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SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

For the fiscal year ended December 31, 2002 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).

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.

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TEXAS EASTERN TRANSMISSION, LP

FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 2002

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

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

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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 Texas Eastern Transmission, LP has described. Texas Eastern Transmission, LP undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

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PART I.

Item 1. Business.

GENERAL

Texas Eastern Transmission, LP, 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.

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.

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.

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.

Transmission System. An interconnected group of natural gas pipelines and associated facilities for transporting natural gas in bulk between points of supply and delivery to industrial customers, local distribution companies, or for delivery to other natural gas transmission systems.

The Company’s throughput was 1,202 trillion Btu (TBtu) for 2002, 1,241 TBtu for 2001 and 1,312 TBtu for 2000. 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 cf (Bcf). The Company also leases storage capacity.

Public Service Electric and Gas Company (PSE&G), a LDC, was the Company’s only customer accounting for 10% or more of consolidated revenues in 2002, 2001 and 2000. Total billings for transportation and storage services provided by the Company to PSE&G were approximately $78 million, $80 million, and $110 million during 2002, 2001, and 2000, respectively.

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COMPETITION

The Company competes with other interstate and intrastate pipeline companies in the transportation and storage of natural gas. The principal elements of competition among pipelines are rates, terms of service and flexibility and reliability of service.

The Company competes directly with other interstate pipelines serving the Mid-Atlantic and northeastern states.

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. (For more information on rate matters, see Note 3 to the Consolidated Financial Statements, “Regulatory Matters.”) 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. In addition, the DOT is developing regulations that will require pipelines 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 people and their property. The Pipeline Safety Improvement Act of 2002, which was enacted on December 17, 2002, establishes that these mandatory inspections of high consequence areas for all U.S. oil and natural gas pipelines must take place within the next 10 years. The Company continues to investigate the costs associated with the implementation of these new requirements but does not anticipate a material adverse effect on its consolidated results of operations, cash flows or financial position.

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ENVIRONMENTAL MATTERS

The Company is subject to federal, state and local regulations with regard to 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, 2002, the Company had approximately 1,136 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 system consists of approximately 8,600 miles of pipeline and has 73 compressor stations.

The Company also owns and operates two offshore Louisiana pipelinesystems, which extend over 100 miles into the Gulf of Mexico and include approximately 470 miles of its pipeline system.

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

Item 3. Legal Proceedings.

The Company is involved in legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding performance, contracts, and other matters arising in the ordinary course of business, some of which involve substantial amounts. Management believes that the final disposition of these proceedings will have no material adverse effect on the consolidated results of operations, cash flows or financial position of the Company.

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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 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.

The Company is an indirect wholly owned subsidiary of Duke Energy and is primarily engaged in the interstate transportation and storage of natural gas for customers primarily in the Mid-Atlantic and northeastern states. Interstate natural gas transmission and storage operations are subject to the FERC’s rules and regulations.

BUSINESS STRATEGY

The Company’s business strategy is 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, the pace and direction of industry restructuring, regulatory constraints, acquisition and divestiture opportunities, market volatility, access to the capital markets, and economic trends.

RESULTS OF OPERATIONS

The Company reported consolidated net income of $237 million in 2002 compared to consolidated net income of $228 million in 2001. Operating revenues remained relatively unchanged while operating expenses decreased primarily due to lower contract labor and other employee related expenses, lower capitalization of preliminary construction costs incurred and net reductions in certain environmental provisions. Interest expense increased primarily as a result of bond issuances in July 2002. The Company’s effective tax rate in 2002 was approximately 2% lower than the rate in 2001 as a result of state tax adjustments in 2002 related to prior period returns.

The Company’s throughput was 1,202 TBtu for 2002 and 1,241 TBtu for 2001. The decrease of approximately 3% was mostly due to milder temperatures in 2002 compared to 2001, and had no material impact on revenues.

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CRITICAL ACCOUNTING POLICIES

The selection and application of accounting policies is an important process that has developed 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 each of its critical accounting policies, in addition to certain less significant accounting policies, with senior members of management and the audit committee of its parent.

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 state 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 current period earnings. Total regulatory assets were $65 million as of December 31, 2002 and $78 million as of December 31, 2001. Total regulatory liabilities were $23 million as of December 31, 2002 and $22 million as of December 31, 2001. (For additional information on regulatory assets and liabilities, see Note 3 to the Consolidated Financial Statements, “Regulatory Matters.”)

Depreciation Expense and Cost Capitalization Policies. The Company’s assets consist primarily of natural gas transmission pipeline, storage, processing, and compression facilities. 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 costs of certain funds used in construction. The cost of funds used in construction represents estimated debt and equity costs of capital funds necessary to finance the construction of new regulated facilities. After construction is completed, the Company is permitted to recover these costs, for regulated facilities, plus a defined return, by including them in the rate base and in the depreciation provision.

As discussed in the Notes to the Consolidated Financial Statements, depreciation of the Company’s assets is generally computed using the straight-line method over the estimated useful life of the assets. The costs of renewals and betterments that extend the useful life of property, plant and equipment are also capitalized. The cost of repairs, replacements and major maintenance projects is expensed as it is incurred.

The computation of depreciation expense requires judgment regarding the estimated useful lives and salvage value of assets. As circumstances warrant, depreciation estimates are reviewed to determine if any changes are needed. Such changes could involve an increase or decrease in estimated useful lives or salvage values which would impact future depreciation expense.

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Impairment of Long-lived Assets. The Company evaluates the carrying value of long-lived assets, excluding goodwill, when circumstances indicate the carrying value of those assets may not be recoverable under the guidance of SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” For long-lived assets the Company determines the carrying amount is not recoverable if it exceeds the sum of estimates of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. The Company considers various factors when determining if impairment tests are warranted, including but not limited to:

Judgment is exercised to estimate future cash flows, and the useful lives of these long-lived assets and to determine management’s intent to use the assets. The sum of undiscounted cash flows is primarily dependent on forecasted transportation volumes under contract. The Company incorporates current market information as well as historical, fundamental analysis and other factors into forecasting its future cash flows. If the carrying value of the long-lived assets is not recoverable based on these estimated future cash flows, the impairment loss is measured as the excess of the asset’s carrying value over its fair value. Management assesses the fair value of the long-lived assets using commonly accepted techniques including, but not limited to, recent third party comparable sales and discounted cash flow analysis.

Impairment of Goodwill. The Company evaluates the impairment of goodwill under SFAS No. 142, “Goodwill and Other Intangible Assets.” The majority of the Company’s goodwill relates to the purchase of the Company and its subsidiaries in 1989. As required by SFAS No. 142, the Company 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 the Company’s operations below its carrying amount. To determine the existence of an impairment, management estimated the fair value of the assets and operations using the present value of expected future cash flows in comparison to the carrying values. There were no goodwill impairments recorded in 2002.

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 measurements and allocations. Final bills for the current month are billed in the following month. (See Note 2 to the Consolidated Financial Statements, “Summary of Significant Accounting Policies”.)

Contingencies. The Company follows SFAS No. 5, “Accounting for Contingencies,” to determine accounting and disclosure requirements for contingencies. The Company operates in a highly regulated environment. Governmental bodies such as the FERC, the Securities and Exchange Commission (SEC), the Internal Revenue Service, the Department of Labor, the EPA, the DOT and others have purview over various aspects of the Company’s business operations and public reporting. Reserves are established when required in management’s judgment and disclosures are made when appropriate regarding litigation, assessments, creditworthiness of customers or counterparties, and self-insurance exposures, among others. (See Note 10 to the Consolidated Financial Statements, “Commitments and Contingencies,” for a

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discussion of various contingencies.) The evaluation of these contingencies is performed by various specialists inside and outside of the Company. Accounting for contingencies requires significant judgment by management regarding the estimated probabilities and ranges of exposure to potential liability. Management’s assessment of the Company’s exposure to contingencies could change as new developments occur or more information becomes available. The outcome of the contingencies could vary significantly and could materially impact the consolidated results of operations, cash flows, and financial position of the Company. Management has applied its best judgment in applying SFAS No. 5 to these matters.

LIQUIDITY AND CAPITAL RESOURCES

As of December 31, 2002 and 2001, 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 $157 million deficit as of December 31, 2002, compared to a $207 million deficit as of December 31, 2001. The Company’s capital expenditures, debt repayments and operating requirements are expected to be funded by cash from operations. Management believes the Company has adequate financial flexibility and resources to meet its future needs.

Operating Cash Flows

Net cash provided by operating activities increased to $419 million in 2002 from $312 million in 2001, mostly due to reduced tax payments as a result of increased taxable income timing differences in 2002 associated with the capitalization of certain costs.

Investing Cash Flows

The primary uses of cash for investing activities are capital expenditures and advances funded to affiliates. Capital expenditures were $180 million for 2002 and $150 million for 2001. These expenditures consist primarily of business expansion projects, and renewals and betterments which extend the useful life of property, plant and equipment. Projected 2003 capital expenditures, including allowance for funds used during construction, are approximately $85 million, with market expansion approximating 36% of the capital budget. The decrease in projected capital expenditures in comparison to previous years is due primarily to an anticipated decrease in expansion projects.

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, acquisition opportunities, market volatility and economic trends.

The increase in advances receivable-affiliate was primarily a result of advancing the net proceeds of the $750 million bond issuances in July 2002 to Duke Capital Corporation (Duke Capital), a wholly owned subsidiary of Duke Energy that provides cash-management, financing, and credit enhancement services on a centralized basis for its subsidiaries, including the Company.

Financing Cash Flows

The Company’s consolidated capital structure at December 31, 2002, including short-term debt, was 36% debt and 64% partners’ capital. Fixed charges coverage, calculated using SEC guidelines, was 6.4 times for 2002.

In July 2002, the Company issued $300 million of 5.25% senior unsecured bonds due in 2007 and $450 million of 7.0% senior unsecured bonds due in 2032. The proceeds from these issuances were used for the repayment of $100 million, 8% notes payable in July 2002 and other pipeline and corporate activities, including pipeline expansion and maintenance projects and advances to affiliates.

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Credit Ratings. In August 2002, Standard & Poor’s (S&P) downgraded its long term ratings for Duke Energy, Duke Capital, and the Company, one ratings level, changing its outlook to Stable and leaving Duke Energy’s commercial paper ratings unchanged. S&P’s actions were based principally on a reassessment of Duke Energy’s consolidated creditworthiness and S&P’s perceived increase in risk of energy trading and merchant generation activities. In January 2003, S&P again lowered its long-term ratings for Duke Energy, Duke Capital, and the Company. In addition, S&P lowered the short-term ratings for Duke Energy and Duke Capital. This action was based primarily on S&P’s determination that reductions in Duke Energy’s capital and investment expenditures and Duke Energy’s planned asset divestitures will not be sufficient to provide funds needed to lower debt and reduce interest expense quickly enough to offset the impact of Duke Energy’s consolidated decreased earnings in 2002 and anticipated lower Duke Energy consolidated earnings in 2003. S&P concluded this action by placing Duke Energy, Duke Capital, and the Company on Negative Outlook citing the need to review Duke Energy’s progress on its divestiture program and its need to improve certain financial measures.

In October 2002, Fitch Ratings (Fitch) downgraded its long-term ratings for Duke Energy and its long-term and short-term ratings of Duke Capital one ratings level, due primarily to Duke Energy’s reduced earnings outlook for the remainder of 2002 and 2003. Although the ratings of the Company’s senior unsecured notes were not changed by Fitch, Fitch placed Duke Energy, Duke Capital, and the Company on Negative Outlook due to the ongoing uncertainty surrounding the merchant power industry and investigations by the FERC and the SEC into certain Duke Energy matters. In January 2003, Fitch lowered the long-term and short-term ratings of Duke Energy and the long-term ratings of Duke Capital, and also lowered the ratings of the Company. Those actions were based on Duke Energy’s announcements that consolidated profits for 2002 and 2003 were expected to be well below previous estimates. Fitch concluded its actions leaving Duke Energy, Duke Capital, and the Company, on Negative Outlook due to the continued uncertainty of ongoing FERC and SEC investigations and the perceived execution risk in Duke Energy’s plans for non-core asset dispositions over the next year.

In December 2002, Moody’s Investors Service (Moody’s) lowered its long-term and short-term ratings of Duke Energy, and its long-term ratings of Duke Capital and the Company. Moody’s actions were in response to lower actual and anticipated Duke Energy consolidated earnings and cash flow as a result of continued weakness in wholesale energy markets both in the U.S. and abroad. Moody’s concluded its action placing Duke Energy, Duke Capital, and the Company on Negative Outlook reflecting Moody’s perceived execution risk in Duke Capital’s program to strengthen its balance sheet.

As of February 28, 2003, the Company’s senior unsecured credit ratings were “A-”(S&P), “Baa1” (Moody’s), and “BBB+” (Fitch). The ratings of the Company and its parent companies may be 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, including disposition of non-core assets, or if Duke Energy’s earnings outlook deteriorates, Duke Energy’s and the Company’s ratings could be further affected.

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Contractual Obligations and Commercial Commitments

The following table summarizes the Company’s contractual cash obligations for each of the years presented.

Contractual Cash Obligations

There were no outstanding commercial commitments (such as guarantees or letters of credits) as of December 31, 2002.

CURRENT ISSUES

Regulatory Matters. The FERC is continually proposing and implementing new rules and regulations affecting the natural gas industry, most notably interstate natural gas transmission companies that 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. (For information on additional regulatory matters, see Note 3 to the Consolidated Financial Statements, “Regulatory Matters.”)

In 2000, the FERC issued Order 637, which revised its regulations for the intended purpose of improving the competitiveness and efficiency of natural gas markets. Order 637 effected changes in capacity segmentation, rights of first refusal (ROFR), scheduling procedures, as well as various reporting requirements intended to provide more transparent pricing information and permit more effective monitoring of the market. The FERC also required each interstate pipeline to submit individual compliance filings to implement the requirements of Order 637. Several parties, including the Company, filed appeals in the District of Columbia Court of Appeals seeking court review of various aspects of Order 637, including (i) the right of customers to segment their capacity rights in a manner that would allow both a forwardhaul and a backhaul transportation transaction to a single delivery point, and (ii) the ROFR granted to existing customers to extend contracts beyond the end of the contract’s primary term. In April, 2002, the District of Columbia Court of Appeals generally affirmed Order 637 but remanded certain issues to the FERC for further disposition, including the forwardhaul/backhaul and ROFR issues. These matters are still under review by the FERC.

In addition to the FERC’s general Order 637 rulemaking proceeding, the FERC also required each interstate pipeline company to make individual compliance filings to implement the specific requirements of Order 637. The Company made its Order 637 compliance filing with the FERC during the third quarter of 2001. On February 27, 2002, the FERC issued an order approving, subject to modifications, the pro forma tariff sheets submitted by the Company. The Company, as well as several other parties, filed for rehearing of the February 27, 2002, order with respect to certain issues. The Company also submitted revised tariff sheets on May 29, 2002, reflecting the modifications required by the FERC. The FERC issued an order on February 24, 2003 addressing the various rehearing requests as well as the Company’s tariff filings, and requiring the Company to implement certain findings from the order in the second quarter of 2003 and other findings in the third quarter of 2003.

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Management believes that the implementation of Order 637 will have no material adverse effect on the Company’s future consolidated results of operations, cash flows or financial position.

Environmental. The Company is subject to federal, state and local regulations regarding air and water quality, hazardous and solid waste disposal and other environmental matters.

Remediation activities. The Company is responsible for environmental remediation at various impacted properties or contaminated sites. These include some sites that are part of ongoing Company operations or are owned by the Company as well as sites owned by third parties. These matters typically involve management of contaminated soils and may involve ground water remediation. They are managed in conjunction with the relevant federal, state, and local agencies. These sites or matters vary, for example, with respect to site conditions and location, remedial requirements, sharing of responsibility by other entities, and complexity. Certain matters can involve statutory joint and several liability provisions, strict liability, or cost recovery or contribution actions, whereby the Company could potentially be held responsible for contamination caused by other parties. In some instances, the Company may share any liability associated with contamination with other potentially responsible parties, and the Company may benefit from insurance policies or contractual indemnities that cover some cleanup costs. All of these sites generally are managed in the normal course of business. At December 31, 2002 and 2001, the Company has recorded reserves for remediation activities on an undiscounted basis for approximately $26 million and $52 million, respectively. Management believes that completion or resolution of these matters will have no material adverse effect on consolidated results of operations, cash flows, or financial position.

Air Quality Control. The Company operates compressor stations located in 15 different states. From time to time states, as well as the EPA, will modify the regulatory requirements in order to maintain compliance with the Federal Clean Air Act requirements. These regulatory modifications sometimes necessitate the addition of emission controls. Management estimates that the Company will spend up to approximately $30 million in capital costs for additional emission controls through 2007 in order to comply with new EPA and state regulatory requirements. These estimates remain subject to change, however, due to continuing changes to the requirements. Management believes that completion or resolution of these matters will have no material adverse effect on consolidated results of operations, cash flows, or financial position.

New Accounting Standards

SFAS No. 142, “Goodwill and Other Intangible Assets.” The Company adopted SFAS No. 142 as of January 1, 2002. SFAS No. 142 requires that goodwill no longer be amortized over an estimated useful life, as previously required. Instead, goodwill amounts are subject to fair value-based impairment assessments. The Company did not recognize any impairment due to the adoption of SFAS No. 142. SFAS No. 142 also requires certain identifiable intangible assets to be recognized separately and amortized as appropriate upon adoption. No adjustments to intangibles were identified by the Company at adoption.

The following table shows what net income would have been if amortization (including any related tax effects) related to goodwill that is no longer being amortized had been excluded from prior periods.

Goodwill—Adoption of SFAS No. 142

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SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” The Company adopted SFAS No. 144 on January 1, 2002. The new rules supersede SFAS No. 121, “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of.” The new rules retain many of the fundamental recognition and measurement provisions, but significantly change the criteria for classifying an asset as held-for-sale or as a discontinued operation. Adoption of the new standard had no effect on the Company’s consolidated results of operations or financial position.

SFAS No. 143, “Accounting for Asset Retirement Obligations.” In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 143 which addresses financial accounting and reporting for 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.

SFAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset. This additional carrying amount is then depreciated over the life of the asset. The liability increases due to the passage of time based on the time value of money until the obligation is settled.

SFAS No. 143 was effective for fiscal years beginning after June 15, 2002, and will be adopted by the Company in the first quarter of 2003. The implementation of the standard is expected to result in a net $6 million increase in property, plant and equipment. Liabilities are expected to increase by approximately $6 million, which represents the establishment of an asset retirement obligation.

FASB Interpretation No. 45 (FIN 45), “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.” In November 2002, the FASB issued FIN 45 which requires a guarantor to recognize a liability for the fair value of the obligation it assumes under certain guarantees. Additionally, FIN 45 requires a guarantor to disclose certain aspects of each guarantee, or each group of similar guarantees, including the nature of the guarantee, the maximum exposure under the guarantee, the current carrying amount of any liability for the guarantee, and any recourse provisions allowing the guarantor to recover from third parties any amounts paid under the guarantee. The disclosure provisions of FIN 45 are effective for financial statements for both interim and annual periods ending after December 15, 2002. As of December 31, 2002, the Company had no outstanding guarantees. The fair value measurement provisions of FIN 45 are to be applied on a prospective basis to guarantees issued or modified after December 31, 2002.

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

Risk and Accounting Policies

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

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Commodity Price Risk

Hedging Strategies. The Company is exposed to market fluctuations in the prices of energy commodities related to the Company’s operations. 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 contracts to hedge such price risks. 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 fair value of the hedge instrument offsets the transaction being hedged, there is no impact to the Consolidated Statements of Income. However, changes in fair values will result in changes in the Consolidated Balance Sheets and the Consolidated Statements of Comprehensive Income. Accordingly, assumptions and valuation techniques for these contracts have no impact on reported earnings or cash flows prior to settlement. The unrealized gains or losses on these contracts are deferred in Other Comprehensive Income (OCI) and included in Other Current or Noncurrent Assets or Liabilities on the Consolidated Balance Sheets, in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” Amounts deferred in OCI are realized in earnings concurrently with the transaction being hedged. (See Notes 2 and 8 to the Consolidated Financial Statements.) However, in instances where the hedging contract no longer qualifies for hedge accounting, amounts included in OCI through the date of de-designation remain in OCI until the underlying transaction actually occurs. The derivative contract (if continued as an open position) will be marked to market currently through earnings. Several factors influence the effectiveness of a hedge contract, including counterparty credit risk and using contracts with different commodities or unmatched terms. Hedge effectiveness is monitored regularly and measured each month. To the extent hedge contracts are deemed ineffective, as defined by SFAS No. 133, the impact may increase or decrease earnings.

Based on a sensitivity analysis as of December 31, 2002, it was estimated that a difference of one cent per gallon in the average price of natural gas liquids in 2003 would have a corresponding effect on Earnings Before Income Taxes (EBT) of approximately $1 million, after considering the effect of the Company’s commodity hedge positions. Comparatively, the same sensitivity analysis as of December 31, 2001 estimated that EBT would have changed by approximately $1 million for 2002 production.

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 in accordance with corporate credit policy and monitors the appropriateness of those limits on an ongoing basis. The Company also obtains cash, letters of credit, or other 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

See Notes to Consolidated Financial Statements.

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TEXAS EASTERN TRANSMISSION, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

See Notes to Consolidated Financial Statements.

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TEXAS EASTERN TRANSMISSION, LP

CONSOLIDATED BALANCE SHEETS

See Notes to Consolidated Financial Statements.

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TEXAS EASTERN TRANSMISSION, LP

CONSOLIDATED BALANCE SHEETS

See Notes to Consolidated Financial Statements.

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TEXAS EASTERN TRANSMISSION, LP

CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL AND STOCKHOLDER’S EQUITY

See Notes to Consolidated Financial Statements.

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TEXAS EASTERN TRANSMISSION, LP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

See Notes to Consolidated Financial Statements.

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TEXAS EASTERN

Notes To Consolidated Financial Statements

For the Years Ended December 31, 2002, 2001 and 2000

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 was reclassified as partnership equity. 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 significant intercompany transactions and balances.

Conformity with generally accepted accounting principles (GAAP) 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.

For hedge contracts, the Company formally assesses, both at the hedge contract’s inception and on an ongoing basis, whether the hedge contract is highly effective in offsetting changes in fair values or cash flows of hedged items.

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 pricing models developed primarily from historical and expected correlations with quoted market prices.

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 the Consolidated Statements of Comprehensive Income as Other Comprehensive Income (OCI) until earnings are affected by the hedged item. Settlement amounts and ineffective portions of cash flow hedges are removed from OCI and recorded in the Consolidated Statements of Operations in the same accounts as the item being hedged. The Company discontinues hedge accounting prospectively when it is determined that the derivative no longer qualifies as an effective hedge, or when it is no longer probable that the hedged transaction will occur. When hedge accounting is discontinued because the derivative no longer qualifies as an effective hedge, the derivative continues to be carried on the Consolidated Balance Sheets at its fair value, with subsequent changes in its fair value recognized in current-period earnings. Gains and losses related to discontinued hedges that were previously accumulated in OCI will remain in OCI until the underlying contract is reflected in earnings, unless it is no

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Notes To Consolidated Financial Statements — Continued

longer probable that the hedged transaction will occur. Gains and losses that were accumulated in OCI will be immediately recognized in current-period earnings if it is no longer probable that the hedged transaction will occur.

Gas Imbalances. Gas imbalances occur as a result of differences in volumes of gas received and delivered. Gas imbalance receivables and payables are valued at market. (See Note 5 for additional information.)

Goodwill. Goodwill is the cost of an acquisition less the fair value of the net assets of the acquired business. Prior to 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. The amount of goodwill reported on the Consolidated Balance Sheets as of December 31, 2002 and 2001 was $136 million, net of accumulated amortization of $109 million. The Company implemented Statement of Financial Accounting Standards (SFAS) No. 142, “Goodwill and Other Intangible Assets” as of January 1, 2002. For information on the impact of SFAS No. 142 on goodwill and goodwill amortization see the New Accounting Standards section of this footnote.

The changes in the carrying amount of goodwill for the years ended December 31, 2002 and 2001 are as follows:

Goodwill

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 2002, 2.4% for 2001 and 2.3% for 2000.

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.

Impairment of Long-Lived Assets. The Company reviews the recoverability of long-lived assets and intangible assets, excluding goodwill, when circumstances indicate that the carrying amount of the asset may not be recoverable. This evaluation is based on various analyses, including undiscounted cash flow projections. The carrying amount is not recoverable if it exceeds the undiscounted sum of cash flows expected to result from the use and eventual disposition of the asset. If the carrying value is not recoverable, the impairment loss is measured as the excess of the asset’s carrying value over its fair value measure.

Goodwill is reviewed annually for impairment unless changes in circumstances indicate an interim review should be performed.

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Notes To Consolidated Financial Statements — Continued

For the years ended 2002, 2001 and 2000, there were no impairments recorded by the Company for its long-lived or intangible assets.

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.

Contingencies. The Company follows SFAS No. 5, “Accounting for Contingencies,” to determine accounting and disclosure requirements for contingencies. The Company operates in a highly regulated environment. Governmental bodies such as the FERC, the Securities Exchange Commission (SEC), the Internal Revenue Service, the Department of Labor, the Environmental Protection Agency (EPA), the U.S. Department of Transportation and others have purview over various aspects of the Company’s business operations and public reporting. Reserves are established when required in management’s judgment and disclosures are made when appropriate regarding litigation, assessments, creditworthiness of customers or counterparties, and self-insurance exposures, among others. Discussion of various contingencies that the Company is addressing is covered in Note 10. The evaluation of these contingencies is performed by various specialists inside and outside of the Company. Accounting for contingencies requires significant judgment by management regarding the estimated probabilities and ranges of exposure to potential liability. Management’s assessment of the Company’s exposure to contingencies could change as new developments occur or more information becomes available. The outcome of the contingencies could vary significantly and could materially impact the financial results and cash flows of the Company. Management has applied its best judgment in applying SFAS No. 5 to these matters.

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. (For more information on regulatory assets and liabilities, see Note 3.) 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.

Revenue. Revenues on natural gas transportation and storage are recognized when the service is provided. Pending final approval of rate cases, a portion of the revenues is subject to possible refund, 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, 2002 or 2001. The allowance for doubtful accounts was $2 million as of December 31, 2002 and December 31, 2001.

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Notes To Consolidated Financial Statements — Continued

Revenues from natural gas throughput are estimated in the month of delivery based on contract data, regulatory information, and preliminary measurements and allocations. Final bills for the current month are billed in the following month. Receivables on the Consolidated Balance Sheets included $62 million as of December 31, 2002, and $58 million as of December 31, 2001, for natural gas transportation and storage services provided but not yet billed.

Public Service Electric and Gas Company (PSE&G), a local distribution company (or LDC), was the Company’s only customer accounting for 10% or more of consolidated revenues in 2002, 2001 and 2000. Total billings for transportation and storage services provided by the Company to PSE&G were approximately $78 million, $80 million, and $110 million during 2002, 2001, and 2000, 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. (See Note 7 for additional information.)

Rates used for capitalization of AFUDC by the Company’s regulated operations are calculated in compliance with GAAP rules.

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. For the year ended December 31, 2001, the Company reclassified as earnings $1 million of losses from OCI for derivatives included in the transition adjustment related to hedge transactions that settled. The amount reclassified out of OCI will be different from the amount included in the transition adjustment due to market price changes since January 1, 2001.

New Accounting Standards. SFAS No. 142, “Goodwill and Other Intangible Assets.” The Company adopted SFAS No. 142 as of January 1, 2002. SFAS No. 142 requires that goodwill no longer be amortized over an estimated useful life, as previously required. Instead, goodwill amounts are subject to fair value-based impairment assessments. The Company did not recognize any impairment due to the adoption of SFAS No. 142. SFAS No. 142 also requires certain identifiable intangible assets to be recognized separately and amortized as appropriate upon adoption. No adjustments to intangibles were identified by the Company at adoption.

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TEXAS EASTERN

Notes To Consolidated Financial Statements — Continued

The following table shows what net income would have been if amortization (including any related tax effects) related to goodwill that is no longer being amortized had been excluded from prior periods. (See additional goodwill disclosures made earlier in this footnote.)

Goodwill—Adoption of SFAS No. 142

SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” The Company adopted SFAS No. 144 on January 1, 2002. The new rules supersede SFAS No. 121, “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of.” The new rules retain many of the fundamental recognition and measurement provisions, but significantly change the criteria for classifying an asset as held-for-sale or as a discontinued operation. Adoption of the new standard had no effect on the Company’s consolidated results of operations or financial position.

SFAS No. 143, “Accounting for Asset Retirement Obligations.” In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 143 which addresses financial accounting and reporting for 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.

SFAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset. This additional carrying amount is then depreciated over the life of the asset. The liability increases due to the passage of time based on the time value of money until the obligation is settled.

SFAS No. 143 was effective for fiscal years beginning after June 15, 2002, and will be adopted by the Company in the first quarter of 2003. The implementation of the standard is expected to result in a net $6 million increase in property, plant and equipment. Liabilities are expected to increase by approximately $6 million, which represents the establishment of an asset retirement obligation.

FASB Interpretation No. 45 (FIN 45), “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.” In November 2002, the FASB issued FIN 45 which requires a guarantor to recognize a liability for the fair value of the obligation it assumes under certain guarantees. Additionally, FIN 45 requires a guarantor to disclose certain aspects of each guarantee, or each group of similar guarantees, including the nature of the guarantee, the maximum exposure under the guarantee, the current carrying amount of any liability for the guarantee, and any recourse provisions allowing the guarantor to recover from third parties any amounts paid under the guarantee. The disclosure provisions of FIN 45 are effective for financial statements for both interim and annual periods ending after December 15, 2002. As of December 31, 2002, the Company had no outstanding guarantees. The fair value measurement provisions of FIN 45 are to be applied on a prospective basis to guarantees issued or modified after December 31, 2002.

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

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Notes To Consolidated Financial Statements — Continued

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

Order 637. In 2000, the FERC issued Order 637, which revised its regulations for the intended purpose of improving the competitiveness and efficiency of natural gas markets. Order 637 effected changes in capacity segmentation, rights of first refusal (ROFR), scheduling procedures, as well as various reporting requirements intended to provide more transparent pricing information and permit more effective monitoring of the market. The FERC also required each interstate pipeline to submit individual compliance filings to implement the requirements of Order 637. Several parties, including the Company, filed appeals in the District of Columbia Court of Appeals seeking court review of various aspects of Order 637, including (i) the right of customers to segment their capacity rights in a manner that would allow both a forwardhaul and a backhaul transportation transaction to a single delivery point, and (ii) the ROFR granted to existing customers to extend contracts beyond the end of the contract’s primary term. In April, 2002, the District of Columbia Court of Appeals generally affirmed Order 637 but remanded certain issues to the FERC for further disposition, including the forwardhaul/backhaul and ROFR issues. These matters are still under review by the FERC.

In addition to the FERC’s general Order 637 rulemaking proceeding, the FERC also required each interstate pipeline company to make individual compliance filings to implement the specific requirements of Order 637. The Company made its Order 637 compliance filing with the FERC during the third quarter of 2001. On February 27, 2002, the FERC issued an order approving, subject to modifications, the pro forma tariff sheets submitted by the Company. The Company, as well as several other parties, filed for rehearing of the February 27, 2002, order with respect to certain issues. The Company also submitted revised tariff sheets on May 29, 2002, reflecting the modifications required by the FERC. The FERC issued an order on February 24, 2003 addressing the various rehearing requests as well as the Company’s tariff filings, and requiring the Company to implement certain findings from the order in the second quarter of 2003 and other findings in the third quarter of 2003.

Management believes that the implementation of Order 637 will have no material adverse effect on the Company’s future consolidated results of operations, cash flows or financial position.

In addition, 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 that remain subject to the FERC’s jurisdiction. 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.

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Notes To Consolidated Financial Statements — Continued

Fuel Tracker. At December 31, 2002 and 2001, Other Current Assets on the Consolidated Balance Sheets included $9 million and $17 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.

Standards of Conduct. In September 2001, the FERC issued a Notice of Proposed Rulemaking (NOPR) announcing they would substantially modify the current standards of conduct uniformly applicable to natural gas pipelines and electric transmitting public utilities currently subject to differing standards. The proposal impacts how companies and their affiliates interact and share information by broadening the definition of “affiliate” covered by the standards of conduct. Duke Energy filed extensive comments on the NOPR with the FERC in December 2001. In April 2002, the FERC Staff issued an analysis of all comments received which reflected important progress in several areas. With regard to corporate governance, however, the FERC Staff’s analysis recommended adoption of an automatic imputation rule which could impact parent company oversight of subsidiaries with pipeline and storage functions. A public conference was held in May 2002 to discuss the proposed revisions to the gas and electric standards of conduct. Duke Energy filed supplemental comments with respect to the FERC Staff’s analysis in June 2002. The FERC is expected to take further action on the NOPR in the first half of 2003.

Note 4. Related Party Transactions

Income Statement Transactions