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SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

For the fiscal year ended December 31, 2003

or

For the transition period from              to             

Commission file number 1-4456

TEXAS EASTERN TRANSMISSION, LP

(Exact name of registrant as specified in its charter)

713-627-5400

(Registrant’s telephone number, including area code)

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

Title of class

None

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

Title of class

None

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 or any amendment to this Form 10-K.    x

The registrant meets the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K and is therefore filing this Form 10-K with the reduced disclosure format. Items 4, 6, 10, 11, 12 and 13 have been omitted in accordance with Instruction (I)(2)(a) and (c). Item 7 has been reduced in accordance with Instruction (I)(2)(a) and Items 1 and 2 have been reduced in accordance with Instruction (I)(2)(d).

All of the registrant’s interests are indirectly owned by Duke Energy Corporation (File No. 1-4928), which files reports and proxy materials pursuant to the Securities Exchange Act of 1934.

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  ¨    No  x

TEXAS EASTERN TRANSMISSION, LP

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

TABLE OF CONTENTS

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

Texas Eastern Transmission, LP’s (together with its subsidiaries, the “Company’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 the Company’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 the Company’s control and could cause actual results to differ materially from the results expressed or implied by those forward-looking statements. Those factors include:

i

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 the Company has described. The Company undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

ii

PART I.

Item 1. Business.

GENERAL

Texas Eastern Transmission, LP (Texas Eastern), a Delaware limited partnership (together with its subsidiaries, the “Company”) is an indirect, wholly owned subsidiary of Duke Energy Corporation (Duke Energy). The Company is primarily engaged in the interstate transportation and storage of natural gas. The Company’s interstate natural gas transmission and storage operations are subject to the rules and regulations of the Federal Energy Regulatory Commission (FERC).

Executive offices of the Company are located at 5400 Westheimer Court, Houston, Texas 77056-5310, and the telephone number is (713) 627-5400. The Company electronically files reports with the Securities and Exchange Commission (SEC), primarily annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to such reports. The public may read and copy any materials that the Company 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.

Terms used to describe the Company’s business are defined below.

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.

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.

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.

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

The Company’s throughput was 1,219 trillion Btu (TBtu) for 2003, 1,202 TBtu for 2002 and 1,241 TBtu for 2001. Approximately 70% of the Company’s contracted volumes are under long-term firm service agreements with LDC customers in the pipeline’s market area. Firm transportation services are also provided to gas marketers, producers, other pipelines, electric power generators and a variety of end-users. In addition, firm and interruptible transportation services are provided to customers on a short-term or seasonal basis. The Company’s major customers are in Pennsylvania, New Jersey, New York, and New England. Demand for gas transmission on the Company’s interstate pipeline system is seasonal, with the highest throughput occurring during the colder periods in the first and fourth quarters.

The Company also provides 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. The Company has two joint venture storage facilities in Pennsylvania and one wholly owned and operated storage field in Maryland. The Company’s certificated working capacity in these three fields is 75 billion cubic feet (Bcf). The Company also leases storage capacity.

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The Company’s only customers accounting for 10% or more of consolidated revenues in 2003, 2002, and 2001 were Public Service Electric and Gas Company (PSE&G), an LDC, KeySpan Energy, and Duke Energy affiliates. Total billings for services provided by the Company to PSE&G, KeySpan Energy, and Duke Energy affiliates, were approximately $90 million, $79 million, and $124 million during 2003, $88 million, $77 million, and $98 million, during 2002 and $83 million, $79 million, and $127 million, during 2001, respectively.

COMPETITION

The Company competes with other interstate and intrastate pipeline companies in the transportation and storage of natural gas serving the Mid-Atlantic and northeastern states.

The principal elements of competition among pipelines are rates, terms of service and flexibility and reliability of service.

Natural gas competes with other forms of energy available to the Company’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 and governmental regulations, the capability to convert to alternative fuels, and other factors, including weather, affect the demand for natural gas in the areas served by the Company.

REGULATION

The FERC has authority to regulate rates and charges for natural gas transported or stored for interstate commerce or sold by a natural gas company in interstate commerce for resale. The FERC also has authority over the construction and operation of pipeline and related facilities used in the transportation and storage of natural gas in interstate commerce, including the extension, enlargement or abandonment of such facilities. The Company holds certificates of public convenience and necessity issued by the FERC, authorizing it to construct and operate the pipeline, facilities and related properties, and to transport and store natural gas via interstate commerce.

As required by FERC Order 636, the Company’s pipeline operates as an open-access transporter of natural gas, providing unbundled firm and interruptible transportation and storage services on a not unduly discriminatory basis for all gas supplies, whether purchased from the pipeline or from another gas supplier.

The Company 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.) The Company is also subject to the jurisdiction of the U.S. Department of Transportation (DOT) concerning pipeline safety. DOT regulations have incorporated certain provisions of the Natural Gas Pipeline Safety Act of 1968, which regulates gas pipeline and liquefied natural gas plant safety requirements.

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ENVIRONMENTAL MATTERS

The Company is subject to federal, state and local regulations regarding air and water quality, hazardous and solid waste disposal and other environmental matters. Environmental regulations affecting the Company include, but are not limited to:

(For more information on environmental matters involving the Company, including possible liability and capital costs, see Note 10 to the Consolidated Financial Statements, “Commitments and Contingencies – Environmental.”)

Compliance with 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 the Company.

EMPLOYEES

As of December 31, 2003, the Company had approximately 1,027 employees.

Item 2. Properties.

The Company’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 has three large-diameter parallel pipelines and the other has from one to three large-diameter pipelines. The Company’s onshore system consists of approximately 8,600 miles of pipeline and has 73 compressor stations.

The Company 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 its pipeline system.

For information concerning natural gas storage properties, see “Business, General.”

Item 3. Legal Proceedings.

For information regarding legal proceedings, including regulatory and environmental matters, see Note 3 to the Consolidated Financial Statements, “Regulatory Matters” and Note 10 to the Consolidated Financial Statements, “Commitments and Contingencies – Environmental” and “Commitments and Contingencies –Litigation.”

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PART II.

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

The Company has no established public trading market for any of its partners’ capital. All of the Company’s partnership interests are indirectly owned by Duke Energy.

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

INTRODUCTION

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

Because all of the partnership interests of the Company are owned indirectly by Duke Energy, the following discussion has been prepared in accordance with the reduced disclosure format permitted by Form 10-K for certain issuers that are wholly owned subsidiaries of reporting companies under the Securities Exchange Act of 1934 set forth in General Instruction I (1)(a) and (b) for Form 10-K.

Overview of Business Strategy and Economic Factors

The Company’s business strategy is to continue the focus on customer service and reliability, and to continue developing expanded services and incremental projects that meet increasing customer needs. Pipeline growth will be driven by customer expansions in the current market area.

The Company’s business strategy and growth expectations may vary significantly depending on many factors, including, but not limited to, regulatory constraints, market volatility, and economic trends.

Sustained downturns or sluggishness in the economy generally affect the markets in which the Company operates and negatively influences its operations. Lower economic output would cause the Company’s business to experience a decline in the volume of natural gas shipped through the pipeline, which could affect the ability to re-market services as contracts terminate.

The Company’s goals can also be substantially at risk due to the regulation of its business. Regulations applicable to the gas transmission and storage industry have a significant impact on the nature of the industry and the manner in which its participants conduct their business. Changes to regulations are ongoing and the Company cannot predict the future course of changes in the regulatory environment or the ultimate effect that any future changes will have on its business.

RESULTS OF OPERATIONS

The Company reported consolidated net income of $239 million in 2003 compared to consolidated net income of $237 million in 2002. Operating revenues increased primarily due to new firm contracts and higher prices of energy-related products. Operation and maintenance expense increased $20 million in 2003 as a result of environmental provision reductions in 2002 and severance charges in 2003 due to workforce reductions. Property tax expense decreased $19 million resulting from the 2003 reversal of accrued liabilities associated with the resolution of pending tax contingencies. Interest expense increased primarily as a result of debt issuances in July 2002.

The Company’s throughput was 1,219 TBtu for 2003 and 1,202 TBtu for 2002. The increase of approximately 1% was mostly due to colder temperatures in the Northeast market areas in 2003 compared to 2002, but had no material impact on revenues. The Company continues to experience renewals of its customer contracts as they expire and the weighted average firm contract life, based on contracted volumes, is nine years.

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CRITICAL ACCOUNTING POLICIES

The selection and application of accounting policies is an important process that continues to evolve as the Company’s operations change and accounting guidance evolves. The Company 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 the Company’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. The Company discusses its critical accounting policies and other significant accounting policies with senior members of management and the audit committee of its parent, as appropriate. The Company’s critical accounting policies are listed below.

Regulatory Accounting. The Company accounts for its regulated operations under the provisions of Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation.” As a result, the Company records assets and liabilities that result from the regulated ratemaking process that would not be recorded under generally accepted accounting principles for non-regulated entities. Regulatory assets generally represent incurred costs that have been deferred because they 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 to other regulated entities, and the status of any pending or potential deregulation legislation. Management believes the existing regulatory assets are probable of recovery. This determination reflects the current political and regulatory climate at the federal level, 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 current period earnings.

Revenue Recognition. Revenues on natural gas transportation and storage are recognized when the service is provided. Revenues from natural gas throughput are estimated in the month of delivery based on contract data, regulatory information, and preliminary throughput and allocation measurements. Final bills for the current month are billed and collected in the following month.

LIQUIDITY AND CAPITAL RESOURCES

As of December 31, 2003 and 2002, the Company had no cash or cash equivalents since all cash is managed collectively at the parent-company level and is therefore advanced to/from affiliates as cash is generated or paid by the Company. The Company’s working capital was a $245 million deficit as of December 31, 2003, compared to a $128 million deficit as of December 31, 2002. The decrease in working capital was primarily attributable to an increase in current maturities of long-term debt.

The Company relies primarily upon cash flows from operations to fund its liquidity and capital requirements. The Company’s cash flows are relatively stable since they are supported by revenues from long-term firm contracts.

Management monitors compliance with all debt covenants and restrictions, and does not currently believe that the Company will be in violation or breach of its debt covenants. However, circumstances could arise that could alter that view. If and when management had a belief that such potential breach could exist, management will move to take appropriate action with the affected stakeholders to mitigate any such issue.

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Operating Cash Flows

Net cash provided by operating activities was $362 million in 2003 compared to $419 million in 2002, a decrease of $57 million. The decrease in cash provided by operating activities was due primarily to the negative changes in working capital compared to 2002.

Investing Cash Flows

The primary uses of cash for investing activities are capital expenditures and advances funded to affiliates. Capital expenditures were $78 million for 2003 and $180 million for 2002. These expenditures consist primarily of business expansion projects, and renewals and betterments which extend the useful life of property, plant and equipment. The decrease from 2002 is primarily a result of significant expansion projects in 2002. Projected 2004 capital expenditures are approximately $183 million, with market expansion expenditures approximating 60% of the capital budget. The increase in projected capital expenditures in comparison to 2003 is due primarily to an anticipated increase in pipeline expansion projects in the Company’s market area.

All projected capital 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, market volatility and economic trends.

Increases and decreases in advances receivable–affiliates generally result from the movement of funds to provide for operations, capital expenditures and debt payments of the Company. The significant increase in 2002 in advances was primarily a result of advancing the net proceeds of the $750 million bond issuances in July 2002. Advances receivable-affiliates do not bear interest. Advances are carried as unsecured, open accounts and are not segregated between current and non-current amounts.

Financing Cash Flows

The Company’s consolidated capital structure at December 31, 2003, including short-term debt, was 34% debt and 66% partners’ capital. The ratio of earnings to fixed charges coverage, calculated using SEC guidelines, was 5.4 times for 2003.

Cash flows from financing activities decreased $725 million in 2003 versus 2002 due to proceeds of $750 million in bond issuances and $100 million in payments for debt redemption in 2002 and partnership distributions of $75 million in 2003.

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Credit Ratings. As of March 1, 2004, the Company’s senior unsecured credit ratings were “BBB” Standard & Poor’s (S&P) and “Baa2” Moody’s Investor Service (Moody’s). In March 2003, (Moody’s) placed its long-term and short-term ratings of Duke Energy and Duke Capital Corporation (the predecessor to Duke Capital LLC), an indirect parent company, and its long-term ratings of the Company and PanEnergy Corp, an indirect parent company, 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 Corporation, and its long-term ratings of the Company and PanEnergy Corp one 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 other, non-regulated subsidiaries of Duke Energy. Moody’s concluded its action by placing Duke Energy, Duke Capital Corporation, the Company and PanEnergy Corp on Stable Outlook.

In June 2003, (S&P) lowered its long-term ratings of Duke Energy, Duke Capital Corporation, the Company and PanEnergy Corp 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 action by leaving Duke Energy, Duke Capital Corporation, the Company and PanEnergy Corp on Negative Outlook. In February 2004, S&P again lowered its long-term ratings of Duke Energy, Duke Capital Corporation, the Company and PanEnergy Corp 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 Corporation, the Company and PanEnergy Corp all have a Stable Outlook.

The credit ratings of the Company and its parent companies are dependent on, among other factors, Duke Energy’s ability to generate sufficient cash to fund its 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 Duke Energy’s earnings outlook materially deteriorates, Duke Energy’s and the Company’s ratings could be further affected.

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Contractual Obligations and Commercial Commitments

The Company enters into contracts that require payment of cash at certain specified periods, based on certain specified minimum quantities and prices. The following table summarizes the Company’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.

Contractual Obligations as of December 31, 2003 (in millions)

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

Risk and Accounting Policies

The Company is exposed to commodity prices and credit exposure. 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 comprised 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.

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Commodity Price Risk

The Company is exposed to the impact of market fluctuations in the prices of energy commodities related to the Company’s operations. The Company employs established policies and procedures to manage its risks associated with these market fluctuations using commodity derivatives, such as swaps (See Notes 2 and 8 to the Consolidated Financial Statements).

Hedging Strategies. The Company closely monitors the risks associated with these commodity price changes on its future operations and, where appropriate, uses various commodity instruments, such as natural gas liquids and crude oil swaps to mitigate the effect of such fluctuations on operations. Contract terms are up to two years. Since these contracts are designated and qualify as effective hedge positions of future cash flows of the Company, to the extent that the hedge instrument is effective in offsetting the transactions 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 2 and 8 to the Consolidated Financial Statements).

Credit Risk

The Company’s principal customers for natural gas transportation and storage services are LDCs, industrial end-users, and natural gas marketers located throughout the Mid-Atlantic and northeastern states. The Company has concentrations of receivables from these industries throughout these regions. These concentrations of customers may affect the Company’s overall credit risk in that risk factors can negatively impact the credit quality of the entire sector. Where exposed to credit risk, the Company 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 Company also obtains cash, letters of credit or other acceptable forms of security from customers, where appropriate, based on a financial analysis of the customer and the regulatory or contractual terms and conditions applicable to each transaction.

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Item 8. Financial Statements and Supplementary Data.

TEXAS EASTERN TRANSMISSION, LP

CONSOLIDATED STATEMENTS OF OPERATIONS

(In millions)

See Notes to Consolidated Financial Statements.

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TEXAS EASTERN TRANSMISSION, LP

CONSOLIDATED BALANCE SHEETS

(In millions)

See Notes to Consolidated Financial Statements.

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TEXAS EASTERN TRANSMISSION, LP

CONSOLIDATED BALANCE SHEETS

(In millions)

See Notes to Consolidated Financial Statements.

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TEXAS EASTERN TRANSMISSION, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

Non-cash investing and financing transactions:

In 2003, the Company transferred its primary office building in Houston, Texas to its limited partner at its net book value of $59 million.

In 2002, the Company received a transfer from its direct parent of approximately $5 million of property, plant & equipment.

See Notes to Consolidated Financial Statements.

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TEXAS EASTERN TRANSMISSION, LP

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL AND STOCKHOLDER’S EQUITY

(In millions)

See Notes to Consolidated Financial Statements.

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TEXAS EASTERN TRANSMISSION, LP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In millions)

See Notes to Consolidated Financial Statements.

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Notes to Consolidated Financial Statements

For The Years Ended December 31, 2003, 2002 and 2001

Note 1. Nature of Operations

On April 16, 2001, Texas Eastern Transmission Corporation (TETCO), a Delaware corporation, changed its form of organization from a corporation to a limited partnership. Pursuant to the conversion, all rights and liabilities of TETCO vested in Texas Eastern Transmission, LP, a Delaware limited partnership (together with its subsidiaries, the “Company”). As a result of the conversion, retained earnings of $274 million and paid-in capital of $1,485 million were reclassified as partnership capital. There was no effect on the Company’s results of operations, cash flows or financial position as a result of this conversion. The Company is an indirect, wholly owned subsidiary of Duke Energy Corporation (Duke Energy).

The Company is primarily engaged in the interstate transportation and storage of natural gas. The Company’s interstate natural gas transmission and storage operations are subject to the rules and regulations of the Federal Energy Regulatory Commission (FERC).

Note 2. Summary of Significant Accounting Policies

Consolidation. The Consolidated Financial Statements include the accounts of the Company and all wholly-owned subsidiaries, after eliminating intercompany transactions and balances.

Conformity with generally accepted accounting principles (GAAP) in the U.S. requires management to make estimates and assumptions that affect the amounts reported in the financial statements and notes. Although these estimates are based on management’s best available knowledge of current and expected future events, actual results could be different from those estimates.

Inventory. Inventory consists primarily of materials and supplies and natural gas held for storage and is recorded at the lower of cost or market value, primarily using the average cost method.

Accounting for Hedges. The Company enters into derivative transactions that are hedges of the future cash flows of forecasted transactions (cash flow hedges). These derivatives are recorded on the Consolidated Balance Sheets at their fair value as Accounts Receivable, Accounts Payable, Regulatory Assets and Deferred Debits, Other Current Liabilities, or Deferred Credits and Other Liabilities, as appropriate.

Qualifying non-trading energy commodity derivatives may be designated as either a hedge of a forecasted transaction or future cash flows (cash flow hedge). For all hedge contracts, the Company provides formal documentation of the hedge in accordance with Statements of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities.” In addition, at inception and on a monthly basis the Company formally assesses whether the hedge contract is highly effective in offsetting changes in cash flows. The Company documents hedging activity by transaction type (i.e. swaps) and risk management strategy (i.e. commodity price risk).

Cash Flow Hedges. Changes in the fair value of a derivative designated and qualified as a cash flow hedge are included in the Consolidated Statements of Partners’ Capital and Stockholder’s Equity and Comprehensive Income as Accumulated Other Comprehensive Income (AOCI) until earnings are affected by the hedged item. Settlement amounts of cash flow hedges are removed from AOCI and included in Storage of Natural Gas and Other Services Revenue on the Company’s Consolidated Statements of Operations. The Company discontinues hedge accounting prospectively when it has determined that a derivative no longer qualifies as an effective hedge, or when it is no longer probable that the hedged forecasted transaction will occur. When hedge accounting is discontinued because the derivative no longer qualifies as an effective hedge, the derivative is subject to the mark-to-market accounting method prospectively. Gains and losses related to discontinued hedges that were previously accumulated in AOCI will remain in AOCI until the underlying contract is reflected in earnings, unless it is no longer probable that the hedged forecasted transaction will occur.

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Valuation. When available, quoted market prices are used to verify a contract’s fair value. For contracts with a delivery location or duration for which quoted market prices are not available, fair value is determined based on internally developed valuation techniques or models. Valuation adjustments for performance and market risk, and administration costs are used to adjust the fair value of the contract to the gain or loss ultimately recognized in the Consolidated Balance Sheets.

Goodwill. Prior to the adoption of SFAS No. 142, “Goodwill and Other Intangible Assets” as of January 1, 2002, the amount of goodwill related to the purchase of Texas Eastern Transmission Corporation and its subsidiaries in 1989 was amortized on a straight-line basis over 40 years. Under the provisions of SFAS No. 142, goodwill is no longer amortized. Net income for 2001 would have been $231 million compared to $228 million if amortization (including any related tax effects) related to goodwill would not have been amortized. Under SFAS No. 142, the Company has designated August 31 as the date it performs the annual review for impairment.

Property, Plant and Equipment. Property, plant and equipment are stated at cost less accumulated depreciation. The Company capitalizes all construction-related direct labor and material costs, as well as indirect construction costs. Indirect costs include general engineering, taxes and the cost of funds used during construction. The cost of renewals and betterments that extend the useful life of property, plant and equipment is also capitalized. The cost of repairs, replacements and major maintenance projects is expensed as it is incurred. Depreciation is generally computed over the asset’s estimated useful life using the straight-line method. The composite weighted-average depreciation rates were 2.1% for 2003, 2.1% for 2002 and 2.4% for 2001.

When the Company retires its regulated property, plant and equipment, it charges the original cost plus the cost of retirement, less salvage, to accumulated depreciation and amortization. When it sells entire regulated operating units, or retires or sells non-regulated properties, the cost is removed from the property account and the related accumulated depreciation and amortization accounts are reduced. Any gain or loss is recorded as income, unless otherwise required by the FERC.

Unamortized Debt Premium, Discount and Expense. Premiums, discounts and expenses with the issuance of outstanding long-term debt are amortized over the terms of the debt issues. Any call premiums or unamortized expenses associated with refinancing higher-cost debt obligations used to finance regulated assets and operations are amortized consistent with regulatory treatment of those items, where appropriate.

Environmental Expenditures. The Company expenses environmental expenditures related to conditions caused by past operations that do not generate current or future revenue. Environmental expenditures related to operations that generate current or future revenues are expensed or capitalized as appropriate. Liabilities are recorded when environmental assessments and/or cleanups are probable and the costs can be reasonably estimated.

Cost-Based Regulation. The Company accounts for its regulated operations under the provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” The economic effects of regulation can result in a regulated company recording costs that have been or are expected to be allowed in the rate-setting process in a period different from the period in which the costs would be charged to expense by an unregulated enterprise. Accordingly, the Company records assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for non-regulated entities. These regulatory assets and liabilities are classified in the Consolidated Balance Sheets as Regulatory Assets and Deferred Debits, and Deferred Credits and Other Liabilities. The Company periodically evaluates the applicability of SFAS No. 71 and considers factors such as regulatory changes and the impact of competition. If cost-based regulation ends or competition increases, the Company may have to reduce its asset balances to reflect a market basis less than cost, and write-off the associated regulatory assets and liabilities.

Revenues. Revenues on natural gas transportation and storage are recognized when the service is provided. From time to time certain revenues may be subject to refund pending the outcome of rate matters before the FERC, and reserves are established where required. As a result of a 1998 FERC approved uncontested settlement between the Company and its customers (which among other matters, established a rate moratorium through December 31, 2003), there were no pending rate cases and no related reserves were recorded as of December 31, 2003 or 2002. The allowance for doubtful accounts was $2 million as of December 31, 2003 and December 31, 2002.

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Revenues from natural gas throughput are estimated in the month of delivery based on contract data, regulatory information, and preliminary throughput and allocation measurements. Final bills for the current month are billed and collected in the following month. Receivables on the Consolidated Balance Sheets included $61 million as of December 31, 2003, and $62 million as of December 31, 2002, for natural gas transportation and storage services provided but not yet billed.

The Company’s only customers accounting for 10% or more of consolidated revenues in 2003, 2002, and 2001 were Public Service Electric and Gas Company (PSE&G), an LDC, KeySpan Energy, and Duke Energy affiliates. Total billings for services provided by the Company to PSE&G, KeySpan Energy, and Duke Energy affiliates, were approximately $90 million, $79 million, and $124 million during 2003, $88 million, $77 million, and $98 million, during 2002 and $83 million, $79 million, and $127 million, during 2001, respectively.

Allowance for Funds Used During Construction (AFUDC). AFUDC, recorded in accordance with SFAS 71, represents the estimated debt and equity costs of capital funds necessary to finance the construction of new regulated facilities. AFUDC is a non-cash item and is capitalized as a component of Property, Plant and Equipment cost, with offsetting credits to Other Income and Expenses, net and to Interest Expense. After construction is completed, the Company is permitted to recover these costs, including a fair return, through inclusion in the rate base and in the depreciation provision. The total amount of AFUDC included in Other Income and Expenses and Interest Expense was $2 million in 2003, $5 million in 2002 and $4 million in 2001.

Stock-Based Compensation. The Company utilizes Duke Energy’s stock-based compensation arrangements for eligible employees. The Company accounts for its stock-based compensation arrangements under the intrinsic value recognition and measurement principles of Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees” and FASB Interpretation No. 44, “Accounting for Certain Transactions Involving Stock Compensation (an Interpretation of APB Opinion 25).” Since the exercise price for all options granted under those plans was equal to the market value of the underlying Duke Energy common stock on the date of grant, no compensation cost is recognized in the accompanying Consolidated Statements of Operations. Restricted stock grants, phantom stock awards and certain stock-based performance awards are recorded over the required vesting period as compensation cost, based on the market value on the date of the grant. Other stock-based performance awards are recorded over the vesting period as compensation cost and are adjusted for increases and decreases in market value up to the measurement date.

The following table illustrates the effect on net income if the Company had applied the fair value recognition provisions of SFAS No. 123, “Accounting for Stock-Based Compensation,” to all stock-based compensation awards and reflects the provisions of SFAS No. 148, “Accounting for Stock-based Compensation – Transition and Disclosure (an amendment of SFAS No. 123).”

Pro Forma Stock-Based Compensation (in millions)

Income Taxes. Duke Energy and its subsidiaries file a consolidated federal income tax return and other U.S. jurisdictional returns as required. The Company’s limited partner filed an election with the Internal Revenue Service to be taxed as a C-corporation for federal income tax purposes. The Company is also subject to corporate income tax as a division of the limited partner. Federal income taxes have been provided by the Company on the basis of its separate company income and deductions in accordance with established practices of the consolidated group. Deferred income taxes have been provided for temporary differences. These occur when there are differences between the GAAP and tax carrying amounts of assets and liabilities. These differences create taxable or tax-deductible amounts for future periods. Investment tax credits have been deferred and are being amortized over the estimated useful lives of the related properties.

Cumulative Effect of Change in Accounting Principle. The Company adopted SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended and interpreted on January 1, 2001. In accordance with the transition provisions of SFAS No. 133, the Company recorded a net-of-tax cumulative effect adjustment reducing OCI and Common Stockholder’s Equity by $2 million.

New Accounting Standard. The following new accounting standard has been adopted by the Company during the year-ended December 31, 2003 and the impact of such adoption, if applicable, has been presented in the accompanying consolidated financial statements.

As of January 1, 2003, the Company adopted SFAS No. 143, “Accounting for Asset Retirement Obligations.” which addressed financial accounting and reporting for legal obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. The standard applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset. The implementation of SFAS No. 143 in the first quarter of 2003 resulted in a net $6 million increase in property, plant and equipment. Liabilities increased approximately $6 million representing the establishment of an asset retirement obligation. The asset retirement obligation is reviewed each quarter for any liabilities incurred or settled during the period, accretion expense and any revisions made to the estimated cash flows. For the year ended December 31, 2003 the accretion expense was $0.4 million, liabilities settled were $0.2 million and revisions in estimated cash flows were ($1.5) million. The Company has no assets that are legally restricted for the purposes of settling asset retirement obligations as of December 31, 2003.

Reclassifications. Certain prior period amounts have been reclassified to conform to current year presentation.

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Note 3. Regulatory Matters

Regulatory Assets and Liabilities. The Company’s regulated operations are subject to SFAS No. 71. Accordingly, the Company records assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for non-regulated entities. (See Note 2.) The following table details the Company’s regulatory assets and liabilities.

Regulatory Assets and Liabilities (in millions)

Standards of Conduct. On November 25, 2003, the FERC issued Order No. 2004, which adopted standards of conduct that apply uniformly to interstate natural gas pipelines and public utilities (referred to in the order as “Transmission Providers”). The standards of conduct govern the relationship between Transmission Providers (including the Company) and their energy affiliates. By June 1, 2004, all Transmission Providers must comply with the revised standards of conduct and post procedures on the Internet that will enable customers and the FERC to determine whether Transmission Providers are in compliance with the standards of conduct. Various parties, including Duke Energy, have requested clarification and/or rehearing of Order No. 2004, which are currently pending before the FERC.

Fuel Tracker. At December 31, 2003 and 2002, Other Current Assets on the Consolidated Balance Sheets included $30 million and $9 million, respectively, for costs related to fuel and balancing activity of the pipeline system that are recovered annually in transportation rates in accordance with the Company’s FERC gas tariff.

Note 4. Related Party Transactions

Statement of Operations Transactions (in millions)

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Balance Sheet Transactions (in millions)

Advances receivable-affiliates do not bear interest. Advances are carried as unsecured, open accounts and are not segregated between current and non-current amounts. Increases and decreases in advances generally result from the movement of funds to provide for operations, capital expenditures and debt payments of the Company. The increase in advances receivable-affiliates as of December 31, 2003 includes the non-cash transfer of the Company’s primary office building in Houston, Texas to its limited partner at its net book value of $59 million.

The Company paid $75 million in distributions to its partners in 2003.

Two notes payable issued to an affiliate, PanEnergy Corp, totaling $1.6 billion, and two notes receivable from PanEnergy Corp, totaling $1.6 billion, were outstanding at December 31, 2002. These notes were transferred to the general partner of the Company on December 31, 2003. As these notes contain a right of setoff and were presented, along with their interest components, net in the consolidated financial statements, this transfer did not affect the consolidated financial statements. Interest expense related to these notes totaled approximately $151 million, $152 million and $153 million in 2003, 2002, and 2001, respectively. Interest income related to these notes totaled approximately $151 million, $152 million and $153 million in 2003, 2002 and 2001, respectively.

Note 5. Gas Imbalances

The Consolidated Balance Sheets include in-kind balances as a result of differences in gas volumes received and delivered for customers. As the settlement of imbalances are in-kind, changes in the balances do not have an impact on the Company’s Consolidated Statements of Cash Flows. Accounts Receivable and Other Current Liabilities each include $80 million as of December 31, 2003 and $51 million as of December 31, 2002, related to gas imbalances. Natural gas volumes owed to (by) the Company are valued at natural gas market prices as of the balance sheet dates.

Note 6. Income Taxes

Income Tax Expense (in millions)

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Income Tax Expense Reconciliation to Statutory Rate (in millions)

Net Deferred Income Tax Liability Components (in millions)