other external factors over which Duke Energy has no control

 

    The results of financing efforts, including Duke Energy’s ability to obtain financing on favorable terms, which can be affected by various factors, including Duke Energy’s credit ratings and general economic conditions

 

    Lack of improvement or further declines in the market prices of equity securities and resultant cash funding requirements for Duke Energy’s defined benefit pension plans

 

    The level of creditworthiness of counterparties to Duke Energy’s transactions

 

    The amount of collateral required to be posted from time to time in Duke Energy’s transactions

 

    Growth in opportunities for Duke Energy’s business units, including the timing and success of efforts to develop domestic and international power, pipeline, gathering, processing and other infrastructure projects

 

    Competition and regulatory limitations affecting the success of Duke Energy’s divestiture plans, including the prices at which Duke Energy is able to sell its assets

 

    The performance of electric generation, pipeline and gas processing facilities

 

    The extent of success in connecting natural gas supplies to gathering and processing systems and in connecting and expanding gas and electric markets

 

    The effect of accounting pronouncements issued periodically by accounting standard-setting bodies and

 

    Conditions of the capital markets and equity markets during the periods covered by the forward-looking statements

 

In light of these risks, uncertainties and assumptions, the events described in the forward-looking statements might not occur or might occur to a different extent or at a different time than Duke Energy has described. Duke Energy undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

 

2


Table of Contents

Item 1. Business.

 

GENERAL

 

Duke Energy Corporation (collectively with its subsidiaries, Duke Energy) is a leading energy company located in the Americas with an affiliated real estate operation. Duke Energy provides its services through the business segments described below.

 

Duke Energy operates the following business units: Franchised Electric, Natural Gas Transmission, Field Services, Duke Energy North America (DENA), International Energy and Crescent Resources, LLC (Crescent). Duke Energy’s chief operating decision maker regularly reviews financial information about each of these business units in deciding how to allocate resources and evaluate performance. The entities under each business unit have similar economic characteristics, services, production processes, distribution methods and regulatory concerns. All of the Duke Energy business units are considered reportable segments under Statement of Financial Accounting Standards No. 131, “Disclosures about Segments of an Enterprise and Related Information.”

 

Franchised Electric generates, transmits, distributes and sells electricity in central and western North Carolina and western South Carolina. It conducts operations through Duke Power. These electric operations are subject to the rules and regulations of the Federal Energy Regulatory Commission (FERC), the North Carolina Utilities Commission (NCUC) and the Public Service Commission of South Carolina (PSCSC).

 

Natural Gas Transmission provides transportation and storage of natural gas for customers throughout the East Coast and Southern U.S., the Pacific Northwest, and in Canada. Natural Gas Transmission also provides natural gas sales and distribution service to retail customers in Ontario, and gas transportation and processing services to customers in Western Canada. Natural Gas Transmission does business primarily through Duke Energy Gas Transmission Corporation. Duke Energy Gas Transmission Corporation’s natural gas transmission and storage operations in the U.S. are subject to the FERC’s, the Texas Railroad Commission’s, and the U.S. Department of Transportation’s (DOT’s) rules and regulations, while natural gas gathering, processing, transmission, distribution and storage operations in Canada are subject to the rules and regulations of the National Energy Board (NEB) or the Ontario Energy Board (OEB).

 

Field Services gathers, compresses, treats, processes, transports, trades and markets, and stores natural gas; and produces, transports, trades and markets, and stores natural gas liquids (NGLs). It conducts operations primarily through Duke Energy Field Services, LLC (DEFS), which is approximately 30% owned by ConocoPhillips and approximately 70% owned by Duke Energy. Field Services gathers natural gas from production wellheads in Western Canada and 10 states in the U.S. Those systems serve major natural gas-producing regions in the Western Canadian Sedimentary Basin, Rocky Mountain, Permian Basin, Mid-Continent and East Texas-Austin Chalk-North Louisiana areas, as well as onshore and offshore Gulf Coast areas.

 

DENA operates and manages merchant power generation facilities and engages in commodity sales and services related to natural gas and electric power around its generation assets and contractual positions. DENA conducts business throughout the U.S. and Canada generally through Duke Energy North America, LLC and Duke Energy Trading and Marketing, LLC (DETM). DETM is 40% owned by Exxon Mobil Corporation and 60% owned by Duke Energy. In 2003, Duke Energy discontinued the proprietary trading business at DENA, commenced actions to unwind DETM, and announced its intent to reduce its investment in merchant power generation facilities by selling its facilities in the Southeast U.S. and reducing its interests in partially constructed facilities in the Western U.S.

 

International Energy develops, operates and manages power generation facilities, and engages in sales and marketing of electric power and natural gas outside the U.S. and Canada. It conducts operations primarily through Duke Energy International, LLC (DEI) and its activities target power generation in Latin America.

 

During 2003, International Energy began the process to discontinue proprietary trading and is in the process of exiting its European and Australian operations.

 

3


Table of Contents

Beginning in 2004, Crescent, formerly part of Other Operations, is considered a separate reportable segment. All information for all the years presented within this report has been updated to show the impact of presenting Crescent as a separate reportable segment. Crescent develops high-quality commercial, residential and multi-family real estate projects, and manages “legacy” land holdings primarily in the Southeastern and Southwestern U.S.

 

All other entities previously included in Other Operations and now within Other still remain, primarily: DukeNet Communications, LLC (DukeNet), Duke Energy Merchants, LLC (DEM) and Duke/Fluor Daniel (D/FD). DukeNet develops and manages fiber optic communications systems for wireless, local and long-distance communications companies; and for selected educational, governmental, financial and health care entities. DEM is in the refined products business. During 2003, Duke Energy determined that it will exit the refined products business at DEM in an orderly manner, and is unwinding its portfolio of contracts. D/FD provides comprehensive engineering, procurement, construction, commissioning and operating plant services for fossil-fueled electric power generating facilities worldwide. D/FD is a 50/50 partnership between subsidiaries of Duke Energy and Fluor Corporation. During 2003, Duke Energy and Fluor Corporation announced that the D/FD partnership will be dissolved. The D/FD partners have adopted a plan for an orderly wind-down of the business targeted for completion in July 2005. Also previously included in Other Operations was Energy Delivery Services, an engineering, construction, maintenance and technical services firm specializing in electric transmission and distribution lines and substation projects, until its sale in December 2003. Additionally, Duke Capital Partners, LLC, a wholly owned merchant finance company that provided debt and equity capital and financial advisory services primarily to the merchant energy industry, had been previously included in Other Operations, but is now classified as discontinued operations.

 

Duke Energy is a North Carolina corporation. Its principal executive offices are located at 526 South Church Street, Charlotte, North Carolina 28202-1803. The telephone number is 704-594-6200. Duke Energy electronically files reports with the Securities and Exchange Commission (SEC), including annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxies and amendments to such reports. The public may read and copy any materials that Duke Energy files with the SEC at the SEC’s Public Reference Room at 450 Fifth Street, N.W., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains an internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC at http://www.sec.gov. Additionally, information about Duke Energy, including its reports filed with the SEC, is available through Duke Energy’s web site at http://www.duke-energy.com. Such reports are accessible at no charge through Duke Energy’s web site and are made available as soon as reasonably practicable after such material is filed with or furnished to the SEC.

 

Terms used to describe Duke Energy’s business are defined below.

 

Allowance for Funds Used During Construction.    A non-cash accounting convention of regulatory utilities that represents the estimated composite interest costs of debt and a return on equity funds used to finance construction. The allowance is capitalized in the property accounts and included in income.

 

British Thermal Unit (Btu).    A standard unit for measuring thermal energy or heat commonly used as a gauge for the energy content of natural gas and other fuels.

 

Cubic Foot (cf).    The most common unit of measurement of gas volume; the amount of natural gas required to fill a volume of one cubic foot under stated conditions of temperature, pressure and water vapor.

 

Decommissioning.    The process of closing down a nuclear facility and reducing the residual radioactivity to a level that permits the release of the property and termination of the license. Nuclear power plants are required by the Nuclear Regulatory Commission (NRC) to set aside funds for their decommissioning costs during operation.

 

4


Table of Contents

Derivative.    A contract in which its price is based on the value of underlying securities, equity indices, debt instruments, commodities or other benchmarks or variables. Often used to hedge risk, derivatives involve the trading of rights or obligations, but not the direct transfer of property and gains or losses are often settled net.

 

Distribution.    The system of lines, transformers, switches and mains that connect electric and natural gas transmission systems to customers.

 

Duke Capital.    Duke Capital LLC (formerly known as Duke Capital Corporation), a wholly owned subsidiary of Duke Energy that provides financing and credit enhancement services for its subsidiaries.

 

Federal Energy Regulatory Commission (FERC).    The U.S. agency that regulates the transportation of electricity and natural gas in interstate commerce and authorizes the buying and selling of energy commodities at market-based rates.

 

Forward Contract.    A contract in which the buyer is obligated to take delivery, and the seller is obligated to deliver a fixed amount of a commodity at a predetermined price on a specified future date, at which time payment is due in full.

 

Fractionation/Fractionate.    The process of separating liquid hydrocarbons from natural gas into propane, butane, ethane, etc.

 

Gathering System.    Pipeline, processing and related facilities that access production and other sources of natural gas supplies for delivery to mainline transmission systems.

 

Generation.    The process of transforming other forms of energy, such as nuclear or fossil fuels, into electricity. Also, the amount of electric energy produced, expressed in megawatt-hours.

 

Independent System Operator (ISO).    An entity that ensures non-discriminatory access to a regional transmission system, providing all customers access to the power exchange and clearing all bilateral contract requests for use of the electric transmission system. Also responsible for maintaining bulk electric system reliability.

 

Light-off Fuel.    Fuel oil used to light the coal prior to generating electricity.

 

Liquefied Natural Gas (LNG).    Natural gas that has been converted to a liquid by cooling it to –260 degrees Fahrenheit.

 

Local Distribution Company (LDC).    A company that obtains the major portion of its revenues from the operations of a retail distribution system for the delivery of electricity or gas for ultimate consumption.

 

Logistics & Optimization.    The act of maximizing returns from physical positions through arbitrage, especially on contractual assets such as storage, transportation, generation and transmission.

 

Mark-to-Market.    The process whereby an asset or liability is recognized at fair value and the change in the fair value of that asset or liability is recognized in revenues in the Consolidated Statements of Operations or in Other Comprehensive Income within equity during the current period.

 

Natural Gas.    A naturally occurring mixture of hydrocarbon and non-hydrocarbon gases found in porous geological formations beneath the earth’s surface, often in association with petroleum. The principal constituent is methane.

 

Natural Gas Liquids (NGLs).    Liquid hydrocarbons extracted during the processing of natural gas. Principal commercial NGLs include butanes, propane, natural gasoline and ethane.

 

5


Table of Contents

No-notice Bundled Service.    A pipeline delivery service which allows customers to receive or deliver gas on demand without making prior nominations to meet service needs and without paying daily balancing and scheduling penalties.

 

Origination.    Identification and execution of physical energy related transactions, generally with customized provisions to meet the needs of the customer or supplier, throughout the value chain.

 

Peak Load.    The amount of electricity required during periods of highest demand. Peak periods fluctuate by season, generally occurring in the morning hours in winter and in late afternoon during the summer.

 

Regional Transmission Organization (RTO).    An independent entity which is established to have “functional control” over utilities’ transmission systems, in order to expedite transmission of electricity.

 

Reliability Must Run.    Generation that the California ISO determines is required to be on-line to meet applicable reliability criteria requirements.

 

Residue Gas.    Gas remaining after the processing of natural gas.

 

Spark Spread.    The difference between the value of electricity and the value of the gas required to generate the electricity at a specified heat rate.

 

Throughput.    The amount of natural gas or natural gas liquids transported through a pipeline system.

 

Tolling.    Process whereby a party provides fuel to a power generator and receives kilowatt hours in return for a pre-established fee.

 

Transmission System (Electric).    An interconnected group of electric transmission lines and related equipment for moving or transferring electric energy in bulk between points of supply and points at which it is transformed for delivery over a distribution system to customers, or for delivery to other electric transmission systems.

 

Transmission System (Natural Gas).    An interconnected group of natural gas pipelines and associated facilities for transporting natural gas in bulk between points of supply and delivery points to industrial customers, LDCs, or for delivery to other natural gas transmission systems.

 

Volatility.    An annualized measure of the fluctuation in the price of an energy contract. Implied volatility is a measure of what the market values volatility to be, as reflected in the option’s price.

 

Watt.    A measure of power production or usage equal to one joule per second.

 

The following sections describe the business and operations of each of Duke Energy’s business segments. (For more information on the operating outlook of Duke Energy and its segments, see “Management’s Discussion and Analysis of Results of Operations and Financial Condition, Introduction—Overview of Business Strategy and Economic Factors.” For financial information on Duke Energy’s business segments, see Note 3 to the Consolidated Financial Statements, “Business Segments.”)

 

6


Table of Contents

FRANCHISED ELECTRIC

 

Service Area and Customers

 

Franchised Electric generates, transmits, distributes and sells electricity. It conducts operations primarily through Duke Power. Its service area covers about 22,000 square miles with an estimated population of 5.9 million in central and western North Carolina and western South Carolina. Franchised Electric supplies electric service to approximately 2.2 million residential, commercial and industrial customers over 92,000 miles of distribution lines and a 13,000 mile transmission system. Electricity is sold wholesale to incorporated municipalities and to public and private utilities. In addition, municipal and cooperative customers who purchased portions of the Catawba Nuclear Station buy power through contractual agreements. (For more information on the Catawba Nuclear Station joint ownership, see Note 5 to the Consolidated Financial Statements, “Joint Ownership of Generating Facilities.”)

 

Industrial and commercial development in Franchised Electric’s service area is highly diversified. The textile industry, machinery and equipment manufacturing, and chemical industries are of major significance to the area’s economy. Other industries operating in the area include rubber and plastic products, paper and related products, and other manufacturing and service businesses. The textile industry, the largest industry served by Franchised Electric, accounted for approximately $309 million of Franchised Electric’s revenues for 2003, representing 6% of total electric revenues and 29% of industrial revenues. Franchised Electric normally experiences seasonal peak loads in summer and winter months.

 

LOGO

 

7


Table of Contents

Energy Capacity and Resources

 

Electric energy for Franchised Electric’s customers is generated by three nuclear generating stations with a combined net capacity of 5,020 megawatts (MW) (including Duke Energy’s 12.5% ownership in the Catawba Nuclear Station), eight coal-fired stations with a combined capacity of 7,699 MW, 31 hydroelectric stations (including two pumped-storage facilities) with a combined capacity of 2,806 MW and seven combustion turbine stations with a combined capacity of 2,424 MW. Energy and capacity are also supplied through contracts with other generators and purchased on the open market. Franchised Electric has interconnections and arrangements with its neighboring utilities to facilitate planning, emergency assistance, exchange of capacity and energy, and reliability of power supply. Franchised Electric expects that additional construction, purchased power contracts and open market purchases will meet customers’ energy needs in the future.

 

Franchised Electric’s generation portfolio is a balanced mix of energy resources with different operating characteristics and fuel sources designed to provide energy at the lowest possible cost to meet its obligation to serve native load customers. All options including owned generation resources and purchased power opportunities are continually evaluated on a real time basis to select and dispatch the lowest cost resources available to meet system load requirements. The vast majority of customer energy needs are met by Franchised Electric’s large, low energy production cost nuclear and coal fired generating units that operate almost continuously (or at baseload levels). In 2003, more than 97% of the total generated energy came from Franchised Electric’s low cost, efficient nuclear and coal units (46.7% nuclear and 50.7% coal). The remainder of energy needs was supplied by hydro and combustion turbine generation or economical purchases from the wholesale market.

 

Hydroelectric (both conventional and pumped storage) and gas/oil combustion turbine stations operate during fewer peak hour load periods (or peaking levels) when customer loads are rapidly changing. Combustion turbines produce energy at higher production costs than either nuclear or coal, but are less expensive to build, maintain, and can be rapidly started or stopped as needed to meet changing customer loads. Hydroelectric units produce low cost energy, but their operations are limited by the availability of water flow which increased dramatically in 2003 as compared to the four previous drought years. Since these hydroelectric units can also be rapidly started or stopped, they are also used in peak periods when customer loads are rapidly changing so that system operators can match changing customer loads with the appropriate amount of generation.

 

Franchised Electric’s two major pumped-storage hydroelectric facilities offer the added flexibility of using low cost off-peak energy to pump water that will be stored for later generation use during times of higher cost on-peak generation periods. These plants allow Franchised Electric to maximize the value spreads between different high and low cost generation periods.

 

Fuel Supply

 

Franchised Electric relies principally on coal and nuclear fuel for its generation of electric energy. The following table lists Franchised Electric’s sources of power and fuel costs for the three years ended December 31, 2003.

 

     Generation by Source
(Percent)


   Cost of Delivered Fuel
per Net Kilowatt-hour
Generated (Cents)


     2003

   2002

   2001

   2003

   2002

   2001

Coal

   50.7    51.2    50.9    1.59    1.54    1.48

Nuclear(a)

   46.7    48.3    48.6    0.42    0.42    0.42

Oil and gas(b)

   0.1    0.1    0.2    15.52    11.89    11.48
    
  
  
              

All fuels (cost based on weighted average)(a)

   97.5    99.6    99.7    1.05    1.01    0.98

Hydroelectric(c)

   2.5    0.4    0.3               
    
  
  
              
     100.0    100.0    100.0               
    
  
  
              

(a)   Statistics related to nuclear generation and all fuels reflect Franchised Electric’s 12.5% ownership interest in the Catawba Nuclear Station.
(b)   Cost statistics include amounts for light-off fuel at Franchised Electric’s coal-fired stations.
(c)   Generating figures are net of output required to replenish pumped storage facilities during off-peak periods.

 

8


Table of Contents

Coal.    Franchised Electric meets its coal demand through purchase supply contracts and spot agreements. Large amounts of coal are obtained under supply contracts with mining operators who mine both underground and at the surface. Franchised Electric has an adequate supply of coal to fuel its current operations. Expiration dates for its supply contracts, which have price adjustment provisions, range from 2004 to 2006. Duke Energy expects to renew these contracts or enter into similar contracts with other suppliers for the quantities and quality of coal required, though prices will fluctuate over time. The coal purchased under these contracts is produced from mines in eastern Kentucky, southern West Virginia and southwestern Virginia. Franchised Electric uses spot market purchases to meet coal requirements not met by supply contracts.

 

The average sulfur content of coal purchased by Franchised Electric is approximately 1%. This coal, coupled with utilization of available sulfur dioxide emission allowances on the open market satisfies the current emission limitation for sulfur dioxide for existing facilities.

 

Nuclear.    Developing nuclear generating fuel generally involves the mining and milling of uranium ore to produce uranium concentrates, the conversion of uranium concentrates to uranium hexafluoride gas, enrichment of that gas, and then the fabrication of the enriched uranium hexafluoride into usable fuel assemblies.

 

Franchised Electric has contracted for uranium materials and services required to fuel the Oconee, McGuire and Catawba Nuclear Stations. Uranium concentrates, conversion services and enrichment services are primarily met through a diversified portfolio of long-term supply contracts. The contracts are diversified by supplier, country of origin and pricing. Franchised Electric staggers its contracting so that its portfolio of long-term contracts covers the majority of its fuel requirements at Oconee, McGuire and Catawba in the near term, but so that its level of coverage decreases each year into the future. Due to the technical complexities of changing suppliers of fuel fabrication services, Franchised Electric generally sole sources these services to domestic suppliers on a plant by plant basis using multi-year contracts.

 

Based upon current projections, Franchised Electric’s existing portfolio of contracts will meet the requirements of Oconee, McGuire and Catawba Nuclear Stations through the following years:

 

Nuclear Station


   Uranium
Material


   Conversion
Service


   Enrichment
Service


   Fabrication
Service


Oconee

   2005    2005    2007    2006

McGuire

   2005    2005    2007    2009

Catawba

   2005    2005    2007    2009

 

After the years indicated above, a portion of the fuel requirements at Oconee, McGuire and Catawba are covered by long-term contracts. For requirements not covered under long-term contracts, Duke Energy believes it will be able to renew contracts as they expire, or enter into similar contractual arrangements with other suppliers of nuclear fuel materials and services. Near-term requirements not met by long-term supply contracts have been and are expected to be fulfilled with uranium spot market purchases.

 

Duke Power has entered into a contract under which Duke Power has agreed to prepare the McGuire and Catawba nuclear reactors for use of mixed oxide fuel and to purchase mixed oxide fuel for use in such reactors. Mixed oxide fuel will be fabricated by Duke COGEMA Stone and Webster, LLC from the U.S. government’s excess plutonium in its nuclear weapons programs and is similar to conventional uranium fuel. Before using the fuel, Duke Energy must apply for and obtain amendments to the facilities’ operating licenses from the NRC. (See Note 18 to the Consolidated Financial Statements, “Guarantees and Indemnifications,” for additional information.)

 

9


Table of Contents

Insurance and Decommissioning

 

Duke Energy owns and operates the McGuire and Oconee Nuclear Stations and operates and has a partial ownership interest in the Catawba Nuclear Station. The McGuire and Catawba Nuclear Stations have two nuclear reactors each and Oconee has three. Nuclear insurance includes: liability coverage; property, decontamination and decommissioning coverage; and business interruption and/or extra expense coverage. The other joint owners of the Catawba Nuclear Station reimburse Duke Energy for certain expenses associated with nuclear insurance premiums. The Price-Anderson Act requires Duke Energy to insure against public liability claims resulting from nuclear incidents to the full limit of liability, approximately $10.9 billion. (See Note 17 to the Consolidated Financial Statements, “Commitments and Contingencies—Nuclear Insurance,” for more information.)

 

Estimated site-specific nuclear decommissioning costs, including the cost of decommissioning plant components not subject to radioactive contamination, total approximately $1.9 billion in 1999 dollars, based on decommissioning studies completed in 1999 (studies are completed every five years). This includes costs related to Duke Energy’s 12.5% ownership in the Catawba Nuclear Station. The other joint owners of the Catawba Nuclear Station are responsible for decommissioning costs related to their ownership interests in the station. Both the NCUC and the PSCSC have allowed Duke Energy to recover estimated decommissioning costs through rates over the expected remaining service periods of Duke Energy’s nuclear stations.

 

After spent fuel is removed from a nuclear reactor, it is cooled in a spent fuel pool at the nuclear station. Under provisions of the Nuclear Waste Policy Act of 1982, Duke Energy has contracted with the U.S. Department of Energy (DOE) for the disposal of spent nuclear fuel. The DOE failed to begin accepting spent nuclear fuel on January 31, 1998, the date specified by the Nuclear Waste Policy Act and in Duke Energy’s contract with the DOE. In 1998, Duke Energy filed a claim with the U.S. Court of Federal Claims against the DOE related to the DOE’s failure to accept commercial spent nuclear fuel by the required date. Damages claimed in the lawsuit are based upon Duke Energy’s costs incurred as a result of the DOE’s partial material breach of its contract, including the cost of securing additional spent fuel storage capacity. Duke Energy will continue to safely manage its spent nuclear fuel until the DOE accepts it. Payments made to the DOE for disposal costs are based on nuclear output and are included in the Consolidated Statements of Operations as Fuel Used in Electric Generation and Purchased Power.

 

Competition

 

Duke Energy continues to monitor electric industry restructuring; however, movement toward retail deregulation has virtually stopped. (For more information, see “Management’s Discussion and Analysis of Results of Operations and Financial Condition, Current Issues—Electric Competition.”)

 

Franchised Electric competes in some areas with government-owned power systems, municipally owned electric systems, rural electric cooperatives and other private utilities. By statute, the NCUC and the PSCSC assign all service areas outside municipalities in North Carolina and South Carolina to regulated electric utilities and rural electric cooperatives. Substantially all of the territory comprising Franchised Electric’s service area has been assigned in this manner. In unassigned areas, Franchised Electric’s business remains subject to competition. A decision of the North Carolina Supreme Court limits, in some instances, the right of North Carolina municipalities to serve customers outside their corporate limits. In South Carolina, competition continues between municipalities and other electric suppliers outside the municipalities’ corporate limits, subject to the regulation of the PSCSC. In addition, Franchised Electric continues to compete with natural gas providers.

 

Regulation

 

The NCUC and the PSCSC approve rates for retail electric sales within their respective states. The FERC approves Franchised Electric’s rates for some electric sales to wholesale customers, excluding the other joint owners of the Catawba Nuclear Station: those rates are set through contractual agreements. (For more

 

10


Table of Contents

information on rate matters, see Note 4 to the Consolidated Financial Statements, “Regulatory Matters—Franchised Electric.”) The FERC, the NCUC and the PSCSC also have authority over the construction and operation of Franchised Electric’s facilities. Certificates of public convenience and necessity issued by the FERC, the NCUC and the PSCSC authorize Franchised Electric to construct and operate its electric facilities, and to sell electricity to retail and wholesale customers. Prior approval from the NCUC and the PSCSC is required for Duke Energy to issue securities.

 

NCUC, PSCSC and FERC regulations govern access to regulated electric customer and other data by non-regulated entities, and services provided between regulated and non-regulated affiliated entities. These regulations affect the activities of non-regulated affiliates with Franchised Electric.

 

The Energy Policy Act of 1992 and the FERC’s subsequent rulemaking activities opened the wholesale energy market to competition. Open-access transmission for wholesale customers, as defined by the FERC’s rules, provides energy suppliers, including Duke Energy, with opportunities to sell and deliver capacity and energy at market-based prices. From the FERC’s open-access rule, Franchised Electric obtained the rights to sell capacity and energy at market-based rates from its own assets, which also allows Franchised Electric to purchase, at attractive rates, a portion of its capacity and energy requirements resulting in lower overall costs to customers. Open access also provides Franchised Electric’s existing wholesale customers with competitive opportunities to seek other suppliers for their capacity and energy requirements.

 

In 1999 and 2000, the FERC issued its Order 2000 and Order 2000-A regarding RTOs. These orders set minimum characteristics and functions RTOs must meet, including independent authority to establish the terms and conditions of transmission service over the facilities they control. The orders provide for an open and flexible RTO structure to meet the needs of the market, and for the possibility of incentive ratemaking and other benefits for transmission owners that participate. The FERC proposes to have RTOs or other independent transmission providers operate transmission systems in all regions of the country.

 

As a result of these rulemakings, Duke Power and the franchised electric units of two other investor-owned utilities, Carolina Power & Light Company and South Carolina Electric & Gas Company, planned to establish GridSouth Transco, LLC (GridSouth), as an RTO responsible for the functional control of the companies’ combined transmission systems. As of December 31, 2003, Duke Energy had invested $41 million in GridSouth, including carrying costs calculated through December 31, 2002. This amount is included in Other Regulatory Assets and Deferred Debits on the Consolidated Balance Sheets. The sponsors expected that GridSouth would be substantially operational by the FERC’s Order 2000 “deadline” date of December 15, 2001. However, in July 2001 the FERC ordered GridSouth and other utilities in the Southeast to join in a mediation to negotiate terms of a southeastern RTO. It does not appear that the FERC will issue an order specifically based on that proceeding. In 2002, the GridSouth sponsors withdrew their applications to the NCUC and the PSCSC for approval of the transfer of functional control of their electric transmission assets to GridSouth, and announced that development of the GridSouth implementation project had been suspended until the sponsors have an opportunity to further consider regulatory circumstances. Duke Energy believes that more open wholesale electric markets will at some point provide benefits to consumers and other market participants. Duke Energy continues to examine options relative to RTOs in light of the existing complex regulatory environment. Management expects it will recover its investment in GridSouth.

 

Franchised Electric is subject to the NRC jurisdiction for the design, construction and operation of its nuclear generating facilities. In 2000, the NRC renewed the operating license for Duke Energy’s three Oconee nuclear units through 2033 and 2034. In 2003, the NRC renewed the operating licenses for all units at Duke Energy’s McGuire and Catawba stations. The two McGuire units are licensed through 2041 and 2043, while the two Catawba units are licensed through 2043. Franchised Electric’s hydroelectric generating facilities are licensed by the FERC under Part I of the Federal Power Act, with license terms expiring from 2005 to 2036. The FERC has authority to extend hydroelectric generating licenses. Other hydroelectric facilities whose licenses expire between 2005 and 2008 are in various stages of relicensing.

 

11


Table of Contents

Franchised Electric is subject to the jurisdiction of the Environmental Protection Agency (EPA) and state environmental agencies. (For a discussion of environmental regulation, see “Environmental Matters” in this section.)

 

NATURAL GAS TRANSMISSION

 

Natural Gas Transmission provides transportation and storage of natural gas for customers throughout the East Coast and Southern U.S., the Pacific Northwest, and in Canada. Natural Gas Transmission also provides natural gas sales and distribution service to retail customers in Ontario, and gas transportation and processing services to customers in Western Canada. Natural Gas Transmission does business primarily through Duke Energy Gas Transmission Corporation.

 

For 2003, Natural Gas Transmission’s proportional throughput for its pipelines totaled 3,362 trillion British thermal units (TBtu), compared to 3,160 TBtu in 2002, a 6% increase mainly due to the Westcoast Energy Incorporated (Westcoast) acquisition. This includes throughput on Natural Gas Transmission’s wholly owned U.S. and Canadian pipelines and its proportional share of throughput on pipelines that are not wholly owned. The operations purchased in the Westcoast acquisition contributed 1,396 TBtu in 2003, compared to 1,229 TBtu in 2002. A majority of Natural Gas Transmission’s contracted transportation volumes are under long-term firm service agreements with LDC customers in the pipelines’ market areas. Firm transportation services are also provided to gas marketers, producers, other pipelines, electric power generators and a variety of end-users. In addition, the pipelines provide both firm and interruptible transportation to various customers on a short-term or seasonal basis. Demand on Natural Gas Transmission’s pipeline systems is seasonal, with the highest throughput occurring during colder periods in the first and fourth calendar quarters. Natural Gas Transmission’s pipeline systems consist of more than 17,500 miles of transmission pipelines. The pipeline systems receive natural gas from major North American producing regions for delivery to markets primarily in the Mid-Atlantic, New England and Southeastern states, Ontario, British Columbia, and the Pacific Northwest. (For detailed descriptions of Natural Gas Transmission’s pipeline systems, see “Properties—Natural Gas Transmission”)

 

Natural Gas Transmission provides retail distribution services through its subsidiary, Union Gas Limited (Union Gas). Union Gas owns and operates natural gas transmission, distribution and storage facilities in Ontario. Union Gas distributes natural gas to customers in northern, southwestern and eastern Ontario and provides storage, transportation and related services to utilities and other industry participants in the gas markets of Ontario, Quebec and the Central and Eastern U.S. Union Gas’ distribution service area extends throughout northern Ontario from the Manitoba border to the North Bay/Muskoka area, through southern Ontario from Windsor to just west of Toronto, and across eastern Ontario from Port Hope to Cornwall. Union Gas’ distribution system consists of approximately 21,000 miles of distribution pipelines serving approximately 1.2 million residential, commercial and industrial customers.

 

12


Table of Contents

LOGO

 

Natural Gas Transmission, through Market Hub Partners (MHP), wholly owns natural gas salt cavern facilities in south Texas and Louisiana with a total storage capacity of approximately 31 billion cubic feet (Bcf). MHP markets natural gas storage services to pipelines, LDCs, producers, end users and natural gas marketers. Texas Eastern Transmission, LP (Texas Eastern) and East Tennessee Natural Gas Company (ETNG) also provide firm and interruptible open-access storage services. Storage is offered as a stand-alone unbundled service or as part of a no-notice bundled service with transportation. Texas Eastern has two joint-venture storage facilities in Pennsylvania and one wholly owned and operated storage field in Maryland. Texas Eastern’s certificated working capacity in these three fields is 75 Bcf. ETNG has an LNG storage facility in Tennessee with a certificated working capacity of 1.2 Bcf. Union Gas owns approximately 150 Bcf of natural gas storage capacity in 20 underground facilities located in depleted gas fields near Sarnia, Ontario.

 

Competition

 

Natural Gas Transmission’s pipeline, storage and gas gathering and processing businesses compete with other pipeline and storage facilities in the transportation, processing and storage of natural gas. Natural Gas Transmission competes directly with other pipelines and storage facilities serving its market areas. Natural Gas Transmission also competes directly with other natural gas storage facilities in south Texas, Louisiana and Ontario. The principal elements of competition are rates, terms of service, and flexibility and reliability of service.

 

Natural gas competes with other forms of energy available to Natural Gas Transmission’s customers and end-users, including electricity, coal and fuel oils. The primary competitive factor is price. Changes in the availability or price of natural gas and other forms of energy, the level of business activity, conservation, legislation, governmental regulations, the ability to convert to alternative fuels, weather and other factors affect the demand for natural gas in the areas served by Natural Gas Transmission.

 

Union Gas’ distribution sales to industrial customers are affected by weather, economic conditions and the price of competitive energy sources. Most of Union Gas’ industrial and commercial customers, and a portion of residential customers, purchase their natural gas supply directly from suppliers or marketers. As Union Gas earns income from the distribution of natural gas and not the sale of the natural gas commodity, the gas distribution margin is not affected by the source of the customer’s gas supply.

 

13


Table of Contents

Regulation

 

Most of Natural Gas Transmission’s pipeline and storage operations in the U.S. are regulated by the FERC. The FERC has authority to regulate rates and charges for natural gas transported or stored for U.S. interstate commerce or sold by a natural gas company via interstate commerce for resale. (For more information on rate matters, see Note 4 to the Consolidated Financial Statements, “Regulatory Matters—Natural Gas Transmission.”) The FERC also has authority over the construction and operation of U.S. pipelines and related facilities used in the transportation, storage and sale of natural gas in interstate commerce, including the extension, enlargement or abandonment of such facilities. In addition, certain operations are subject to state regulatory commissions.

 

The FERC regulations restrict access to U.S. interstate pipeline natural gas transmission customer and other data by affiliated gas marketing entities, and place certain conditions on services provided by the U.S. interstate pipelines to their affiliated gas marketing entities. These regulations affect the activities of non-regulated affiliates with Natural Gas Transmission.

 

Natural Gas Transmission’s U.S. operations are subject to the jurisdiction of the EPA and state environmental agencies. (For a discussion of environmental regulation, see “Environmental Matters” in this section.) Natural Gas Transmission’s interstate natural gas pipelines are subject to the regulations of the DOT concerning pipeline safety. DOT regulations have incorporated certain provisions of the Natural Gas Pipeline Safety Act of 1968 (and subsequent acts). The DOT has developed new regulations, effective February 14, 2004, that establish mandatory inspections for all natural gas transmission pipelines in high-consequence areas within 10 years. The new regulations require pipeline operators to implement integrity management programs, including more frequent inspections, and other safety protections in areas where the consequences of potential pipeline accidents pose the greatest risk to life and property. Management believes that compliance with these new DOT regulations for Natural Gas Transmission will not have a material adverse effect on the consolidated results of operations, cash flows or financial position of Duke Energy.

 

The natural gas gathering, processing, transmission, storage and distribution operations in Canada are subject to regulation by the NEB and provincial agencies in Canada, such as the OEB and the British Columbia Utilities Commission. These agencies have authorization similar to the FERC for setting rates, regulating the operations of facilities and construction of any additional facilities.

 

FIELD SERVICES

 

Field Services gathers, compresses, treats, processes, transports, trades and markets, and stores natural gas; and produces, transports, trades and markets, and stores NGLs. It conducts operations primarily through DEFS, which is approximately 30% owned by ConocoPhillips and approximately 70% owned by Duke Energy. Field Services gathers natural gas from production wellheads in Western Canada and ten states in the U.S. Those systems serve major gas-producing regions in the Western Canadian Sedimentary Basin, Rocky Mountain, Permian Basin, Mid-Continent and East Texas-Austin Chalk-North Louisiana areas, as well as onshore and offshore Gulf Coast areas. Field Services owns and operates approximately 58,000 miles of natural gas gathering systems with approximately 34,000 active receipt points.

 

Field Services’ natural gas processing operations separate raw natural gas that has been gathered on its systems and third-party systems into condensate, NGLs and residue gas. Field Services processes the raw natural gas at the 56 natural gas processing facilities that it owns and operates and at ten third-party operated facilities in which it has an equity interest.

 

The NGLs separated from the raw natural gas are either sold and transported as NGL raw mix, or further separated through a fractionation process into their individual components (ethane, propane, butanes and natural gasoline) and then sold as components. Field Services fractionates NGL raw mix at ten processing facilities that it owns and operates and at four third-party-operated facilities in which it has an equity interest. In addition, Field

 

14


Table of Contents

Services operates a propane wholesale marketing business. Field Services sells NGLs to a variety of customers ranging from large, multinational petrochemical and refining companies to small regional retail propane distributors. Substantially all of its NGL sales are at market-based prices.

 

The residue gas separated from the raw natural gas is sold at market-based prices to marketers or end-users, including large industrial customers and natural gas and electric utilities serving individual consumers. Field Services markets residue gas directly or through its wholly owned gas marketing company and its affiliates. Field Services also stores residue gas at its 6 Bcf natural gas storage facility.

 

Field Services uses NGL trading and storage at the Mont Belvieu, Texas and Conway, Kansas NGL market centers to manage its price risk and to provide additional services to its customers. Asset based gas trading and marketing activities are supported by ownership of the Spindletop storage facility and various intrastate pipelines which provide access to market centers/hubs such as Waha, Texas; Katy, Texas and the Houston Ship Channel. Field Services undertakes these NGL and gas trading activities through the use of fixed forward sales, basis and spread trades, storage opportunities, put/call options, term contracts and spot marketing trading. Field Services believes there are additional opportunities to grow its services with its customer base.

 

The following map includes Field Services’ natural gas gathering systems, intrastate pipelines, regional offices and supply areas. The map also shows Natural Gas Transmission’s interstate pipeline systems.

 

LOGO

 

Field Services also owns Texas Eastern Products Pipeline Company, LLC (TEPPCO), the general partner of TEPPCO Partners, L.P., a publicly traded limited partnership which owns one of the largest common carrier pipelines of refined petroleum products and liquefied petroleum gases in the U.S., as well as, natural gas gathering systems, petrochemical and natural gas liquid pipelines, and is engaged in crude oil transportation, storage, gathering and marketing. TEPPCO is responsible for the management and operations of TEPPCO Partners, L.P.

 

15


Table of Contents

Field Services’ operating results are significantly impacted by changes in average NGL prices, which increased approximately 39% in 2003 compared to 2002. (See “Management’s Discussion and Analysis of Results of Operations and Financial Condition, Quantitative and Qualitative Disclosures About Market Risk” for a discussion of Field Services’ exposure to changes in commodity prices.)

 

Field Services’ activities can fluctuate in response to seasonal demand for natural gas.

 

Competition

 

Field Services competes with major integrated oil companies, major interstate and intrastate pipelines, national and local natural gas gatherers, and brokers, marketers and distributors for natural gas supplies, in gathering and processing natural gas and in marketing and transporting natural gas and NGLs. Competition for natural gas supplies is based primarily on the reputation, efficiency and reliability of operations, the availability of gathering and transportation to high-demand markets, the pricing arrangement offered by the gatherer/processor and the ability of the gatherer/processor to obtain a satisfactory price for the producer’s residue gas and extracted NGLs; whereas, competition for sales to customers is based primarily upon reliability, services offered, and price of delivered natural gas and NGLs.

 

Regulation

 

The intrastate pipelines owned by Field Services are subject to state regulation. To the extent they provide services under Section 311 of the Natural Gas Policy Act of 1978, the pipelines are also subject to FERC regulation. However, most of Field Services’ natural gas gathering activities are not subject to FERC regulation.

 

Field Services is subject to the jurisdiction of the EPA and state environmental agencies. (For more information, see “Environmental Matters” in this section.) Some of Field Services’ operations are subject to the jurisdiction of the Federal and state transportation agencies.

 

Recently, the DOT has developed new regulations, effective February 14, 2004, that require gas transmission pipeline operators to develop and implement integrity management programs for gas transmission pipelines located where a leak or rupture could have the greatest impact to life and property in areas referred to as “high consequence areas.” The regulations require gas pipeline transmission operators to perform ongoing assessments of pipeline integrity and to implement preventative and mitigative actions. Baseline integrity assessments are required to be completed by December 2012. Reassessments are to be conducted at prescribed intervals. Field Services is presently developing its implementation program to address these new DOT requirements, and is also evaluating the effects of complying with this new DOT regulatory program.

 

Field Services’ Canadian assets are regulated by the Alberta Energy and Utilities Board and the NEB.

 

DUKE ENERGY NORTH AMERICA

 

DENA operates and manages merchant power generation facilities and engages in commodity sales and services related to natural gas and electric power around its generation and contractual positions. DENA conducts business throughout the U.S. and Canada through Duke Energy North America and DETM. DETM is 40% owned by Exxon Mobil Corporation and 60% owned by Duke Energy. As discussed below, during 2003 certain key events led DENA to undertake a number of actions to change its existing business strategy.

 

As an active participant in the North American wholesale energy market, DENA has redefined its business strategy primarily in response to:

 

    Power generation oversupply in certain regions in the U.S., resulting in low spark spreads

 

    Reduction of major wholesale energy marketing and trading participants resulting in decreased market liquidity and increased collateral demands

 

16


Table of Contents

As a result of these market developments DENA:

 

    Executed substantial re-organization efforts, resulting in significant staff and annual cost reductions

 

    Discontinued proprietary trading and other non-core businesses

 

    Decided to exit the Southeast region

 

    Resolved to wind down the operations of DETM. The majority of the commodity contracts have been eliminated or sold to third parties. DENA will continue its participation in the market through 100% Duke Energy-owned entities.

 

In the fourth quarter 2003, management decided to: a) exit the Southeast region through a contemplated disposition of its merchant generation plants located in that region, b) not use Duke Energy funds to complete construction and reduce DENA’s interest in deferred plants, and c) wind-down DETM. These actions negatively impacted operating income by approximately $3.1 billion.

 

Previously, DETM was committed to market substantially all of ExxonMobil’s U.S. and Canadian natural gas production through 2006. Beginning in March 2003, most of this natural gas production was no longer made available to be marketed by DETM. This change in gas supply along with the other key market events described above prompted the wind-down of DETM. As stated above, the majority of DETM’s commodity contracts have been eliminated or sold to third parties during 2003 and the remaining actions to wind-down DETM’s operations will continue in 2004.

 

In June 2003, DENA sold its 50% ownership interest in Duke/UAE Ref-Fuel for $325 million to Highstar Renewable Fuels LLC. DENA recorded a gain on the sale of approximately $178 million, which is included in Gains on Sales of Equity Investments in the Consolidated Statements of Operations.

 

Generation Assets

 

DENA currently owns or operates approximately 15,820 net MW of operating generation and has approximately 2,402 net MW of operating generation under construction. During 2003, DENA determined that the partially constructed power generation facilities, Moapa, Grays Harbor, and Luna (collectively the “deferred plants”), will not be completed with Duke Energy funds. DENA will look to sell and/or solicit funding for completion of the deferred plants in 2004. Additionally, DENA has decided to sell all of its power generation facilities in the Southeast U.S.

 

17


Table of Contents

The following map shows DENA’s power generation facilities.

 

LOGO

 

Marketing Portfolio

 

The majority of DENA’s portfolio of purchase and sales agreements incorporate market-sensitive pricing terms. Physical purchase and sales commitments involving significant price and location risk are generally hedged with financial derivatives. DENA’s results may also fluctuate in response to seasonal demand for electricity, natural gas and other energy-related commodities. Additionally, weather has a significant impact on electricity and natural gas demand. (For information concerning DENA’s risk-management activities, see “Management’s Discussion and Analysis of Results of Operations and Financial Condition, Quantitative and Qualitative Disclosures About Market Risk” and Note 8 to the Consolidated Financial Statements, “Risk Management and Hedging Activities, Credit Risk and Financial Instruments.”)

 

Customers

 

DENA markets electricity to investor-owned utilities, municipal power generators and other power marketers. DENA markets natural gas primarily to LDCs, electric power generators, municipalities, large industrial end-users and energy marketing companies. DENA also provides energy management services, such as supply and market aggregation, peaking services, dispatching, balancing, transportation, storage, tolling, contract negotiation and administration, as well as energy commodity risk management products and services.

 

Competition

 

DENA’s competitors include utilities, other merchant electric generation companies in North America, certain financial institutions engaged in commodity trading, major integrated oil companies, major interstate pipelines and their marketing affiliates, brokers, marketers and distributors, and other domestic and international electric power and natural gas marketers. The price of commodities and services delivered, along with the quality and reliability of services provided, drive competition in the energy marketing business.

 

18


Table of Contents

Over the past two years, there has been a significant reduction in number of market participants due to the profitability decline resulting from oversupply of generation, increase in regulation, cost of capital to maintain generation facilities, collateral requirements, and bankruptcies. With fewer market participants, liquidity has been further depressed.

 

Regulation

 

DENA’s energy marketing activities are, in some circumstances, subject to the jurisdiction of the FERC. Current FERC policies permit DENA’s trading and marketing entities to market natural gas, electricity and other energy-related commodities at market-based rates, subject to FERC jurisdiction. DENA continues to monitor the varied pace of wholesale electricity market restructuring. (For more information, see “Management’s Discussion and Analysis of Results of Operations and Financial Condition, Current Issues—Electric Competition.”)

 

Certain of DENA’s generating stations in California sell electricity to the California ISO under “reliability must run” agreements; those sales are made at FERC regulated rates. In addition, several legal and regulatory proceedings at the state and federal levels are ongoing related to DENA’s activities in California during the electricity supply situation and related to trading activities. (See Note 17 to the Consolidated Financial Statements, “Commitments and Contingencies—Litigation” for further discussion.)

 

The operation and maintenance of DENA’s power plants in California will be subject to regulation pursuant to rules that are currently being promulgated by state authorities. The new rules are intended to increase the reliability of the generation supply in California by setting maintenance standards and regulating when plants may be taken out of service for routine maintenance. Duke Energy does not believe that the new rules, when finalized, will have a material impact on the operation of its power plants in California.

 

DENA is subject to the jurisdiction of the EPA and state environmental agencies. (For a discussion of environmental regulation, see “Environmental Matters” in this section.)

 

INTERNATIONAL ENERGY

 

International Energy develops, operates and manages power generation facilities, and engages in sales and marketing of electric power and natural gas outside the U.S. and Canada. It conducts operations primarily through DEI and its activities target power generation in Latin America.

 

During 2003, International Energy sold its interest in P.T. Puncakjaya Power in Indonesia as well as decided to exit the European market and sell its Australian assets. As a result, these operations are not included in International Energy’s results but have been reclassified to discontinued operations for current and prior years. As of December 31, 2003, the European and Australian assets and liabilities are classified as Assets Held for Sale, and Liabilities Associated with Assets Held for Sale, respectively, on the Consolidated Balance Sheet. (See Note 12 to the Consolidated Financial Statements, “Assets Held for Sale and Discontinued Operations” for further discussion.)

 

From its platform of assets, International Energy provides customers with energy supply at competitive prices, manages the logistics associated with power and natural gas delivery, and offers services that allow customers to improve energy efficiency and hedge their commodity price exposure. International Energy’s customers include retail distributors, electric utilities, independent power producers and large industrial companies. International Energy is committed to building integrated regional businesses that provide customers with a full range of innovative and competitively priced energy services.

 

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 all regions in which it currently does business, optimizing the output and efficiency of its various facilities, controlling and reducing costs and divesting selected assets.

 

19


Table of Contents

International Energy’s continuing operations owns, operates or has substantial interests in approximately 4,121 net MW of generation facilities. The following map shows the locations of International Energy’s facilities, including projects under construction. The capacities shown in the map are gross MW values (for net MW values see “Properties—International Energy”).

 

LOGO

 

Competition and Regulation

 

International Energy’s sales and marketing of electric power and natural gas competes directly with other generators and marketers serving its market areas. Competitors are country and region-specific but include government owned electric generating companies, LDC’s with self-generation capability and other privately owned electric generating companies. The principal elements of competition are price and availability, terms of service, flexibility and reliability of service.

 

A high percentage of International Energy’s portfolio is base-load hydro electric generation facilities which compete with other forms of electric generation available to International Energy’s customers and end-users, including natural gas and fuel oils. Economic activity, conservation, legislation, governmental regulations, weather and other factors affect the supply and demand for electricity in the regions served by International Energy.

 

International Energy’s operations are subject to international environmental regulations. (See “Environmental Matters” in this section.)

 

CRESCENT

 

Beginning in 2004, Crescent, formerly part of Other Operations, is considered a separate reportable segment. Crescent develops high-quality commercial, residential and multi-family real estate projects, and manages land holdings, primarily in the Southeastern and Southwestern U.S. On December 31, 2003, Crescent owned 1.3 million square feet of commercial, industrial and retail space, with an additional 0.9 million square

 

20


Table of Contents

feet under construction. This portfolio included 1.4 million square feet of office space, 0.4 million square feet of warehouse space and 0.4 million square feet of retail space. Crescent’s residential developments include high-end country club and golf course communities, with individual lots sold to custom builders and tract developments sold to national builders. Crescent had four multi-family communities at December 31, 2003, including two operating properties and two properties under development. On December 31, 2003, Crescent also managed approximately 134,000 acres of land.

 

Competition and Regulation

 

Crescent competes with multiple regional and national real estate developers across its various business lines in the Southeastern and Southwestern U.S. Crescent’s residential division sells developed lots to regional and national home builders and retail buyers, competing with other developers and home builders with an inventory of developed lots. Crescent’s commercial division leases office, industrial and retail space, competing with other public and private developers and owners of commercial property, including national real estate investment trusts (REITs). Similarly, Crescent’s multi-family division leases apartment units primarily to individuals, competing with other private developers and multi-family REITs.

 

Crescent is subject to the jurisdiction of the EPA and state and local environmental agencies. (For a discussion of environmental regulation, see “Environmental Matters” in this section.)

 

OTHER

 

Beginning in 2004, with the exception of Crescent, all other entities previously part of Other Operations as defined in Duke Energy’s Form 10-K for December 31, 2003 and now within Other, still remain, primarily: DukeNet, DEM and D/FD. Unallocated corporate costs are also included in Other.

 

DukeNet provides telecommunications bandwidth capacity for industrial and commercial customers through its fiber optic network. It owns and operates a fiber optic communications network centered in North Carolina and South Carolina and is interconnected with a fiber optic communications network through affiliate agreements with third parties.

 

DEM engages in commodity buying and selling, and risk management and financial services in non-regulated energy commodity markets other than physical natural gas and power (such as petroleum products). DEM’s activities can fluctuate in response to seasonal demand for other energy-related commodities. In 2003, Duke Energy determined that it will exit the refined products and NGL business at DEM in an orderly manner. DEM expects to complete the exit during 2004. The exiting process will include both a wind down of the current business and the selling of remaining long-term contracts. In 2003, DEM also sold Duke Energy Hydrocarbons LLC, and the related hydrocarbons activity was classified as discontinued operations.

 

D/FD, operating through several entities, provides full-service siting, permitting, licensing, engineering, procurement, construction, start-up, operating and maintenance services for fossil-fueled electric power plants, both domestically and internationally. Subsidiaries of Duke Energy and Fluor Corporation each own 50% of D/FD. In 2003, Duke Energy and Fluor Corporation announced that the D/FD partnership will be dissolved. The partners of D/FD have adopted a plan for an orderly wind-down of the D/FD business targeted for completion in July 2005.

 

Competition and Regulation

 

DEM competes for other energy-related commodities. Competitors include major integrated oil companies, major interstate pipelines and their marketing affiliates, brokers and distributors. D/FD competes with major companies who provide engineering, procurement, construction, start-up and maintenance services for fossil fueled power generation facilities.

 

21


Table of Contents

The entities within Other are subject to the jurisdiction of the EPA and international, state and local environmental agencies. (For a discussion of environmental regulation, see “Environmental Matters” in this section.)

 

ENVIRONMENTAL MATTERS

 

Duke Energy is subject to international, federal, state and local regulations with regard to air and water quality, hazardous and solid waste disposal and other environmental matters. Environmental regulations affecting Duke Energy include, but are not limited to:

 

    The Clean Air Act and the 1990 amendments to the Act, as well as state laws and regulations impacting air emissions, including State Implementation Plans related to existing and new national ambient air quality standards for ozone and particulate matter. Owners and/or operators of air emissions sources are responsible for obtaining permits and for annual compliance and reporting.

 

    The Federal Water Pollution Control Act which requires permits for facilities that discharge treated wastewater into the environment.

 

    The Comprehensive Environmental Response, Compensation and Liability Act, which can require any individual or entity that may have owned or operated a disposal site, as well as transporters or generators of hazardous substances sent to such site, to share in remediation costs.

 

    The Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act, which requires certain solid wastes, including hazardous wastes, to be managed pursuant to a comprehensive regulatory regime.

 

    The National Environmental Policy Act, which requires consideration of potential environmental impacts by federal agencies in their decisions, including siting approvals.

 

(For more information on environmental matters involving Duke Energy, including possible liability and capital costs, see Note 17 to the Consolidated Financial Statements, “Commitments and Contingencies—Environmental.”)

 

Except to the extent discussed in Note 4 and Note 17 to the Consolidated Financial Statements, compliance with international, federal, state and local provisions regulating the discharge of materials into the environment, or otherwise protecting the environment, is not expected to have a material adverse effect on the competitive position, consolidated results of operations, cash flows or financial position of Duke Energy.

 

GEOGRAPHIC REGIONS

 

For a discussion of Duke Energy’s foreign operations and the risks associated with them, see “Management’s Discussion and Analysis of Results of Operations and Financial Condition, Quantitative and Qualitative Disclosures About Market Risk—Foreign Currency Risk,” and Notes 3 and 8 to the Consolidated Financial Statements, “Business Segments” and “Risk Management and Hedging Activities, Credit Risk and Financial Instruments.”

 

EMPLOYEES

 

On December 31, 2003, Duke Energy had approximately 23,800 employees. A total of 3,124 operating and maintenance employees were represented by unions. This amount consists of the following:

 

    1,214 employees represented by the International Brotherhood of Electrical Workers

 

    1,039 employees represented by the Communications, Energy and Paperworkers of Canada

 

    219 employees represented by the United Steel Workers of America

 

22


Table of Contents
    186 employees represented by the Canadian Pipeline Employees Association

 

    85 employees represented by Sindicato de Trabajadores del Sector Petroquimico

 

    79 employees represented by Sindicato de Trabajadores del Sector Electrico

 

    77 employees represented by Sindicato dos Trabalhadores na Industria da Energia Hidroeletrica de Ipaussu

 

    63 employees represented by the International Union of Operating Engineers

 

    29 employees represented by Asociacion del Personal Jerarquico del Agua y la Energia

 

    25 employees represented by Sindicato Unico de Centrales de Generacion Canion del Pato

 

    24 employees represented by Sindicato dos Trabalhadores na Industria de Energia Eletrica de Campinas

 

    24 employees represented by Sindicato Unico de Generacion Electrica Carhuaquero

 

    20 employees represented by Sindicato Corani

 

    14 employees represented by Federacion Argentina de Trabajadores de Luz y Fuerza

 

    11 employees represented by Sindicato dos Trabalhadores nas Industrias de Energia Eletrica de Sao Paulo

 

    11 employees represented by the National Distribution Union

 

    4 employees represented by the United Association of Journeymen and Apprentices of the Plumbing and Pipe Fitting Industries of the U.S. and Canada

 

23


Table of Contents

EXECUTIVE OFFICERS OF DUKE ENERGY

 

PAUL M. ANDERSON, 58, Chairman of the Board and Chief Executive Officer. Mr. Anderson was named to his current position in November 2003. Mr. Anderson most recently served as Managing Director and Chief Executive Officer of BHP Billiton Ltd and BHP Billiton PLC, from which he retired in July 2002. Prior to joining BHP, Mr. Anderson had a career that spanned more than 20 years at Duke Energy and its predecessor companies, including serving as CEO of PanEnergy Corp (PanEnergy).

 

KEITH G. BUTLER, 43, Vice President and Controller. Mr. Butler was named Senior Vice President and Chief Financial Officer of Duke Energy Global and its affiliated companies in February 1998, Senior Vice President and Chief Financial Officer of Duke Energy North America in July 1998, and Chief Operating Officer of DukeSolutions in September 1999 before he assumed his current position in August 2001.

 

MYRON L. CALDWELL, 46, Vice President and Treasurer. Mr. Caldwell was named to his current position in December 2003. He previously served as Vice President of corporate finance since October 2000, and managing director of corporate finance since September 1999. Mr. Caldwell held various other positions since joining Duke Energy in 1981, including Controller of Duke Power and Senior Vice President and Chief Financial Officer of Duke Engineering & Services.

 

FRED J. FOWLER, 58, President and Chief Operating Officer. Mr. Fowler assumed his current position in November 2002. Mr. Fowler served as Group Vice President of PanEnergy from 1996 until the PanEnergy merger in 1997, when he was named Group President, Energy Transmission.

 

DAVID L. HAUSER, 52, Group Vice President and Chief Financial Officer. Mr. Hauser assumed his current position in February 2004, but had been the Acting Chief Financial Officer since December 2003. He previously served as Senior Vice President and Treasurer. Mr. Hauser held various positions, including Controller, at Duke Power before being named Senior Vice President, Global Asset Development in 1997.

 

JIM W. MOGG, 55, Group Vice President and Chief Development Officer. Mr. Mogg assumed his current position in January 2004. He previously served as President and Chief Executive Officer of DEFS since December 1994 and Chairman, President and Chief Executive Officer of DEFS since 1999.

 

RICHARD J. OSBORNE, 53, Group Vice President, Public and Regulatory Policy. Mr. Osborne assumed his current position in January 2004. He previously served as Executive Vice President and Chief Risk Officer. He also served as Executive Vice President and Chief Financial Officer since 1997 and Senior Vice President and Chief Financial Officer since 1994.

 

RUTH G. SHAW, 56, President, Duke Power. Dr. Shaw assumed her current position in February 2003. Dr. Shaw served as Senior Vice President, Corporate Resources, from 1994 until the PanEnergy merger in 1997, when she was named Executive Vice President and Chief Administrative Officer.

 

MARTHA B. WYRSCH, 46, Group Vice President, General Counsel and Secretary. Ms. Wyrsch was named to her current position in January 2004. She previously served as Senior Vice President of Legal Affairs. Ms. Wyrsch joined Duke Energy in September 1999 as Senior Vice President, General Counsel and Secretary for DEFS.

 

Executive officers are elected annually by the Board of Directors. They serve until the first meeting of the Board of Directors following the annual meeting of shareholders and until their successors are duly elected.

 

There are no family relationships between any of the executive officers, nor any arrangement or understanding between any executive officer and any other person involved in officer selection.

 

24


Table of Contents

Item 2. Properties.

 

FRANCHISED ELECTRIC

 

As of December 31, 2003, Franchised Electric operated three nuclear generating stations with a combined net capacity of 5,020 MW (including a 12.5% ownership in the Catawba Nuclear Station), eight coal-fired stations with a combined capacity of 7,699 MW, 31 hydroelectric stations (including two pumped-storage facilities) with a combined capacity of 2,806 MW and seven combustion turbine stations with a combined capacity of 2,424 MW. All of the stations are located in North Carolina or South Carolina.

 

Name


   Gross
MW


   Net
MW


  

Fuel


   Location

   Ownership
Interest
(percentage)


 

Oconee

   2,538    2,538    Nuclear    SC    100 %

Catawba

   2,258    282    Nuclear    SC    12.5  

Belews Creek

   2,240    2,240    Coal    NC    100  

McGuire

   2,200    2,200    Nuclear    NC    100  

Marshall

   2,090    2,090    Coal    NC    100  

Lincoln CT

   1,267    1,267    Natural gas/Fuel Oil    NC    100  

Allen

   1,140    1,140    Coal    NC    100  

Bad Creek

   1,065    1,065    Hydro    SC    100  

Cliffside

   760    760    Coal    NC    100  

Jocassee

   610    610    Hydro    SC    100  

Riverbend

   454    454    Coal    NC    100  

Lee

   370    370    Coal    SC    100  

Buck

   369    369    Coal    NC    100  

Cowans Ford

   325    325    Hydro    NC    100  

Mill Creek CT

   573    573    Natural gas/Fuel Oil    SC    100  

Dan River

   276    276    Coal    NC    100  

Buzzard Roost CT

   196    196    Natural gas/Fuel Oil    SC    100  

Keowee

   160    160    Hydro    SC    100  

Riverbend CT

   120    120    Natural gas/Fuel Oil    NC    100  

Buck CT

   93    93    Natural gas/Fuel Oil    NC    100  

Lee CT

   90    90    Natural gas/Fuel Oil    SC    100  

Dan River CT

   85    85    Natural gas/Fuel Oil    NC    100  

Other small hydro (27 plants)

   646    646    Hydro    NC/SC    100  
    
  
                

Total

   19,925    17,949                 
    
  
                

 

In addition, Franchised Electric owned, as of December 31, 2003, approximately 13,000 conductor miles of electric transmission lines, including 600 miles of 525 kilovolts, 2,600 miles of 230 kilovolts, 6,600 miles of 100 to 161 kilovolts, and 3,200 miles of 13 to 66 kilovolts. Franchised Electric also owned approximately 92,600 conductor miles of electric distribution lines, including 49,300 miles of rural overhead lines, 16,500 miles of urban overhead lines, 14,300 miles of rural underground lines and 12,500 miles of urban underground lines. As of December 31, 2003, the electric transmission and distribution systems had approximately 1,600 substations.

 

Substantially all of Franchised Electric’s electric plant in service is mortgaged under the indenture relating to Duke Energy’s various series of First and Refunding Mortgage Bonds.

 

(For a map showing Franchised Electric’s properties, see “Business—Franchised Electric” earlier in this section.)

 

25


Table of Contents

NATURAL GAS TRANSMISSION

 

Texas Eastern’s gas transmission system extends approximately 1,700 miles from producing fields in the Gulf Coast region of Texas and Louisiana to Ohio, Pennsylvania, New Jersey and New York. It consists of two parallel systems, one with three large-diameter parallel pipelines and the other with one to three large-diameter pipelines. Texas Eastern’s onshore system consists of approximately 8,600 miles of pipeline and 73 compressor stations.

 

Texas Eastern also owns and operates two offshore Louisiana pipeline systems, which extend approximately 100 miles into the Gulf of Mexico and include approximately 500 miles of Texas Eastern’s pipeline system.

 

Algonquin Gas Transmission Company’s (Algonquin) transmission system connects with Texas Eastern’s facilities in New Jersey, and extends approximately 250 miles through New Jersey, New York, Connecticut, Rhode Island and Massachusetts. The system consists of approximately 1,100 miles of pipeline with six compressor stations. Algonquin is a wholly owned subsidiary of Duke Energy.

 

ETNG’s transmission system crosses Texas Eastern’s system at two points in Tennessee and consists of two mainline systems totaling approximately 1,400 miles of pipeline in Tennessee, Georgia, North Carolina and Virginia, with 18 compressor stations.

 

Maritimes and Northeast Pipeline’s transmission system (approximately 75% owned by Duke Energy) extends approximately 900 miles from producing fields in Nova Scotia through New Brunswick, Maine, New Hampshire and Massachusetts, connecting to Algonquin in Beverly, Massachusetts. It has two compressor stations on the system.

 

The British Columbia Pipeline System consists of two divisions. The field services division operates more than 1,840 miles of gathering pipelines in British Columbia, Alberta, the Yukon Territory and the Northwest Territories, as well as 22 field compressor stations; four gas processing plants located in British Columbia near Fort Nelson, Taylor, Chetwynd and in the Sikanni area northwest of Fort St. John, and three elemental sulphur recovery plants located at Fort Nelson, Taylor and Chetwynd. Total contractible capacity of approximately 1.8 Bcf of residue gas per day. The pipeline division has approximately 1,740 miles of transmission pipelines in British Columbia and Alberta, as well as 18 mainline compressor stations.

 

Union Gas owns and operates natural gas transmission, distribution and storage facilities in Ontario. Union Gas distributes natural gas to customers in northern, southwestern and eastern Ontario and provides storage, transportation and related services to utilities and other industry participants in the gas markets of Ontario, Quebec and the Central and Eastern U.S. Union Gas’ underground natural gas storage facilities have a working capacity of approximately 150 Bcf in 20 underground facilities located in depleted gas fields. Its transmission system consists of approximately 3,000 miles of pipeline and six mainline compressor stations. Union Gas’ distribution system consists of approximately 21,000 miles of distribution.

 

MHP owns and operates two natural gas storage facilities: Moss Bluff and Egan. The Moss Bluff facility consists of three storage caverns located in Liberty and Chambers counties near Houston, Texas and has access to five pipelines. The Egan facility consists of three storage caverns located in Acadia Parish in the south central part of Louisiana and has access to seven pipeline facilities.

 

(For a map showing natural gas transmission and storage properties and additional information on Natural Gas Transmission’s properties, see “Business—Natural Gas Transmission” earlier in this section.)

 

FIELD SERVICES

 

(For information and a map showing Field Services’ properties, see “Business—Field Services” earlier in this section.)

 

26


Table of Contents

DUKE ENERGY NORTH AMERICA

 

The following table provides information about DENA’s generation portfolio in operation as of December 31, 2003.

 

Name


   Gross
MW


   Net
MW


  

Plant Type


  

Primary Fuel


   Location

   Approximate
Ownership
Interest
(percentage)


 

Moss Landing

   2,538    2,538    Combined Cycle    Natural Gas    CA    100 %

Hanging Rock

   1,240    1,240    Combined Cycle    Natural Gas    OH    100  

Murray(a)

   1,240    1,240    Combined Cycle    Natural Gas    GA    100  

Morro Bay

   1,002    1,002    Combined Cycle    Natural Gas    CA    100  

South Bay

   700    700    Combined Cycle    Natural Gas    CA    100  

Enterprise Energy(a)

   640    640    Simple Cycle    Natural Gas    MS    100  

Lee

   640    640    Simple Cycle    Natural Gas    IL    100  

Marshall(a)

   640    640    Simple Cycle    Natural Gas    KY    100  

Sandersville(a)

   640    640    Simple Cycle    Natural Gas    GA    100  

Southhaven(a)

   640    640    Simple Cycle    Natural Gas    MS    100  

Vermillion

   640    640    Simple Cycle    Natural Gas    IN    100  

Fayette

   620    620    Combined Cycle    Natural Gas    PA    100  

Hot Springs(a)

   620    620    Combined Cycle    Natural Gas    AR    100  

Washington

   620    620    Combined Cycle    Natural Gas    OH    100  

Griffith Energy

   600    300    Combined Cycle    Natural Gas    AZ    50  

Arlington Valley

   570    570    Combined Cycle    Natural Gas    AZ    100  

Hinds(a)

   520    520    Combined Cycle    Natural Gas    MS    100  

Maine Independence

   520    520    Combined Cycle    Natural Gas    ME    100  

St. Francis

   500    250    Combined Cycle    Natural Gas    MO    50  

Bridgeport

   490    326    Combined Cycle    Natural Gas    CT    67  

New AlbanyEnergy(a)

   385    385    Simple Cycle    Natural Gas    MS    100  

Bayside

   260    195    Combined Cycle    Natural Gas    NB    75  

Oakland

   165    165    Simple Cycle    Oil    CA    100  

McMahon

   117    59    Cogen    Natural Gas    BC    50  

Ft. Francis

   110    110    Cogen    Natural Gas    ON    100  
    
  
                     

Total

   16,657    15,820                      
    
  
                     

(a)   Southeast region

 

(For a map showing DENA’s properties, see “Business—Duke Energy North America” earlier in this section.)

 

INTERNATIONAL ENERGY

 

The following table provides information about International Energy’s generation portfolio in operation as of December 31, 2003

 

Name


   Gross
MW


   Net
MW


  

Fuel


  

Location


   Approximate
Ownership
Interest
(percentage)


 

Paranapanema

   2,307    2,185    Hydro    Brazil    95 %

Hidroelectrica Cerros Colorados

   576    523    Hydro/Natural gas    Argentina    91  

Egenor

   540    538    Hydro/Diesel/Oil    Peru    100  

Acajutla

   324    293    Oil/Diesel    El Salvador    90  

Electroquil

   180    130    Diesel    Ecuador    72  

DEI Guatemala y Cia

   328    328    Oil/Diesel    Guatemala    100  

Aquaytia

   160    61    Natural Gas    Peru    38  

Empressa Electrica Corani

   126    63    Hydro    Bolivia    50  
    
  
                

Total(a)

   4,541    4,121                 
    
  
                

(a)   Excludes discontinued operations

 

27


Table of Contents

(For additional information and a map showing International Energy’s properties, see “Business—International Energy” earlier in this section.)

 

CRESCENT

 

(For information regarding Crescent’s properties, see “Business—Crescent” earlier in this section.)

 

OTHER

 

(For information regarding the properties of the business unit now known as Other, see “Business—Other” earlier in this section.)

 

Item 3. Legal Proceedings.

 

For information regarding legal proceedings, including regulatory and environmental matters, see Note 4 to the Consolidated Financial Statements, “Regulatory Matters” and Note 17 to the Consolidated Financial Statements, “Commitments and Contingencies—Litigation” and “Commitments and Contingencies—Environmental.”

 

Item 4. Submission of Matters to a Vote of Security Holders.

 

No matters were submitted to a vote of Duke Energy’s security holders during the fourth quarter of 2003.

 

28


Table of Contents

PART II.

 

Item 5. Market for Registrant’s Common Equity and Related Stockholder Matters.

 

Duke Energy’s common stock is listed for trading on the New York Stock Exchange. As of February 27, 2004, there were approximately 147,900 common stockholders of record.

 

Common Stock Data by Quarter

 

     2003

   2002

     Dividends
Per Share


  

Stock Price Range(a)


   Dividends
Per Share


   Stock Price Range(a)

        High

   Low

      High

   Low

First Quarter

   $ 0.275    $ 21.57    $ 12.21    $ 0.275    $ 40.00    $ 31.99

Second Quarter

     0.550      20.75      13.51      0.550      39.60      28.50

Third Quarter

     —        19.70      16.75      —        31.10      17.81

Fourth Quarter

     0.275      20.89      17.08      0.275      22.00      16.42

(a)   Stock prices represent the intra-day high and low stock price.

 

On December 17, 1998, Duke Energy’s Board of Directors adopted a shareholder rights plan. Under the terms of the plan, one preference stock purchase right was distributed for each share of common stock outstanding on February 12, 1999, and for each share issued thereafter, subject to adjustment as specified. The NCUC and the PSCSC approved this distribution. The plan is intended to ensure the fair treatment of all shareholders in the event of a hostile takeover attempt and to encourage a potential acquirer to negotiate with the Board of Directors a fair price for all shareholders before attempting a takeover. The adoption of the plan was not in response to any takeover offer or threat. The Corporate Governance Committee of the Board of Directors evaluates the plan at least every three years.

 

29


Table of Contents

Item 6. Selected Financial Data.(d)

 

     2003(b)(d)

    2002(d)

    2001(d)

    2000(d)

    1999(d)

     (in millions, except per share amounts)

Statement of Operations

                                      

Operating revenues

   $ 22,154     $ 15,898     $ 17,946     $ 15,970     $ 9,618

Operating expenses

     22,872       13,295       14,367       12,934       8,163

Gains on sales of investments in commercial and multi-family properties

     84       106       106       75       116

(Losses) gains on sales of other assets, net

     (199 )     32       238       214       132
    


 


 


 


 

Operating (loss) income

     (833 )     2,741       3,923       3,325       1,703

Other income and expenses, net

     556       379       311       707       314

Interest expense

     1,380       1,097       760       887       583

Minority interest expense

     61       116       326       305       141
    


 


 


 


 

(Loss) earnings from continuing operations before income taxes

     (1,718 )     1,907       3,148       2,840       1,293

Income tax (benefit) expense from continuing operations

     (709 )     611       1,149       1,035       456
    


 


 


 


 

(Loss) income from continuing operations

     (1,009 )     1,296       1,999       1,805       837

(Loss) income from discontinued operations, net of tax

     (152 )     (262 )     (5 )     (29 )     10
    


 


 


 


 

(Loss) income before extraordinary item and cumulative effect of change in accounting principle

     (1,161 )     1,034       1,994       1,776       847

Extraordinary gain, net of tax

     —         —         —         —         660

Cumulative effect of change in accounting principle, net of tax and minority interest

     (162 )     —         (96 )     —         —  
    


 


 


 


 

Net (loss) income

     (1,323 )     1,034       1,898       1,776       1,507

Dividends and premiums on redemption of preferred and preference stock

     15       13       14       19       20
    


 


 


 


 

(Loss) earnings available for common stockholders

   $ (1,338 )   $ 1,021     $ 1,884     $ 1,757     $ 1,487
    


 


 


 


 

Ratio of Earnings to Fixed Charges

     —   (c)     2.2       3.9       3.7       2.8

Common Stock Data(a)

                                      

Shares of common stock outstanding

                                      

Year-end

     911       895       777       739       733

Weighted average

     903       836       767       736       729

(Loss) earnings per share (from continuing operations)

                                      

Basic

   $ (1.13 )   $ 1.53     $ 2.59     $ 2.43     $ 1.12

Diluted

     (1.13 )     1.53       2.57       2.42       1.12

(Loss) earnings per share (from discontinued operations)

                                      

Basic

   $ (0.17 )   $ (0.31 )   $ (0.01 )   $ (0.04 )   $ 0.01

Diluted

     (0.17 )     (0.31 )     (0.01 )     (0.04 )     0.01

(Loss) earnings per share (before extraordinary item and cumulative effect of change in accounting principle)

                                      

Basic

   $ (1.30 )   $ 1.22     $ 2.58     $ 2.39     $ 1.13

Diluted

     (1.30 )     1.22       2.56       2.38       1.13

(Loss) earnings per share

                                      

Basic

   $ (1.48 )   $ 1.22     $ 2.45     $ 2.39     $ 2.04

Diluted

     (1.48 )     1.22       2.44       2.38       2.03

Dividends per share

     1.10       1.10       1.10       1.10       1.10

Balance Sheet

                                      

Total assets

   $ 56,203     $ 60,122     $ 49,624     $ 59,276     $ 34,388

Long-term debt, less current maturities

     20,622       20,221       12,321       10,717       8,683

(a)   Amounts prior to 2001 were restated to reflect the two-for-one common stock split effective January 26, 2001.
(b)   As of January 1, 2003, Duke Energy adopted the remaining provisions of Emerging Issues Task Force 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” and Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations.” In accordance with the transition guidance for these standards, Duke Energy recorded a net-of-tax and minority interest cumulative effect adjustment for change in accounting principles. See Note 1 to the Consolidated Financial Statements, “Summary of Significant Accounting Policies,” for further discussion.
(c)   Earnings were inadequate to cover fixed charges by $1,715 million for the year ended December 31, 2003.
(d)   Certain amounts have been revised. See Note 24 to the Consolidated Financial Statements.

 

30


Table of Contents

Item 7. Management’s Discussion and Analysis of Results of Operations and Financial Condition.

 

INTRODUCTION

 

Management’s Discussion and Analysis includes the effects of revisions in order to (1) present Duke Energy’s real estate operations, Crescent Resources, LLC (Crescent), as a separate reportable segment (see Note 3 to the Consolidated Financial Statements), (2) to present the effects of additional discontinued operations as a result of the change within the Field Services reportable segment (see Note 11 to the Consolidated Financial Statements), (3) to revise certain financial statement captions related to Crescent (see Note 24 to the Consolidated Financial Statements), (4) to provide updates to significant litigation matters since the original filing date of March 15, 2004 (see Note 17 to the Consolidated Financial Statements), (5) to remove the presentation of consolidated earnings before interest and taxes (EBIT) pursuant to the Securities and Exchange Commission’s rules on presentation of non-GAAP financial measures, and (6) to update for material subsequent events occurring since the original filing date of March 15, 2004 (see Note 23 to the Consolidated Financial Statements). These revisions did not affect consolidated net income, total assets, liabilities or stockholders’ equity.

 

Management’s Discussion and Analysis should be read in connection with the Consolidated Financial Statements.

 

Overview of Business Strategy and Economic Factors.    Duke Energy’s business strategy is to develop integrated energy businesses in targeted regions where Duke Energy’s capabilities in developing energy assets; operating power plants, natural gas liquid (NGL) plants and natural gas pipelines; optimizing commercial operations (including its affiliated real estate operation); and managing risk can provide comprehensive energy solutions for customers and create value for shareholders.

 

The energy industry and Duke Energy are experiencing a number of challenges, including the substantial imbalance between supply and demand for electricity, the pace of economic recovery, and regulatory and legal uncertainties. In response to these current challenges, Duke Energy is focusing on reducing risks and restructuring its business to be well positioned as the energy marketplace regains its health and vigor. In 2003, Duke Energy established a platform for future growth by selling certain non-strategic assets, cutting expenses and paying down debt, while still funding capital expenditures at the core regulated Franchised Electric and Natural Gas Transmission businesses. Duke Energy also resolved many outstanding legal and regulatory issues; reduced the scope of its international operations by announcing its intention to exit the Australian and European markets; and repositioned Duke Energy North America (DENA) to be a more focused, asset-backed merchant business. The repositioning of DENA included discontinuing proprietary trading and announcing its intentions to exit the merchant generation business in the Southeast region.

 

Duke Energy’s current goals for 2004 include: positive net cash generation; investing in its strongest businesses such as Franchised Electric, Natural Gas Transmission and Crescent; continuing to size its businesses to market realities; addressing merchant energy issues; strengthening relationships with customers; and further reducing regulatory and legal uncertainty. A major focus for 2004 will be to complete the execution of the plans Duke Energy announced for its merchant and international business, including the sale of its assets in the Southeastern U.S and Australia, and its exit from Europe. Duke Energy also plans to preserve its dividend payout of $1.10 per share and to continue to pay down debt in 2004 by $3.5 to $4.0 billion to further strengthen its balance sheet. (Included in the expected 2004 debt reduction amount is approximately $900 million of Australian dollar denominated debt related to International Energy’s Australian operations.) Duke Energy believes it is well-positioned to generate cash in 2004 from operations, the settlement of the forward stock purchase component of the outstanding equity units, and from asset sales to meet its goals of reducing debt, paying the dividend and providing for maintenance and modest expansion.

 

Duke Energy’s business model provides diversification between stable, less cyclical businesses like Franchised Electric and Natural Gas Transmission, and the traditionally higher-growth and more cyclical energy

 

31


Table of Contents

businesses like DENA, International Energy and Field Services. Additionally, Crescent’s portfolio strategy is diversified between residential, commercial and multi-family development. Although Duke Energy expects to return to profitability in 2004, all of its businesses can be negatively affected by sustained downturns or sluggishness in the economy, including low market price of commodities, all of which are beyond Duke Energy’s control, and could impair Duke Energy’s ability to meet its goals for 2004.

 

Declines in demand for electricity as a result of economic downturns would reduce overall electricity sales and lessen Duke Energy’s cash flows; especially as industrial customers reduce production and, thus, consumption of electricity. A portion of Franchised Electric’s business risk is mitigated by its being subject to regulated allowable rates of return and recovery of fuel costs under fuel adjustment clauses. Natural Gas Transmission is also subject to mandated tariff rates and recovery of certain fuel costs. Lower economic output would also cause the Natural Gas Transmission and Field Services businesses to experience a decline in the volume of natural gas shipped through their pipelines, gathered and processed at their plants, or distributed by their local distribution company, resulting in lower revenue and cash flows. Natural Gas Transmission continues to experience positive renewals of its customer contracts as they expire.

 

If negative market conditions persist over time and estimated cash flows over the lives of Duke 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 and diminish results of operations. 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 result in an impairment. The largest impairments over the past two years have been related to DENA and International Energy and it is estimated that the most significant future risk of impairments also resides within these segments.

 

Duke Energy and its goals for 2004 can also be substantially at risk due to the regulation of its businesses. Duke Energy’s businesses in North America are subject to regulations on the federal and state level. The majority of Duke Energy’s Canadian natural gas assets is also subject to various degrees of federal or provincial regulation and are subject to the same risks. Regulations, applicable to the electric power industry and gas transmission and storage industry, have a significant impact on the nature of the businesses and the manner in which they operate. Changes to regulations are ongoing and Duke Energy cannot predict the future course of changes in the regulatory environment or the ultimate effect that any future changes will have on its business.

 

Additionally, Duke Energy’s investments and projects located outside of the U.S. expose it to risks related to laws of other countries, taxes, economic conditions, fluctuations in currency rates, political conditions and policies of foreign governments. Changes in these factors are difficult to predict and may impact Duke Energy’s future results. Duke Energy’s recent restructuring, which focuses its non-U.S. operations on only Latin America and Canada, will help mitigate this exposure.

 

Duke Energy also relies on access to both short-term money markets and longer-term capital markets as a source of liquidity for capital requirements not satisfied by the cash flow from its operations. If Duke Energy is not able to access capital at competitive rates, its ability to implement its strategy could be adversely affected. Market disruptions or a downgrade of Duke Energy’s credit rating may increase its cost of borrowing or adversely affect its ability to access one or more sources of liquidity.

 

RESULTS OF OPERATIONS

 

Overview of Drivers and Variances for 2003 and 2002

 

Year 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

 

32


Table of Contents

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:

 

    Charges of $2.8 billion related to asset impairment of DENA’s Southeastern plants and its deferred Western plants, and wind-down costs associated with the Duke Energy Trading and Marketing, LLC (DETM) joint venture

 

    Charges of $262 million for the disqualification of certain hedges from the accrual method of accounting to mark-to-market accounting that were related to the impaired assets at DENA

 

    Charges and impairments of $292 million for International Energy’s Australian and European businesses, which have been classified as discontinued operations

 

    A charge of $254 million for goodwill impairment at DENA, related primarily to the trading and marketing business

 

    Net losses of $199 million on other assets sold or held for sale

 

    Severance and related charges of $153 million associated with workforce reductions across all segments

 

    A charge of $51 million for the write-off of an abandoned corporate risk management information system

 

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:

 

    Increased interest expense of $283 million due primarily to decreased capitalized interest and higher average debt balances, primarily resulting from debt assumed in, and issued with respect to, the acquisition of Westcoast Energy Inc. (Westcoast)

 

    Charges related to changes in accounting principles of $162 million, net of tax and minority interest (see Note 1 to the Consolidated Financial Statements)

 

    Increased amortization expense of $115 million at Franchised Electric related to North Carolina clean air legislation (see Note 4 to the Consolidated Financial Statements)

 

    A regulatory action by the Public Service Commission of South Carolina (PSCSC) which resulted in decreased earnings of $46 million at Franchised Electric, $16 million of which was an order to write-off regulatory assets related to debt issuance costs through interest expense (see Note 4 to the Consolidated Financial Statements)

 

    International Energy’s reserve and charges for environmental settlements with Brazil of $26 million

 

    A settlement with the Commodity Futures Trading Commission (CFTC) of $17 million, net of minority interest expense, by DENA (see Note 17 to the Consolidated Financial Statements)

 

    Milder weather which negatively impacted operations at DENA and Franchised Electric

 

    Foregone earnings of assets and equity investments sold

 

The above decreases in earnings were partially offset by additional earnings in 2003 from the Westcoast acquisition in March 2002.

 

33


Table of Contents

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:

 

    Decreased trading and marketing results, due primarily to negative impacts of a prolonged economic downturn, low commodity prices, low volatility levels, reduced sparks spreads and decreased market liquidity

 

    Charges at several business units, such as asset impairments and severance costs, related to market conditions in 2002 and strategic actions taken by management

 

    A decline in the average price realized for electricity generated by Duke Energy’s merchant plants

 

    An increase in interest expense due primarily to the debt assumed in the acquisition of Westcoast

 

The above drivers were partially offset by:

 

    Increased transportation, storage and distribution income from assets acquired or consolidated as a part of the acquisition of Westcoast in March 2002

 

    A one-time net-of-tax charge in 2001 of $96 million, or $0.13 per basic share, related to the cumulative effect of a change in accounting principle for the January 1, 2001 adoption of Statement of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities”

 

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 Revenues

 

Year Ended December 31, 2003 as Compared to December 31, 2002.    Consolidated operating revenues for 2003 increased $6,256 million, compared to 2002. This change was driven by a $5,368 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 $2,048 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.

 

34


Table of Contents

Consolidated Operating Expenses

 

Year Ended December 31, 2003 as Compared to December 31, 2002.    Consolidated operating expenses for 2003 increased $9,577 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 $1,072 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 Gains on Sales of Investments in Commercial and Multi-Family Real Estate

 

Consolidated gains on sales of investments in commercial and multi-family real estate were $84 million in 2003, and $106 million in 2002 and 2001. For a detailed discussion of this item see the Crescent segment discussion below.

 

Consolidated (Losses) Gains on Sales of Other Assets, net

 

Consolidated (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 Income

 

Year Ended December 31, 2003 as Compared to December 31, 2002.    For 2003, consolidated operating income decreased $3,574 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 $1,182 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 $314 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 Other Income and Expenses

 

Other Income and Expenses 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

 

35


Table of Contents

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.

Segment Results

 

Management evaluates segment performance primarily based on earnings before interest and taxes from continuing operations, after deducting minority interest expense related to those profits (EBIT). 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.

 

EBIT is viewed as a non-Generally Accepted Accounting Principle (GAAP) measure under the rules of the Securities and Exchange Commission (SEC). 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

 

     Years Ended December 31,

 
     2003

    2002

    2001

 
     (in millions)  

Franchised Electric

   $ 1,403     $ 1,595     $ 1,626  

Natural Gas Transmission

     1,317       1,161       607  

Field Services

     186       149       334  

Duke Energy North America

     (3,341 )     169       1,487  

International Energy

     210       102       236  

Crescent

     133       158       167  
    


 


 


Total reportable segment EBIT

     (92 )     3,334       4,457  

Other

     (272 )     (368 )     (539 )
    


 


 


Total reportable segment and other EBIT

     (364 )     2,966       3,918  

Minority interest expense and other(a)

     26       38       (10 )

Interest expense

     (1,380 )     (1,097 )     (760 )
    


 


 


Consolidated (loss) earnings from continuing operations before income taxes

   $ (1,718 )   $ 1,907     $ 3,148  
    


 


 



(a)   Includes interest income, foreign currency remeasurement gains and losses, and additional minority interest expense not allocated to the segment results.

 

36


Table of Contents

The amounts discussed below include intercompany transactions that are eliminated in the Consolidated Financial Statements.

 

Franchised Electric

 

     Years Ended December 31,

     2003

   2002

   2001

     (in millions, except where noted)

Operating revenues

   $ 4,883    $ 4,888    $ 4,746

Operating expenses

     3,533      3,329      3,185

Gains on sales of other assets, net

     6      —        —  
    

  

  

Operating income

     1,356      1,559      1,561

Other income, net of expenses

     47      36      65
    

  

  

EBIT

   $ 1,403    $ 1,595    $ 1,626
    

  

  

Sales, Gigawatt-hours (GWh)

     82,828      83,783      79,685

 

The following table shows the changes in GWh sales and average number of customers for Franchised Electric for the past two years.

 

Increase (decrease) over prior year


   2003

    2002

 

Residential sales(a)

   (2.3 )%   5.2 %

General service sales(a)

   0.4 %   2.4 %

Industrial sales(a)

   (5.7 )%   (2.4 )%

Wholesale sales

   5.1 %   35.4 %

Total Franchised Electric sales(b)

   (1.1 )%   5.1 %

Average number of customers

   2.0 %   2.4 %

(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:

 

    An $80 million decrease from lower GWh sales to retail customers due to mild weather, particularly during the summer months of 2003

 

    A $30 million decrease due to a one year rate decrement ordered by the PSCSC during the third quarter of 2003 (see Note 4 to the Consolidated Financial Statements)

 

    A $28 million decrease in sales to industrial customers, which continued to decline due to the sluggish economy in North Carolina and South Carolina

 

    An $87 million increase from wholesale power sales, as a result of favorable market conditions. The primary driver was higher prices for natural gas, which increased both the market price and demand for wholesale power, coupled with availability of low cost generation (primarily coal-fired generation for Franchised Electric).

 

    A $38 million increase due to continued growth in the number of residential and general service customers in Franchised Electric’s service territory

 

37


Table of Contents

Operating Expenses.    Operating expenses for 2003 increased $204 million, compared to 2002. The increase was driven primarily by:

 

    Increased depreciation and amortization expense of $137 million, primarily driven by amortization expense related to North Carolina’s clean air legislation, which totaled $115 million (see Note 4 to the Consolidated Financial Statements)

 

    Increased severance expenses of $42 million due to additional workforce reductions in 2003

 

    Charges in 2003 of $40 million for right-of-way maintenance costs

 

    Insurance recoveries in 2002 of $25 million related to injuries and damages claims

 

    Decreased storm costs of $59 million, with $30 million incurred in 2003 compared to $89 million associated with an ice storm in December 2002

 

    Decreased purchased power expense of $12 million, driven by lower demand from retail customers due to the milder weather

 

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:

 

    A $130 million increase from increased GWh sales to retail customers, driven by favorable weather in the latter half of 2002

 

    A $40 million increase from continued growth in the number of residential and general service customers in Franchised Electric’s service territory

 

    A $36 million reduction in 2001 revenues resulting from a refinement in the estimates used to calculate unbilled kilowatt-hour sales

 

    A $45 million decrease in wholesale power sales, primarily driven by lower prices in 2002

 

    A $35 million decrease from decreased GWh sales to industrial customers as a result of a slow economy in North Carolina and South Carolina

 

Operating Expenses.    Operating expenses for 2002 increased $144 million, compared to 2001. The increase was driven primarily by:

 

    Expenses totaling $89 million associated with an ice storm in December 2002

 

    Increased fuel costs of $54 million, resulting from the increase in electric sales

 

38


Table of Contents
    A $36 million charge in 2002 for severance costs related to workforce reductions

 

    Lower operating and maintenance expenses of $20 million at Franchised Electric’s generating plants

 

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

 

     Years Ended December 31,

     2003

   2002

   2001

     (in millions, except where noted)

Operating revenues

   $ 3,197    $ 2,464    $ 1,060

Operating expenses

     1,969      1,420      504

Gains on sales of other assets, net

     7      —        —  
    

  

  

Operating income

     1,235      1,044      556

Other income, net of expenses

     125      148      51

Minority interest expense

     43      31      —  
    

  

  

EBIT

   $ 1,317    $ 1,161    $ 607
    

  

  

Proportional throughput, TBtu(a)

     3,362      3,160      1,781

(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:

 

    A $466 million increase in transportation, storage and distribution revenue in January and February 2003 from assets acquired or consolidated as a part of the Westcoast acquisition in March 2002 (see Note 2 to the Consolidated Financial Statements)

 

    A $177 million increase due to foreign exchange favorably impacting revenues from the Canadian operations as a result of the strengthening Canadian dollar

 

    An $81 million increase from recovery of natural gas commodity costs that are passed through to customers without a mark-up at Union Gas Limited (Union Gas). This amount is offset in expenses.

 

    A $31 million increase from completed and operational business expansion projects in the U.S.

 

    A $58 million decrease from operations sold in 2003 and the fourth quarter of 2002 (see Note 2 to the Consolidated Financial Statements)

 

Operating Expenses.    Operating expenses for 2003 increased $549 million, compared to 2002. This increase was driven primarily by:

 

    A $319 million increase in transportation, storage, and distribution expenses in January and February 2003 from assets acquired or consolidated as a part of the Westcoast acquisition in March 2002

 

    A $132 million increase caused by foreign exchange impacts

 

39


Table of Contents
    An $81 million increase related to increased natural gas prices at Union Gas. This amount is offset in revenues.

 

    A $20 million increase from 2003 severance charges related to workforce reductions

 

    A $38 million decrease from operations sold in the fourth quarter of 2002 and in 2003

 

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:

 

    A $36 million decrease from negative foreign exchange impacts in 2003, due to the settlement of hedges related to foreign currency exposure

 

    A $33 million decrease in equity earnings associated with the sold investments

 

    A $28 million decrease due to a construction fee received in 2002 from an affiliate related to the successful completion of the Gulfstream Natural Gas System, LLC (Gulfstream), 50% owned by Duke Energy which went into service in May 2002

 

    A $58 million increase in gains from the sale of various equity investments in 2003 (see Note 2 to the Consolidated Financial Statements)

 

    A $17 million increase in allowance for funds used during construction related to additional capital projects

 

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.

 

40


Table of Contents

Operating Expenses.    Operating expenses for 2002 increased $916 million, compared to 2001. This increase was driven primarily by:

 

    Incremental operating expenses of $877 million related to the gas transmission, storage and distribution assets acquired or consolidated in the Westcoast acquisition in March 2002

 

    Severance costs of $9 million associated with a workforce reduction in 2002

 

    Incremental operating expenses associated with business expansion projects

 

    Reversal of reserves of $25 million related to certain environmental issues that were resolved in 2002

 

    Reduced goodwill amortization of $14 million in 2002 as a result of the implementation of SFAS No. 142, “Goodwill and Other Intangible Assets”

 

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

 

     Years Ended December 31,

     2003

    2002

   2001

     (in millions, except where
noted)

Operating revenues

   $ 8,661     $ 5,990    $ 8,341

Operating expenses

     8,428       5,854      7,891

Losses on sales of other assets, net

     (4 )     —        —  
    


 

  

Operating income

     229       136      450

Other income, net of expenses

     67       60      45

Minority interest expense

     110       47      161
    


 

  

EBIT

   $ 186     $ 149    $ 334
    


 

  

Natural gas gathered and processed/transported, TBtu/d (a)

     7.5       8.0      8.2

NGL production, MBbl/d (b)

     359.1       384.4      390.0

Average natural gas price per MMBtu (c)

   $ 5.39     $ 3.22    $ 4.27

Average NGL price per gallon (d)

   $ 0.53     $ 0.38    $ 0.45

(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

 

41


Table of Contents

Year Ended December 31, 2003 as Compared to December 31, 2002

 

Operating Revenues.    Operating revenues for 2003 increased $2,671 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 $2,574 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 $63 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 $37 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 $2,351 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.

 

42


Table of Contents

Operating Expenses.    Operating expenses for 2002 decreased $2,037 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 $114 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 $185 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

 

     Years Ended December 31,

     2003

    2002

    2001

     (in millions, except where noted)

Operating revenues

   $ 4,321     $ 1,552     $ 3,014

Operating expenses and impairments

     7,767       1,507       1,768

(Losses) gains on sales of other assets, net

     (208 )     —         229
    


 


 

Operating (loss) income

     (3,654 )     45       1,475

Other income, net of expenses

     206       81       56

Minority interest (benefit) expense

     (107 )     (43 )     44
    


 


 

EBIT

   $ (3,341 )   $ 169     $ 1,487
    


 


 

Actual plant production, GWh (a)

     24,046       24,962       20,516

Proportional megawatt capacity in operation

     15,820       14,157       6,799

(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:

 

    A $3,025 million increase related to the January 1, 2003 adoption of the final consensus on EITF Issue No. 02-03. See earlier discussion under “Consolidated Operating Revenues.”

 

    A $346 million reduction in overall power revenues, due primarily to $299 million decrease resulting from lower power prices and a $47 million decrease due to volumes delivered due to decreased demand

 

    An increase in net trading margin driven by less unfavorable market changes in correlation and volatility in 2003 as compared to 2002, partially offset by a $76 million increase in 2002 from the appreciation of the fair value of the mark-to-market portfolio as a result of applying improved and standardized valuation modeling techniques to all North American regions

 

43


Table of Contents

Operating Expenses and Impairments.    Operating expenses and impairments for 2003 increased $6,260 million, compared to 2002. The increase was driven primarily by:

 

    A $3,025 million increase due primarily to the adoption of the final consensus on EITF Issue No. 02-03, as described earlier

 

    A $2,928 million increase due to asset impairments and other related charges related to current market conditions and strategic actions taken by management. For 2003 these charges totaled $3,157 million and related to $2,903 million of impairments, primarily on DENA’s Southeastern plants and its deferred Western plants, and disqualification of certain hedges that were related to the impaired assets; and goodwill impairment related to the trading and marketing business of $254 million. These amounts were offset by $229 million of charges taken in 2002 comprised of provisions for the termination of certain turbines on order and the write-down of other uninstalled turbines of $121 million, the write-off of site development costs (primarily in California) of $31 million, partial impairment of a merchant plant of $31 million, a charge of $24 million for the write-off of an information technology system and demobilization costs related to the deferral of three merchant power projects of $22 million.

 

    A $32 million increase in overall gas costs due primarily to higher gas prices

 

    A $62 million increase in other plant related operations, maintenance, and depreciation due primarily to increased costs associated with projects that entered into commercial operation during 2002 and 2003

 

    A $117 million increase in other general and administrative expenses due primarily to a CFTC settlement in 2003 of $28 million ($17 million at Duke Energy’s 60% share) and the release of incentive accruals in 2002 of $89 million

 

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:

 

    A $178 million increase due to a gain on the sale of DENA’s 50% ownership interest in Ref-Fuel to Highstar Renewable Fuels LLC in 2003

 

    A $33 million decrease due to 2002 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 in 2002

 

    Remaining decrease due primarily to lower equity earnings from Ref Fuel

 

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.

 

44


Table of Contents

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.

 

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:

 

    Lower incentive compensation expense of $300 million, primarily related to trading activities

 

    Decreased bad debt expense of $123 million

 

    Lower fuel costs of $88 million

 

    Demolition reserves recorded in 2001 of $65 million

 

    Asset impairment and other charges of $229 million related to market conditions in 2002 and strategic actions taken by management, as described above

 

    Higher depreciation expense of $89 million, related to the commencement of operations of nine generation facilities by mid-year 2002

 

    Severance costs of $19 million in 2002 associated with work force reductions

 

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.

 

45


Table of Contents

International Energy

 

     Years Ended December 31,

     2003

   2002

   2001

     (in millions, except where noted)

Operating revenues

   $ 597    $ 743    $ 684

Operating expenses

     406      716      458

Gains on sales of other assets, net

     —        —        9
    

  

  

Operating income

     191      27      235

Other income, net of expenses

     32      85      24

Minority interest expense

     13      10      23
    

  

  

EBIT

   $ 210    $ 102    $ 236
    

  

  

Sales, GWh

     16,374      18,350      15,749

Proportional megawatt capacity in operation

     4,121      3,917      3,968

 

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:

 

    A $91 million increase in 2002 revenues as a result of a Brazilian regulatory ruling in March 2002 that affected all Brazilian energy market participants and finalized the methodology to calculate revenues and expenses related to the 2001 electricity rationing, which is offset in operating expenses

 

    A change in methodology in Peru to reflect a netting of the volumes transferred to/from the electricity grid in 2003 resulting in a $57 million revenue reduction, which is offset in expense. The change related to prices was not material.

 

    Lower revenues of $35 million in El Salvador as a result of a power sales contract not being renewed by a counterparty

 

    Lower liquefied natural gas sales of $33 million, due primarily to the termination of a gas sales contract

 

    Currency translation impacts resulting in a decrease of $10 million in Brazil and Argentina

 

    An increase of $35 million related primarily to favorable recontracting terms on electricity sales contracts in Brazil

 

    An increase of $25 million as a result of the completion of the 160 megawatt (MW) expansion in Guatemala

 

    Increases to revenues and receivables for adjustments of $11 million as a result of a regulatory audit in Brazil

 

Operating Expenses.    Operating expenses for 2003 decreased $310 million compared to 2002. The decrease was driven primarily by:

 

    A $91 million increase in 2002 operating expenses as a result of a Brazilian regulatory ruling in March 2002 that affected all Brazilian energy market participants and finalized the methodology to calculate revenues and expenses related to the 2001 electricity rationing, which is offset in operating revenues

 

    A $75 million write-down in 2002 for the cancellation of capital projects in Brazil and Bolivia

 

    A change in methodology in Peru to reflect a netting of the volumes transferred to/from the electricity grid in 2003 resulting in a $57 million expense reduction, which is offset in revenue

 

46


Table of Contents
    Lower expenses in the liquefied natural gas business due to a $40 million reduction in estimated probable losses due the early termination of a natural gas sales contract and $31 million in lower gas purchases

 

    Lower expenses of $19 million in El Salvador as a result of reduced contract sales volumes

 

    Cost savings of $17 million from lower International Energy corporate expenses

 

    Higher operating expenses of $22 million due to the completion of the 160 MW expansion in Guatemala

 

Other Income, net of expenses.    Other income, net of expenses decreased $53 million compared to 2002. The decrease was primarily the result of:

 

    A $43 million decrease in equity investment income in Mexico due to a change in revenue recognition, increased repair costs, lower revenue due to downtime, and currency translation

 

    A $26 million charge and reserve for environmental settlements in Brazil

 

    An $11 million increase in equity investment income at National Methanol Company due to favorable product prices

 

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.

 

47


Table of Contents

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:

 

    A $91 million increase in 2002 revenues as a result of a Brazilian regulatory ruling in March 2002 that affected all Brazilian energy market participants and finalized the methodology to calculate revenues and expenses related to the 2001 electricity rationing, which is offset in operating expenses

 

    A $36 million increase due to the effect of reporting a full year of operations in 2002 for assets acquired in Guatemala during 2001, compared to only two months in 2001

 

    A $15 million increase in Peru due primarily to higher electricity sales volumes

 

    A $70 million decrease from currency translations within Brazil and Argentina

 

    A $15 million decrease as a result of lower sales volumes and commodity prices at International Energy’s liquefied natural gas business

 

Operating Expenses.    Operating expenses for 2002 increased $258 million, compared to 2001. The increase was driven primarily by:

 

    A $91 million increase in 2002 operating expenses as a result of a Brazilian regulatory ruling in March 2002 that affected all Brazilian energy market participants and finalized the methodology to calculate revenues and expenses related to the 2001 electricity rationing, which is offset in operating revenues

 

    A $75 million impairment charge in 2002 related to the write-off of project and site development costs in Brazil and Bolivia

 

    A $28 million increase in operating expenses related to the effect of reporting a full year of operations in 2002 for assets acquired in Guatemala during 2001, compared to only two months in 2001

 

    A $22 million increase in the liquefied natural gas business reserve for estimated probable losses due to the early termination of a natural gas sales contract

 

    A $19 million increase in Brazil as a result of reserve reversals in 2001 and the establishment of settlement provisions in 2002

 

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.

 

48


Table of Contents

Crescent

 

     Years Ended December 31,

     2003

   2002

    2001

     (in millions)

Operating revenues

   $ 284    $ 226     $ 213

Operating expenses

     232      177       151

Gains on sales of investments in commercial and multi-family real estate

     84      106       106
    

  


 

Operating income

     136      155       168

Other income, net of expenses

     —        1       1

Minority interest expense (benefit)

     3      (2 )     2
    

  


 

EBIT

   $ 133    $ 158     $ 167
    

  


 

 

Year Ended December 31, 2003 as Compared to December 31, 2002

 

Operating Revenues.    Operating revenues for 2003 increased $58 million, compared to 2002. The increase was driven primarily by increased revenues of $69 million from residential developed lot sales offset by a $5 million decrease in commercial rents. Residential developed lot sales increased in 2003 primarily due to sales in a new development in South Carolina of $51 million and increased sales in an existing project in Florida of $28 million. The decrease in commercial rents was due to a smaller portfolio of commercial properties in 2003 as a result of decreased development activities in the commercial sector.

 

Operating Expenses.    Operating expenses for 2003 increased $55 million, compared to 2002. The cost of residential developed lot sales increased $50 million as a result of increased sales as discussed above.

 

Gains on Sales of Investments in Commercial and Multi-Family Real Estate.    2003 Gains on sales of Investments in Commercial and Multi-family Real Estate decreased $22 million compared to 2002 primarily due to a $40 million decrease in legacy land sales offset by a $17 million increase in commercial land sales. The decrease in legacy land sales is due to a declining inventory of large, contiguous tracts in North and South Carolina, as well as a decrease in demand by large tract purchasers. The increase in commercial land sales is due to the initial sales of land at our Potomac Yard project in the Washington, DC area.

 

EBIT.    For 2003, EBIT decreased $25 million, compared to 2002, due primarily to decreased land management sales partially offset by earnings from commercial land sales and increased residential developed lot sales.

 

Matters Impacting Future Crescent’s Results

 

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 earnings growth over the next three years.

 

Year Ended December 31, 2002 as Compared to December 31, 2001

 

Operating Revenues.    Operating revenues for 2002 increased $13 million, compared to 2001. The increase was driven primarily by a $29 million increase in Crescent’s residential developed lot sales in 2002, due to the addition of several high-end communities offset by a $19 million reduction in commercial rental revenue due to soft market conditions and a smaller portfolio of commercial properties due to large portfolio sales in 2001.

 

Operating Expenses.    Operating expenses for 2002 increased $26 million, compared to 2001. The increase was driven by a $28 million increase in the cost of developed lot sales resulting from an increase in sales as discussed above.

 

49


Table of Contents

Gains on Sales of Investments in Commercial and Multi-Family Real Estate.    The 2002 gains on sales of investments in commercial and multi-family real estate remained flat over 2001. However, commercial project sales decreased $30 million due to a reduced inventory of commercial buildings available for sale resulting from large portfolio sales in 2001. Offsetting this decrease was a $29 million increase in legacy land sales in 2002, resulting from opportunities to accelerate sales of large, contiguous tracts in North and South Carolina.

 

Other

 

     Years Ended December 31,

 
     2003

    2002

    2001

 
     (in millions)  

Operating revenues

   $ 1,628     $ 303     $ 597  

Operating expenses

     1,933       655       1,113  

Gains on sales of other assets, net

     —         32       —    
    


 


 


Operating loss

     (305 )     (320 )     (516 )

Other income (loss), net of expenses

     33       (48 )     (23 )
    


 


 


EBIT

   $ (272 )   $ (368 )   $ (539 )
    


 


 


 

Year Ended December 31, 2003 as Compared to December 31, 2002

 

Operating Revenues.    Operating revenues for 2003 increased $1,325 million, compared to 2002. The increase was driven primarily by:

 

    A $1,300 million increase at Duke Energy Merchants, LLC (DEM) in connection with the January 1, 2003 adoption of the final consensus on EITF Issue No. 02-03. See earlier discussion under “Consolidated Operating Revenues.”

 

    A $70 million increase in revenues at Energy Delivery Services (EDS), as a result of EDS beginning operations in May 2002 and thus not recognizing a full year of operations in the prior year. EDS was sold in December 2003.

 

    A $172 million decrease due to the sale of Duke Engineering & Services, Inc. (DE&S) and DukeSolutions, Inc. (DukeSolutions) in 2002

 

Operating Expenses.    Operating expenses for 2003 increased $1,278 million, compared to 2002. The increase was driven primarily by:

 

    A $1,300 million increase at DEM, due primarily to the adoption of the final consensus on EITF Issue No. 02-03, as described earlier

 

    A $72 million increase at EDS, as a result of EDS beginning operations in May 2002 and thus not recognizing a full year of operations in the prior year. EDS was sold in December 2003.

 

    A $51 million increase for a 2003 write-off related to a corporate risk management information system that was abandoned

 

    A $164 million decrease due to the sale of DE&S and DukeSolutions in 2002

 

    A $21 million decrease in DEM’s general and administrative costs due to the wind-down of its business

 

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 increased $81 million for 2003, compared to 2002, due primarily to increased earnings related to Duke/Fluor Daniel (D/FD).

 

50


Table of Contents

EBIT.    For 2003, EBIT increased $96 million, compared to 2002. As discussed above, the increase in EBIT was primarily driven by the increase in other income, offset by the decrease due to the sale of assets.

 

Matters Impacting Future Other Results

 

In 2003, a significant portion of Other was either sold or classified as held-for-sale. For 2004, Other will be comprised mainly of DEM, DukeNet Communications, LLC (DukeNet), D/FD and certain unallocated corporate costs. 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 $294 million, compared to 2001. The decrease was driven primarily by:

 

    A $339 million decrease due primarily to the sale of DE&S and DukeSolutions in 2002, resulting in a partial year of revenues compared to a full year in 2001

 

    A $142 million decrease due to revenues in 2001 on corporately managed energy risk positions used to hedge exposure to commodity prices

 

    A $92 million increase in revenues from EDS, which was formed in the second quarter of 2002

 

    A $39 million increase at DEM as a result of increased trading and marketing net margins in 2002, and the write-offs for Enron Corporation (Enron) and Agrifos in 2001

 

Operating Expenses.    Operating expenses for 2002 decreased $458 million, compared to 2001. The decrease was driven primarily by:

 

    A $364 million decrease due primarily to sale of DE&S and DukeSolutions in 2002, resulting in a partial year of expenses

 

    A $134 million decrease due to expenses in 2001 on corporately managed energy risk positions used to hedge exposure to commodity prices

 

    A $52 million decrease due to 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)

 

    A $77 million increase in operating expenses as a result of the formation of EDS in the second quarter of 2002

 

    A $17 million increase for severance charges in 2002 at D/FD due to the downturn in the domestic power industry.

 

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 decreased $25 million due primarily to decreased equity earnings from D/FD.

 

EBIT.    EBIT for 2002 increased $171 million, compared to 2001. The increase was due primarily to gains on sales of other assets, as described above, earnings generated from EDS and the DEM write-off for Enron and Agrifos in 2001.

 

51


Table of Contents

Other Impacts on Earnings Available for Common Stockholders

 

Interest 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 $55 million in 2003 as compared to 2002, and decreased $210 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 $20 million in 2003 as compared to 2002, and decreased $179 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 $1,320 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 $538 million in 2002, compared to 2001, due primarily to a $1,241 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 from discontinued operations was $152 million for 2003, $262 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

 

52


Table of Contents

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.)

 

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 presentation of the accounting 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 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

 

53


Table of Contents

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 only limited recognition related to hedge ineffectiveness 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

 

54


Table of Contents

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.

 

55


Table of Contents

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.

 

Crescent sells residential developed lots in North Carolina, South Carolina, Georgia, Florida, Texas and Arizona. Crescent recognizes revenues from the sale of residential developed lots at closing. Profit is recognized under the full accrual method using estimates of average gross profit per lot within a project or phase of a project based on total estimated project costs. Land and land development costs are allocated to land sold based on relative sales values. Crescent recognizes revenues from commercial project sales at closing using the full accrual method. Profit is recognized based on the difference between the sales price and the carrying cost of the project.

 

56


Table of Contents

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.

 

57


Table of Contents

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.

 

58


Table of Contents

LIQUIDITY AND CAPITAL RESOURCES

 

Known Trends and Uncertainties

 

Duke Energy relies primarily upon cash flows from operations, as well as borrowings and the sale of assets to fund its liquidity and capital requirements. A material adverse change in operations or available financing may impact Duke Energy’s ability to fund its current liquidity and capital resource requirements. The relatively stable operating cash flows of the Franchised Electric and Natural Gas Transmission businesses currently comprise a substantial portion of Duke Energy’s cash flow from operations and it is anticipated to continue as such for the next several years.

 

Duke Energy currently anticipates net cash provided by operating activities in 2004 to be approximately $4.0 billion. In addition to net cash provided by operating activities, Duke Energy also expects to generate approximately $2.2 billion of proceeds from asset sales in 2004, including approximately $900 million of debt that is intended to be transferred in connection with the Australian sales transaction and subsequently retired. Achievement of these projected amounts is subject to a number of factors, including, but not limited to, regulatory constraints, economic trends, divestiture opportunities and market volatility. The 2004 asset sales principally include International Energy’s Australian operations, including its related debt, and DENA’s Southeast merchant generation plants. Management anticipates either an initial public offering or the sale of the Australian operations by mid-2004, and the sale of merchant generation plants by the end of 2004.

 

Duke Energy’s projected 2004 capital and investment expenditures are approximately $2.5 billion. Duke Energy is focusing on reducing risk and restructuring its business for future success, including opportunities to reduce further projected capital and investment expenditures. Duke Energy will invest in its strongest business sectors with an overall focus on positive net cash generation. Based on this goal, approximately 65% of total projected 2004 capital expenditures are projected to be allocated to Natural Gas Transmission and Franchised Electric. Total projected capital and investment expenditures include approximately $1.5 billion for maintenance and upgrades of existing plants, pipelines, and infrastructure to serve load growth. Additionally, Duke Energy has approximately $0.3 billion in capital and investment expenditures designated for Crescent, including amounts for residential real estate. Expenditures at Crescent and Natural Gas Transmission constitute the majority of the expansion capital planned in 2004 by Duke Energy.

 

In 2004, Duke Energy expects to continue to pay down overall debt by approximately $3.5 billion to $4.0 billion, which includes approximately $900 million for Australian dollar denominated debt that is intended to be transferred in connection with the sale transaction and subsequently retired, through the settlement of the forward stock purchase component of the outstanding Equity Units in May and November 2004 totaling $1,625 million, asset sales, and cash from operations. The reductions in debt are expected to consist of debt maturities, the early retirement of all economically callable debt, and other reductions. Additionally, Duke Energy expects to obtain some funding through common stock issuances in its InvestorDirect Choice Plan (a stock purchase and dividend reinvestment plan) and employee benefits.

 

Duke Energy monitors compliance with all debt covenants and restrictions, and does not currently believe that it will be in violation or breach of its debt covenants. However, circumstances could arise that may alter that view. If and when management had a belief that such potential breach could exist, appropriate action will be taken to mitigate any such issue. Duke Energy also maintains an active dialogue with the credit rating agencies, and believes that the current credit ratings have stabilized as evidenced by the Stable Outlook ratings of the agencies that are retained to rate Duke Energy and its subsidiaries.

 

Operating Cash Flows

 

Net cash provided by operating activities was $3,419 million in 2003 compared to $4,199 million in 2002, a decrease of $780 million. The decrease in cash provided by operating activities was due primarily to lower cash

 

59


Table of Contents

settlements from trading and hedging activities, and less cash flows in 2003 from changes in working capital, principally accounts payables and accounts receivable. Additionally, in 2003, Duke Energy made a voluntary contribution of $181 million to its U.S. defined benefit pension plan. No contributions to the Duke Energy defined pension plan were made in 2002 or 2001. No decision for the U.S. plan 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. Also, Duke Energy made contributions to the Westcoast retirement plans (Westcoast plans) of approximately $11 million in 2003 and $9 million in 2002. Duke Energy anticipates that it will make contributions of approximately $27 million to the Westcoast plans in 2004.

 

Net cash provided by operating activities was $4,199 million in 2002 compared to $3,749 million in 2001, an increase of $450 million. The increase in cash provided by operating activities was due primarily to higher cash earnings plus changes in working capital from 2001. Although net income significantly decreased in 2002 (see Results of Operation for further discussion) many of the items affecting net income were non-cash. Non-cash items affecting earnings included an increase in depreciation expense, primarily due to the acquisition of Westcoast; non-cash impairment charges for goodwill (at International Energy), project sites (primarily at DENA) and property plant and equipment; and higher deferred tax expense.

 

Investing Cash Flows

 

Cash used in investing activities was $421 million in 2003 compared to $6,461 million in 2002, a decrease of $6,040 million. Additionally, cash used in investing activities was $6,461 million in 2002 compared to $5,435 million in 2001, an increase of $1,026 million. The primary use of cash related to investing activities is capital and investment expenditures, which are detailed by business segment in the following table.

 

Capital and Investment Expenditures by Business Segment(a)

 

     Years Ended December 31,

 
     2003

   2002

    2001

 
     (in millions)  

Franchised Electric

   $ 1,030    $ 1,269     $ 1,115  

Natural Gas Transmission

     766      2,878       748  

Field Services

     211      309       587  

Duke Energy North America

     277      2,013       3,213  

International Energy

     71      412       442  

Crescent(c)

     290      275       452  

Other(b)

     116      193       483  

Cash acquired in acquisitions

     —        (77 )     (17 )
    

  


 


Total consolidated

   $ 2,761    $ 7,272     $ 7,023  
    

  


 



(a)   Amounts include the acquisition of Westcoast in 2002
(b)   Amounts include deferral in the consolidation of fifty percent of the profit earned by D/FD for the construction of DENA’s merchant generation plants, which is associated with Duke Energy’s ownership.
(c)   Amounts include capital expenditures for residential real estate included in operating cash flows of $196 million in 2003, $179 million in 2002 and $230 million in 2001.

 

Capital and investment expenditures, including Crescent residential real estate investments, decreased $4,511 million in 2003 compared to 2002. The decrease was due primarily to the 2002 acquisition of Westcoast for $1,707 million, net of cash acquired, and lower investments in generating facilities at DENA, resulting from the downturn in the merchant energy portion of its business, the most significant of which are due to deferred construction on the Moapa, Grays Harbor, and Luna facilities of $621 million, decreases in expenditures for the Marshall, Sandersville, and Moss Landing facilities of $380 million, and a decrease in turbine purchases of

 

60


Table of Contents

$434 million. Capital and investment expenditures also decreased in 2003 due to a decrease in plant construction costs at Franchised Electric primarily due to a decrease of approximately $250 million in expenditures related to environmental equipment at its coal-fired plants and the Mill Creek combustion turbine plant, which was completed in 2003; a decrease in plant construction costs at International Energy of $268 million, primarily in Australia; a decrease in investments in Natural Gas Transmission’s 50% interest in Gulfstream of $226 million; and a reduction in investments at Other (primarily related to DCP).

 

The decrease in investing cash flow in 2003 when compared to 2002 was also impacted by the increase in proceeds from the sale of equity investments and other assets, and sales of and collections on notes receivable of $1,450 million. The increased proceeds were primarily due to the sale of DENA’s 50% ownership interest in Ref Fuel; Natural Gas Transmission’s sale of its wholly owned Empire State Pipeline, sale of its investment in the Alliance Pipeline and the associated Aux Sable liquids plant, Foothills Pipe Lines, Ltd, and Vector Pipelines L.P.; Field Services’ sale of assets to Crosstex Energy Services, L.P. & ScissorTail Energy, LLC, and Duke Energy’s sale of the TEPPCO Partners, L.P. Class B units; DEM’s sale of DE Hydrocarbons LLC; International Energy’s sale of its 85.7% majority interest in P.T. Puncakjaya Power, sale of its European gas marketing business, and sale of its French generating facility; and the monetization of various investments at DCP.

 

Capital and investment expenditures increased $249 million in 2002 compared to 2001. The increase was due primarily to cash used in the acquisition of Westcoast of $1,707 million, net of cash acquired, partially offset by decreases in capital expenditures and investment expenditures. Capital expenditures decreased when compared to 2001 due to a decrease in DENA investments in generating facilities of approximately $1,030 million, as a result of management’s revised outlook for the merchant energy portion of its business, and a decrease in acquisitions of businesses and assets of approximately $375 million when compared to 2001. These decreases in capital expenditures were partially offset by an increase in plant construction costs at Franchised Electric of approximately $185 million primarily due to expenditures at the Mill Creek combustion turbine plant and related to environmental equipment at coal-fired plants; and an increase in investments in property plant and equipment of approximately $520 million at Natural Gas Transmission due primarily to increased expansion and maintenance projects related to the Westcoast, Algonquin Gas Transmission Company, East Tennessee Natural Gas Company, and Texas Eastern Transmission LP (Texas Eastern) systems, along with the Maritimes & Northeast Pipeline (M&N Pipeline) expansion costs after its consolidation in 2002. Investment activities also decreased when compared to 2001, due primarily to reduced investments at Other (primarily related to a decrease of approximately $110 million in notes receivable at DCP) and a decrease of approximately $205 million in expenditures for Natural Gas Transmission’s investment in Gulfstream. The remaining decrease of approximately $440 million is associated with a decrease in capital and investment expenditures throughout Duke Energy’s segments.

 

In June 2002, the state of North Carolina passed new clean air legislation that includes provisions that freeze electric utility rates from June 20, 2002 (the effective date of the statute) to December 31, 2007 (rate freeze period), subject to certain conditions, in order for certain North Carolina electric utilities, including Duke Energy, to make significant reductions in emissions of sulfur dioxide and nitrogen oxides from the state’s coal-fired power plants. The legislation permits Duke Energy the flexibility to vary the amortization schedule for recording of compliance costs. During the rate freeze period, Duke Energy is expected to recover a minimum of 70% of the total estimated costs of compliance. (See Note 17 to the Consolidated Financial Statements.) As part of this legislation Duke Energy will spend an estimated total of $1.5 billion over the next ten years to install pollution controls in its coal-fired plants. Duke Energy expects to incur approximately $80 million of total capital costs associated with this legislation in 2004.

 

All projected capital and investment expenditures are subject to periodic review and revision and may vary significantly depending on a number of factors, including, but not limited to, industry restructuring, regulatory constraints, acquisition opportunities, market volatility and economic trends.

 

61


Table of Contents

Financing Cash Flows and Liquidity

 

Duke Energy’s consolidated capital structure as of December 31, 2003, including short-term debt, was 58% debt, 37% common equity and 5% minority interests. Fixed charges coverage ratio, calculated using SEC guidelines, was 2.2 times for 2002 and 3.9 times for 2001. Earnings were inadequate to cover fixed charges by $1,715 million for the year ended December 31, 2003 as a result of approximately $3.5 billion in non-cash impairment charges incurred in 2003.

 

Cash flows from financing activities decreased $5,503 million to net cash used in financing activities of $2,657 million in 2003 from net cash provided by financing activities of $2,846 million in 2002. This change was due primarily to the net reduction of outstanding long-term debt, trust preferred securities, and notes payable and commercial paper during 2003 as compared to the same period in 2002 when Duke Energy acquired Westcoast and financed other business expansion projects. This change was also due to a reduction in the issuance of common stock in 2003, compared to 2002, when Duke Energy issued 54.5 million shares of common stock in a public offering, the proceeds of which were used to repay commercial paper that had been issued to fund a portion of the consideration for the Westcoast acquisition. This change in cash flows from financing activities was aligned with Duke Energy’s strategy to reduce outstanding debt and strengthen the balance sheet.

 

Cash flows provided by financing activities were $2,846 million in 2002 and $1,354 million in 2001, an increase of $1,492 million. This change was due primarily to the net increase in outstanding long-term debt as a result of the 2002 Westcoast acquisition.

 

During 2003, cash from operations and the sale of assets was adequate for funding Duke Energy’s cash requirements such as capital expenditures, dividend payments and permanently retiring a portion of scheduled debt maturities.

 

Significant Financing Activities.    During 2003, Duke Energy issued $500 million of 3.75% first and refunding mortgage bonds due in 2008 in a private placement transaction exempt from registration under Rule 144A of the Securities Act of 1933, as amended (Securities Act). Pursuant to a registration agreement, Duke Energy registered an exchange with the holders of identical bonds under the Securities Act on a registration statement filed with the SEC. This registration statement was declared effective and the exchange offer was completed during the third quarter of 2003 with substantially all of the private bonds exchanged for registered bonds. There were no proceeds to Duke Energy from the exchange. The proceeds of the offering of the private bonds were used to repay short-term debt, to replace $100 million of Duke Energy’s first and refunding mortgage bonds that matured in February 2003, to repay approximately $200 million of an intercompany loan from Duke Capital and for general corporate purposes.

 

Also in 2003, Duke Energy completed a $700 million offering of 1.75% convertible senior notes due in 2023. In connection with the offering, the underwriters exercised an option to purchase an additional $70 million of convertible senior notes to cover any over allotments. Each of these senior notes is convertible to Duke Energy common stock at a premium of 40% above the May 1, 2003 closing common stock market price of $16.85 per share. Upon conversion, the senior notes are potentially convertible into approximately 32.6 million shares of common stock. The conversion of these senior notes into shares of Duke Energy common stock is contingent on the occurrence of certain events during specified periods. These events include whether the price of Duke Energy common stock reaches specified thresholds, the credit rating of Duke Energy falls below certain thresholds, the holders put the senior notes back to Duke Energy, the convertible notes are called for redemption by Duke Energy, or specified transactions have occurred. The conditions that permit such conversion were not satisfied as of December 31, 2003. Holders of the senior notes may require Duke Energy to purchase all or a portion of their senior notes for cash on May 15, 2007, May 15, 2012, and May 15, 2017, at a price equal to the principal amount of the senior notes plus accrued interest, if any. Duke Energy may redeem for cash all or a portion of the senior notes at any time on or after May 20, 2007, at a price equal to the sum of the issue price plus accrued interest, if any, on the redemption date. The net proceeds of the offering were used for general corporate purposes, including the reduction of outstanding commercial paper.

 

62


Table of Contents

During 2003, Duke Energy completed a securitization of certain accounts receivable through Duke Energy Receivables Finance Company, LLC (DERF), a newly formed, bankruptcy remote, special purpose subsidiary. DERF is a wholly owned limited liability company with a separate legal existence from its parent, and its assets are not intended to be generally available to creditors of Duke Energy. As a result of the securitization, Duke Energy sold, and will continue to sell on a daily basis to DERF, certain accounts receivable arising from the sale of electricity and/or related services as part of Duke Energy’s franchised electric business. The proceeds from the initial sale of the accounts receivable to DERF were used for general corporate purposes in its franchised electric business, which included the repayment of outstanding commercial paper. In order to fund its purchases of accounts receivable, DERF entered into a two-year $300 million secured credit facility, with a commercial paper conduit administered by Citicorp North America, Inc. The credit facility and related securitization documentation contain several covenants, including covenants with respect to the accounts receivable held by DERF as well as a covenant requiring that the ratio of Duke Energy consolidated indebtedness to Duke Energy consolidated capitalization not exceed 65%. As of December 31, 2003, the interest rate associated with the credit facility, which is based on commercial paper rates, was 1.5% and $300 million was outstanding under the credit facility. The securitization transaction was not structured to meet the criteria for sale treatment under SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities,” and accordingly is reflected as a secured borrowing in the Consolidated Financial Statements. As of December 31, 2003, the $300 million outstanding balance of the credit facility was secured by approximately $446 million of accounts receivable held by DERF. The obligations of DERF under the credit facility are non-recourse to Duke Energy.

 

Additionally, during 2003, Duke Energy issued $200 million of 4.50% first and refunding mortgage bonds due in 2010, and $500 million of 5.30% first and refunding mortgage bonds due in 2015. The proceeds from the first mortgage bond issuances were used for general corporate purposes, to repay commercial paper, and to redeem (1) at 102% of their aggregate principal amount, $200 million of 6.875% first and refunding mortgage bonds due in 2023, (2) at 101.785% of their aggregate principal amount, $150 million of 6.75% first and refunding mortgage bonds due in 2025 and (3) at 102.35% of their aggregate principal amount, $150 million of 7.0% first and refunding mortgage bonds due in 2033. The loss of approximately $23 million from the redemption of the first and refunding mortgage bonds will be deferred over the life of the 5.30% first and refunding mortgage bond issuance. Duke Energy also issued $300 million of 4.20% senior unsecured notes due in 2008, and $250 million of senior unsecured floating rate notes (based on the three-month LIBOR plus 0.45%) due in 2005. The net proceeds from the note issuances were used for general corporate purposes, including the repayment of commercial paper.

 

During 2003, PanEnergy Corp (PanEnergy), a wholly owned subsidiary of Duke Energy, called $328 million of 7.75% bonds due in 2022. The bonds were redeemed at 102% of their aggregate principal amount. The pre-tax loss of approximately $13 million on the early extinguishment of the debt was recorded as Interest Expense in the Consolidated Statements of Operations.

 

In June 2003, prior to the implementation of SFAS No. 150, Duke Capital redeemed $250 million of its 7.375% trust preferred securities due in 2038. The redemption price for this issuance was approximately $250 million, and an approximate loss of $8 million on the early extinguishment of the trust preferred securities was recorded as Dividends and Premiums on Redemption of Preferred and Preference Stock in the Consolidated Statements of Operations. In December 2003, subsequent to the implementation of SFAS No. 150, Duke Capital redeemed $350 million of its 7.375% trust preferred securities due in 2038. The redemption price for this issuance was approximately $350 million, and an approximate loss of $10 million on the early extinguishment of the trust preferred securities was recorded as Interest Expense in the Consolidated Statements of Operations.

 

During 2003, $1,000 million of commercial paper that had been included in Long-term Debt on the December 31, 2002 Consolidated Balance Sheet was reclassified as Notes Payable and Commercial Paper. This reclassification reflects Duke Energy’s intention to no longer maintain a significant outstanding long-term portion of commercial paper. As of December 31, 2003, $150 million of commercial paper was included in Long-term Debt.

 

63


Table of Contents

Also, in 2003, as a result of International Energy’s Australian operations being classified as discontinued operations, $883 million of debt related to those operations was reclassified from Notes Payable and Commercial Paper and Long-term Debt to Current and Non-Current Liabilities Associated with Assets Held for Sale on the December 31, 2003 Consolidated Balance Sheet. For additional information about discontinued operations see Note 12 to the Consolidated Financial Statements.

 

In February 2004, Duke Capital remarketed $875 million of its 5.87% senior notes due in 2006. As a result of the remarketing, the interest rate on the notes was reset to 4.302%. The remarketing was required under the terms of the Equity Units originally issued by Duke Energy in March 2001. Proceeds from the remarketed senior notes were used to purchase U.S. Treasury securities being held by a collateral agent to satisfy the forward stock purchase contracts component of the Equity Units. In May 2004, Duke Energy intends to receive $875 million from the collateral agent, and to issue approximately 22.5 million shares of Duke Energy common stock pursuant to the forward stock purchase contracts. Additionally, in February 2004, Duke Capital issued $200 million of 4.37% senior unsecured notes due in 2009 and $288 million of 5.50% senior unsecured notes due in 2014 in exchange for $475 million of the principal amount of the remarketed senior notes. After the exchange, $400 million of the principal amount of the remarketed senior notes remained outstanding.

 

Also, in February 2004, Duke Energy announced that on March 26, 2004, it will redeem the entire issue of 7.20% Duke Energy debt to an affiliate due in 2037. The redemption price will be approximately $360 million, and the redemption is not anticipated to have a material impact on Duke Energy’s Consolidated Statements of Operations.

 

For additional information on subsequent debt issuances and redemptions see Subsequent Events section.

 

For additional information about Duke Energy’s financing activities, and the impact of the 2003 adoption of SFAS No. 150 and FIN 46 (Revised December 2003) (FIN 46R), “Consolidation of Variable Interest Entities—An Interpretation of ARB No. 51,” see Notes 14, 15 and 16 to the Consolidated Financial Statements.

 

Available Credit Facilities and Restrictive Debt Covenants.    During 2003, Duke Energy, Duke Capital, Westcoast, Union Gas, DEFS and Duke Australia Finance Pty Ltd. (a wholly owned subsidiary of Duke Energy) replaced portions of their expiring credit facilities, thereby reducing the total amount of credit facilities available by approximately $2.2 billion. The majority of the credit facilities support commercial paper programs. The issuance of commercial paper, letters of credit and other borrowings reduces the amount available under the credit facilities.

 

Duke Energy’s credit agreements contain various financial and other covenants. Failure to meet those covenants beyond applicable grace periods could result in acceleration of due dates of certain borrowings and/or termination of the agreements. As of December 31, 2003, Duke Energy was in compliance with those covenants. In addition, certain of the agreements contain cross-acceleration provisions that may allow for acceleration of payments or termination of the agreements upon: (1) nonpayment or (2) acceleration of other significant indebtedness of the applicable borrower or certain of its subsidiaries. None of the credit agreements contain material adverse change clauses or any covenants based upon credit ratings.

 

For information on Duke Energy’s credit facilities as of December 31, 2003, see Note 14 to the Consolidated Financial Statements.

 

Duke Energy has approximately $2,900 million of credit facilities which expire in 2004. It is Duke Energy’s intent to resyndicate less than the total $2,900 million of expiring credit facilities.

 

Credit Ratings.    In March 2003, Moody’s Investors Service (Moody’s) placed its long-term and short-term ratings of Duke Energy, Duke Capital and DEFS, and its long-term ratings of Texas Eastern and PanEnergy, on Review for Potential Downgrade. In June 2003, Moody’s lowered its long-term rating of Duke Energy, its long-term and short-term ratings of Duke Capital, and its long-term ratings of Texas Eastern and PanEnergy one

 

64


Table of Contents

ratings level. Moody’s actions were prompted by concerns regarding leverage ratios and cash flow coverage metrics at Duke Energy, and uncertainties associated with cash flow contributions from DENA and Duke Energy International, LLC. Moody’s concluded its actions by placing Duke Energy, Duke Capital, Texas Eastern and PanEnergy on Stable Outlook. In September 2003, Moody’s confirmed its long and short-term ratings of DEFS and placed DEFS on Stable Outlook, concluding its Review for Potential Downgrade.

 

In June 2003, S&P lowered its long-term ratings of Duke Energy, Duke Capital and its subsidiaries (with the exception of Maritimes & Northeast Pipeline, LLC and Maritimes & Northeast Pipeline, LP (collectively, M&N Pipeline) and DEFS) one ratings level. In addition, S&P lowered its Canadian commercial paper ratings of Westcoast and Union Gas one ratings level. S&P’s actions were based on concern about Duke Energy’s ability to strengthen its financial profile during the remainder of 2003 and in 2004, and its ability to absorb any further weakening in operating cash flows, while still meeting its debt reduction targets. S&P concluded its actions by leaving Duke Energy and its subsidiaries, excluding M&N Pipeline and DEFS, on Negative Outlook. In February 2004, S&P again lowered its long-term ratings of Duke Energy and its subsidiaries, with the exception M&N Pipeline, DEFS and DETM one ratings level. S&P’s actions were based upon Duke Energy’s weaker than anticipated financial performance in 2003 and the execution risk associated with Duke Energy’s 2004 debt reduction plans. Additionally, S&P noted that Duke Energy’s continuation of trading and marketing activities around merchant generation assets will continue to expose Duke Energy to market risk and the need to dedicate material liquidity to support such activities. At the conclusion of S&P’s actions, Duke Energy, Duke Capital and its subsidiaries all have a Stable Outlook, with the exception of DETM, which remained on Negative Outlook until July 9, 2004 when it was upgraded to stable.

 

The following table summarizes the March 1, 2004 credit ratings from the rating agencies, retained by Duke Energy to rate its securities, its principal funding subsidiaries and its trading and marketing subsidiary DETM.

 

Credit Ratings Summary as of March 1, 2004

 

     Standard
and
Poor’s


  

Moody’s

Investor Service


   Dominion Bond
Rating Service
(DBRS)


Duke Energy(a)

   BBB    Baa1    Not Applicable

Duke Capital LLC(a)

   BBB-    Baa3    Not Applicable

Duke Energy Field Services(a)

   BBB    Baa2    Not Applicable

Texas Eastern Transmission, LP(a)

   BBB    Baa2    Not Applicable

Westcoast Energy Inc.(a)

   BBB    Not applicable    A(low)

Union Gas Limited(a)

   BBB    Not applicable    A

Maritimes & Northeast Pipeline, LLC(b)

   A    A1    A(d)

Maritimes & Northeast Pipeline, LP(b)

   A    A1    A

Duke Energy Trading and Marketing, LLC(c)

   BBB-    Not applicable    Not applicable

(a) Represents senior unsecured credit rating
(b)   Represents senior secured credit rating
(c)   Represents corporate credit rating
(d)   In August 2003, DBRS initiated a rating on Maritimes & Northeast Pipeline, LLC.

 

Duke Energy’s credit ratings are dependent on, among other factors, the ability to generate sufficient cash to fund Duke Energy’s capital and investment expenditures and dividends, while strengthening the balance sheet through debt reductions. If, as a result of market conditions or other factors affecting Duke Energy’s business, Duke Energy is unable to execute its business plan or if its earnings outlook materially deteriorates, Duke Energy’s ratings could be further affected.

 

Duke Energy and its subsidiaries are required to post collateral under certain trading and marketing and other contracts. Typically, the amount of the collateral is dependent upon Duke Energy’s economic position at

 

65


Table of Contents

points in time during the life of a contract and the credit rating of the subsidiary obligated under the collateral agreement. Business activity by DENA generates the majority of Duke Energy’s collateral requirements. DENA frequently transacts through DETM or Duke Energy Marketing America, a wholly owned subsidiary of Duke Capital.

 

A reduction in DETM’s credit rating to below investment grade as of December 31, 2003 would have resulted in Duke Capital posting additional collateral of up to approximately $220 million. Additionally, in the event of a reduction in DETM’s credit rating to below investment grade, collateral agreements may require the segregation of cash held as collateral to be placed in escrow. As of December 31, 2003, Duke Capital would have been required to escrow approximately $150 million of such cash collateral held if DETM’s credit rating had been reduced to below investment grade. Amounts above reflect Duke Energy’s 60% ownership of DETM and the allocation of collateral to DENA for contracts executed by DETM on its behalf.

 

A reduction in the credit rating of Duke Capital to below investment grade as of December 31, 2003 would have resulted in Duke Capital posting additional collateral of up to approximately $510 million. The amount of cash held as collateral that would have been required to be segregated into escrow due to a Duke Capital downgrade to below investment grade was less than $10 million. Additionally, in the event of a reduction in Duke Capital’s credit rating to below investment grade, certain interest rate and foreign exchange swap agreements may require settlement payments due to the termination of the agreements. As of December 31, 2003, Duke Capital could have been required to pay up to $100 million in such settlement payments if Duke Capital’s credit rating had been reduced to below investment grade. Duke Capital would fund any additional collateral requirements through a combination of cash on hand and the use of credit facilities.

 

If credit ratings for Duke Energy or its affiliates fall below investment grade there is likely to be a negative impact on its working capital and terms of trade that is not possible to quantify fully in addition to the posting of additional collateral and segregation of cash described above.

 

Acceleration Clauses.    Duke Energy may be required to repay certain debt should its credit ratings fall to a certain level at S&P or Moody’s. As of December 31, 2003, Duke Energy had $19 million of senior unsecured notes which mature serially through 2012 that may be required to be repaid if Duke Energy’s senior unsecured debt ratings fall below BBB- at S&P or Baa3 at Moody’s, and $30 million of senior unsecured notes which mature serially through 2016 that may be required to be repaid if Duke Energy’s senior unsecured debt ratings fall below BBB at S&P or Baa2 at Moody’s. As of March 1, 2004, Duke Energy’s senior unsecured credit rating was BBB at S&P and Baa1 at Moody’s.

 

Other Financing Matters.    As of December 31, 2003, Duke Energy and its subsidiaries had effective SEC shelf registrations for up to $1,950 million in gross proceeds from debt and other securities. Subsequent to December 31, 2003, these SEC shelf registrations were reduced by $488 million as a result of the senior unsecured notes issued by Duke Capital in February 2004. Additionally, as of December 31, 2003, Duke Energy had access to 700 million Canadian dollars (U.S. $542 million) available under Canadian shelf registrations for issuances in the Canadian market. A shelf registration is effective in Canada for a 25-month period. Of the total amount available under Canadian shelf registrations, 200 million Canadian dollars will expire in June 2004 and 500 million Canadian dollars will expire in November 2005.

 

Duke Energy’s Board of Directors adopted a dividend policy in 2000 that maintains dividends at the current quarterly rate of $0.275 per share, subject to the discretion of the Board of Directors. Duke Energy has paid quarterly cash dividends for 77 consecutive years. Dividends on common and preferred stocks in 2004 are expected to be paid on March 16, June 16, September 16 and December 16, subject to the discretion of the Board of Directors.

 

Duke Energy’s InvestorDirect Choice Plan allows investors to reinvest dividends in common stock and to purchase common stock directly from Duke Energy. Issuances under this plan were $111 million in 2003, $105 million in 2002 and $100 million in 2001.

 

66


Table of Contents

Duke Energy also sponsors employee savings plans that cover substantially all employees. Issuances of common stock under these plans were $156 million in 2003, $188 million in 2002 and $170 million in 2001. Duke Energy also issues authorized but unissued shares of its common stock to meet other employee benefit requirements. Issuances of common stock to meet other employee benefit requirements were approximately $20 million for 2003, approximately $50 million for 2002 and approximately $60 million for 2001. This practice is expected to continue in 2004. (See Notes 20 and 21 to the Consolidated Financial Statements for additional information on stock-based compensation and employee benefit plans.)

 

Off-Balance Sheet Arrangements

 

Duke Energy and certain of its subsidiaries enter into guarantee arrangements in the normal course of business to facilitate commercial transactions with third parties. These arrangements include financial and performance guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications. These arrangements are largely entered into by Duke Capital. See Note 18 to the Consolidated Financial Statements, “Guarantees and Indemnifications,” for further details of the guarantee arrangements.

 

Most of the guarantee arrangements entered into by Duke Energy enhance the credit standing of certain subsidiaries, non-consolidated entities or less than wholly-owned entities, enabling them to conduct business. As such, these guarantee arrangements involve elements of performance and credit risk, which are not included on the Consolidated Balance Sheets. The possibility of Duke Energy or Duke Capital having to honor its contingencies is largely dependent upon the future operations of the subsidiaries, investees and other third parties, or the occurrence of certain future events.

 

Issuance of these guarantee arrangements is not required for the majority of Duke Energy’s operations. Thus, if Duke Energy discontinued issuing these guarantee arrangements, there would not be a material impact to the consolidated results of operations, cash flows or financial position.

 

As discussed in Note 1 to the Consolidated Financial Statements, “Summary of Significant Accounting Policies,” Duke Energy has a variable interest in, but is not the primary beneficiary of, Duke COGEMA Stone & Webster, LLC (DCS) due to certain guarantee obligations as discussed in Note 18, “Guarantees and Indemnifications.” This guarantee obligation is an off-balance sheet arrangement. Duke Energy’s maximum exposure to loss as a result of its variable interest in DCS cannot be quantified.

 

Duke Energy does not have any material off-balance sheet financing entities or structures, except for normal operating lease arrangements and guarantee arrangements. For additional information on these commitments, see Notes 17 and 18 to the Consolidated Financial Statements.

 

Contractual Obligations

 

Duke Energy enters into contracts that require payment of cash at certain specified periods, based on certain specified minimum quantities and prices. The following table summarizes Duke Energy’s contractual cash obligations for each of the periods presented. The table below excludes all amounts classified as current liabilities on the Consolidated Balance Sheets, other than current maturities of long-term debt. The majority of current liabilities on the Consolidated Balance Sheets will be paid in cash in 2004.

 

67


Table of Contents

Contractual Obligations as of December 31, 2003

 

     Payments Due By Period

     Total

  

Less than 1
year

(2004)


   2-3 Years
(2005 &
2006)


   4-5 Years
(2007 &
2008)


   More than
5 Years
(Beyond
2008)


     (in millions)

Long-term debt(a)

   $ 34,922    $ 2,484    $ 7,460    $ 3,739    $ 21,239

Capital leases(a)

     367      15      193      36      123

Operating leases(b)

     508      98      127      76      207

Purchase Obligations:

                                  

Firm capacity payments(c)

     2,917      444      560      444      1,469

Energy commodity contracts(d)

     10,571      5,221      3,531      958      861

Other purchase obligations(e)

     4,561      1,120      1,264      376      1,801

Other long-term liabilities on the Consolidated Balance Sheets(f)

     544      133      212      199      —  
    

  

  

  

  

Total contractual cash obligations

   $ 54,390    $ 9,515    $ 13,347    $ 5,828    $ 25,700
    

  

  

  

  


(a)   See Note 14 to the Consolidated Financial Statements. Amount also includes interest payments over life of debt.
(b)   See Note 17 to the Consolidated Financial Statements.
(c)   Includes firm capacity payments that provide Duke Energy with uninterrupted firm access to natural gas transportation and storage, electricity transmission capacity, refining capacity and the option to convert natural gas to electricity at third-party owned facilities (tolling arrangements) in some natural gas and power locations throughout North America. Also includes firm capacity payments under electric power agreements entered into to meet Franchised Electric’s native load requirements.
(d)   Includes contractual obligations to purchase physical quantities of power, natural gas and NGLs. Amount includes certain normal purchases, energy derivates and hedges per SFAS No. 133. For contracts where the price paid is based on an index, the amount is based on forward market prices at December 31, 2003. For certain of these amounts, Duke Energy may net settle rather than paying cash. Amount excludes contracts to purchase commodities that do not require delivery of physical quantities and also are expected to net settle. The amounts presented for this line item have been revised from the originally presented total of $15, 923 million to adjust for amounts related to certain intercompany contracts that were included in the amount previously disclosed.
(e)   Includes purchase commitments for coal, nuclear fuel supply contracts, outsourcing of certain real estate services, contracts for software, telephone, data and consulting or advisory services. Amount also includes contractual obligations for engineering, procurement and construction costs for nuclear plant refurbishments, environmental projects on fossil facilities, pipeline and real estate projects, and major maintenance of certain merchant plants. Amount excludes certain open purchase orders for services that are provided on demand, and the timing of the purchase can not be determined.
(f)   Includes expected retirement plan contributions for 2004 (see Note 21 to the Consolidated Financial Statements), certain executive benefits, Department of Energy assessment fee (see Note 4 to the Consolidated Financial Statements), and asset retirement obligations which are contractually committed and contributions to the nuclear decommissioning trust fund (see Note 7 to the Consolidated Financial Statements). Duke Energy has not determined these amounts beyond 2008. The majority of asset retirement obligations is not yet contractually committed, and thus is excluded. Amount excludes reserves for litigation, environmental remediation, asbestos-related injuries and damages claims and self-insurance claims (see Note 17 to the Consolidated Financial Statements) because Duke Energy is uncertain as to the timing of when cash payments will be required. Additionally, amount excludes annual insurance premiums that are necessary to operate the business, including nuclear insurance (see Note 17 to the Consolidated Financial Statements), funding of other post-employment benefits (see Note 21 to the Consolidated Financial Statements) and regulatory credits (see Note 4 to the Consolidated Financial Statements) because the amount and timing of the cash payments are uncertain. Also amount excludes Deferred Income Taxes and Investment Tax Credits on the Consolidated Balance Sheets since cash payments for income taxes are determined based primarily on taxable income for each discrete fiscal year. Liabilities Associated with Assets Held for Sale (see Note 12 to the Consolidated Financial Statements) are also excluded as Duke Energy expects these liabilities will be assumed by the buyer upon sale of the assets.

 

68


Table of Contents

Quantitative and Qualitative Disclosures About Market Risk

 

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 Executive Committee is responsible for the overall approval of market risk management policies and the delegation of approval and authorization levels. The Executive 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 governance of managing credit risk and commodity price risk, including monitoring exposure limits.

 

See Critical Accounting Policies—Risk Management Activities and Revenue Recognition—Trading and Marketing Revenues for further discussion of the accounting for derivative contracts.

 

Commodity Price Risk

 

Duke Energy is exposed to the impact of market fluctuations in the prices of natural gas, electricity, NGLs and other energy-related products marketed and purchased as a result of its ownership of energy related assets, remaining proprietary trading contracts, and interests in structured contracts classified as undesignated. 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. (See Notes 1 and 8 to the Consolidated Financial Statements.)

 

Hedging Strategies.    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 mitigate the effect of such fluctuations on operations. 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.

 

To the extent that the hedge instrument is effective in offsetting the transaction being hedged, there is no impact to the Consolidated Statements of Operations. Accordingly, assumptions and valuation techniques for these contracts have no impact on reported earnings prior to settlement. 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. (See Notes 1 and 8 to the Consolidated Financial Statements.)

 

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. For contracts qualifying for the scope exception, no recognition of the contract’s fair value in the Consolidated Financial Statements is required until settlement of the contract. Normal purchases and sales contracts are generally subject to collateral requirements under the same credit risk reduction guidelines used for other contracts. Duke Energy has applied this scope exception for certain contracts involving the purchase and sale of electricity at fixed prices in future periods.

 

Income recognition and realization related to normal purchases and normal sales contracts generally coincide with the physical delivery of power. However, Duke Energy’s decision to sell DENA’s merchant plants in the Southeast U.S. and reduce DENA’s interest in deferred plants required the reassessment of all associated derivatives, including normal purchases and normal sales. This required an accounting change from the accrual method of accounting to the mark-to-market method of accounting and introduced substantial unrealized losses not previously recognized in the Consolidated Financial Statements.

 

69


Table of Contents

Based upon the current net open positions for DENA’s commodity derivatives recorded using the mark-to-market accounting method which includes the trading and undesignated portfolios, 2004 EBIT at DENA would change by approximately $25 million if forward power and natural gas prices were to increase or decrease over the entire position term in tandem by $1.00 per megawatt hour and $0.15 per million Btu’s, respectively.

 

Based on a sensitivity analysis as of December 31, 2003, it was estimated that a difference of one cent per gallon in the average price of NGLs in 2004 would have a corresponding effect on operating income of approximately $6 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, 2002 estimated that operating income would have changed by approximately $7 million in 2003. The effect on operating income for 2004 or 2003 was also not expected to be material as of December 31, 2003 or 2002 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.

 

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 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 commodity derivatives recorded using the MTM accounting method are shown in the following table.

 

Daily Earnings at Risk (in millions)

 

     Period Ending
One-Day Impact
on Operating
Income for
2003(a)


   Estimated
Average One-
Day Impact on
Operating
Income for
2003(a)


   Estimated
Average One-
Day Impact on
Operating
Income for
2002


   High One-Day
Impact on Operating
Income for 2003(a)


   Low One-Day
Impact on Operating
Income for 2003(a)


Calculated DER

   $ 20    $ 8    $ 14    $ 32    $ 2

(a)   These figures include all trading contracts and all undesignated commodity contracts as described in the notes to the consolidated financial statements.

 

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 fair value of trading contracts by commodity and settlement method as of December 31, 2003.

 

70


Table of Contents

Commodity Type

 

     Fair Value
(in millions)


 

Financial gas and power contracts

   $ 498  

Physical power contracts

     (280 )

Physical natural gas contracts

     (37 )

Refined products/NGL contracts

     (4 )
    


Total fair value of contracts

   $ 177  
    


 

See Note 8 to the Consolidated Financial Statements for the Changes in Fair Value of Trading Contracts and Fair Value of Trading Contracts by source and maturity date.

 

Credit Risk

 

Credit risk represents the loss that Duke Energy would incur if a counterparty fails to perform under its contractual obligations. To reduce credit exposure, Duke Energy seeks to enter into payment netting agreements with counterparties that permit Duke Energy to offset receivables and payables with such counterparties. Duke Energy attempts to further reduce credit risk with certain counterparties by entering into agreements that enable Duke Energy to obtain collateral or to terminate or reset the terms of transactions after specified time periods or upon the occurrence of credit-related events. Duke Energy may, at times, use credit derivatives or other structures and techniques to provide for third-party credit enhancement of Duke Energy’s counterparties’ obligations.

 

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 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.

 

The following table represents Duke Energy’s distribution of unsecured credit exposure with the largest 30 enterprise credit exposures at December 31, 2003. These credit exposures are aggregated by ultimate parent company, include on and off balance sheet exposures, are presented net of collateral, and take into account contractual netting rights.

 

Distribution of Largest 30 Enterprise Credit Exposures

As of December 31, 2003

 

     % of Total

 

Investment Grade—Externally Rated

   74 %

Non-Investment Grade—Externally Rated

   11 %

Investment Grade—Internally Rated

   7 %

Non-Investment Grade—Internally Rated

   8 %
    

Total

   100 %
    

 

“Externally Rated” represents enterprise relationships that have published ratings from at least one major credit rating agency. “Internally Rated” represents those relationships which have no rating by a major credit rating agency. For those relationships, Duke Energy utilizes appropriate rating methodologies and credit scoring

 

71


Table of Contents

models to develop a public rating equivalent. The total of the unsecured credit exposure included in the table above represents approximately 29% of the gross fair value of Duke Energy’s Receivables and Unrealized Gains on Mark-to-Market and Hedging Transactions on the Consolidated Balance Sheet at December 31, 2003.

 

Duke Energy had no net exposure to any one customer that represented greater than 10% of the gross fair value of trade accounts receivable, energy trading assets and derivative assets at December 31, 2003. Based on Duke Energy’s policies for managing credit risk, its exposures and its credit and other reserves, Duke Energy does not anticipate a materially adverse effect on its financial position or results of operations as a result of non-performance by any counterparty.

 

Duke Energy’s industry has historically operated under negotiated credit lines for physical delivery contracts. Duke Energy frequently uses master collateral agreements to mitigate certain credit exposures, primarily in its marketing and trading operations. The collateral agreements provide for a counterparty to post cash or letters of credit to the exposed party for exposure in excess of an 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.

 

Duke Energy also obtains cash or letters of credit from customers to provide credit support outside of collateral agreements, where appropriate, based on its 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 terms of the collateral agreement and the nature of the underlying exposure 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 reductions in Duke Energy’s unsecured thresholds granted by counterparties, with Duke Energy posting more collateral to 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 and its affiliates. (See Liquidity and Capital Resources—Financing Cash Flows and Liquidity for additional discussion of downgrades.)

 

The change in market value of New York Mercantile Exchange-traded futures and options contracts requires daily cash settlement in margin accounts with brokers.

 

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. (See Note 17 to the Consolidated Financial Statements.)

 

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.

 

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

 

72


Table of Contents

variable-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, 8, 14, and 15 to the Consolidated Financial Statements.)

 

Based on a sensitivity analysis as of December 31, 2003, it was estimated that if market interest rates average 1% higher (lower) in 2004 than in 2003, interest expense, net of offsetting impacts in interest income, would increase (decrease) by approximately $34 million. Comparatively, based on a sensitivity analysis as of December 31, 2002, had interest rates averaged 1% higher (lower) in 2003 than in 2002, it was estimated that interest expense would have increased (decreased) by approximately $55 million. These amounts include the effects of interest rate hedges and invested cash and were determined by considering the impact of the hypothetical interest rates on the variable-rate securities outstanding as of December 31, 2003 and 2002. The decrease in interest rate sensitivity was primarily due to the decrease in outstanding variable-rate commercial paper and increase in invested cash. 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 Nuclear Regulatory Commission (NRC), to fund certain costs of nuclear decommissioning. (See Note 17 to the Consolidated Financial Statements.) As of December 31, 2003 and 2002, 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 changes in the equity market since 2000. As a result, at September 30, 2003 (Duke Energy’s measurement date), Duke Energy’s pension plan obligation, excluding Westcoast, exceeded the value of the plan assets by $170 million and Duke Energy was therefore required to reduce the minimum liability as prescribed by SFAS No. 87 and SFAS No. 132, “Employers’ Disclosures about Pensions and Postretirement Benefits,” by approximately $83 million to $689 million. The $689 million pension liability was a combination of the $170 million excess obligation and $519 million in pre-paid pension assets. The net pension liability as of December 31, 2003 is included in Other Deferred Credits and Other Liabilities on the Consolidated Balance Sheets. The liability was recorded as a reduction to Accumulated Other Comprehensive Income (AOCI), net of income taxes, and did not affect net income for 2003. When the fair value of the plan assets exceeds the accumulated benefit obligations on the measurement date, the recorded liability will be reduced and AOCI will be restored in the Consolidated Balance Sheets. Also, Westcoast has a $36 million minimum pension liability recorded as of December 31, 2003.

 

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.

 

73


Table of Contents

As of December 31, 2003, Duke Energy’s primary foreign currency rate exposures were the Canadian dollar and the Brazilian real. A 10% devaluation in the currency exchange rate in all of Duke Energy’s exposure currencies would result in an estimated net loss on the translation of local currency earnings of $16 million to Duke Energy’s Consolidated Statements of Operations. The Consolidated Balance Sheets would be negatively impacted by approximately $480 million currency translation through the cumulative translation adjustment in AOCI.

 

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.

 

CURRENT ISSUES

 

Electric Competition

 

Wholesale Competition.    The Energy Policy Act of 1992 and the Federal Energy Regulatory Commission (FERC’s) subsequent rulemaking activities opened the wholesale energy market to competition. Open-access transmission for wholesale customers, as defined by the FERC’s rules, provides energy suppliers, including Duke Energy, with opportunities to sell and deliver capacity and energy at market-based prices. From the FERC’s open-access rule, Franchised Electric obtained the rights to sell capacity and energy at market-based rates from its own assets, which also allows Franchised Electric to purchase, at attractive rates, a portion of its capacity and energy requirements resulting in lower overall costs to customers. Open access also provides Franchised Electric’s existing wholesale customers with competitive opportunities to seek other suppliers for their capacity and energy requirements.

 

In 1999 and 2000, the FERC issued its Order 2000 and Order 2000-A regarding Regional Transmission Organizations (RTOs). These orders set minimum characteristics and functions RTOs must meet, including independent authority to establish the terms and conditions of transmission service over the facilities they control. The orders provide for an open and flexible RTO structure to meet the needs of the market, and for the possibility of incentive ratemaking and other benefits for transmission owners that participate. The FERC proposes to have RTOs or other independent transmission providers operate transmission systems in all regions of the country.

 

As a result of these rulemakings, Duke Power and the franchised electric units of two other investor-owned utilities, Carolina Power & Light Company and South Carolina Electric & Gas Company, planned to establish GridSouth Transco, LLC (GridSouth), as an RTO responsible for the functional control of the companies’ combined transmission systems. As of December 31, 2003, Duke Energy had invested $41 million in GridSouth, including carrying costs calculated through December 31, 2002. This amount is included in Other Regulatory Assets and Deferred Debits on the Consolidated Balance Sheets. The sponsors expected that GridSouth would be

 

74


Table of Contents

substantially operational by the FERC’s Order 2000 “deadline” date of December 15, 2001. However, in July 2001 the FERC ordered GridSouth and other utilities in the Southeast to join in a mediation to negotiate terms of a southeastern RTO. It does not appear that the FERC will issue an order specifically based on that proceeding. In 2002, the GridSouth sponsors withdrew their applications to the NCUC and the PSCSC for approval of the transfer of functional control of their electric transmission assets to GridSouth, and announced that development of the GridSouth implementation project had been suspended until the sponsors have an opportunity to further consider regulatory circumstances. Duke Energy believes that more open wholesale electric markets will at some point provide benefits to consumers and other market participants. Duke Energy continues to examine options relative to RTOs in light of the existing complex regulatory environment. Management expects it will recover its investment in GridSouth.

 

Today, the pace of electricity restructuring varies quite substantially across the U.S. Duke Energy is actively engaged in most markets, particularly those in which it owns assets. Duke Energy continues to believe that wholesale competitive markets bring added value to consumers; therefore, Duke Energy supports the continued restructuring of wholesale electric markets through a disciplined, prudent transition to regional markets. Transforming the current regulated industry into efficient, competitive wholesale and retail electric markets is a complex undertaking, and will continue to require careful planning and coordination between federal and state regulators and other key stakeholders. Duke Energy intends to continue to work with customers, legislators and regulators to address all the important issues. Management currently cannot predict the impact, if any, of these competitive forces on future consolidated results of operations, cash flows or financial position.

 

Natural Gas Competition

 

The FERC is continually proposing and implementing new rules and regulations affecting those segments of the natural gas industry, most notably interstate natural gas transmission companies, which remain subject to the FERC’s jurisdiction. These initiatives may also affect the intrastate transportation of gas under certain circumstances. The stated purpose of these regulatory changes is to promote competition among the various sectors of the natural gas industry and these initiatives generally reflect more light-handed regulation of the natural gas industry.

 

Retail Competition.    Changes in regulation to allow retail competition could affect Duke Energy’s natural gas transportation contracts with local natural gas distribution companies. Since natural gas retail deregulation is in the very early stages of development, management believes the effects of this matter will have no material adverse effect on Duke Energy’s future consolidated results of operations, cash flows or financial position.

 

Other Current Issues

 

For information on other current issues related to Duke Energy, see the following Notes to the Consolidated Financial Statements: Note 4, Notices of Proposed Rulemaking section; Note 17, Environmental and Litigation sections.

 

New Accounting Standards

 

SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity.”    In May 2003, the FASB issued SFAS No. 150 which establishes standards for classification and measurement of certain financial instruments with characteristics of both liabilities and equities. Under SFAS No. 150, such financial instruments are required to be classified as liabilities in the statement of financial position. The financial instruments affected include mandatorily redeemable stock, certain financial instruments that require or may require the issuer to buy back some of its shares in exchange for cash or other assets, and certain obligations that can be settled with shares of stock. SFAS No. 150 is effective for all financial instruments entered into or modified after May 31, 2003 and has been applied to Duke Energy’s existing financial instruments beginning on July 1, 2003.

 

75


Table of Contents

As a result of the adoption of SFAS No. 150, Long-term Debt included trust preferred securities which had been previously included on the Consolidated Balance Sheet as Guaranteed Preferred Beneficial Interests in Subordinated Notes of Duke Energy or Subsidiaries. However, upon the adoption of the provisions of FIN 46R as of December 31, 2003, which required deconsolidation of the trust subsidiary, this long-term debt of $876 million has been reclassified as an affiliate debt balance in the Consolidated Balance Sheet. In addition, Long-term Debt, including current maturities, as of December 31, 2003 also included $25 million of preferred stock with sinking fund requirements, which had been previously included on the Consolidated Balance Sheet as Preferred and Preference Stock with Sinking Fund Requirements. In addition, $23 million of DEFS’ preferred members’ interest held by ConocoPhillips, which had previously been included on the Consolidated Balance Sheets as Minority Interests was reclassified to Long-term Debt. As of December 31, 2003, DEFS had redeemed all outstanding amounts of the preferred members’ interest. In accordance with the requirements of SFAS No. 150, prior period amounts have not been reclassified to be in conformity with the current presentation.

 

Duke Energy’s financial statements do not include any effects for the application of SFAS No. 150 to non-controlling interests in certain limited life entities, which are required to be liquidated or dissolved on a certain date, based on the decision of the FASB in November 2003 to defer these provisions indefinitely with the issuance of FASB Staff Position 150-3, “Effective Date, Disclosures, and Transition for Mandatorily Redeemable Financial Instruments of Certain Nonpublic Entities and Certain Mandatorily Redeemable Noncontrolling Interests under FASB Statement No. 150, Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity.” Duke Energy has a non-controlling interest in a limited life entity in Bolivia, whereby the entity is required to be liquidated 99 years after formation. Upon termination or liquidation of the entity in 2094, the remaining assets of the entity are to be sold, the liabilities liquidated and any remaining cash distributed to the owners based upon their ownership percentages. At December 31, 2003 the fair value of the entity’s non-controlling interest of approximately $40 million is approximately $5 million less than its carrying value. Duke Energy continues to evaluate the potential significance of these aspects of SFAS No. 150, but does not anticipate this will have a material impact on Duke Energy’s consolidated results of operations, cash flows or financial position. SFAS No. 150 continues to be interpreted by the FASB and it is possible that significant changes could be made by the FASB during such future deliberations. Therefore, Duke Energy is not able to conclude as to whether such future changes would be likely to materially affect the amounts already recorded and disclosed under the provisions of SFAS No. 150.

 

Revised SFAS No. 132, “Employers’ Disclosures about Pensions and Other Postretirement Benefits.”    In December 2003, the FASB revised the provisions of SFAS No. 132 to include additional disclosures related to defined benefit pension plans and other defined benefit postretirement plans, such as the following: (1) long-term rate of return on plan assets along with narrative discussion of basis for selecting the rate of return used; (2) information about plan assets for each major asset category (i.e. equity securities, debt securities, real estate, etc) along with the targeted allocation percentage of plan assets by each major asset category and the actual allocation percentage at the measurement date; (3) amount of benefit payments expected to be paid in each of the next five years and the following five year period, in the aggregate; (4) current best estimate of range of contributions expected to be made in following year; (5) the accumulated benefit obligation for defined benefit pension plans; and (6) disclosure of measurement date utilized. Additionally, interim reports require certain additional disclosures related to the components of net periodic pension cost recognized and amounts paid or expected to be paid to the plan in the current fiscal year, if materially different than amounts previously disclosed the provisions of revised SFAS No. 132 do not change the measurement or recognition provisions of defined benefit pension and postretirement plans as required by previous accounting standards. Except as discussed below, the provisions of revised SFAS No. 132 are effective for fiscal years ending after December 15, 2003 (December 31, 2003 for calendar-year entities) and all interim periods beginning after December 15, 2003 (March 31, 2004 for calendar-year entities). The disclosure provisions of estimated future benefit payments and information about foreign plans are effective for fiscal years ending after June 15, 2004 (December 31, 2004 for calendar-year entities). See Note 21 to the Consolidated Financial Statements for additional disclosures required as of December 31, 2003.

 

76


Table of Contents

FASB Interpretation No. 46 (FIN 46), “Consolidation of Variable Interest Entities.”    In January 2003, the FASB issued FIN 46 which requires the primary beneficiary of a variable interest entity’s activities to consolidate the variable interest entity. FIN 46 defines a variable interest entity as an entity in which the equity investors do not have substantive voting rights and there is not sufficient equity at risk for the entity to finance its activities without additional subordinated financial support. The primary beneficiary is the party that absorbs a majority of the expected losses and/or receives a majority of the expected residual returns of the variable interest entity’s activities. In December 2003, FIN 46 was revised with the issuance of FIN 46R, which supercedes and amends certain provisions of FIN 46. While FIN 46R retains many of the concepts and provisions of FIN 46, it also provides additional guidance related to the application of FIN 46, provides for certain additional scope exceptions, and incorporates several FASB Staff Positions issued related to the application of FIN 46.

 

The provisions of FIN 46 are immediately applicable to variable interest entities created, or interests in variable interest entities obtained, after January 31, 2003 and the provisions of FIN 46R are required to be applied to such entities, except for special-purpose entities, by the end of the first reporting period ending after March 15, 2004 (March 31, 2004 for calendar-year entities). For variable interest entities created, or interests in variable interest entities obtained, on or before January 31, 2003, FIN 46 or FIN 46R is required to be applied to special-purpose entities by the end of the first reporting period ending after December 15, 2003 (December 31, 2003 for calendar-year entities) and is required to be applied to all other non-special purpose entities by the end of the first reporting period ending after March 15, 2004 (March 31, 2004 for calendar-year entities). FIN 46 and FIN 46R may be applied prospectively with a cumulative-effect adjustment as of the date it is first applied, or by restating previously issued financial statements with a cumulative-effect adjustment as of the beginning of the first year restated. FIN 46 and FIN 46R also require certain disclosures of an entity’s relationship with variable interest entities.

 

Duke Energy has not identified any material variable interest entities created, or interests in variable entities obtained, after January 31, 2003 which require consolidation or disclosure under FIN 46 and continues to assess the existence of any interests in variable interest entities created on or prior to January 31, 2003. Duke Energy currently anticipates certain non-special purpose entities, previously accounted for under the equity method of accounting, will be consolidated by Duke Energy in the first quarter of 2004 under the provisions of FIN 46R. These entities, which are substantive entities, have total assets of approximately $225 million as of December 31, 2003 and total revenue of approximately $150 million for the year ended December 31, 2003. Duke Energy’s maximum exposure to loss as a result of its involvement with these entities is approximately $100 million, generally limited to Duke Energy’s investment and guarantee obligations in these entities, as of December 31, 2003. Duke Energy adopted the provisions of FIN 46R on December 31, 2003, related to its special-purpose entities consisting of the trust subsidiaries that have issued the trust preferred securities, as discussed in Note 15 to the Consolidated Financial Statements. Since Duke Energy is not the primary beneficiary of such trust subsidiaries, these entities have been deconsolidated in the accompanying Consolidated Financial Statements effective December 31, 2003. This deconsolidation resulted in Duke Energy reflecting affiliate debt to the trusts in Long-term Debt in the Consolidated Balance Sheets. Interest paid to the subsidiary trust will be classified as Interest Expense in the accompanying Consolidated Statements of Operations beginning January 1, 2004 consistent with the classification under SFAS No. 150. Additionally, Duke Energy has a significant variable interest in, but is not the primary beneficiary of, DCS due to certain guarantee obligations as discussed in Note 18 to the Consolidated Financial Statements. As further discussed in Note 18 to the Consolidated Financial Statements, Duke Energy’s maximum exposure to loss as a result of its variable interest in DCS cannot be quantified. Duke Energy continues to assess FIN 46R but does not anticipate that it will have a material impact on its consolidated results of operations, cash flows or financial position.

 

FASB Staff Position (FSP) FAS 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.”    In January 2004, the FASB staff issued FSP FAS 106-1, which allows a one-time election to defer accounting for the effects of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act), which became law in December 2003. The Act introduced a prescription drug benefit under Medicare as well as a federal subsidy to sponsors of retiree health

 

77


Table of Contents

care benefit plans. FSP FAS 106-1 allows a sponsor to defer recognizing the effects of the Act in accounting for its postretirement benefit plans under SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions” until further authoritative accounting guidance is issued. Duke Energy has a measurement date of September 30th for its SFAS No. 106 postretirement benefit plans and has elected to defer application of SFAS No. 106 to the provisions of the Act under the guidance given in FSP FAS 106-1. Therefore, the accumulated postretirement benefit obligation and net periodic postretirement benefit cost contained in Note 21 to the Consolidated Financial Statements do not reflect the effects of the Act. Specific authoritative guidance on the accounting for the federal subsidy is pending and such guidance, when issued, could require a change to previously reported information. Duke Energy is still reviewing the potential impacts of the Act on its postretirement benefit plans, but currently anticipates it will qualify for the federal subsidy under the Act.

 

Subsequent Events

 

On March 1, 2004, Duke Capital Corporation, a Delaware corporation which is a wholly owned subsidiary of Duke Energy, announced that it had changed its form of organization from a corporation to a Delaware limited liability company. The change in form of organization was effected by conversion pursuant to Section 266 of the General Corporation Law of the State of Delaware and Section 18-214 of the Delaware Limited Liability Company Act. Pursuant to the conversion, all rights and liabilities of Duke Capital Corporation vested in Duke Capital LLC, a Delaware limited liability company. This conversion will not have any effect on the Duke Energy consolidated results of operations or financial position.

 

In the second quarter of 2004, DEFS acquired gathering, processing and transmission assets in southeast New Mexico from ConocoPhillips for a total purchase price approximately $80 million, consisting of $74 million in cash and the assumption of approximately $6 million of liabilities.

 

On July 2, 2004, Duke Energy realigned certain subsidiaries resulting in all of its wholly owned merchant generation facilities being owned by a newly created entity, Duke Energy Americas, LLC (DEA), a directly wholly owned subsidiary of Duke Capital. DEA and Duke Capital are pass-through entities for US income tax purposes. As a result of these changes, Duke Capital will recognize a federal and state tax expense of approximately $900 million in the third quarter of 2004 from the elimination of the deferred tax assets that existed on its balance sheet prior to the July 2, 2004 reorganization. Correspondingly, Duke Energy, the parent of Duke Capital, will reflect, through consolidation, the elimination of the $900 million deferred tax asset at Duke Capital and the creation of a deferred tax asset of approximately $900 million on its balance sheet. Duke Energy will additionally recognize an approximate $45 million income tax benefit and corresponding deferred tax asset as a result of restating its deferred taxes to reflect a change in state tax rates. In future periods, as these deferred tax assets are converted into cash due to the realization of certain tax losses, Duke Energy intends to infuse the related cash flows back into Duke Capital. Most of these cash benefits result from tax losses arising from the sales of DENA’s Southeastern U.S generation assets and the Moapa facility.

 

Asset Sales

 

In January 2004, Duke Energy, through its wholly owned subsidiary Duke Energy Royal, LLC, agreed to sell its interest in six energy service agreements and Duke Energy Huntington Beach, LLC. In February 2004, DEFS entered into a purchase and sale agreement to sell certain gas gathering and processing plant assets in West Texas. Also in February 2004, DEM sold its 15-percent ownership interest in Caribbean Nitrogen Company. Additionally, during the first and second quarter of 2004, DENA sold turbines and surplus equipment. In total, all of these transactions resulted in cash proceeds of approximately $209 million and a net gain of approximately $14 million.

 

During the first and second quarter of 2004, DETM sold certain physical power contracts in which it held a liability position. As part of the sale, DETM paid a third party an immaterial amount, which approximated the carrying value of the contracts at December 31, 2003.

 

78


Table of Contents

In the first quarter of 2004, Duke Energy recorded a $238 million after-tax gain related to International Energy’s Asia Pacific power generation and natural transmission businesses. The estimated fair value, less costs to sell was classified as “held for sale” as of December 31, 2003. The gain recorded in the first quarter of 2004 restores the loss recorded during the fourth quarter of 2003. The December 31, 2003 estimated fair value was based upon third-party bids received by International Energy. During the first quarter, Duke Energy determined that it was likely a bid in excess of the originally determined fair value would be accepted. In April 2004, Duke Energy completed the sale of the Asia-Pacific businesses to Alinta Ltd. for a gross sales price of approximately $1.2 billion. This resulted in recording an additional $40 million after-tax gain in the second quarter. Duke Energy received approximately $390 million of cash proceeds, net of debt repayment of approximately $840 million of debt retired (as a non-cash financing activity) as part of the Asia-Pacific operations. The $840 million does not include approximately $50 million of Australian debt which has been placed in trust and fully funded in connection with the closing of the sale transaction and will be repaid in September 2004. This trust is included in the Consolidated Financial Statements as Duke Energy is the primary beneficiary of the trust and, therefore, is required to consolidate the trust under provisions of FIN 46. The Asia-Pacific debt had been classified as Current and Non-Current Liabilities Associated with Assets Held for Sale on the December 31, 2003 Consolidated Balance Sheet. All gains related to this transaction and the results of operations for these assets are included in Net Gain (Loss) on Dispositions, net of tax, within Discontinued Operations, in the 2004 Consolidated Statements of Operations.

 

On May 4, 2004 Duke Energy announced the sale of its merchant generation business in the southeastern United States to KGen Partners LLC (KGen). The sale transaction has obtained all required regulatory approvals and consents and closed on August 5, 2004. This transaction resulted in a cumulative pre-tax loss of approximately $367 million, of which approximately $360 million was recognized in the first quarter of 2004 to reduce the carrying value of those assets to their estimated fair values, while the remaining amount of the loss will be recognized by Duke Energy in the third quarter of 2004. Subsequent to the closing of the transaction, DENA will continue to provide certain transitional services and operating and maintenance services for the sold assets, including potential exercise of limited plant dispatch rights for a period not to exceed six months form the date of August 5, 2004. DENA anticipates recognizing the sale transaction in the third quarter of 2004, pending resolution of certain continuing involvement provisions.

 

In conjunction with the sale of DENA’s southeastern assets to KGen, Duke Energy arranged a letter of credit with a face amount of $120 million in favor of Georgia Power Company, to secure obligations of a KGen subsidiary under a seven-year power sales agreement, commencing in May 2005, under which KGen will provide power from its Murray facility to Georgia Power. Duke Energy is the primary obligor to the letter of credit provider, but KGen has an obligation to reimburse Duke Energy for any payments made by it under the letter of credit, as well as expenses incurred by Duke Energy in connection with the letter of credit. Duke Energy will operate the Murray facility under an operation and maintenance agreement with a KGen subsidiary.

 

As disclosed in Note 12 to the Consolidated Financial Statements, Subsequent Events, in Duke Energy’s Form 10-Q for June 30, 2003, Duke Energy announced the sale of a 25% undivided interest in the Duke Energy Vermillion facility. In May 2004, the sale of the 25% undivided interest in the Vermillion facility was completed for approximately $44 million. A loss on the sale of approximately $18 million was recorded in the third quarter of 2003. Duke Energy will continue to own the remaining 75% interest in the facility.

 

In May 2004, Duke Energy reached an agreement to sell its 30% equity interest in Compañia de Nitrógeno de Cantarell, S.A. de C.V., nitrogen production and delivery facility in the Bay of Campeche, Gulf of Mexico for approximately $60 million. Duke Energy recorded a non-cash charge of $13 million to Operation, Maintenance and Other expenses on the Consolidated Statements of Operations in the first quarter of 2004 in anticipation of this sale. The sale is expected to close in the third quarter of 2004.

 

In the second quarter of 2004, Duke Energy announced an agreement to sell one of DENA’s deferred facilities, Moapa, to Nevada Power Company for approximately $182 million in cash, with closing expected

 

79


Table of Contents

during the fourth quarter of 2004 pending regulatory approvals. The Moapa asset was classified as “held for sale” in the June 30, 2004 Consolidated Balance Sheet. This facility will not be reported in Discontinued Operations as, among other considerations, the facility never entered into operations and has no associated historical operating revenues or costs.

 

Debt and Financing Related Matters

 

In March 2004, Duke Energy redeemed the entire issue of 7.20% Duke Energy debt to an affiliate due in 2037 for approximately $350 million, in connection with the redemption of its Duke Energy Capital Trust I 7.20% Cumulative Quarterly Income Preferred Securities due 2037. As the securities were redeemed at par, security holders received $25 per each note held, plus accrued and unpaid distributions to the redemption date.

 

In April 2004, Duke Capital purchased $101 million of its outstanding notes in the open market. These purchases included $49 million of Duke Capital 5.50% senior notes due March 1, 2014 and $52 million of Duke Capital 4.37% senior notes due March 1, 2009. The securities were redeemed at the then current market price plus accrued interest.

 

In May 2004, Duke Energy redeemed Duke Energy Series C 6.60% Senior Notes due 2038, at a $200 million face value. As the securities were redeemed at par, security holders received $25 per each note held, plus accrued interest to the redemption date.

 

In May 2004, Duke Energy issued 22,449,000 shares of its common stock in the settlement of the forward purchase contract component of its Equity Units issued in March 2001. Duke Energy issued 35,000,000 Equity Units in March 2001 at $25 per unit. Under the terms of the contract, the Equity Unit holders were required to purchase common stock at a settlement rate based on the current market price of Duke Energy’s common stock at the time of settlement. The rate was 0.6414 shares of stock per Equity Unit.

 

In June 2004, Westcoast Energy, Inc. redeemed all remaining outstanding Cumulative Redeemable First Preferred Shares, Series 6. The Series 6 Shares were redeemed for 25.00 per share in Canadian dollars plus all accrued and unpaid dividends to the date of redemption for a total redemption amount of approximately 104 million Canadian dollars.

 

In June 2004, Duke Energy redeemed the entire issue of its 7.20% debt due to an affiliate in 2039 for approximately $250 million, in connection with the redemption of its Duke Energy Capital Trust II 7.20% Trust Preferred Securities. As the securities were redeemed at par, security holders received $25 per preferred security held, plus accrued and unpaid distributions to the redemption date.

 

In July 2004, Duke Energy announced that on August 31, 2004, it will redeem the entire issue of Duke Capital Financing Trust III 8 3/8% Trust Preferred Securities due August 31, 2029 with a face value of $250 million. As the securities are being redeemed at par, security holders will receive $25 per preferred security held, plus accrued and unpaid distributions to the redemption date. Additionally, Duke Energy plans to remarket $750 million of its 4.32% senior notes, due in 2006, underlying its 8.00% Equity Units on August 11, 2004. Proceeds from the remarketed notes will be held by a collateral agent and used to purchase U.S. Treasury securities to satisfy the forward stock purchase contract component of the Equity Units in November 2004.

 

Regulatory Matters

 

Bulk Power Marketing Profit Sharing.    On June 9, 2004, the NCUC approved Duke Energy’s proposal to share an amount equal to 50% of the North Carolina retail allocation of the profits from certain wholesale sales of bulk power from Duke Power generating units at market based rates (BPM Profits). Duke Energy also informed the NCUC that it would no longer include BPM Profits in calculating its North Carolina retail

 

80


Table of Contents

jurisdictional rate of return for its quarterly reports to the NCUC. As approved by the NCUC, the sharing arrangement provides for 50% of the North Carolina allocation of BPM Profits to be distributed through various assistance programs, up to a maximum of $5 million per year. Any amounts exceeding the maximum will be used to reduce rates for industrial customers in North Carolina.

 

On June 29, 2004, Duke Energy informed the PSCSC that it would no longer include BPM Profits in calculating its South Carolina retail jurisdictional rate of return for its quarterly reports to the PSCSC. Duke Energy proposed to establish an entity to receive 50% of the South Carolina allocable share of the BPM Profits to support public assistance programs, education programs to promote economic development, and grants to promote the attraction and retention of industrial customers. The PSCSC has not addressed the appropriateness of the proposed change in reporting BPM Profits. Duke Energy’s sharing proposal does not require PSCSC approval.

 

The sharing agreement in both states applies to BPM Profits from January 1, 2004 until the earlier of December 31, 2007, or the effective date of any rates approved by the respective commission after a general rate case. The 2004 year-to-date total of $27 million of shared profits was recorded as a $14 million decrease to revenues (for the portion related to reduced industrial customers rates) and a $13 million charge to expenses (for the portion related to donations to charitable, educational and economic development programs in North Carolina and South Carolina) in the second quarter of 2004.

 

For information on additional subsequent events related to debt and other financing matters refer to Financing Cash Flows and Liquidity—Significant Financing Activities and Other Financing Matters sections. For information on additional subsequent events related to Regulatory Matters refer to Note 4 to the Consolidated Financial Statements. For information on subsequent events related to litigation and contingencies refer to Note 17—Litigation to the Consolidated Financial Statements. For information on subsequent events related to the MOX guarantee refer to Note 18 to the Consolidated Financial Statements.

 

Item 7A. Quantitative and Qualitative Disclosures About Market Risk.

 

See “Management’s Discussion and Analysis of Results of Operations and Financial Condition, Quantitative and Qualitative Disclosures About Market Risk.”

 

81


Table of Contents

Item 8. Financial Statements and Supplementary Data.

 

DUKE ENERGY CORPORATION

 

Consolidated Statements Of Operations

 

     Years Ended December 31,

 
     2003

    2002

    2001

 
     (as Revised, See Note 24)

 
     (In millions, except
per-share amounts)
 

Operating Revenues

                        

Non-regulated electric, natural gas, natural gas liquids, and other

   $ 14,186     $ 8,818     $ 11,936  

Regulated electric

     5,026       4,880       5,088  

Regulated natural gas

     2,942       2,200       922  
    


 


 


Total operating revenues

     22,154       15,898       17,946  
    


 


 


Operating Expenses

                        

Natural gas and petroleum products purchased

     11,473       5,382       6,909  

Fuel used in electric generation and purchased power

     2,087       2,191       2,022  

Operation and maintenance

     3,777       3,313       3,712  

Depreciation and amortization

     1,799       1,511       1,258  

Property and other taxes

     526       534       430  

Impairment and other related charges

     2,956       364       —    

Impairment of goodwill

     254       —         36  
    


 


 


Total operating expenses

     22,872       13,295       14,367  
    


 


 


Gains on Sales of Investments in Commercial and Multi-family Real Estate

     84       106       106  

(Losses) Gains on Sales of Other Assets, net

     (199 )     32       238  
    


 


 


Operating (Loss) Income

     (833 )     2,741       3,923  
    


 


 


Other Income and Expenses

                        

Equity in earnings of unconsolidated affiliates

     123       218       164  

Gains on sales of equity investments

     279       32       —    

Other income and expenses, net

     154       129       147  
    


 


 


Total other income and expenses

     556       379       311  

Interest Expense

     1,380       1,097       760  

Minority Interest Expense

     61       116       326  
    


 


 


(Loss) Earnings From Continuing Operations Before Income Taxes

     (1,718 )     1,907       3,148  

Income Tax (Benefit) Expense From Continuing Operations

     (709 )     611       1,149  
    


 


 


(Loss) Income From Continuing Operations

     (1,009 )     1,296       1,999  

Discontinued Operations

                        

Net operating loss, net of tax

     (23 )     (262 )     (5 )

Net loss on dispositions, net of tax

     (129 )     —         —    
    


 


 


Loss From Discontinued Operations

     (152 )     (262 )     (5 )

(Loss) Income Before Cumulative Effect of Change in Accounting Principle

     (1,161 )     1,034       1,994  

Cumulative Effect of Change in Accounting Principle, net of tax and minority interest

     (162 )     —         (96 )
    


 


 


Net (Loss) Income

     (1,323 )     1,034       1,898  

Dividends and Premiums on Redemption of Preferred and Preference Stock

     15       13       14  
    


 


 


(Loss) Earnings Available For Common Stockholders

   $ (1,338 )   $ 1,021     $ 1,884  
    


 


 


Common Stock Data

                        

Weighted-average shares outstanding

     903       836       767  

(Loss) Earnings per share (from continuing operations)

                        

Basic

   $ (1.13 )   $ 1.53     $ 2.59  

Diluted

   $ (1.13 )   $ 1.53     $ 2.57  

Loss per share (from discontinued operations)

                        

Basic

   $ (0.17 )   $ (0.31 )   $ (0.01 )

Diluted

   $ (0.17 )   $ (0.31 )   $ (0.01 )

(Loss) Earnings per share (before cumulative effect of change in accounting principle)

                        

Basic

   $ (1.30 )   $ 1.22     $ 2.58  

Diluted

   $ (1.30 )   $ 1.22     $ 2.56  

(Loss) Earnings per share

                        

Basic

   $ (1.48 )   $ 1.22     $ 2.45  

Diluted

   $ (1.48 )   $ 1.22     $ 2.44  

Dividends per share

   $ 1.10     $ 1.10     $ 1.10  

 

See Notes to Consolidated Financial Statements.

 

82


Table of Contents

DUKE ENERGY CORPORATION

 

Consolidated Balance Sheets

 

     December 31,

     2003

   2002

     (as Revised, see Note 24)
     (In millions)

ASSETS

             

Current Assets

             

Cash and cash equivalents

   $ 1,160    $ 874

Receivables (net of allowance for doubtful accounts of $280 at 2003 and $349 at 2002)

     2,888      4,861

Inventory

     941      971

Assets held for sale

     424      —  

Unrealized gains on mark-to-market and hedging transactions

     1,566      2,144

Other

     694      887
    

  

Total current assets

     7,673      9,737
    

  

Investments and Other Assets

             

Investments in unconsolidated affiliates

     1,398      2,015

Nuclear decommissioning trust funds

     925      708

Goodwill

     3,962      3,747

Notes receivable

     260      589

Unrealized gains on mark-to-market and hedging transactions

     1,857      2,480

Assets held for sale

     1,444      —  

Investments in residential, commercial and multi-family real estate (net of accumulated depreciation of $32 at 2003 and 2002)

     1,331      1,440

Other

     1,117      1,645
    

  

Total investments and other assets

     12,294      12,624
    

  

Property, Plant and Equipment

             

Cost

     46,009      47,368

Less accumulated depreciation and amortization

     12,139      11,266
    

  

Net property, plant and equipment

     33,870      36,102
    

  

Regulatory Assets and Deferred Debits

             

Deferred debt expense

     275      263

Regulatory assets related to income taxes

     1,152      936

Other

     939      460
    

  

Total regulatory assets and deferred debits

     2,366      1,659
    

  

Total Assets

   $ 56,203    $ 60,122
    

  

 

See Notes to Consolidated Financial Statements.

 

83


Table of Contents

DUKE ENERGY CORPORATION

 

Consolidated Balance Sheets—(Continued)

 

     December 31,

 
     2003

   2002

 
     (as Revised, see Note 24)  
     (In millions)  

LIABILITIES AND COMMON STOCKHOLDERS’ EQUITY

               

Current Liabilities

               

Accounts payable

   $ 2,331    $ 3,637  

Notes payable and commercial paper

     130      915  

Taxes accrued

     —        156  

Interest accrued

     304      310  

Liabilities associated with assets held for sale

     651      —    

Current maturities of long-term debt and preferred stock

     1,200      1,331  

Unrealized losses on mark-to-market and hedging transactions

     1,283      1,918  

Other

     1,799      1,770  
    

  


Total current liabilities

     7,698      10,037  
    

  


Long-term Debt, including debt to affiliates of $876 at 2003

     20,622      20,221  
    

  


Deferred Credits and Other Liabilities

               

Deferred income taxes

     4,120      4,834  

Investment tax credit

     165      176  

Unrealized losses on mark-to-market and hedging transactions

     1,754      1,548  

Liabilities associated with assets held for sale

     737      —    

Other

     5,524      4,893  
    

  


Total deferred credits and other liabilities

     12,300      11,451  
    

  


Commitments and Contingencies

               

Guaranteed Preferred Beneficial Interests in Subordinated Notes of Duke Energy Corporation or Subsidiaries

     —        1,408  
    

  


Minority Interests

     1,701      1,904  
    

  


Preferred and Preference Stock

               

Preferred and preference stock with sinking fund requirements

     —        23  

Preferred and preference stock without sinking fund requirements

     134      134  
    

  


Total preferred and preference stock

     134      157  
    

  


Common Stockholders’ Equity

               

Common stock, no par, 2 billion shares authorized; 911 million and 895 million shares outstanding at December 31, 2003 and 2002, respectively

     9,519      9,236  

Retained earnings

     4,060      6,417  

Accumulated other comprehensive income (loss)

     169      (709 )
    

  


Total common stockholders’ equity

     13,748      14,944  
    

  


Total Liabilities and Common Stockholders’ Equity

   $ 56,203    $ 60,122  
    

  


 

See Notes to Consolidated Financial Statements.

 

84


Table of Contents

DUKE ENERGY CORPORATION

 

Consolidated Statements of Cash Flows

 

     Years Ended December 31,

 
     2003

    2002

    2001

 
     (as Revised, See Note 24)  
     (In millions)  

Cash Flows From Operating Activities

                        

Net (loss) income

   $ (1,323 )   $ 1,034     $ 1,898  

Adjustments to reconcile net (loss) income to net cash provided by operating activities

                        

Depreciation and amortization (including amortization of nuclear fuel)

     1,987       1,692       1,450  

Cumulative effect of change in accounting principle

     162       —         96  

Gains on sales of investments in commercial and multi-family real estate

     (103 )     (106 )     (106 )

Gain on sales of equity investments and other assets

     (86 )     (81 )     (238 )

Impairment charges

     3,495       545       36  

Deferred income taxes

     (534 )     495       129  

Purchased capacity levelization

     194       175       156  

Contribution to company-sponsored pension plan

     (181 )     —         —    

(Increase) decrease in

                        

Net realized and unrealized mark-to-market and hedging transactions

     (15 )     596       91  

Receivables

     1,126       12       3,166  

Inventory

     (30 )     134       (192 )

Other current assets

     (77 )     (335 )     694  

Increase (decrease) in

                        

Accounts payable

     (1,030 )     798       (3,545 )

Taxes accrued

     (168 )     (332 )     183  

Other current liabilities

     79       (194 )     325  

Capital expenditures for residential real estate

     (196 )     (179 )     (230 )

Cost of residential real estate sold

     167       117       90  

Other, assets

     (29 )     200       (11 )

Other, liabilities

     (19 )     (372 )     (243 )
    


 


 


Net cash provided by operating activities

     3,419       4,199       3,749  
    


 


 


Cash Flows From Investing Activities

                        

Capital expenditures, net of refund

     (2,275 )     (4,745 )     (5,700 )

Investment expenditures

     (290 )     (641 )     (1,093 )

Acquisition of Westcoast Energy Inc., net of cash acquired

     —         (1,707 )     —    

Proceeds from sales of commercial and multi-family real estate

     314       169       378  

Net proceeds from the sales of equity investment and other assets, and sales of and collections on notes receivable

     1,966       516       943  

Other

     (136 )     (53 )     37  
    


 


 


Net cash used in investing activities

     (421 )     (6,461 )     (5,435 )
    


 


 


Cash Flows From Financing Activities

                        

Proceeds from the

                        

Issuance of long-term debt

     3,009       5,114       2,673  

Issuance of common stock and common stock related to employee benefit plans

     277       1,323       1,432  

Payments for the redemption of

                        

Long-term debt

     (2,849 )     (1,837 )     (1,298 )

Preferred and preference stock and preferred member interests

     (38 )     (88 )     (33 )

Guaranteed preferred beneficial interests in subordinated notes

     (250 )     —         —    

Notes payable and commercial paper

     (1,702 )     (1,067 )     (246 )

Distributions to minority interests

     (2,508 )     (2,260 )     (3,063 )

Contributions from minority interests

     2,432       2,535       2,733  

Dividends paid

     (1,051 )     (938 )     (871 )

Other

     23       64       27  
    


 


 


Net cash (used in) provided by financing activities

   <