Form 10-K

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes ¨ No x

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 (or for such shorter period that the registrant was required to file such reports) 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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer (as defined in Rule 12b-2 of the Securities Exchange Act of 1934).

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

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

All of the registrant’s limited liability company member interests are directly owned by Duke Energy Corporation (File No. 1-32853), which files reports and proxy material pursuant to the Securities Exchange Act of 1934, as amended.

This document includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements are based on management’s beliefs and assumptions. These forward-looking statements are identified by terms and phrases such as “anticipate,” “believe,” “intend,” “estimate,” “expect,” “continue,” “should,” “could,” “may,” “plan,” “project,” “predict,” “will,” “potential,” “forecast,” and similar expressions. Forward-looking statements involve risks and uncertainties that may cause actual results to be materially different from the results predicted. Factors that could cause actual results to differ materially from those indicated in any forward-looking statement include, but are not limited to:

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

Duke Energy Holding Corp. (Duke Energy HC) was incorporated in Delaware on May 3, 2005 as Deer Holding Corp., a wholly-owned subsidiary of Duke Energy Corporation (Old Duke Energy). On April 3, 2006, in accordance with their previously announced merger agreement, Old Duke Energy and Cinergy Corp. (Cinergy) merged into wholly-owned subsidiaries of Duke Energy HC, resulting in Duke Energy HC becoming the parent entity. In connection with the closing of the merger transactions, Duke Energy HC changed its name to Duke Energy Corporation (Duke Energy) and Old Duke Energy converted its form of organization from a North Carolina corporation to a North Carolina limited liability company named Duke Power Company LLC (Duke Power). As a result of the merger transactions, each share of common stock of Old Duke Energy was exchanged for one share of Duke Energy common stock, with Duke Energy becoming the owner of Old Duke Energy shares. All shares of Old Duke Energy were subsequently converted into membership interests in Duke Power, which is owned by Duke Energy. Effective October 1, 2006, Duke Power changed its name to Duke Energy Carolinas, LLC (Duke Energy Carolinas). The term “Duke Energy Carolinas,” used in this report for all periods presented, refers to Old Duke Energy or to Duke Energy Carolinas, as the context requires. Additionally, the term “Duke Energy” as used in this report refers to Old Duke Energy or Duke Energy, as the context requires.

Up through April 3, 2006, Duke Energy Carolinas represented an energy company located in the Americas with a real estate subsidiary. On April 3, 2006, Duke Energy Carolinas transferred to its parent, Duke Energy, all of its membership interests in its wholly-owned subsidiary Spectra Energy Capital LLC (Spectra Energy Capital, formerly Duke Capital, LLC), including the operations of Duke Energy Merchants, LLC and Duke Energy Merchant Finance, LLC (collectively DEM), which Duke Energy Carolinas transferred to Spectra Energy Capital on April 1, 2006. As a result of Duke Energy Carolinas’ transfer of its membership interests in Spectra Energy Capital, Spectra Energy Capital’s results of operations, including DEM, for the three months ended March 31, 2006 and the years ended December 31, 2005 and 2004 are reflected as discontinued operations in the accompanying Consolidated Statements of Operations. Following these transactions, Duke Energy Carolinas is an electric utility company with operations in North Carolina and South Carolina.

Duke Energy Carolinas generates, transmits, distributes and sells electricity. Its service area covers about 22,000 square miles with an estimated population of 6 million in central and western North Carolina and western South Carolina. Duke Energy Carolinas supplies electric service to more than 2.2 million residential, commercial and industrial customers over 97,000 miles of distribution lines and a 13,000 mile transmission system. In addition, municipal and cooperative customers who purchased portions of the Catawba Nuclear Station may also buy power from a variety of suppliers including Duke Energy Carolinas, through contractual agreements. (For more information on the Catawba Nuclear Station joint ownership, see Note 5 to the Consolidated Financial Statements, “Joint Ownership of Generating Facilities.”). These electric operations are subject to the rules and regulations of the Federal Energy Regulatory Commission (FERC), the North Carolina Utilities Commission (NCUC) and the Public Service Commission of South Carolina (PSCSC).

In December 2006, Duke Energy Carolinas announced an agreement to purchase a portion of Saluda River Electric Cooperative, Inc.’s ownership interest in the Catawba Nuclear Station. Under the terms of the agreement, Duke Energy Carolinas will pay approximately $158 million for the additional ownership interest of the Catawba Nuclear Station. Following the closing of the transaction, Duke Energy Carolinas will own approximately 19 percent of Catawba Nuclear Station. This transaction, which is expected to close prior to September 30, 2008, is subject to approval by various state and federal agencies.

Duke Energy Carolinas is a North Carolina corporation. Its principal executive offices are located at 526 South Church Street, Charlotte, North Carolina 28202-1803. The telephone number is 704-594-6200. Duke Energy Carolinas electronically files reports with the Securities and Exchange Commission (SEC), including annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to such reports. The public may read and copy any materials that Duke Energy Carolinas files with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., 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 and other information regarding issuers that file electronically with the SEC at http://www.sec.gov. Additionally, information about Duke Energy Carolinas, including its reports filed with the SEC, is available through Duke Energy’s web site at http://www.duke-energy.com. Such reports are accessible at no charge through Duke Energy’s web site and are made available as soon as reasonably practicable after such material is filed with or furnished to the SEC.

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

(For more information on environmental matters involving Duke Energy Carolinas, including possible liability and capital costs, see Notes 4 and 16 to the Consolidated Financial Statements, “Regulatory Matters,” and “Commitments and Contingencies—Environmental,” respectively.)

Except to the extent discussed in Note 4 to the Consolidated Financial Statements, “Regulatory Matters,” and Note 16 to the Consolidated Financial Statements, “Commitments and Contingencies,” compliance with federal, state and local provisions regulating the discharge of materials into the environment, or otherwise protecting the environment, is incorporated into the routine cost structure of our business and is not expected to have a material adverse effect on the competitive position, consolidated results of operations, cash flows or financial position of Duke Energy Carolinas.

The risk factors discussed herein relate specifically to risks associated with Duke Energy Carolinas.

Duke Energy Carolinas’ revenues, earnings and results are dependent on state legislation and state and federal regulation that affect electric generation, transmission, distribution and related activities, as well as operations and costs, which may limit Duke Energy Carolinas’ ability to recover costs.

Duke Energy Carolinas is regulated on a cost-of-service/rate-of-return basis subject to the statutes and regulatory commission rules and procedures of North Carolina and South Carolina. If Duke Energy Carolinas’ earnings exceed the returns established by the state regulatory commissions, Duke Energy Carolinas’ retail electric rates may be subject to review by the commissions and possible reduction, which may decrease Duke Energy Carolinas’ future earnings. Additionally, if regulatory bodies do not allow recovery of costs incurred in providing service on a timely basis, Duke Energy Carolinas’ future earnings could be negatively impacted.

Duke Energy Carolinas is also subject to regulation by FERC and the Nuclear Regulatory Commission (NRC), by federal, state and local authorities under environmental laws. Regulation affects almost every aspect of Duke Energy Carolinas’ business, including, among other things, Duke Energy Carolinas’ ability to: take fundamental business management actions; determine the terms and rates of Duke Energy Carolinas’ transmission and distribution businesses’ services; make acquisitions; issue equity or debt securities; and engage in transactions between Duke Energy Carolinas’ utilities and other affiliates. Changes to these regulations are ongoing, and Duke Energy Carolinas cannot predict the future course of changes in this regulatory environment or the ultimate effect that this changing regulatory environment will have on its business. However, changes in regulation (including re-regulating previously deregulated markets) can cause delays in, or affect business planning for, transactions and can substantially increase Duke Energy Carolinas’ costs.

FERC has established certain market screens it employs to assess generation market power. Certain of these screens are difficult for a franchised utility to pass. In an order issued on June 30, 2005 the FERC revoked the authority for Duke Energy Carolinas to make wholesale power sales within its control area at market-based rates based on the FERC’s determination that Duke Energy Carolinas failed one of the applicable market screens. Pursuant to the FERC order, Duke Energy Carolinas paid partial refunds to certain wholesale customers and now makes wholesale power sales within its control area only at market-based rates.

Deregulation or restructuring in the electric industry may result in increased competition and unrecovered costs that could adversely affect Duke Energy Carolinas’ financial condition, results of operations or cash flows and Duke Energy Carolinas’ business.

Increased competition resulting from deregulation or restructuring efforts, including from the Energy Policy Act of 2005, could have a significant adverse financial impact on Duke Energy Carolinas and consequently on its results of operations, financial position, or cash flows. Increased competition could also result in increased pressure to lower costs, including the cost of electricity. Retail competition and the unbundling of regulated energy could have a significant adverse financial impact on Duke Energy Carolinas due to an impairment of assets, a loss of retail customers, lower profit margins or increased costs of capital. Duke Energy Carolinas cannot predict the extent and timing of entry by additional competitors into the electric markets, nor can Duke Energy Carolinas predict the impact of these changes on its financial position, results of operations or cash flows.

Duke Energy Carolinas may incur substantial costs and liabilities due to Duke Energy Carolinas’ ownership and operation of nuclear generating facilities.

Duke Energy Carolinas’ ownership interest in and operation of three nuclear stations subject Duke Energy Carolinas to various risks including, among other things: the potential harmful effects on the environment and human health resulting from the operation of nuclear facilities and the storage, handling and disposal of radioactive materials; limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with nuclear operations; and uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their licensed lives.

Duke Energy Carolinas’ ownership and operation of nuclear generation facilities requires Duke Energy Carolinas to meet licensing and safety-related requirements imposed by the NRC. In the event of non-compliance, the NRC may increase regulatory oversight, impose fines, and/or shut down a unit, depending upon its assessment of the severity of the situation. Revised security and safety requirements promulgated by the NRC, which could be prompted by, among other things, events within or outside of Duke Energy Carolinas’ control, such as a serious nuclear incident at a facility owned by a third-party, could necessitate substantial capital and other expenditures at Duke Energy Carolinas’ nuclear plants, as well as assessments against Duke Energy Carolinas to cover third-party losses. In addition, if a serious nuclear incident were to occur, it could have a material adverse effect on Duke Energy Carolinas’ results of operations and financial condition.

Duke Energy Carolinas’ ownership and operation of nuclear generation facilities also requires Duke Energy Carolinas to maintain funded trusts that are intended to pay for the decommissioning costs of Duke Energy Carolinas’ nuclear power plants. Poor investment performance of these decommissioning trusts’ holdings and other factors impacting decommissioning costs could unfavorably impact Duke Energy Carolinas’ liquidity and results of operations as Duke Energy Carolinas could be required to significantly increase its cash contributions to the decommissioning trusts.

Duke Energy Carolinas’ plans for future expansion and modernization of its generation fleet subject it to risk of future price and inflationary increases in the cost of such expenditures as well as the risk of recovering such costs in a timely manner which could materially impact Duke Energy Carolinas’ financial condition, results of operations or cash flows.

During the three-year period from 2007 to 2009, Duke Energy Carolinas anticipates annual capital expenditures of approximately $2 billion, for a total of approximately $6 billion. Duke Energy Carolinas has begun to see significant increases in the estimated costs of these capital projects as a result of strong domestic and international demand for the material, equipment, and labor necessary to construct these facilities. Increases in costs related to materials and services required to expand and modernize Duke Energy Carolinas’ generation fleet as well as Duke Energy Carolinas’ ability to recover these costs in a timely manner could materially impact Duke Energy Carolinas’ consolidated financial condition, results of operations or cash flows.

Duke Energy Carolinas must meet credit quality standards. If Duke Energy Carolinas is unable to maintain an investment grade credit rating, Duke Energy Carolinas would be required under credit agreements to provide collateral in the form of letters of credit or cash, which may materially adversely affect Duke Energy Carolinas’ liquidity. Duke Energy Carolinas cannot be sure that it will maintain investment grade credit ratings.

Duke Energy Carolinas’ senior unsecured long-term debt is rated investment grade by various rating agencies. Duke Energy Carolinas cannot be sure that the senior unsecured long-term debt of Duke Energy Carolinas will be rated investment grade.

If the rating agencies were to rate Duke Energy Carolinas below investment grade, the entity’s borrowing costs would increase, perhaps significantly. In addition, the entity would likely be required to pay a higher interest rate in future financings, and its potential pool of investors and funding sources would likely decrease. Further, if its short-term debt rating were to fall, the entity’s access to the commercial paper market could be significantly limited.

A downgrade below investment grade could also trigger termination clauses in some interest rate and derivative agreements, which would require cash payments. All of these events would likely reduce Duke Energy Carolinas’ liquidity and profitability and could have a material adverse effect on Duke Energy Carolinas’ financial position, results of operations or cash flows.

Duke Energy Carolinas relies on access to short-term money markets and longer-term capital markets to finance Duke Energy Carolinas’ capital requirements and support Duke Energy Carolinas’ liquidity needs, and Duke Energy Carolinas’ access to those markets can be adversely affected by a number of conditions, many of which are beyond Duke Energy Carolinas’ control.

Duke Energy Carolinas’ business is financed to a large degree through debt and the maturity and repayment profile of debt used to finance investments often does not correlate to cash flows from Duke Energy Carolinas’ assets. Accordingly, Duke Energy Carolinas relies on access to both short-term money markets and longer-term capital markets as a source of liquidity for capital requirements not satisfied by the cash flow from Duke Energy Carolinas’ operations and to fund investments originally financed through debt instruments with disparate maturities. If Duke Energy Carolinas is not able to access capital at competitive rates, Duke Energy Carolinas’ ability to finance its operations and implement its strategy will be adversely affected.

Market disruptions may increase Duke Energy Carolinas’ cost of borrowing or adversely affect its ability to access one or more financial markets. Such disruptions could include: economic downturns; the bankruptcy of an unrelated energy company; capital market conditions generally; market prices for electricity; terrorist attacks or threatened attacks on Duke Energy Carolinas’ facilities or unrelated energy companies; or the overall health of the energy industry. Restrictions on Duke Energy Carolinas’ ability to access financial markets may also affect Duke Energy Carolinas’ ability to execute Duke Energy Carolinas’ business plan as scheduled. An inability to access capital may limit Duke Energy Carolinas’ ability to pursue improvements or acquisitions that Duke Energy Carolinas may otherwise rely on for future growth.

Duke Energy Carolinas maintains revolving credit facilities to provide back-up for commercial paper programs and/or letters of credit. These facilities typically include financial covenants which limit the amount of debt that can be outstanding as a percentage of the total capital. Failure to maintain these covenants could preclude Duke Energy Carolinas from issuing commercial paper or letters of credit or borrowing under the revolving credit facility and could require certain of Duke Energy Carolinas’ affiliates to immediately pay down any outstanding drawn amounts under other revolving credit agreements.

Duke Energy Carolinas is exposed to credit risk of counterparties with whom Duke Energy Carolinas does business.

Adverse economic conditions affecting, or financial difficulties of, counterparties with whom Duke Energy Carolinas does business could impair the ability of these counterparties to pay for Duke Energy Carolinas’ services or fulfill their contractual obligations, or cause them to delay such payments or obligations. Duke Energy Carolinas depends on these counterparties to remit payments on a timely basis. Any delay or default in payment could adversely affect Duke Energy Carolinas’ cash flows, financial position or results of operations.

Poor investment performance of Duke Energy’s pension plan holdings and other factors impacting pension plan costs could unfavorably impact Duke Energy Carolinas’ liquidity and results of operations.

Duke Energy Carolinas participates in employee benefit plans sponsored by its parent, Duke Energy. Duke Energy Carolinas is allocated cost for these plans from Duke Energy. Duke Energy’s costs of providing non-contributory defined benefit pension plans are dependent upon a number of factors, such as the rates of return on plan assets, discount rates, the level of interest rates used to measure the required minimum funding levels of the plans, future government regulation and Duke Energy Carolinas’ proportionate share of

Duke Energy’s required or voluntary contributions made to the plans. Without sustained growth in the pension investments over time to increase the value of Duke Energy’s plan assets and depending upon the other factors impacting Duke Energy Carolinas’ allocated costs as discussed above, Duke Energy could be required to fund its plans with significant amounts of cash. Such cash funding obligations could have a material impact on Duke Energy Carolinas’ cash flows, financial position or results of operations.

Duke Energy Carolinas is subject to numerous environmental laws and regulations that require significant capital expenditures, can increase Duke Energy Carolinas’ cost of operations, and which may impact or limit Duke Energy Carolinas’ business plans, or expose Duke Energy Carolinas to environmental liabilities.

Duke Energy Carolinas is subject to numerous environmental laws and regulations affecting many aspects of Duke Energy Carolinas’ present and future operations, including air emissions (such as reducing NO_x, SO₂ and mercury emissions in the U.S., or potential future control of greenhouse-gas emissions), water quality, wastewater discharges, solid waste and hazardous waste. These laws and regulations can result in increased capital, operating, and other costs. These laws and regulations generally require Duke Energy Carolinas to obtain and comply with a wide variety of environmental licenses, permits, inspections and other approvals. Compliance with environmental laws and regulations can require significant expenditures, including expenditures for clean up costs and damages arising out of contaminated properties, and failure to comply with environmental regulations may result in the imposition of fines, penalties and injunctive measures affecting operating assets. The steps Duke Energy Carolinas takes to ensure that its facilities are in compliance could be prohibitively expensive. As a result, Duke Energy Carolinas may be required to shut down or alter the operation of its facilities, which may cause Duke Energy Carolinas to incur losses. Further, Duke Energy Carolinas’ regulatory rate structure and Duke Energy Carolinas’ contracts with clients may not necessarily allow Duke Energy Carolinas to recover capital costs Duke Energy Carolinas incurs to comply with new environmental regulations. Also, Duke Energy Carolinas may not be able to obtain or maintain from time to time all required environmental regulatory approvals for Duke Energy Carolinas’ operating assets or development projects. If there is a delay in obtaining any required environmental regulatory approvals, if Duke Energy Carolinas fails to obtain and comply with them or if environmental laws or regulations change and become more stringent, then the operation of Duke Energy Carolinas’ facilities or the development of new facilities could be prevented, delayed or become subject to additional costs. Although it is not expected that the costs of complying with current environmental regulations will have a material adverse effect on Duke Energy Carolinas’ cash flows, financial position or results of operations, no assurance can be made that the costs of complying with environmental regulations in the future will not have such an effect.

In addition, Duke Energy Carolinas is generally responsible for on-site liabilities, and in some cases off-site liabilities, associated with the environmental condition of Duke Energy Carolinas’ power generation facilities which Duke Energy Carolinas has acquired or developed, regardless of when the liabilities arose and whether they are known or unknown. In connection with some acquisitions and sales of assets, Duke Energy Carolinas may obtain, or be required to provide, indemnification against some environmental liabilities. If Duke Energy Carolinas incurs a material liability, or the other party to a transaction fails to meet its indemnification obligations to Duke Energy Carolinas, it could suffer material losses.

Duke Energy Carolinas is involved in numerous legal proceedings, the outcome of which are uncertain, and resolution adverse to Duke Energy Carolinas could negatively affect Duke Energy Carolinas’ cash flows, financial condition or results of operations.

Duke Energy Carolinas is subject to numerous legal proceedings. Litigation is subject to many uncertainties and Duke Energy Carolinas cannot predict the outcome of individual matters with assurance. It is reasonably possible that the final resolution of some of the matters in which Duke Energy Carolinas is involved could require Duke Energy Carolinas to make additional expenditures, in excess of established reserves, over an extended period of time and in a range of amounts that could have a material effect on Duke Energy Carolinas’ cash flows and results of operations. Similarly, it is reasonably possible that the terms of resolution could require Duke Energy Carolinas to change its business practices and procedures, which could also have a material effect on Duke Energy Carolinas’ cash flows, financial position or results of operations.

Duke Energy Carolinas’ results of operations may be negatively affected by sustained downturns or sluggishness in the economy, including low levels in the market prices of commodities, all of which are beyond Duke Energy Carolinas’ control.

Sustained downturns or sluggishness in the economy generally affect the markets in which Duke Energy Carolinas operates and negatively influence Duke Energy Carolinas’ energy operations. Declines in demand for electricity as a result of economic downturns in Duke Energy Carolinas’ service territories will reduce overall electricity sales and lessen Duke Energy Carolinas’ cash flows, especially as Duke Energy Carolinas’ industrial customers reduce production and, therefore, consumption of electricity. Although Duke Energy

Carolinas’ business is subject to regulated allowable rates of return and recovery of fuel costs under a fuel adjustment clause, overall declines in electricity sold as a result of economic downturn or recession could reduce revenues and cash flows, thus diminishing results of operations.

Duke Energy Carolinas also sells electricity into the spot market or other competitive power markets on a contractual basis. With respect to such transactions, its revenues and results of operations are likely to depend, in large part, upon prevailing market prices in Duke Energy Carolinas’ regional markets and other competitive markets. These market prices may fluctuate substantially over relatively short periods of time and could reduce Duke Energy Carolinas’ revenues and margins and thereby diminish Duke Energy Carolinas’ results of operations.

Lower demand for the electricity Duke Energy Carolinas sells and lower prices for electricity result from multiple factors that affect the markets where Duke Energy Carolinas sells electricity including:

These factors have led to industry-wide downturns that have resulted in the slowing down or stopping of construction of new power plants and announcements by Duke Energy Carolinas and other energy suppliers of plans to sell non-strategic assets, subject to regulatory constraints, in order to boost liquidity or strengthen balance sheets. Proposed sales by other energy suppliers could increase the supply of the types of assets that Duke Energy Carolinas is attempting to sell. In addition, recent FERC actions addressing power market concerns could negatively impact the marketability of Duke Energy Carolinas’ electric generation assets.

Duke Energy Carolinas’ operating results may fluctuate on a seasonal and quarterly basis.

Electric power generation is generally a seasonal business. In the service territories in which Duke Energy Carolinas operates, demand for power peaks during the hot summer months and colder winter months, with market prices also peaking at that time. Further, extreme weather conditions such as heat waves or winter storms could cause these seasonal fluctuations to be more pronounced. As a result, in the future, the overall operating results of Duke Energy Carolinas’ businesses may fluctuate substantially on a seasonal and quarterly basis and thus make period comparison less relevant.

Certain events in the energy markets beyond Duke Energy Carolinas’ control could result in new laws or regulations which could have a negative impact on Duke Energy Carolinas’ financial position, cash flows or results of operations.

There is growing consensus that some form of regulation will be forthcoming at the federal level with respect to greenhouse gas emissions (including CO₂). Additionally, accounting standard setters are evaluating the accounting and reporting for emission allowances. Resolution of these matters could lead to substantial changes in laws and regulations affecting Duke Energy Carolinas, including new accounting standards that could change the way Duke Energy Carolinas is required to record revenues, expenses, assets and liabilities. These types of regulations could have a negative impact on Duke Energy Carolinas’ financial position, cash flows or results of operations or access to capital.

Potential terrorist activities or military or other actions could adversely affect Duke Energy Carolinas’ business.

The continued threat of terrorism and the impact of retaliatory military and other action by the United States and its allies may lead to increased political, economic and financial market instability and volatility in prices for natural gas and oil which may materially adversely affect Duke Energy Carolinas in ways it cannot predict at this time. In addition, future acts of terrorism and any possible

reprisals as a consequence of action by the United States and its allies could be directed against companies operating in the United States. Infrastructure and generation facilities such as Duke Energy Carolinas’ nuclear plants could be potential targets of terrorist activities. The potential for terrorism has subjected Duke Energy Carolinas’ operations to increased risks and could have a material adverse effect on Duke Energy Carolinas’ business. In particular, Duke Energy Carolinas may experience increased capital and operating costs to implement increased security for its plants, including its nuclear power plants under the NRC’s design basis threat requirements, such as additional physical plant security, additional security personnel or additional capability following a terrorist incident.

The insurance industry has also been disrupted by these events. As a result, the availability of insurance covering risks of Duke Energy Carolinas and its competitors typically insure against may decrease. In addition, the insurance Duke Energy Carolinas is able to obtain may have higher deductibles, higher premiums and more restrictive policy terms.

As of December 31, 2006, Duke Energy Carolinas operated three nuclear generating stations with a combined net capacity of 5,020 megawatts (MW) (including a 12.5% ownership in the Catawba Nuclear Station), eight coal-fired stations with a combined net capacity of 7,754 MW, thirty hydroelectric stations (including two pumped-storage facilities) with a combined net capacity of 3,168 MW and eight combustion turbine stations with a combined net capacity of 3,266 MW. The stations are located in North Carolina and South Carolina.

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

For information regarding legal proceedings, including regulatory and environmental matters, see Note 4 to the Consolidated Financial Statements, “Regulatory Matters” and Note 16 to the Consolidated Financial Statements, “Commitments and Contingencies—Litigation” and “Commitments and Contingencies—Environmental.”

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

All of the outstanding limited liability company member interests of Duke Energy Carolinas are owned by Duke Energy. There is no market for Duke Energy Carolinas’ limited liability company member interests. Duke Energy Carolinas paid $761 million in distributions on its member’s equity for the nine months ended December 31, 2006. During the three months ended March 31, 2006 and the years ended December 31, 2005 and 2004, Duke Energy Carolinas paid dividends on its common stock. Duke Energy Carolinas continues to review its policy with respect to paying future distributions and anticipates making periodic distributions over the next three years to facilitate Duke Energy’s stock repurchase program announced in February 2005 and to provide funding support for Duke Energy’s dividend. The 2006 distribution primarily provided funding support for Duke Energy’s dividend. The distribution was principally obtained from electric sales on Duke Energy Carolinas’ continuing operations.

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

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

Up through April 3, 2006, Duke Energy Carolinas represented an energy company located in the Americas with a real estate subsidiary. On April 3, 2006, Duke Energy Carolinas transferred to its parent, Duke Energy, all of its membership interests in its wholly-owned subsidiary Spectra Energy Capital LLC (Spectra Energy Capital, formerly Duke Capital LLC), including the operations of Duke Energy Merchants, LLC and Duke Energy Merchant Finance, LLC (collectively DEM), which Duke Energy Carolinas transferred to Spectra Energy Capital on April 1, 2006. The use of the term Spectra Energy Capital relates to operations of the former Duke Capital LLC. As a result of Duke Energy Carolinas’ transfer of its membership interests in Spectra Energy Capital, Spectra Energy Capital’s results of operations, including DEM for the three months ended March 31, 2006, and for the years ended December 31, 2005 and 2004 are reflected as discontinued operations in the accompanying Consolidated Statements of Operations. Following these transactions, Duke Energy Carolinas is an electric utility company with operations in North Carolina and South Carolina.

The results of operations and variance discussion for Duke Energy Carolinas is presented in a reduced disclosure format in accordance with General Instruction (I)(2)(a) of Form 10-K.

The $48 million decrease in Duke Energy Carolinas’ income from continuing operations was primarily due to the following factors:

Increased Other income and expenses, net were primarily due to the following factor:

The decrease in Income tax expense from continuing operations was primarily due to the decrease in Income from Continuing Operations Before Income Taxes and a favorable tax settlement in 2006.

The decrease in Net income for the year ended December 31, 2006 as compared to the year ended December 31, 2005 is primarily attributable to the above and the operations of Spectra Energy Capital, which were transferred to Duke Energy on April 3, 2006. The results of operations for Spectra Energy Capital are presented in Income From Discontinued Operations, net of tax, on the Consolidated Statements of Operations for the three months ended March 31, 2006 and the year ended December 31, 2005.

Duke Energy Carolinas continues to increase its customer base, maintain low costs and deliver high-quality customer service in the Carolinas. The residential and general service sectors are expected to grow. The operations of Duke Energy Carolinas are expected to continue to provide strong cash flows from operations. Changes in weather, wholesale power market prices, service area economy, generation availability and changes to the regulatory environment impact future financial results for Duke Energy Carolinas. Rate reductions for merger savings will primarily cease in the second quarter of 2007. In addition, Duke Energy Carolinas’ results will be affected by its ability to exercise flexibility in recognizing amortization expenses associated with the North Carolina clean air legislation. Duke Energy Carolinas’ amortization expense related to this clean air legislation totals $863 million from inception, with $311 million recorded in 2005 and $225 million recorded in 2006. At least $185 million of amortization will be recognized in 2007 in order to recognize the minimum cumulative amortization of approximately $1.05 billion required by the end of 2007.

Various regulatory activities will continue in 2007, including a North Carolina rate review and filings for certification for new generation and approval of various costs to be recovered in trackers. The outcomes of these matters will impact future earnings and cash flows for Duke Energy Carolinas.

During the three-year period from 2007 to 2009, Duke Energy Carolinas anticipates annual capital expenditures of approximately $2 billion, for a total of approximately $6 billion. These expenditures are principally related to expansion plans, environmental spending related to Clean Air requirements, nuclear fuel, as well as maintenance costs. Current estimates are that Duke Energy Carolinas’ generation capacity in North Carolina and South Carolina will need to increase by approximately 6,100 megawatts over the next fifteen years. Duke Energy Carolinas is committed to adding base load capacity at a reasonable price while modernizing the current generation facilities by replacing older, less efficient plants with cleaner, more efficient plants. Significant expansion projects are expected to include a new coal unit (or units) at Duke Energy Carolinas’ existing Cliffside facility in North Carolina, and costs related to the evaluation of the potential construction of a new nuclear power plant in Cherokee County, South Carolina, as well as normal additions due to system growth. On February 28, 2007, the NCUC issued a notice of decision approving the construction of one unit at the Cliffside Steam Station. Duke Energy Carolinas will continue to evaluate this option and determine whether to proceed with the Cliffside project or consider other alternatives, including gas-fired generation. Costs related to environmental spending are expected to decrease over the three-year period as the upgrades to comply with the new environmental regulations are completed.

Duke Energy Carolinas’ fixed charges coverage ratio, as calculated using Securities and Exchange Commission guidelines, was 3.2 times for 2006 and 2.2 times for 2005.

Duke Energy Carolinas is exposed to market risks associated with commodity prices, credit exposure, interest rates and equity prices. Management has established comprehensive risk management policies to monitor and manage these market risks. The Treasurer of Duke Energy Carolinas’ parent entity, Duke Energy Corporation, is responsible for the overall governance of managing credit risk and commodity price risk, including monitoring exposure limits.

Duke Energy Carolinas has limited exposure to market price changes in fuel incurred for its retail customers due to the use of cost tracking and recovery mechanisms in its retail jurisdictions. Duke Energy Carolinas does have exposure to the impact of market fluctuations in the price of electricity, fuel, and emissions allowances with its bulk power marketing sales. Price risk represents the potential risk of loss from adverse changes in the market price of electricity or other energy commodities. Duke Energy Carolinas employs established policies and procedures to manage its risks associated with these market fluctuations using various commodity derivatives, such as forwards and options. (See Note 1 to the Consolidated Financial Statements, “Summary of Significant Accounting Policies” and Note 8 to the Consolidated Financial Statements, “Risk Management and Hedging Activities, Credit Risk, and Financial Instruments.”)

Validation of a contract’s fair value is performed by an internal group independent of Duke Energy Carolinas’ deal origination areas. While Duke Energy Carolinas uses common industry practices to develop its valuation techniques, changes in Duke Energy Carolinas’ pricing methodologies or the underlying assumptions could result in significantly different fair values and income recognition.

Generation Portfolio Risks. Duke Energy Carolinas is primarily exposed to market price fluctuations of wholesale power prices through its bulk power marketing activities. The portion of generation output not utilized to serve native load or committed load, which may be sold into the spot market or other competitive power markets, is subject to commodity price fluctuations. Based on a sensitivity analysis as of December 31, 2006 and 2005, it was estimated that a ten percent price change per mega-watt hour in wholesale power prices would have a corresponding effect on Duke Energy Carolinas’ pre-tax income from continuing operations of approximately $16 million in 2007 and $20 million in 2006.

Normal Purchases and Normal Sales. Duke Energy Carolinas enters into other contracts that qualify for the normal purchases and sales exception described in paragraph 10 of Statement of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” (SFAS No. 133) and Derivative Implementation Group Issue C15, “Scope Exceptions: Normal Purchases and Normal Sales Exception for Option-Type Contracts and Forward Contracts in Electricity,” (DIG Issue No. C15). For contracts qualifying for the scope exception, no recognition of the contract’s fair value in the Consolidated Financial Statements is required until settlement of the contract unless the contract is designated as the hedged item in a fair value hedge. Normal purchases and sales contracts are generally subject to collateral requirements under the same credit risk reduction guidelines used for other contracts. Duke Energy Carolinas has applied this scope exception for certain contracts involving the purchase and sale of electricity. Recognition for the contracts in the Consolidated Statements of Operations will be the same regardless of whether the contracts are accounted for as cash flow hedges or as normal purchases and sales, unless designated as the hedged item in a fair value hedge, assuming no hedge ineffectiveness.

Income recognition and realization related to normal purchases and normal sales contracts generally coincide with the physical delivery of power.

Other Commodity Risks. Pre-tax income for 2007 or 2006 was also not expected to be materially impacted as of December 31, 2006 or 2005 for exposures to other commodities’ price changes since most of the other commodity price risk is minimized by regulatory treatment for commodity transactions. These hypothetical calculations consider existing hedge positions and estimated production levels, but do not consider other potential effects that might result from such changes in commodity prices.

Duke Energy Carolinas’ exposure to commodity price risk is influenced by a number of factors, including contract size, length, market liquidity, location and unique or specific contract terms.

Credit risk represents the loss that Duke Energy Carolinas would incur if a counterparty fails to perform under its contractual obligations.

Retail. Credit risk associated with Franchised Electric’s service to residential, commercial and industrial customers is generally limited to outstanding accounts receivable. Franchised Electric mitigates this credit risk by requiring customers to provide a cash deposit or letter of credit until a satisfactory payment history is established, at which time the deposit is typically refunded. Charge-offs for the retail customers are diminutive and are mostly recovered through the rate base.

Bulk Power Marketing. To reduce credit exposure related to bulk power marketing, Duke Energy Carolinas seeks to enter into netting agreements with counterparties that permit Duke Energy Carolinas to offset receivables and payables with such counterparties. Duke Energy Carolinas attempts to further reduce credit risk with certain counterparties by entering into agreements that enable Duke Energy Carolinas to obtain collateral or to terminate or reset the terms of transactions after specified time periods or upon the occurrence of credit-related events. Where exposed to credit risk, Duke Energy Carolinas analyzes the counterparties’ financial condition prior to entering into an agreement, establishes credit limits and monitors the appropriateness of those limits on an ongoing basis.

Duke Energy Carolinas’ principal customers for bulk power marketing are marketers, local distribution companies and utilities located throughout the Southeastern U.S. Duke Energy Carolinas has concentrations of receivables from electric utilities and their affiliates, as well as marketers throughout these regions. These concentrations of customers may affect Duke Energy Carolinas’ overall credit risk in that risk factors can negatively impact the credit quality of the entire sector. Where exposed to credit risk, Duke Energy Carolinas analyzes the counterparties’ financial condition prior to entering into an agreement, establishes credit limits and monitors the appropriateness of those limits on an ongoing basis. Duke Energy Carolinas’ distribution of unsecured credit exposures related to bulk power marketing at December 31, 2006 is immaterial. Credit exposures are aggregated by ultimate parent company, include on and off balance sheet exposures, are net of collateral, and take into account contractual netting rights. Over 90% of the unsecured credit exposures related to bulk power marketing was rated investment grade by at least one major credit rating agency at December 31, 2006.

Duke Energy Carolinas had no net exposure to any one customer that represented greater than 10% of the gross fair value of trade accounts receivable and unrealized gains on mark-to-market and hedging transactions at December 31, 2006. Based on Duke Energy Carolinas’ policies for managing credit risk, its exposures and its credit and other reserves, Duke Energy Carolinas does not anticipate a materially adverse effect on its consolidated financial position or results of operations as a result of non-performance by any counterparty.

Duke Energy Carolinas also enters into various service and/or supply contracts, which may result in economic losses if the counterparty is unable to perform its contractual obligations on a timely basis and/or within budget. Duke Energy Carolinas attempts to mitigate this risk through the use of credit enhancements such as parent guarantees, letters of credit and surety bonds.

Duke Energy Carolinas is exposed to risk resulting from changes in interest rates as a result of its issuance of variable and fixed rate debt and commercial paper. Duke Energy Carolinas manages its interest rate exposure by limiting its variable-rate exposures to percentages of total capitalization and by monitoring the effects of market changes in interest rates. Duke Energy Carolinas also enters into financial derivative instruments, including, but not limited to, interest rate swaps, swaptions and U.S. Treasury lock agreements to manage and mitigate interest rate risk exposure. (See Notes 1, 8, and 15 to the Consolidated Financial Statements, “Summary of Significant Accounting Policies,” “Risk Management and Hedging Activities, Credit Risk, and Financial Instruments,” and “Debt and Credit Facilities.”)

Based on a sensitivity analysis as of December 31, 2006, it was estimated that if market interest rates average 1% higher (lower) in 2007 than in 2006, interest expense, net of offsetting impacts in interest income, would increase (decrease) by approximately $7 million. This amount was estimated by considering the impact of the hypothetical interest rates on variable-rate securities outstanding, adjusted for interest rate hedges, short-term investments, cash and cash equivalents outstanding as of December 31, 2006. If interest rates changed significantly, management would likely take actions to manage its exposure to the change. However, due to the uncertainty of the specific actions that would be taken and their possible effects, the sensitivity analysis assumes no changes in Duke Energy Carolinas’ financial structure.

Duke Energy Carolinas maintains trust funds, as required by the NRC and the NCUC, to fund the costs of nuclear decommissioning. (See Note 7 to the Consolidated Financial Statements, “Asset Retirement Obligations.”) As of December 31, 2006 and 2005, these funds were invested primarily in domestic and international equity securities, fixed-rate, fixed-income securities and cash and cash equivalents. Per NRC and NCUC requirements, these funds may be used only for activities related to nuclear decommissioning. Those investments are exposed to price fluctuations in equity markets and changes in interest rates. Accounting for nuclear decommissioning recognizes that costs are recovered through Duke Energy Carolinas’ rates, and fluctuations in equity prices or interest rates do not affect Duke Energy Carolinas’ consolidated results of operations. Earnings or losses of the fund will ultimately impact the amount of costs recovered from Duke Energy Carolinas’ rates.

Duke Energy Carolinas’ proportionate share of Duke Energy’s costs of providing non-contributory defined benefit retirement and postretirement benefit plans are dependent upon a number of factors, such as the rates of return on plan assets, discount rate, the rate of increase in health care costs and contributions made to the plans.

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

We have audited the accompanying consolidated balance sheets of Duke Energy Carolinas, LLC (formerly Duke Power Company LLC, which was formally Duke Energy Corporation) and subsidiaries (the “Company”) as of December 31, 2006 and 2005, and the related consolidated statements of operations, member’s equity/common stockholders’ equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2006. Our audits also included the consolidated financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Duke Energy Carolinas, LLC and subsidiaries as of December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

As discussed in Note 1 to the consolidated financial statements, on April 3, 2006 the Company converted its form of organization to a limited liability company and transferred to its parent all of its membership interests in its wholly owned subsidiary Spectra Energy Capital LLC (formerly Duke Capital LLC).

Nature of Operations and Basis of Consolidation. Duke Energy Holding Corp. (Duke Energy HC) was incorporated in Delaware on May 3, 2005 as Deer Holding Corp., a wholly-owned subsidiary of Duke Energy Corporation (Old Duke Energy). On April 3, 2006, in accordance with their previously announced merger agreement, Old Duke Energy and Cinergy Corp. (Cinergy) merged into wholly-owned subsidiaries of Duke Energy HC, resulting in Duke Energy HC becoming the parent entity. In connection with the closing of the merger transactions, Duke Energy HC changed its name to Duke Energy Corporation (Duke Energy) and Old Duke Energy converted its form of organization from a North Carolina corporation to a North Carolina limited liability company named Duke Power Company LLC (Duke Power). As a result of the merger transactions, each share of common stock of Old Duke Energy was exchanged for one share of Duke Energy common stock, with Duke Energy becoming the owner of Old Duke Energy shares. All shares of Old Duke Energy were subsequently converted into membership interests in Duke Power, which is owned by Duke Energy. Effective October 1, 2006, Duke Power changed its name to Duke Energy Carolinas, LLC (Duke Energy Carolinas). The term “Duke Energy Carolinas,” used in this report for all periods presented, refers to Old Duke Energy or to Duke Energy Carolinas, as the context requires. Additionally, the term “Duke Energy” as used in this report refers to Old Duke Energy or Duke Energy, as the context requires.

As a result of Duke Energy’s merger with Cinergy, Duke Energy Carolinas entered into a tax sharing agreement with Duke Energy, where the separate return method is used to allocate tax expenses and benefits to the subsidiaries whose investments or results of operations provide these tax expenses or benefits. The accounting for income taxes essentially represents the income taxes that Duke Energy Carolinas would incur if Duke Energy Carolinas were a separate company filing its own tax return as a C-Corporation.

These Consolidated Financial Statements include, after eliminating intercompany transactions and balances, the accounts of Duke Energy Carolinas. These Consolidated Financial Statements also reflect Duke Energy Carolinas’ 12.5% undivided interest in the Catawba Nuclear Station. As a result of the conversion from a North Carolina Corporation to a limited liability company, the Consolidated Balance Sheet as of December 31, 2006 no longer reflects Common Stock and Retained Earnings as those accounts are now characterized as Member’s Equity.

Use of Estimates. To conform to generally accepted accounting principles (GAAP) in the United States, management makes estimates and assumptions that affect the amounts reported in the Consolidated Financial Statements and Notes. Although these estimates are based on management’s best available knowledge at the time, actual results could differ.

Reclassifications and Revisions. Certain prior period amounts have been reclassified within the Consolidated Statements of Cash Flows to conform to current year presentation.

Cash and Cash Equivalents. All highly liquid investments with original maturities of three months or less at the date of acquisition are considered cash equivalents.

Restricted Funds Held in Trust. At December 31, 2006, Duke Energy Carolinas had approximately $46 million of restricted cash related primarily to proceeds from debt issuances that are held in trust, primarily for the purpose of funding future environmental expenditures. This amount is reflected in Other Investments and Other Assets on the Consolidated Balance Sheets.

Short-term Investments. Duke Energy Carolinas actively invests a portion of its available cash balances in various financial instruments, such as tax-exempt debt securities that frequently have stated maturities of 20 years or more and tax-exempt money market preferred securities. These instruments provide for a high degree of liquidity through features such as daily and seven day notice put options and 7, 28, and 35 day auctions which allow for the redemption of the investments at their face amounts plus earned income. As Duke Energy Carolinas intends to sell these instruments within one year or less, generally within 30 days from the balance sheet date, they are

classified as current assets. Duke Energy Carolinas has classified all short-term investments that are debt securities as available-for-sale under Statement of Financial Accounting Standards (SFAS) No. 115, “Accounting For Certain Investments in Debt and Equity Securities” (SFAS No. 115), and they are carried at fair market value. Investments in money-market preferred securities that do not have stated redemptions are accounted for at their cost, as the carrying values approximate market values due to their short-term maturities and no credit risk. Realized gains and losses and dividend and interest income related to these securities, including any amortization of discounts or premiums arising at acquisition, are included in earnings as incurred. Purchases and sales of available-for-sale securities are presented on a gross basis within Investing Cash Flows in the accompanying Consolidated Statements of Cash Flows.

Inventory. At December 31, 2006, inventory consists primarily of materials and supplies and coal held for electric generation. Inventory is recorded at the lower of cost or market value, primarily using the average cost method. The decrease in inventory at December 31, 2006 as compared to December 31, 2005 is primarily attributable to inventory related to the transfer to Duke Energy by Duke Energy Carolinas of all of its membership interests in Spectra Energy Capital effective April 3, 2006.

Cost-Based Regulation. Duke Energy Carolinas accounts for its regulated operations under the provisions of SFAS No. 71, “Accounting for Certain Types of Regulation” (SFAS No. 71). The economic effects of regulation can result in a regulated company recording assets for costs that have been or are expected to be approved for recovery from customers or recording liabilities for amounts that are expected to be returned to customers in the rate-setting process in a period different from the period in which the amounts would be recorded by an unregulated enterprise. Accordingly, Duke Energy Carolinas records assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for non-regulated entities. Management continually assesses whether regulatory assets are probable of future recovery by considering factors such as applicable regulatory changes, recent rate orders applicable to other regulated entities and the status of any pending or potential deregulation legislation. Based on this continual assessment, management believes the existing regulatory assets are probable of recovery. These regulatory assets and liabilities are primarily classified in the Consolidated Balance Sheets as Regulatory Assets and Deferred Debits, and Deferred Credits and Other Liabilities. Duke Energy Carolinas 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, Duke Energy Carolinas may have to reduce its asset balances to reflect a market basis less than cost and write-off their associated regulatory assets and liabilities. (For further information see Note 4.)

Accounting for Risk Management and Hedging Activities and Financial Instruments. Duke Energy Carolinas uses a number of different derivative and non-derivative instruments in connection with its commodity price and interest rate risk management activities, such as swaps, futures, forwards, options and swaptions. All derivative instruments not designated and qualifying for the normal purchases and normal sales exception under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS No. 133), as amended, are recorded on the Consolidated Balance Sheets at their fair value as Unrealized Gains or Unrealized Losses on Mark-to-Market and Hedging Transactions. Cash inflows and outflows related to derivative instruments, except those that contain financing elements and those related to other investing activities, are a component of operating cash flows in the accompanying Consolidated Statements of Cash Flows. Cash inflows and outflows related to derivative instruments containing financing elements are a component of financing cash flows in the accompanying Consolidated Statements of Cash Flows while cash inflows and outflows from derivatives related to other investing activities are a component of investing cash flows in the accompanying Consolidated Statements of Cash Flows.

Normal Purchases and Normal Sales. On a limited basis, Duke Energy Carolinas applies the normal purchase and normal sales exception to certain contracts. If contracts cease to meet this exception, the fair value of the contracts is recognized on the Consolidated Balance Sheets and the contracts are accounted for using the Mark-to-Market (MTM) Model unless immediately designated as a cash flow or fair value hedge.

Valuation. When available, quoted market prices or prices obtained through external sources are used to measure 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. For derivatives recognized under the MTM Model, valuation adjustments are also recognized in the Consolidated Statements of Operations.

Other Long-term Investments. Other long-term investments, primarily marketable securities held in the Nuclear Decommissioning Trust Funds (NDTF) are classified as available-for-sale securities as management does not have the intent or ability to hold the securities to maturity, nor are they bought and held principally for selling them in the near term. The securities are reported at fair value on Duke Energy Carolinas’ Consolidated Balance Sheets. Unrealized and realized gains and losses, net of tax, on the NDTF are reflected in regulatory assets or liabilities on Duke Energy Carolinas’ Consolidated Balance Sheets as Duke Energy Carolinas expects to recover all costs for decommissioning its nuclear generation assets through regulated rates. Cash flows from purchases and sales of long-term investments are presented on a gross basis within investing cash flows in the accompanying Consolidated Statements of Cash Flows.

The NDTF is managed by independent investment managers with discretion to buy, sell and invest pursuant to the objectives set forth by the trust agreement. As Duke Energy Carolinas has limited oversight over the day-to-day management of the NDTF investments, all losses related to NDTF holdings are immediately realized and deferred as a regulatory asset pursuant to an order by the North Carolina Utilities Commission (NCUC).

Property, Plant and Equipment. Property, plant and equipment are stated at the lower of historical cost less accumulated depreciation or fair value, if impaired. Duke Energy Carolinas 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, which do not extend the useful life or increase the expected output of property, plant and equipment, 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, excluding nuclear fuel, were 2.56% for 2006, 3.34% for 2005, and 3.49% for 2004. Also, see “Deferred Returns and Allowance for Funds Used During Construction (AFUDC),” discussed below.

When Duke Energy Carolinas retires its regulated property, plant and equipment, it charges the original cost plus the cost of retirement, less salvage value, to accumulated depreciation and amortization. When it sells entire regulated operating units, the cost is removed from the property account and the related accumulated depreciation and amortization accounts are reduced. Any gain or loss is recorded in earnings, unless otherwise required by the applicable regulatory body.

Duke Energy Carolinas recognizes asset retirement obligations (ARO’s) in accordance with SFAS No. 143, “Accounting For Asset Retirement Obligations” (SFAS No. 143), for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset and FIN No. 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47), for conditional ARO’s in which the timing or method of settlement are conditional on a future event that may or may not be within the control of Duke Energy Carolinas. Both SFAS No. 143 and FIN 47 require that the fair value of a liability for an ARO 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 estimated useful life of the asset.

Long-Lived Asset Impairments, Assets Held For Sale and Discontinued Operations. Duke Energy Carolinas evaluates whether long-lived assets, excluding goodwill, have been impaired when circumstances indicate the carrying value of those assets may not be recoverable. For such long-lived assets, an impairment exists when its carrying value exceeds the sum of estimates of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. When alternative courses of action to recover the carrying amount of a long-lived asset are under consideration, a probability-weighted approach is used for developing estimates of future undiscounted cash flows. If the carrying value of the long-lived asset is not recoverable based on these estimated future undiscounted cash flows, the impairment loss is measured as the excess of the asset’s carrying value over its fair value, such that the asset’s carrying value is adjusted to its estimated fair value.

Management assesses the fair value of long-lived assets using commonly accepted techniques, and may use more than one source. Sources to determine fair value include, but are not limited to, recent third party comparable sales, internally developed discounted cash flow analysis and analysis from outside advisors. Significant changes in market conditions resulting from events such as changes in commodity prices or the condition of an asset, or a change in management’s intent to utilize the asset would generally require management to re-assess the cash flows related to the long-lived assets.

Duke Energy Carolinas uses the criteria in SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (SFAS No. 144) to determine when an asset is classified as “held for sale.” Upon classification as “held for sale,” the long-lived asset or asset group is measured at the lower of its carrying amount or fair value less cost to sell, depreciation is ceased and the asset or asset group is separately presented on the Consolidated Balance Sheets. When an asset or asset group meets the SFAS No. 144 criteria for classification as held for sale within the Consolidated Balance Sheets, Duke Energy Carolinas does not retrospectively adjust prior period balance sheets to conform to current year presentation.

Duke Energy Carolinas uses the criteria in SFAS No. 144 and EITF 03-13, “Applying the Conditions in Paragraph 42 of FASB Statement No. 144 in Determining Whether to Report Discontinued Operations” (EITF 03-13), to determine whether components of Duke Energy Carolinas that are being disposed of or are classified as held for sale are required to be reported as discontinued operations in the Consolidated Statements of Operations. To qualify as a discontinued operation under SFAS No. 144, the component being disposed of must have clearly distinguishable operations and cash flows. Additionally, pursuant to EITF 03-13, Duke Energy Carolinas must not have significant continuing involvement in the operations after the disposal (i.e. Duke Energy Carolinas must not have the ability to influence the operating or financial policies of the disposed component) and cash flows of the operations being disposed of must have been eliminated from Duke Energy Carolinas’ ongoing operations (i.e. Duke Energy Carolinas does not expect to generate significant direct cash flows from activities involving the disposed component after the disposal transaction is completed). Assuming both preceding conditions are met, the related results of operations for the current and prior periods, including any related impairments, are reflected as Income From Discontinued Operations, net of tax, in the Consolidated Statements of Operations. If an asset held for sale does not meet the requirements for discontinued operations classification, any impairments and gains or losses on sales are recorded in continuing operations as Gains on Sales of Other Assets and Other, net, in the Consolidated Statements of Operations. Impairments for all other long-lived assets, excluding goodwill, are recorded as Impairment and Other Charges in the Consolidated Statements of Operations.

Other Current and Non-Current Liabilities. At December 31, 2006 and December 31, 2005, approximately $1,394 million and $1,278 million, respectively, of regulatory liabilities associated with asset removal costs was included in Other Deferred Credits and Other Liabilities in the Consolidated Balance Sheets. At December 31, 2006, this balance exceeded 5% of total liabilities. Also see “Other Litigation and Legal Proceedings” in Note 16.

Unamortized Debt Premium, Discount and Expense. Premiums, discounts and expenses incurred 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 to finance regulated assets and operations are amortized consistent with regulatory treatment of those items, where appropriate.

Environmental Expenditures. Duke Energy Carolinas expenses environmental expenditures related to conditions caused by past operations that do not generate current or future revenues. Environmental expenditures related to operations that generate current or future revenues are expensed or capitalized, as appropriate. Liabilities are recorded when the necessity for environmental remediation becomes probable and the costs can be reasonably estimated, or when other potential environmental liabilities are reasonably estimable and probable.

Guarantees. Duke Energy Carolinas accounts for guarantees and related contracts, for which it is the guarantor, under FIN No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others” (FIN 45). In accordance with FIN 45, upon issuance or modification of a guarantee on or after January 1, 2003, Duke Energy Carolinas recognizes a liability at the time of issuance or material modification for the estimated fair value of the obligation it assumes under that guarantee, if any. Fair value is estimated using a probability-weighted approach. Duke Energy Carolinas reduces the obligation over the term of the guarantee or related contract in a systematic and rational method as risk is reduced under the obligation. Any additional contingent loss for guarantee contracts outside the scope of FIN 45 is accounted for and recognized in accordance with SFAS No. 5, “Accounting for Contingencies” (SFAS No. 5).

Duke Energy Carolinas has entered into various indemnification agreements related to purchase and sale agreements and other types of contractual agreements with vendors and other third parties. These agreements typically cover environmental, tax, litigation and other matters, as well as breaches of representations, warranties and covenants. Typically, claims may be made by third parties for various periods of time, depending on the nature of the claim. Duke Energy Carolinas’ potential exposure under these indemnification agreements can range from a specified to an unlimited dollar amount, depending on the nature of the claim and the particular transaction (see Note 17).

Stock-Based Compensation. Effective January 1, 2006, Duke Energy Carolinas adopted the provisions of SFAS No. 123(R), “Share-Based Payment” (SFAS No. 123(R)) (see Note 18). SFAS No. 123(R) establishes accounting for stock-based awards exchanged for employee and certain non-employee services. Accordingly, for employee awards, equity classified stock-based compensation cost is measured at the grant date, based on the fair value of the award, and is recognized as expense over the requisite service period, which generally begins on the date the award is granted through the earlier of the date the award vests or the date the employee becomes retirement eligible. Awards, including stock options, granted to employees that are already retirement eligible are deemed to have vested immediately upon issuance, and therefore, compensation cost for those awards is recognized on the date such awards are granted.

Duke Energy Carolinas elected to adopt the modified prospective application method as provided by SFAS No. 123(R), and accordingly, financial statement amounts periods prior to January 1, 2006 in this Form 10-K have not been restated. There were no modifications to outstanding stock options prior to the adoption of SFAS 123(R). Subsequent to the transfer of all of its membership interests in Spectra Energy Capital to Duke Energy on April 3, 2006, Duke Energy Carolinas is allocated its proportionate share of stock-based compensation expense from its parent, Duke Energy.

Duke Energy Carolinas previously applied Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees,” and FIN 44, “Accounting for Certain Transactions Involving Stock Compensation—an Interpretation of APB Opinion 25” and provided the required pro forma disclosures of SFAS No. 123, “Accounting for Stock-Based Compensation” (SFAS No. 123). Since the exercise price for all stock options granted under those plans was equal to the market value of the underlying common stock on the grant date, no compensation cost was recognized in the accompanying Consolidated Statements of Operations. Compensation expense for awards with graded vesting provisions is recognized in accordance with FIN 28, “Accounting for Stock Appreciation Rights and Other Variable Stock Option or Award Plans.”

Revenue Recognition. Revenues on sales of electricity are recognized when the service is provided. Unbilled revenues are estimated by applying an average revenue/kilowatt hour for all customer classes to the number of estimated kilowatt hours delivered, but not billed. Differences between actual and estimated unbilled revenues are immaterial.

Nuclear Fuel. Amortization of nuclear fuel purchases is included in the Consolidated Statements of Operations as Fuel Used in Electric Generation and Purchased Power. The amortization is recorded using the units-of-production method.

Deferred Returns and Allowance for Funds Used During Construction (AFUDC). Deferred returns, recorded in accordance with SFAS No. 71, represent the estimated financing costs associated with funding certain regulatory assets or liabilities of Duke Energy Carolinas. Those costs arise primarily from the funding of purchased capacity costs collected in rates. Deferred returns are non-cash items and are primarily recognized as an addition to purchased capacity costs, which are included in Other Current Liabilities and Other Deferred Credits and Other Liabilities on the Consolidated Balance Sheets, with an offsetting debit or credit to Other Income and Expenses, net. The amount of deferred returns included in Other Income and Expenses, net was ($15) million in 2006, ($13) million in 2005, and ($9) million in 2004.

AFUDC, which represents the estimated debt and equity costs of capital funds necessary to finance the construction of new regulated facilities, consists of two components, an equity component and an interest component. The equity component is a non-cash item. AFUDC is capitalized as a component of Property, Plant and Equipment cost, with offsetting credits to the Consolidated Statements of Operations. After construction is completed, Duke Energy Carolinas is permitted to recover these costs through inclusion in the rate base and in the depreciation provision. The total amount of AFUDC included in income from continuing operations on the Consolidated Statements of Operations was $42 million in 2006, which consisted of an after-tax equity component of $30 million and a before-tax interest expense component of $12 million. The total amount of AFUDC included in income from continuing operations on the Consolidated Statements of Operations was $31 million in 2005, which consisted of an after-tax equity component of $22 million and a before-tax interest expense component of $9 million. The total amount of AFUDC included in income from continuing operations on the Consolidated Statements of Operations was $23 million in 2004, which consisted of an after-tax equity component of $16 million and a before-tax interest

expense component of $7 million. The after-tax equity component is included in Other Income and Expenses, net and the pre-tax interest component is included in Interest Expense on the Consolidated Statements of Operations. These amounts exclude AFUDC included in discontinued operations of $6 million for the period January 1, 2006 through March 31, 2006, and $17 million for each of the years ended December 31, 2005 and 2004, respectively.

Accounting For Purchases and Sales of Emission Allowances. Duke Energy Carolinas recognizes emission allowances in earnings as they are consumed or sold. Since Duke Energy Carolinas does not have a mechanism that provides for direct recovery of emission allowances through a cost tracking mechanism, gains and losses on sales of emission allowances are included in Gains on Sales of Other Assets and Other, net in the Consolidated Statements of Operations, or are deferred, depending on level of regulatory certainty. Purchases and sales of emission allowances are presented gross as investing activities on the Consolidated Statements of Cash Flows.

Income Taxes. Duke Energy Carolinas entered into a tax sharing agreement with Duke Energy, where the separate return method is used to allocate tax expenses and benefits to the subsidiaries whose investments or results of operations provide these tax expenses or benefits. The accounting for income taxes essentially represents the income taxes that Duke Energy Carolinas would incur if Duke Energy Carolinas were a separate company filing its own tax return as a C-Corporation. Duke Energy Carolinas files separate state income tax returns in North Carolina and South Carolina.

Management evaluates and records contingent tax liabilities and related interest based on the probability of ultimately sustaining the tax deductions or income positions. Management assesses the probabilities of successfully defending the tax deductions or income positions based upon statutory, judicial or administrative authority.

Excise Taxes. Certain excise taxes levied by state or local governments are collected by Duke Energy Carolinas from its customers. These taxes, which are required to be paid regardless of Duke Energy Carolinas’ ability to collect from the customer, are accounted for on a gross basis. When Duke Energy Carolinas acts as an agent, and the tax is not required to be remitted if it is not collected from the customer, the taxes are accounted for on a net basis. Duke Energy Carolinas’ excise taxes accounted for on a gross basis and recorded as revenues in the accompanying Consolidated Statements of Operations for the years ended December 31, 2006, 2005, and 2004 were as follows:

Segment Reporting. SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information” (SFAS No. 131), establishes standards for a public company to report financial and descriptive information about its reportable operating segments in annual and interim financial reports. Operating segments are components of an enterprise about which separate financial information is available and evaluated regularly by the chief operating decision maker in deciding how to allocate resources and evaluate performance. Two or more operating segments may be aggregated into a single reportable segment provided aggregation is consistent with the objective and basic principles of SFAS No. 131, if the segments have similar economic characteristics, and the segments are considered similar under criteria provided by SFAS No. 131. There is no aggregation within Duke Energy Carolinas’ defined business segments. SFAS No. 131 also establishes standards and related disclosures about the way the operating segments were determined, products and services, geographic areas and major customers, differences between the measurements used in reporting segment information and those used in the general-purpose financial statements, and changes in the measurement of segment amounts from period to period. The description of Duke Energy Carolinas’ reportable segment is consistent with how business results are reported internally to management and the disclosure of segment information in accordance with SFAS No. 131 is presented in Note 3.

Statements of Consolidated Cash Flows. Duke Energy Carolinas has made certain classification elections within its Consolidated Statements of Cash Flows related to discontinued operations, cash received from insurance proceeds and cash overdrafts. Cash flows from discontinued operations are combined with cash flows from continuing operations within operating, investing and financing cash flows within the Consolidated Statements of Cash Flows. Cash received from insurance proceeds are classified depending on the activity that resulted in the insurance proceeds (for example, business interruption insurance proceeds are included as a component of operating activities while insurance proceeds from damaged property are included as a component of investing activities). With respect to cash overdrafts, book overdrafts are included within operating cash flows while bank overdrafts are included within financing cash flows.

Distributions from Equity Investees. Duke Energy Carolinas considers dividends received from equity investees which do not exceed cumulative equity in earnings subsequent to the date of investment a return on investment and classifies these amounts as operating activities within the accompanying Consolidated Statements of Cash Flows. Cumulative dividends received in excess of cumulative equity in earnings subsequent to the date of investment are considered a return of investment and are classified as investing activities within the accompanying Consolidated Statements of Cash Flows.

Cumulative Effect of Changes in Accounting Principles. As of December 31, 2005, Duke Energy Carolinas adopted the provisions of FIN 47. In accordance with the transition guidance of this standard, Duke Energy Carolinas recorded a net-of-tax cumulative effect adjustment of approximately $4 million. The cumulative effect adjustment had an immaterial impact on EPS.

New Accounting Standards. The following new accounting standards were adopted by Duke Energy Carolinas during the year ended December 31, 2006 and the impact of such adoption, if applicable, has been presented in the accompanying Consolidated Financial Statements:

SFAS No. 123(R) “Share-Based Payment” (SFAS No. 123(R)). In December 2004, the Financial Accounting Standards Board (FASB) issued SFAS No. 123(R), which replaces SFAS No. 123, “Accounting for Stock-Based Compensation,” and supersedes APB Opinion No. 25, “Accounting for Stock Issued to Employees.” SFAS No. 123(R) requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values. For Duke Energy Carolinas, timing for implementation of SFAS No. 123(R) was January 1, 2006. The pro forma disclosures previously permitted under SFAS No. 123 are no longer an acceptable alternative. Instead, Duke Energy Carolinas is required to determine an appropriate expense for stock options and record compensation expense in the Consolidated Statements of Operations for stock options. Duke Energy Carolinas implemented SFAS No. 123(R) using the modified prospective transition method, which required Duke Energy Carolinas to record compensation expense for all unvested awards beginning January 1, 2006.

Duke Energy Carolinas currently also has retirement eligible employees with outstanding share-based payment awards (unvested stock awards, stock based performance awards and phantom stock awards). Compensation cost related to those awards was previously expensed over the stated vesting period or until actual retirement occurred. Effective January 1, 2006, Duke Energy Carolinas is required to recognize compensation cost for new awards granted to employees over the requisite service period, which generally begins on the date the award is granted through the earlier of the date the award vests or the date the employee becomes retirement eligible. Awards, including stock options, granted to employees that are already retirement eligible are deemed to have vested immediately upon issuance, and therefore, compensation cost for those awards is recognized on the date such awards are granted.

The adoption of SFAS No. 123(R) did not have a material impact on Duke Energy Carolinas’ consolidated results of operations, cash flows or financial position in 2006 based on awards outstanding as of the implementation date. However, the impact to Duke Energy Carolinas in periods subsequent to adoption of SFAS No. 123(R) will be largely dependent upon the nature of any new share-based compensation awards issued to employees. (See Note 18.)

Staff Accounting Bulletin (SAB) No. 107, “Share-Based Payment” (SAB No. 107). On March 29, 2005, the Securities and Exchange Commission (SEC) staff issued SAB No. 107 to express the views of the staff regarding the interaction between SFAS No. 123(R) and certain SEC rules and regulations and to provide the staff’s views regarding the valuation of share-based payment arrangements for public companies. Duke Energy Carolinas adopted SFAS No. 123(R) and SAB No. 107 effective January 1, 2006.

FASB Staff Position (FSP) No. FAS 123(R)-4, “Classification of Options and Similar Instruments Issued as Employee Compensation That Allow for Cash Settlement upon the Occurrence of a Contingent Event” (FSP No. FAS 123(R)-4). In February 2006, the FASB staff issued FSP FAS No. 123(R)-4 to address the classification of options and similar instruments issued as employee compensation that allow for cash settlement upon the occurrence of a contingent event. The guidance amends SFAS No. 123(R). FSP No. FAS 123(R)-4 provides that cash settlement features that can be exercised only upon the occurrence of a contingent event that is outside the employee’s control does not require classifying the option or similar instrument as a liability until it becomes probable that the event will occur. FSP No. FAS 123(R)-4 applies only to options or similar instruments issued as part of employee compensation arrangements. The guidance in FSP No. FAS 123(R)-4 was effective for Duke Energy Carolinas as of April 1, 2006. Duke Energy Carolinas adopted SFAS No. 123(R) as of January 1, 2006 (see Note 18). The adoption of FSP No. FAS 123(R)-4 did not have a material impact on Duke Energy Carolinas’ consolidated statement of operations, cash flows or financial position.

FSP No. FAS 115-1 and 124-1, “The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments” (FSP No. FAS 115-1 and 124-1). The FASB issued FSP No. FAS 115-1 and 124-1 in November 2005, which was effective for Duke Energy Carolinas beginning January 1, 2006. This FSP addresses the determination as to when an investment is considered impaired, whether that impairment is other than temporary, and the measurement of an impairment loss. This FSP also includes accounting considerations subsequent to the recognition of an other-than-temporary impairment and requires certain disclosures about unrealized losses that have not been recognized as other-than-temporary impairments. The guidance in this FSP amends SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities,” and SFAS No. 124, “Accounting for Certain Investments Held by Not-for-Profit Organizations,” and APB Opinion No. 18. The adoption of FSP No. FAS 115-1 and 124-1 did not have a material impact on Duke Energy Carolinas’ consolidated results of operations, cash flows or financial position.

FSP No. FIN 46(R)-6, “Determining the Variability to Be Considered In Applying FASB Interpretation No. 46(R) (FSP No. FIN 46(R)-6).” In April 2006, the FASB staff issued FSP No. FIN 46(R)-6 to address how to determine the variability to be considered in applying FIN 46(R), “Consolidation of Variable Interest Entities.” The variability that is considered in applying FIN 46(R) affects the determination of whether the entity is a variable interest entity (VIE), which interests are variable interests in the entity, and which party, if any, is the primary beneficiary of the VIE. The variability affects the calculation of expected losses and expected residual returns. This guidance is effective for all entities with which Duke Energy Carolinas first becomes involved or existing entities for which a reconsideration event occurs after July 1, 2006. The adoption of FSP No. FIN 46(R)-6 did not have a material impact on Duke Energy Carolinas’ consolidated results of operations, cash flows or financial position.

EITF Issue No. 05-1, “Accounting for the Conversion of an Instrument that Becomes Convertible Upon the Issuer’s Exercise of a Call Option” (EITF No. 05-1). In June 2006, the EITF reached a consensus on EITF No. 05-1. The consensus requires that the issuance of equity securities to settle a debt instrument (pursuant to the instrument’s original conversion terms) that became convertible upon the issuer’s exercise of a call option be accounted for as a conversion if the debt instrument contained a substantive conversion feature as of its issuance date. If the debt instrument did not contain a substantive conversion option as of its issuance date, the issuance of equity securities to settle the debt instrument should be accounted for as a debt extinguishment. The consensus was effective for Duke Energy Carolinas for all conversions within its scope that resulted from the exercise of call options beginning July 1, 2006. The adoption of EITF No. 05-1 did not have a material impact on Duke Energy Carolinas’ consolidated results of operations, cash flows or financial position.

SAB No. 108, “Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in Current Year Financial Statements” (SAB No. 108). In September 2006 the SEC issued SAB No. 108, which provides interpretive guidance on how the effects of the carryover or reversal of prior year misstatements should be considered in quantifying a current year misstatement. Traditionally, there have been two widely-recognized approaches for quantifying the effects of financial statement misstatements. The income statement approach focuses primarily on the impact of a misstatement on the income statement—including the reversing effect of prior year misstatements—but its use can lead to the accumulation of misstatements in the balance sheet. The balance sheet approach, on the other hand, focuses primarily on the effect of correcting the period-end balance sheet with less emphasis on the reversing effects of prior year errors on the income statement. The SEC staff believes that registrants should quantify errors using both a balance sheet and an income statement approach (a “dual approach”) and evaluate whether either approach results in quantifying a misstatement that, when all relevant quantitative and qualitative factors are considered, is material.

SAB No. 108 was effective for Duke Energy Carolinas’ year ended December 31, 2006. SAB No. 108 permits existing public companies to initially apply its provisions either by (i) restating prior financial statements as if the “dual approach” had always been used or (ii), under certain circumstances, recording the cumulative effect of initially applying the “dual approach” as adjustments to the carrying values of assets and liabilities as of January 1, 2006 with an offsetting adjustment recorded to the opening balance of retained earnings. Duke Energy Carolinas has historically used a dual approach for quantifying identified financial statement misstatements. Therefore, the adoption of SAB No. 108 did not have any material impact on Duke Energy Carolinas’ consolidated results of operations, cash flows or financial position.

The following new accounting standards were adopted by Duke Energy Carolinas during the year ended December 31, 2005 and the impact of such adoption, if applicable, has been presented in the accompanying Consolidated Financial Statements:

SFAS No. 153, “Exchanges of Nonmonetary Assets—an amendment of APB Opinion No. 29” (SFAS No. 153). In December 2004, the FASB issued SFAS No. 153 which amends APB Opinion No. 29, “Accounting for Nonmonetary Transactions,” by eliminating the exception to the fair-value principle for exchanges of similar productive assets, which were accounted for under APB Opinion No. 29

based on the book value of the asset surrendered with no gain or loss recognition. SFAS No. 153 also eliminates APB Opinion No. 29’s concept of culmination of an earnings process. The amendment requires that an exchange of nonmonetary assets be accounted for at fair value if the exchange has commercial substance and fair value is determinable within reasonable limits. Commercial substance is assessed by comparing the entity’s expected cash flows immediately before and after the exchange. If the difference is significant, the transaction is considered to have commercial substance and should be recognized at fair value. SFAS No. 153 is effective for nonmonetary transactions occurring on or after July 1, 2005. The adoption of SFAS No. 153 did not have a material impact on Duke Energy Carolinas’ consolidated results of operations, cash flows or financial position.

FASB Interpretation No. (FIN) 47 “Accounting for Conditional Asset Retirement Obligations” (FIN No. 47). In March 2005, the FASB issued FIN No. 47, which clarifies the accounting for conditional asset retirement obligations as used in SFAS No. 143, “Accounting for Asset Retirement Obligations,” (SFAS No. 143). A conditional asset retirement obligation is an unconditional legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. Therefore, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation under SFAS No. 143 if the fair value of the liability can be reasonably estimated. The provisions of FIN No. 47 were effective for Duke Energy Carolinas as of December 31, 2005, and resulted in an increase in assets of $31 million, an increase in liabilities of $35 million and a net-of-tax cumulative effect adjustment to earnings of approximately $4 million.

FASB Staff Position (FSP) No. APB 18-1, “Accounting by an Investor for Its Proportionate Share of Accumulated Other Comprehensive Income of an Investee Accounted for under the Equity Method in Accordance with APB Opinion No. 18 upon a Loss of Significant Influence” (FSP No. APB 18-1). In July 2005, the FASB staff issued FSP No. APB 18-1 which provides guidance for how an investor should account for its proportionate share of an investee’s equity adjustments for other comprehensive income (OCI) upon a loss of significant influence. APB Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock” (APB Opinion No. 18), requires a transaction of an equity method investee of a capital nature be accounted for as if the investee were a consolidated subsidiary, which requires the investor to record its proportionate share of the investee’s adjustments for OCI as increases or decreases to the investment account with corresponding adjustments in equity. FSP No. APB 18-1 requires that an investor’s proportionate share of an investee’s equity adjustments for OCI should be offset against the carrying value of the investment at the time significant influence is lost and equity method accounting is no longer appropriate. However, to the extent that the offset results in a carrying value of the investment that is less than zero, an investor should (a) reduce the carrying value of the investment to zero and (b) record the remaining balance in income. The guidance in FSP No. APB 18-1 was effective for Duke Energy Carolinas beginning October 1, 2005. The adoption of FSP No. APB 18-1 did not have a material impact on Duke Energy Carolinas’ consolidated results of operations, cash flows or financial position.

The following new accounting standards were adopted by Duke Energy Carolinas during the year ended December 31, 2004 and the impact of such adoption, if applicable, has been presented in the accompanying Consolidated Financial Statements:

FIN 46, “Consolidation of Variable Interest Entities”. (FIN 46) In January 2003, the FASB issued FIN 46 which requires the primary beneficiary of a variable interest entity’s activities to consolidate the variable interest entity. FIN 46 defines a variable interest entity as an entity in which the equity investors do not have substantive voting rights and there is not sufficient equity at risk for the entity to finance its activities without additional subordinated financial support. The primary beneficiary absorbs a majority of the expected losses and/or receives a majority of the expected residual returns of the variable interest entity’s activities. In December 2003, the FASB issued FIN 46 (Revised December 2003), “Consolidation of Variable Interest Entities—An Interpretation of ARB No. 51” (FIN 46R), which supersedes and amends the provisions of FIN 46. While FIN 46R retains many of the concepts and provisions of FIN 46, it also provides additional guidance and additional scope exceptions, and incorporates FASB Staff Positions related to the application of FIN 46.

The provisions of FIN 46 applied immediately to variable interest entities created, or interests in variable interest entities obtained, after January 31, 2003, while the provisions of FIN 46R were required to be applied to those entities, except for special purpose entities, by the end of the first reporting period ending after March 15, 2004 (March 31, 2004 for Duke Energy). For variable interest entities created, or interests in variable interest entities obtained, on or before January 31, 2003, FIN 46 or FIN 46R was required to be applied to special-purpose entities by the end of the first reporting period ending after December 15, 2003 (December 31, 2003 for Duke Energy Carolinas), and was required to be applied to all other non-special purpose entities by the end of the first reporting period ending after March 15, 2004 (March 31, 2004 for Duke Energy Carolinas).

Prior to the transfer of all of its membership interests in Spectra Energy Capital to Duke Energy on April 3, 2006, Duke Energy Carolinas consolidated certain non-special purpose operating entities, previously accounted for under the equity method of accounting. These

entities, which are substantive entities, had an immaterial amount of total assets as of December 31, 2005. In addition, as of December 31, 2005, Duke Energy Carolinas recorded Net Property, Plant and Equipment of $109 million, and Long-term Debt $173 million on the Consolidated Balance Sheets, associated with a variable interest entity that was consolidated by Duke Energy Carolinas. Duke Energy Carolinas leased a natural gas processing plant from this entity, and retained all rights and obligations associated with the operations of this plant. This variable interest entity was consolidated on Duke Energy Carolinas’ Consolidated Financial Statements prior to March 31, 2004 (the effective date of FIN 46R) primarily due to Duke Energy Carolinas’ guarantee of the residual value of the assets. As a result of the transfer of Spectra Energy Capital to Duke Energy on April 3, 2006, this variable interest entity is no longer consolidated by Duke Energy Carolinas.

Various changes and clarifications to the provisions of FIN 46 have been made by the FASB since its original issuance in January 2003. While not anticipated at this time, any additional clarifying guidance or further changes to these complex rules could have an impact on Duke Energy Carolinas’ Consolidated Financial Statements.

SFAS No. 132 (Revised 2003), “Employers’ Disclosures about Pensions and Other Postretirement Benefits” (SFAS No. 132R). In December 2003, the FASB revised the provisions of SFAS No. 132, “Employers’ Disclosures about Pensions and Other Postretirement Benefits—an amendment of FASB Statements No. 87, 88, and 106,” to include additional disclosures related to defined-benefit pension plans and other defined-benefit post-retirement plans, such as the following:

Additionally, interim reports require additional disclosures related to the components of net periodic pension costs and the amounts paid or expected to be paid to the plan in the current fiscal year, if materially different than amounts previously disclosed. The provisions of SFAS No. 132R do not change the measurement or recognition provisions of defined-benefit pension and post-retirement plans as required by previous accounting standards. The provisions of SFAS No. 132R were applied by Duke Energy Carolinas effective December 31, 2003 with the interim period disclosures applied beginning with the quarter ended March 31, 2004, except for the disclosure provisions of estimated future benefit payments which were effective for Duke Energy Carolinas for the year ended December 31, 2004. See Note 20 for the additional related disclosures.

FSP No. FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (FSP No. FAS 106-2). In May 2004, the FASB staff issued FSP No. FAS 106-2, which superseded FSP FAS 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.” FSP No. FAS 106-2 provides accounting guidance for the effects of the Medicare Prescription Drug Improvement and Modernization Act of 2003 (the Modernization Act). The Modernization Act introduced a prescription drug benefit under Medicare, as well as a federal subsidy to sponsors of retiree health care benefit plans that include prescription drug benefits. FSP No. FAS 106-2 requires a sponsor to determine if its prescription drug benefits are actuarially equivalent to the drug benefit provided under Medicare Part D as of the date of enactment of the Modernization Act, and if it is therefore entitled to receive the subsidy. If a sponsor determines that its prescription drug benefits are actuarially equivalent to the Medicare Part D benefit, the sponsor should recognize the expected subsidy in the measurement of the accumulated postretirement benefit obligation (APBO) under SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions.” Any resulting reduction in the APBO is to be accounted for as an actuarial experience gain. The subsidy’s reduction, if any, of the sponsor’s share of future costs under its prescription drug plan is to be reflected in current-period service cost.

The provisions of FSP No. FAS 106-2 were effective for the first interim period beginning after June 15, 2004. Duke Energy Carolinas adopted FSP No. FAS 106-2 retroactively to the date of enactment of the Modernization Act, December 8, 2003, as allowed by the FSP. See Note 20 for discussion of the effects of adopting this FSP.

FSP No. FAS 109-1, “Application of FASB Statement No. 109, ‘Accounting for Income Taxes,’ to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004” (FSP No. FAS 109-1). On October 22, 2004, the President signed the American Jobs Creation Act of 2004 (the Act). The Act provides a deduction for income from qualified domestic production activities, which will be phased in from 2005 through 2010.

Under the guidance in FSP No. FAS 109-1, which was issued in December 2004, the deduction will be treated as a “special deduction” as described in SFAS No. 109, “Accounting for Income Taxes” (SFAS No. 109). As such, for Duke Energy Carolinas, the special deduction had no material impact on deferred tax assets and liabilities existing at the enactment date. Rather, the impact of this deduction is reported in the periods in which the deductions are claimed on the tax returns. For the years ended December 31, 2006 and 2005, Duke Energy Carolinas recognized a benefit of approximately $8 million and $9 million, respectively, relating to the deduction from qualified domestic activities.

FSP No. FAS 109-2, “Accounting and Disclosure Guidance for the Foreign Earnings Repatriation Provision within the American Jobs Creation Act of 2004” (FSP No. FAS 109-2). In addition to the qualified domestic production activities deduction discussed above, the Act creates a temporary incentive for U.S. corporations to repatriate accumulated income earned abroad by providing an 85 percent dividends received deduction for certain dividends from controlled foreign corporations. FSP No. FAS 109-2, which was issued in December 2004, states that a company is allowed time beyond the financial reporting period of enactment to evaluate the effect of the Act on its plan for reinvestment or repatriation of foreign earnings, as it applies to the application of SFAS No. 109. Although the deduction is subject to a number of limitations and some uncertainty remains as to how to interpret numerous provisions in the Act, Duke Energy Carolinas believes that it has the information necessary to make an informed decision on the impact of the Act on its repatriation plans. Based on that decision, Duke Energy Carolinas has repatriated approximately $500 million in extraordinary dividends, as defined in the Act, and accordingly recorded a corresponding tax liability of $39 million as of December 31, 2005. However, Duke Energy Carolinas has not provided for U.S. deferred income taxes or foreign withholding tax on basis differences for its non-U.S. subsidiaries that result primarily from undistributed earnings of approximately $0 as of December 31, 2006 and $290 million as of December 31, 2005, which Duke Energy Carolinas intends to reinvest indefinitely. Determination of the deferred tax liability on these basis differences is not practicable because such liability, if any, is dependent on circumstances existing if and when remittance occurs.

The following new accounting standards have been issued, but have not yet been adopted by Duke Energy Carolinas as of December 31, 2006:

SFAS No. 155, “Accounting for Certain Hybrid Financial Instruments—an amendment of FASB Statements No. 133 and 140” (SFAS No. 155). In February 2006, the FASB issued SFAS No. 155, which amends SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” and SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities.” SFAS No. 155 allows financial instruments that have embedded derivatives to be accounted for at fair value at acquisition, at issuance, or when a previously recognized financial instrument is subject to a remeasurement (new basis) event, on an instrument-by-instrument basis, in cases in which a derivative would otherwise have to be bifurcated. SFAS No. 155 is effective for Duke Energy Carolinas for all financial instruments acquired, issued, or subject to remeasurement after January 1, 2007, and for certain hybrid financial instruments that have been bifurcated prior to the effective date, for which the effect is to be reported as a cumulative-effect adjustment to beginning retained earnings. Duke Energy Carolinas does not anticipate the adoption of SFAS No. 155 will have any material impact on its consolidated results of operations, cash flows or financial position.

SFAS No. 157, “Fair Value Measurements” (SFAS No. 157). In September 2006, the FASB issued SFAS No. 157, which defines fair value, establishes a framework for measuring fair value in GAAP, and expands disclosures about fair value measurements. SFAS No. 157 does not require any new fair value measurements. However, in some cases, the application of SFAS No. 157 may change Duke Energy Carolinas’ current practice for measuring and disclosing fair values under other accounting pronouncements that require or permit fair value measurements. For Duke Energy Carolinas, SFAS No. 157 is effective as of January 1, 2008 and must be applied prospectively except in certain cases. Duke Energy Carolinas is currently evaluating the impact of adopting SFAS No. 157, and cannot currently estimate the impact of SFAS No. 157 on its consolidated results of operations, cash flows or financial position.

SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (SFAS No. 159). In February 2007, the FASB issued SFAS No. 159, which permits entities to choose to measure many financial instruments and certain other items at fair value. For Duke Energy, SFAS No. 159 is effective as of January 1, 2008 and will have no impact on amounts presented for periods prior to the

effective date. Duke Energy Carolinas cannot currently estimate the impact of SFAS No. 159 on its consolidated results of operations, cash flows or financial position and has not yet determined whether or not it will choose to measure items subject to SFAS No. 159 at fair value.

FIN 48, “Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109” (FIN 48). This accounting standard, issued by the FASB in July 2006, provides guidance on accounting for income tax positions about which Duke Energy Carolinas has concluded there is a level of uncertainty with respect to the recognition in Duke Energy Carolinas’ financial statements. FIN 48 prescribes a minimum recognition threshold a tax position is required to meet. Tax positions are defined very broadly and include not only tax deductions and credits but also decisions not to file in a particular jurisdiction, as well as the taxability of transactions. Duke Energy Carolinas will implement this new accounting standard effective January 1, 2007. The implementation will result in a Cumulative Effect of a Change in Accounting Principle, adjusting the beginning balance of Member’s Equity on the Consolidated Statement of Member’s/Common Stockholders’ Equity and Comprehensive Income (Loss) in the first quarter 2007. Corresponding entries will impact a variety of balance sheet line items, including Deferred income taxes, Taxes accrued and Other Liabilities. Upon implementation of FIN 48, Duke Energy Carolinas will reflect interest expense related to taxes as interest expense in Other Income and Expenses in the Consolidated Statement of Operations. In addition, accounting for this standard after January 1, 2007 will involve an evaluation to determine if any changes have occurred that would impact the existing uncertain tax positions as well as determining whether any new tax positions are uncertain. Any impacts resulting from the evaluation of existing uncertain tax positions or from the recognition of new uncertain tax positions would impact income tax expense and interest expense in the Consolidated Statement of Operations, with offsetting impacts to the balance sheet line items described above. Duke Energy Carolinas is still in the process of reviewing the impacts of this standard and expects that the cumulative effect charge to equity will be immaterial.

FSP No. FAS 123(R)-5, “Amendment of FASB Staff Position FAS 123(R)-1” (FSP No. FAS 123(R)-5). In October 2006, the FASB staff issued FSP No. FAS 123(R)-5 to address whether a modification of an instrument in connection with an equity restructuring should be considered a modification for purposes of applying FSP No. FAS 123(R)-1, “Classification and Measurement of Freestanding Financial Instruments Originally Issued in Exchange for Employee Services under FASB Statement No. 123(R) (FSP No. FAS 123(R)-1).” In August 2005, the FASB staff issued FSP FAS 123(R)-1 to defer indefinitely the effective date of paragraphs A230–A232 of SFAS No. 123(R), and thereby require entities to apply the recognition and measurement provisions of SFAS No. 123(R) throughout the life of an instrument, unless the instrument is modified when the holder is no longer an employee. The recognition and measurement of an instrument that is modified when the holder is no longer an employee should be determined by other applicable generally accepted accounting principles. FSP No. FAS 123(R)-5 addresses modifications of stock-based awards made in connection with an equity restructuring and clarifies that for instruments that were originally issued as employee compensation and then modified, and that modification is made to the terms of the instrument solely to reflect an equity restructuring that occurs when the holders are no longer employees, no change in the recognition or the measurement (due to a change in classification) of those instruments will result if certain conditions are met. This FSP is effective for Duke Energy Carolinas as of January 1, 2007. The impact to Duke Energy Carolinas of applying FSP No. FAS 123(R)-5 in subsequent periods will be dependent upon the nature of any modifications to Duke Energy’s share-based compensation awards.

FSP No. AUG AIR-1, “Accounting for Planned Major Maintenance Activities,” (FSP No. AUG AIR-1). In September 2006, the FASB Staff issued FSP No. AUG AIR-1. This FSP prohibits the use of the accrue-in-advance method of accounting for planned major maintenance activities in annual and interim financial reporting periods, if no liability is required to be recorded for an asset retirement obligation based on a legal obligation for which the event obligating the entity has occurred. The FSP also requires disclosures regarding the method of accounting for planned major maintenance activities and the effects of implementing the FSP. The guidance in this FSP is effective for Duke Energy Carolinas as of January 1, 2007 and will be applied retrospectively for all financial statements presented. Duke Energy Carolinas does not anticipate the adoption of FSP No. AUG AIR-1 will have any material impact on its consolidated results of operations, cash flows or financial position.

EITF Issue No. 06-3, “How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (That Is, Gross versus Net Presentation)” (EITF No. 06-3). In June 2006, the EITF reached a consensus on EITF No. 06-3 to address any tax assessed by a governmental authority that is directly imposed on a revenue-producing transaction between a seller and a customer and may include, but are not limited to, sales, use, value added, and some excise taxes. For taxes within the issue’s scope, the consensus requires that entities present such taxes on either a gross (i.e. included in revenues and costs) or net (i.e. exclude from revenues) basis according to their accounting policies, which should be disclosed. If such taxes are reported gross and are

significant, entities should disclose the amounts of those taxes. Disclosures may be made on an aggregate basis. The consensus is effective for Duke Energy Carolinas beginning January 1, 2007. Duke Energy Carolinas does not anticipate the adoption of EITF No. 06-3 will have any material impact on its consolidated results of operations, cash flows or financial position.

EITF Issue No. 06-6, “Debtor’s Accounting for a Modification (or Exchange) of Convertible Debt Instruments” (EITF No. 06-6). In November 2006, the EITF reached a consensus on EITF No. 06-6. EITF No. 06-6 addresses how a modification of a debt instrument (or an exchange of debt instruments) that affects the terms of an embedded conversion option should be considered in the issuer’s analysis of whether debt extinguishment accounting should be applied, and further addresses the accounting for a modification of a debt instrument (or an exchange of debt instruments) that affects the terms of an embedded conversion option when extinguishment accounting is not applied. EITF No. 06-6 applies to modifications (or exchanges) occurring in interim or annual reporting periods beginning after November 29, 2006, regardless of when the instrument was originally issued. Early application is permitted for modifications (or exchanges) occurring in periods for which financial statements have not been issued. There were no modifications to, or exchanges of, any of Duke Energy’s debt instruments within the scope of EITF No. 06-6 in 2006. The impact to Duke Energy Carolinas of applying EITF No. 06-6 in subsequent periods will be dependent upon the nature of any modifications to, or exchanges of, any debt instruments within the scope of EITF No. 06-6. Refer to Note 15.

Duke Energy Carolinas consolidates assets and liabilities from acquisitions as of the purchase date, and includes earnings from acquisitions in consolidated earnings after the purchase date. Assets acquired and liabilities assumed are recorded at estimated fair values on the date of acquisition. The purchase price minus the estimated fair value of the acquired assets and liabilities meeting the definition of a business as defined in EITF Issue No. 98-3, “Determining Whether a Nonmonetary Transaction Involves Receipt of Productive Assets or of a Business” (EITF 98-3), is recorded as goodwill. The allocation of the purchase price may be adjusted if additional, requested information is received during the allocation period, which generally does not exceed one year from the consummation date, however, it may be longer for certain income tax items.

On April 3, 2006, the previously announced merger between Duke Energy and Cinergy was consummated (see Note 1 for additional information). See Note 4 for discussion of regulatory impacts of the merger to Duke Energy Carolinas.

In May 2006, Duke Energy Carolinas announced an agreement to acquire an approximate 825 megawatt power plant located in Rockingham County, North Carolina, from Dynegy Inc. for approximately $195 million. The Rockingham plant is a peaking power plant used during times of high electricity demand, generally in the winter and summer months and consists of five 165 megawatt combustion turbine units capable of using either natural gas or oil to operate. The acquisition is consistent with Duke Energy Carolinas’ plan to meet customers’ electric needs for the foreseeable future. The transaction, which closed in the fourth quarter of 2006, required approvals by the NCUC and the Federal Energy Regulatory Commission (FERC). The NCUC approved it on July 25, 2006 and the FERC issued an order authorizing the transaction on October 31, 2006. In addition, the U.S. Federal Trade Commission (FTC) approved the transaction on July 20, 2006, under the Hart-Scott-Rodino Antitrust Improvement Act. No goodwill was recorded as a result of this acquisition.

The pro-forma results of operations for Duke Energy Carolinas as if the Rockingham facility transaction had occurred as of the beginning of the periods presented do not materially differ from reported results.

See Note 13 for discussion of businesses acquired during the three months ended March 31, 2006 and the years ended December 31, 2005 and 2004 that were included in the transfer of Spectra Energy Capital to Duke Energy on April 3, 2006 and, accordingly, are included in Income From Discontinued Operations, net of tax, on the Consolidated Statements of Operations.

In conjunction with Duke Energy’s merger with Cinergy, effective with the second quarter of 2006, Duke Energy Carolinas adopted new business segments that management believes properly align the various operations of Duke Energy Carolinas with how the chief operating decision maker views the business. Prior period segment information has been recast to conform to the new segment structure. Accordingly, Duke Energy Carolinas has the following reportable business segment:

Duke Energy Carolinas’ chief operating decision maker regularly reviews financial information about the business unit in deciding how to allocate resources and evaluate performance. The business unit is considered a reportable segment under SFAS No. 131. There is no aggregation within Duke Energy Carolinas’ defined business segment.

Prior to Duke Energy’s merger with Cinergy on April 3, 2006, Duke Energy Carolinas operated the following business units, all of which were considered reportable segments under SFAS No. 131: Franchised Electric, Natural Gas Transmission, Field Services, International Energy and Crescent Resources, LLC (Crescent). In connection with Duke Energy’s merger with Cinergy, former Duke Energy North America’s (DENA) continuing operations, which had been included in Other, are included as a component of the Commercial Power segment for all periods presented. As described in Note 1, on April 3, 2006, Duke Energy Carolinas transferred to Duke Energy its membership interests in Spectra Energy Capital, the results of which are included in Income From Discontinued Operations, net of tax, on the Consolidated Statements of Operations for the three months ended March 31, 2006, and for the years ended December 31, 2005 and 2004.

The remainder of Duke Energy Carolinas’ operations is presented as “Other”. While it is not considered a business segment, Other primarily includes certain allocated corporate governance costs, as well as a management fee charged by an unconsolidated affiliate (see Note 11). For the year ended December 31, 2006, Other contains approximately $72 million of severance charges primarily as a result of Duke Energy’s merger with Cinergy.

Prior to the second quarter of 2006, Other also consisted of certain discontinued hedges, DukeNet Communications, LLC, DEM, Bison Insurance Company Limited (Bison), Duke Energy Carolinas’ wholly owned, captive insurance subsidiary, and Duke Energy Carolinas’ 50% interest in Duke/Fluor Daniel, all of which are included in Income From Discontinued Operations, net of tax, on the Consolidated Statements of Operations for the three months ended March 31, 2006, and for the years ended December 31, 2005 and 2004.

Management evaluates segment performance based on earnings before interest and taxes from continuing operations, after deducting minority interest expense related to those profits (EBIT). On a segment basis, EBIT excludes discontinued operations, represents all profits from continuing operations (both operating and non-operating) before deducting interest and taxes, and is net of the minority interest expense related to those profits. Cash, cash equivalents and short-term investments are managed centrally by Duke Energy, so the associated realized and unrealized gains and losses from foreign currency transactions and interest and dividend income on those balances are excluded from segment EBIT.

Deferred Debits/Regulatory Assets and Liabilities. Duke Energy Carolinas’ regulated operations are subject to SFAS No. 71. Accordingly, Duke Energy Carolinas records assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for non-regulated entities. (For further information see Note 1.)

Regulatory Merger Approvals. As discussed in Note 1, on April 3, 2006, the merger between Duke Energy and Cinergy was consummated to create a newly formed company, Duke Energy Holding Corp. (subsequently renamed Duke Energy Corporation). As a condition to the merger approval, the PSCSC and the NCUC required that certain merger related savings be shared with consumers in South Carolina and North Carolina, respectively. The commissions also required Duke Energy Holding Corp. and/or Duke Energy Carolinas to meet additional conditions. Key elements of these conditions include:

In its order approving Duke Energy’s merger with Cinergy, the NCUC stated that the merger will result in a significant change in Duke Energy’s organizational structure which constitutes a compelling factor that warrants a general rate review. Therefore, as a condition of its merger approval and no later than June 1, 2007, Duke Energy Carolinas is required to file a general rate case or demonstrate that Duke Energy Carolinas’ existing rates and charges should not be changed. This review will be consolidated with the proceeding that the NCUC is required to undertake in connection with the North Carolina clean air legislation to review Duke Energy Carolinas’ environmental compliance costs. The NCUC specifically noted that it has made no determination that the rates currently being charged by Duke Energy Carolinas are, in fact, unjust or unreasonable.

Spent Nuclear Fuel. Under provisions of the Nuclear Waste Policy Act of 1982, Duke Energy Carolinas contracted with the U.S. Department of Energy (DOE) for the disposal of spent nuclear fuel. The DOE failed to begin accepting spent nuclear fuel on January 31, 1998, the date specified by the Nuclear Waste Policy Act and in Duke Energy Carolinas’ contract with the DOE. In 1998, Duke Energy filed a claim with the U.S. Court of Federal Claims against the DOE related to the DOE’s failure to accept commercial spent nuclear fuel by the required date. Damages claimed in the lawsuit are based upon Duke Energy Carolinas’ costs incurred as a result of the DOE’s partial material breach of its contract, including the cost of securing additional spent fuel storage capacity. Duke Energy Carolinas will continue to safely manage its spent nuclear fuel until the DOE accepts it. Payments made to the DOE for expected future disposal costs are based on nuclear output and are included in the Consolidated Statements of Operations as Fuel Used in Electric Generation and Purchased Power. On March 6, 2007, Duke Energy Carolinas and the U.S. Department of Justice reached a settlement resolving Duke Energy’s used nuclear fuel litigation against the DOE. The agreement provides for an initial payment to Duke Energy of approximately $56 million for certain storage costs incurred through July 31, 2005, with additional amounts reimbursed annually for future storage costs. Duke Energy Carolinas is still evaluating the financial statement impact of the initial payment, but anticipates a favorable pre-tax earnings impact in 2007 of less than the $56 million settlement.

Other Regulatory Matters. Rate Related Information. The NCUC and PSCSC approve rates for retail electric sales within their states. The FERC approves rates for electric sales to wholesale customers served under cost-based rates.

NC Clean Air Act Compliance. In 2002, the state of North Carolina passed clean air legislation that freezes electric utility rates from June 20, 2002 to December 31, 2007 (rate freeze period), subject to certain conditions, in order for North Carolina electric utilities, including Duke Energy Carolinas, to significantly reduce emissions of sulfur dioxide (SO₂) and nitrogen oxides (NOx) from coal-fired power plants in the state. The legislation allows electric utilities, including Duke Energy Carolinas, to accelerate the recovery of compliance costs by amortizing them over seven years (2003-2009). The legislation provides for significant flexibility in the amount of annual amortization recorded, allowing utilities to vary the amount amortized, within limits, although the legislation does require that a minimum of 70% of the originally estimated total cost of $1.5 billion be amortized within the rate freeze period (2002 to 2007). Duke Energy Carolinas’ amortization expense related to this clean air legislation totals approximately $863 million from inception, with approximately $225 million, $311 million and $211 million recorded during the years ended 2006, 2005 and 2004, respectively. As of December 31, 2006, cumulative expenditures totaled approximately $828 million, with $403 million, $310 million, and $106 million incurred during the years ended December 31, 2006, 2005 and 2004, respectively, and are included within capital expenditures in Net Cash Used In Investing Activities on the Consolidated Statements of Cash Flows. In filings with the NCUC, Duke Energy Carolinas has estimated the costs to comply with the legislation as approximately $1.7 billion. Actual costs may be higher than the estimate based on changes in construction costs and Duke Energy Carolinas’ continuing analysis of its overall environmental compliance plan. Any change in compliance costs will be included in future filings with the NCUC. Additionally, federal, state and environmental regulations, including, among other things, the Clean Air Interstate Rule (CAIR), and the Clean Air Mercury Rule (CAMR) could result in additional costs to reduce emissions from our coal-fired power plants.

Bulk Power Marketing (BPM) Profit Sharing. The NCUC approved Duke Energy Carolinas’ proposal in June 2004 to share an amount equal to fifty percent of the North Carolina retail allocation of the profits from certain wholesale sales of bulk power from Duke Energy Carolinas’ generating units at market based rates (BPM Profits). Duke Energy Carolinas also informed the NCUC that it would no longer include BPM Profits in calculating its North Carolina retail jurisdictional rate of return for its quarterly reports to the NCUC. As approved by the NCUC, the sharing arrangement provides for fifty percent of the North Carolina allocation of BPM Profits to be distributed through various assistance programs, up to a maximum of $5 million per year. Any amounts exceeding the maximum are used to reduce rates for industrial customers in North Carolina.

On June 28, 2006, the NCUC issued an order ruling on a dispute between Duke Energy Carolinas, the NCUC Public Staff and the Carolina Utility Customers Association (CUCA) regarding the method for determining the incremental costs of emission allowances used to calculate the BPM Profits under the sharing arrangement. The Public Staff and CUCA each proposed methods that differ from the method intended by Duke Energy Carolinas when it initially requested approval of the sharing arrangement. Duke Energy Carolinas has consistently used its originally intended method since it first implemented the sharing arrangement. The NCUC adopted the Public Staff’s method and ordered Duke Energy Carolinas to file and implement a revised rate rider. This ruling resulted in an $18 million charge, of which $11 million related to wholesale sales in 2005. On July 17, 2006, Duke Energy Carolinas filed a Motion for Reconsideration requesting that the NCUC reconsider its June 28, 2006 order. In the alternative, Duke Energy Carolinas requested that the NCUC make its order effective only prospectively with respect to sharing periods beginning January 1, 2007. Duke Energy Carolinas also requested that if the NCUC was not inclined to grant its request to reinstate its proposed rider, then the NCUC should approve Duke Energy Carolinas’ withdrawal of the rider at its option. On September 15, 2006, Duke Energy Carolinas and the Public Staff filed an Offer of Settlement under which Duke Energy Carolinas’ method would be used through June 30, 2006 and the Public Staff’s method would be used from July 1, 2006 through the end of the sharing arrangement. Additionally, the sharing arrangement would be extended for the shorter of 1 year (through December 31, 2008) or the effective date of a general rate order from the NCUC addressing the ratemaking treatment of BPM revenues. In December 2006, the NCUC approved the settlement after an evidentiary hearing and Duke Energy Carolinas reversed the $18 million charge previously recognized.

Other. Duke Energy Carolinas is engaged in planning efforts to meet projected load growth in its service territory. Long-term projections indicate a need for significant capacity additions, which may include new nuclear and coal facilities. Because of the long lead times required to develop such assets, Duke Energy Carolinas is taking steps now to ensure those options are available. In March 2006, Duke Energy Carolinas announced that it has entered into an agreement with Southern Company to evaluate potential construction of a new nuclear plant at a site jointly owned in Cherokee County, South Carolina. With selection of the Cherokee County site, Duke Energy Carolinas is moving forward with previously announced plans to develop an application to the U.S. Nuclear Regulatory Commission (NRC) for a combined construction and operating license (COL) for two Westinghouse AP1000 (advanced passive) reactors. Each reactor is capable of producing approximately 1,117 MW. The COL application submittal to the NRC is anticipated in late 2007 or early 2008. Submitting

the COL application does not commit Duke Energy Carolinas to build nuclear units. On September 20, 2006, Duke Energy Carolinas filed an application with the NCUC for assurance that pursuit of the proposed nuclear plant (the William States Lee III Nuclear Station) is prudent and that Duke Energy Carolinas will be allowed to recover prudently incurred expenses related to its development and evaluation of the proposed William States Lee III Nuclear Station. Specifically, Duke Energy Carolinas requests an NCUC order (1) finding that work performed by Duke Energy Carolinas to ensure the availability of nuclear generation by 2016 for its customers is prudent and consistent with the promotion of adequate, reliable, and economical utility service to the citizens of North Carolina and the polices expressed in North Carolina General Statute 62-2, and (2) providing expressly that Duke Energy Carolinas may recover in rates, in a timely fashion, the North Carolina allocable portion of its share of costs prudently incurred to evaluate and develop a new nuclear generation facility through December 31, 2007, whether or not a new nuclear facility is constructed. The NCUC held oral arguments on January 9, 2007, and briefs were filed on February 14, 2007. Duke Energy Carolinas expects the NCUC to rule on its application in the first quarter of 2007.

On June 2, 2006, Duke Energy Carolinas also filed an application with the NCUC for a Certificate of Public Convenience and Necessity (CPCN) to construct two 800 MW state of the art coal generation units at its existing Cliffside Steam Station in North Carolina. The NCUC held public hearings in August 2006, and an evidentiary hearing in Raleigh, North Carolina concluded on September 14, 2006. Post-hearing briefs and proposed orders were filed on October 13, 2006. After the evidentiary hearing, Duke Energy Carolinas received competitive proposals for two major scopes of equipment for the Cliffside Project which suggest that the capital costs for these major components are increasing significantly due to various market pressures that will likely impact utility generation construction projects across the United States. In October 2006, Duke Energy made a filing with the NCUC related to the Duke Energy Carolinas’ request for a CPCN for the Cliffside project. In this filing, Duke Energy stated that due to the rising costs described above, the cost of building the Cliffside units could be approximately $3 billion, excluding allowance for funds used during construction (AFUDC). The costs described above are expected to continue to increase causing the overall cost of the Cliffside project to increase, until such time as the NCUC issues a CPCN and Duke Energy Carolinas is able to enter into definitive agreements with necessary material and service providers. The NCUC issued orders requiring additional public and evidentiary hearings. From January 17, 2007 to January 19, 2007 the NCUC held an evidentiary hearing to consider evidence limited to Duke Energy Carolinas updated cost information for the project. On February 28, 2007, the NCUC issued a notice of decision approving the construction of one unit at the Cliffside Steam Station. The NCUC stated that it will issue a full order in the near future. Duke Energy Carolinas will review the NCUC’s order, once issued, and determine whether to proceed with the Cliffside Project or consider other alternatives, including additional gas fired generation.

New energy legislation has been introduced in the current South Carolina legislative session. Key elements of the legislation include expansion of the annual fuel clause mechanism to include recovery of costs of reagents (ammonia, limestone, etc.) that are consumed in the operation of Duke Energy Carolinas’ SO₂ and NOx control technologies. The cost of reagents for Duke Energy Carolinas in 2007 is expected to be approximately $20 million. Subsequent to the enactment of any legislation, Duke Energy Carolinas then will be allowed to recover the South Carolina portion of these costs through the fuel clause. The legislation also includes provisions to provide cost recovery assurance for upfront development costs associated with nuclear baseload generation, cost recovery assurance for construction costs associated with nuclear or coal baseload generation, and the ability to recover financing costs for new nuclear or coal baseload generation through annual riders. Similar legislation is being discussed in North Carolina and may be introduced in the 2007 legislative session. At this time, Duke Energy Carolinas cannot determine which elements of any pending legislation will be passed into law or the potential financial impact of those legislative initiatives.

FERC To Issue Electric Reliability Standards. Consistent with reliability provisions of the Energy Policy Act of 2005, on July 20, 2006, FERC issued its Final Rule certifying the North American Electric Reliability Council (NERC) as the Electric Reliability Organization (ERO). NERC has filed over 100 proposed reliability standards with FERC. FERC’s proposed action to approve a large number of these standards will result in those standards becoming mandatory and enforceable for the 2007 peak summer season. Other reliability standards will become mandatory and enforceable thereafter. Duke Energy Carolinas does not believe that the issuance of these standards will have a material impact on its consolidated results of operations, cash flows, or financial position.

FERC Issues New Open-Access Transmission Tariff Rules. On February 15, 2007, the FERC issued extensive new rules for the operation by transmission providers such as Duke Energy Carolinas of their Open-Access Transmission Tariffs (OATT). While compliance with these rules will require changes to the operation of the OATT and Duke Energy Carolinas’ transmission system, Duke Energy Carolinas does not believe that the issuance of these new rules will have a material impact on its consolidated results of operations, cash flows or financial position.

Duke Energy Carolinas “Independent Entity” to Perform Transmission Functions. On December 19, 2005, the FERC approved a plan filed by Duke Energy Carolinas to establish an “Independent Entity” (IE) to serve as a coordinator of certain transmission functions and an “Independent Monitor” (IM) to monitor the transparency and fairness of the operation of Duke Energy Carolinas’ transmission system. Under the proposal, Duke Energy Carolinas remains the owner and operator of the transmission system with responsibility for the provision of transmission service under Duke Energy Carolinas’ Open Access Transmission Tariff. Duke Energy Carolinas has retained the Midwest ISO to act as the IE and Potomac Economics, Ltd. to act as the IM. The IE and IM began operations on November 1, 2006. Duke Energy Carolinas is not at this time seeking adjustments to its transmission rates to reflect the incremental cost of the proposal, which is not projected to have a material adverse effect on Duke Energy Carolinas’ future consolidated results of operations, cash flows or financial position.

Duke Energy Carolinas, along with North Carolina Municipal Power Agency Number 1, North Carolina Electric Membership Corporation, Piedmont Municipal Power Agency and Saluda River Electric Cooperative, Inc., have joint ownership of Catawba Nuclear Station, which is a facility operated by Duke Energy Carolinas.

As of December 31, 2006, Duke Energy Carolinas’ share in jointly-owned generating facilities were as follows:

In December 2006, Duke Energy Carolinas announced an agreement to purchase a portion of Saluda River Electric Cooperative, Inc.’s ownership interest in the Catawba Nuclear Station. Under the terms of the agreement, Duke Energy Carolinas will pay approximately $158 million for the additional ownership interest of the Catawba Nuclear Station. Following the closing of the transaction, Duke Energy Carolinas will own approximately 19 percent of the Catawba Nuclear Station. This transaction, which is expected to close prior to September 30, 2008, is subject to approval by various state and federal agencies.

Duke Energy Carolinas’ share of revenues and operating costs of the above jointly owned generating facilities are included within the corresponding line on the Consolidated Statements of Operations.

The following details the components of income tax expense from continuing operations:

Reconciliation of Income Tax Expense at the U.S. Federal Statutory Tax Rate to the Actual Tax Expense (Benefit) from Continuing Operations (Statutory Rate Reconciliation)

During 2006, Duke Energy Carolinas had a favorable tax settlement of approximately $15 million. This benefit in 2006 is included in the Statutory Rate Reconciliation in “Other Items, net”.

During 2004, Duke Energy recorded a $48 million income tax benefit from the change in state tax rates relating to deferred taxes as a result of a reorganization of certain subsidiaries. The $48 million benefit is included in “State income tax, net of federal income tax effect” in the Statutory Rate Reconciliation.

The above amounts have been classified in the Consolidated Balance Sheets as follows:

Although the outcome of tax audits is uncertain, management believes that adequate provisions for income and other taxes, such as sales and use, franchise, and property, have been made for potential liabilities resulting from such matters. As of December 31, 2006, Duke Energy Carolinas has total provisions of $26 million for uncertain tax positions, as compared to approximately $150 million as of December 31, 2005, including interest. The decrease in total provisions from year end is primarily attributable to the restructuring of the organization. Management is not aware of any issues for open tax years that upon final resolution are expected to have a material adverse effect on Duke Energy Carolinas’ consolidated results of operations, cash flows or financial position.

On October 22, 2004, the President of the United States signed the American Jobs Creation Act of 2004 (The Act). The Act provides a deduction for income from qualified domestic production activities, which will be phased in from 2005 to 2010.

Under the guidance in FSP No. FAS 109-1, which was issued in December 2004, the deduction will be treated as a “special deduction” as described in SFAS No. 109. As such, for Duke Energy Carolinas, the special deduction had no material impact on deferred tax assets and liabilities existing at the enactment date. Rather, the impact of this special deduction will be reported in the periods in which the deductions are claimed on the tax returns. For the year ended December 31, 2006, Duke Energy Carolinas recognized a benefit of approximately $8 million relating to the deduction from qualified domestic activities.

In addition to the qualified domestic production activities deduction discussed above, the Act creates a temporary incentive for U.S. corporations to repatriate accumulated income earned abroad by providing an 85 percent dividends received deduction for certain dividends from controlled foreign corporations. FSP No. FAS 109-2, which was issued in December 2004, states that a company is allowed time beyond the financial reporting period of enactment to evaluate the effect of the Act on its plan for reinvestment or repatriation of foreign earnings, as it applies to the application of SFAS No. 109. Although the deduction is subject to a number of limitations and some uncertainty remains as to how to interpret numerous provisions in the Act, Duke Energy Carolinas recorded a $45 million tax liability at December 31, 2004 based upon Duke Energy Carolinas’ plans that it would repatriate approximately $500 million in extraordinary dividends in 2005. In 2005, Duke Energy Carolinas repatriated approximately $500 million in extraordinary dividends. During this process, Duke Energy Carolinas reorganized various entities and reduced its liability from $45 million to $39 million. There is no remaining liability as of December 31, 2006 and 2005. Duke Energy Carolinas has no foreign operation and did not participate in the Duke Energy repatriation.

As of December 31, 2006 and 2005, approximately $94 million and $256 million, respectively, of federal income tax receivables were included in Other within Current Assets on the Consolidated Balance Sheets. As of December 31, 2006, this balance exceeded 5% of total current assets.

In June 2001, the FASB issued SFAS No. 143, which was adopted by Duke Energy Carolinas on January 1, 2003 and addresses financial accounting and reporting for legal obligations associated with the retirement of tangible long-lived assets and the related 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. Subsequent to the initial recognition, the liability is adjusted for any revisions to the expected value of the retirement obligation (with corresponding adjustments to property, plant, and equipment), and for accretion of the liability due to the passage of time. Additional depreciation expense is recorded prospectively for any property, plant and equipment increases.

Asset retirement obligations at Duke Energy Carolinas relate primarily to the decommissioning of nuclear power facilities, obligations related to right-of-way agreements, asbestos removal and contractual leases for land use.

The adoption of SFAS No. 143 had no impact on the income of Duke Energy Carolinas’ regulated operations, as the effects were offset by the establishment of regulatory assets and liabilities pursuant to SFAS No. 71 as Duke Energy Carolinas received approval from both the NCUC and PSCSC to defer all cumulative and future income statement impacts related to SFAS No. 143.

In March 2005, the FASB issued FIN 47. As a result of the adoption of FIN 47 in 2005, an increase in total assets of $31 million was recorded, consisting of an increase in regulatory assets of $24 million, an increase in net property, plant and equipment of $7 million and an increase in ARO liabilities of approximately $35 million. The adoption of FIN 47 had no impact on the income of Duke Energy Carolinas’

regulated operations, as the effects were offset by the establishment of regulatory assets and liabilities pursuant to SFAS No. 71. For obligations related to other operations, a net-of-tax cumulative effect adjustment of approximately $4 million was recorded in the fourth quarter of 2005 as a reduction in earnings (see Note 1).

The pro forma effects of adopting FIN 47, including the impact on the balance sheet and net income are not presented due to the immaterial impact.

The asset retirement obligation is adjusted each period for any liabilities incurred or settled during the period, accretion expense and any revisions made to the estimated cash flows.

Upon adoption of SFAS No. 143, Duke Energy Carolinas’ regulated electric and regulated natural gas operations classified removal costs for property that does not have an associated legal retirement obligation as a regulatory liability, in accordance with regulatory treatment under SFAS No. 71. The total amount of removal costs for Duke Energy Carolinas included in Other Deferred Credits and Other Liabilities on the Consolidated Balance Sheets was $1,433 million and $1,670 million as of December 31, 2006 and 2005, respectively (of which $350 million at December 31, 2005 related to regulated natural gas operations, which were transferred to Duke Energy on April 3, 2006, as discussed in Note 1).

Accretion expense for the years ended December 31, 2006 and 2005 has been deferred as regulatory assets and liabilities in accordance with SFAS No. 71, as discussed above.

Nuclear Decommissioning Costs. Pursuant to an order issued by the NCUC on February 5, 2004, Duke Energy Carolinas was required to contribute amounts reserved for non-contaminated costs of decommissioning to the NDTF over a ten-year period. In April 2004, Duke Energy Carolinas contributed its entire reserve of $262 million in cash to the NDTF. This contribution is presented in the Consolidated Statements of Cash Flows in Purchases of Available-For-Sale Securities within Cash Flows from Investing Activities.

In 2005, the NCUC and PSCSC approved a $48 million annual amount for contributions and expense levels for decommissioning. In each of the years ended December 31, 2006 and 2005, Duke Energy Carolinas expensed approximately $48 million and contributed cash of approximately $48 million to the NDTF for decommissioning costs. These amounts are presented in the Consolidated Statements of Cash Flows in Purchases of Available-For-Sale Securities within Cash Flows from Investing Activities. In both 2006 and 2005, $48 million was contributed entirely to the funds reserved for contaminated costs. Contributions were discontinued to the funds reserved for non-contaminated costs since the current estimates indicate existing funds to be sufficient to cover projected future costs. The balance of the external funds was $1,775 million as of December 31, 2006 and $1,504 million as of December 31, 2005. These amounts are reflected in the Consolidated Balance Sheets as Nuclear Decommissioning Trust Funds (asset). The fair value of assets legally restricted for the purpose of settling asset retirement obligations associated with nuclear decommissioning was $1,421 million as of December 31, 2006 and $1,194 million as of December 31, 2005.

Estimated site-specific nuclear decommissioning costs, including the cost of decommissioning plant components not subject to radioactive contamination, total approximately $2.3 billion in 2003 dollars, based on a decommissioning study completed in 2004. This

includes costs related to Duke Energy Carolinas’ 12.5% ownership in the Catawba Nuclear Station. The other joint owners of the Catawba Nuclear Station are responsible for decommissioning costs related to their ownership interests in the station. Both the NCUC and the PSCSC have allowed Duke Energy Carolinas to recover estimated decommissioning costs through retail rates over the expected remaining service periods of Duke Energy Carolinas’ nuclear stations. Management believes that the decommissioning costs being recovered through rates, when coupled with expected fund earnings, are sufficient to provide for the cost of decommissioning.

The operating licenses for Duke Energy Carolinas’ nuclear units are subject to extension. In December 2003, Duke Energy Carolinas was granted renewed operating licenses for the Catawba and McGuire Nuclear Stations until 2041 and 2043 (license expirations vary by nuclear unit). In 2000, Duke Energy Carolinas was granted a license renewal for the Oconee Nuclear Station until 2033 and 2034 (license expirations vary by nuclear unit).

A provision in the Energy Policy Act of 1992 established a fund for the decontamination and decommissioning of the DOE’s uranium enrichment plants (the D&D Fund). Licensees are subject to an annual assessment for 15 years based on their pro rata share of past enrichment services. The annual assessment is recorded in the Consolidated Statements of Operations as Fuel Used in Electric Generation and Purchased Power. Duke Energy Carolinas has paid $152 million into the D&D Fund, including $12 million during 2006 and $11 million during each of 2005 and 2004. There are no remaining liabilities or regulatory assets as of December 31, 2006. The liability and regulatory assets of $12 million as of December 31, 2005 are reflected in the Consolidated Balance Sheets as Other Deferred Credits and Other Liabilities, and Other Regulatory Assets and Deferred Debits, respectively.

8. Risk Management and Hedging Activities, Credit Risk, and Financial Instruments

Duke Energy Carolinas is exposed to the impact of market fluctuations in the prices of electricity, coal and other energy-related products marketed and purchased as a result of its ownership of energy related assets. Exposure to interest rate risk exists as a result of the issuance of variable and fixed rate debt and commercial paper. Duke Energy Carolinas employs established policies and procedures to manage its risks associated with these market fluctuations using various commodity and financial derivative instruments, including swaps, futures, forwards, options and swaptions. Duke Energy Carolinas’ derivative portfolio carrying value as of December 31, 2006 is immaterial.

Commodity Cash Flow Hedges. Duke Energy Carolinas is exposed to market fluctuations in the price of power related to ongoing bulk power marketing activities. Duke Energy Carolinas monitors the potential impacts of commodity price changes and, where appropriate, enters into contracts, such as forwards and options, as cash flow hedges for sales of electricity. Duke Energy Carolinas hedging activities do not extend beyond 2007.

The ineffective portion of commodity cash flow hedges resulted in a pre-tax gain of $1 million in 2006 and is reported primarily in Regulated electric in the Consolidated Statements of Operations. The amount recognized for transactions that no longer qualified as cash flow hedges was not material in 2006.

As of December 31, 2006, $4 million of pre-tax deferred net gains on derivative instruments related to commodity cash flow hedges were accumulated on the Consolidated Balance Sheets in a separate component of stockholders’ equity, in AOCI, and are expected to be recognized in earnings during the next twelve months as the hedged transactions occur.

Normal Purchases and Normal Sales Exception. Duke Energy Carolinas has applied the normal purchases and normal sales scope exception, as provided in SFAS No. 133, interpreted by Derivative Implementation Group Issue C15, “Scope Exceptions: Normal Purchases and Normal Sales Exception for Option-Type Contracts and Forward Contracts in Electricity,” and amended by SFAS No. 149,

“Amendment of Statement 133 on Derivative Instruments and Hedging Activities,” to certain contracts involving the purchase and sale of electricity at fixed prices in future periods. These contracts relate primarily to the delivery of electricity over the next 2 years.

Interest Rate (Fair Value or Cash Flow) Hedges. Changes in interest rates expose Duke Energy Carolinas to risk as a result of its issuance of variable and fixed rate debt and commercial paper. Duke Energy Carolinas manages its interest rate exposure by limiting its variable-rate exposures to percentages of total capitalization and by monitoring the effects of market changes in interest rates. Duke Energy Carolinas also enters into financial derivative instruments, including, but not limited to, interest rate swaps, swaptions and U.S. Treasury lock agreements to manage and mitigate interest rate risk exposure. Duke Energy Carolinas’ existing interest rate derivative instruments and related ineffectiveness were not material to its consolidated results of operations, cash flows or financial position in 2006, 2005 and 2004.

As of December 31, 2006, $2 million of pre-tax deferred losses on derivative instruments related to interest rate cash flow hedges were accumulated on the Consolidated Balance Sheet in AOCI, and are expected to be recognized in earnings during the next 12 months as the hedged transactions occur. However, due to the volatility of interest rates, the corresponding value in AOCI will likely change prior to its reclassification into earnings.

Credit Risk. Where exposed to credit risk, Duke Energy Carolinas analyzes the counterparties’ financial condition prior to entering into an agreement, establishes credit limits and monitors the appropriateness of those limits on an ongoing basis.

Duke Energy Carolinas’ industry has historically operated under negotiated credit lines for physical delivery contracts. Duke Energy Carolinas also uses master collateral agreements to mitigate certain credit exposures, primarily in its marketing and risk management operations. The collateral agreements provide for a counterparty to post cash or letters of credit to the exposed party for exposure in excess of an established threshold. The threshold amount represents an unsecured credit limit, determined in accordance with the corporate credit policy. Collateral agreements also provide that the inability to post collateral is sufficient cause to terminate contracts and liquidate all positions.

Duke Energy Carolinas also obtains cash or letters of credit from customers to provide credit support outside of collateral agreements, where appropriate, based on its financial analysis of the customer and the regulatory or contractual terms and conditions applicable to each transaction.

Collateral amounts held or posted may be fixed or may vary depending on the terms of the collateral agreement and the nature of the underlying exposure and generally cover retail deposits, marketing, normal purchases and normal sales and hedging contracts outstanding. Duke Energy Carolinas may be required to return certain held collateral and post additional collateral should price movements adversely impact the value of open contracts or positions. In many cases, Duke Energy Carolinas’ and its counterparties’ publicly disclosed credit ratings impact the amounts of additional collateral to be posted. If Duke Energy Carolinas or its affiliates have a credit rating downgrade, it could result in reductions in Duke Energy Carolinas’ unsecured thresholds granted by counterparties. Likewise, downgrades in credit ratings of counterparties could require counterparties to post additional collateral to Duke Energy Carolinas and its affiliates.

Duke Energy Carolinas has an immaterial amount of collateral assets as of December 31, 2006. Included in Other Current Liabilities and Other Deferred Credits and Other Liabilities in the Consolidated Balance Sheets as of December 31, 2006 are collateral liabilities of approximately $100 million, which represents cash collateral posted by other third parties to Duke Energy Carolinas.

Financial Instruments. The fair value of financial instruments, excluding derivatives included elsewhere in this Note and in Note 13, is summarized in the following table. Judgment is required in interpreting market data to develop the estimates of fair value. Accordingly, the estimates determined as of December 31, 2006 and 2005, are not necessarily indicative of the amounts Duke Energy Carolinas could have realized in current markets.

The fair value of cash and cash equivalents, short-term investments, accounts and notes receivable, accounts payable and commercial paper are not materially different from their carrying amounts because of the short-term nature of these instruments or because the stated rates approximate market rates.

Short-term investments. At December 31, 2006 and 2005 Duke Energy Carolinas had $221 million and $632 million, respectively, of short-term investments consisting primarily of highly liquid tax-exempt debt securities. These instruments are classified as available-for-sale securities under SFAS No. 115 as management does not intend to hold them to maturity nor are they bought and sold with the objective of generating profits on short-term differences in price. The carrying value of these instruments approximates their fair value as they contain floating rates of interest. During 2006, Duke Energy Carolinas purchased approximately $19,482 million and received proceeds on sale of approximately $19,915 million of short-term investments. During 2005, Duke Energy Carolinas purchased approximately $38,535 million and received proceeds on sale of approximately $38,386 million of short-term investments. During 2004, Duke Energy Carolinas purchased approximately $63,879 million and received proceeds on sale of approximately $63,323 million of short-term investments. The weighted-average maturity of these debt securities is less than 1 year.

Other Long-term investments. Duke Energy Carolinas also invests in debt and equity securities that are held in the NDTF (see Note 7 for further information on the nuclear decommissioning trust funds) and the captive insurance investment portfolio that are classified as available-for-sale under SFAS No. 115 and therefore are carried at estimated fair value based on quoted market prices. These investments are classified as long-term as management does not intend to use them in current operations. As a result of the transfer of Duke Energy Carolinas’ membership interest in Spectra Energy Capital to Duke Energy on April 3, 2006, Duke Energy Carolinas’ transferred its captive insurance investment portfolio ($203 million at December 31, 2005) to Duke Energy. The NDTF is managed by independent investment managers with discretion to buy, sell and invest pursuant to the objectives set forth by the trust agreement. As of December 31, 2006 Duke Energy’s NDTF ($1,775 million and $1,504 million at December 31, 2006 and 2005, respectively) consists of approximately 70% equity securities, 24% debt securities, and 6% cash and cash equivalents with a weighted-average maturity of the debt securities of approximately 13 years. During 2006, Duke Energy Carolinas purchased approximately $1,141 million and received proceeds on sales of approximately $1,056 million on other long-term investments. During 2005, Duke Energy Carolinas purchased approximately $1,782 million and received proceeds on sales of approximately $1,745 million on other long-term investments. During 2004, Duke Energy Carolinas purchased approximately $2,050 million and received proceeds on sales of approximately $1,775 million on other long-term investments. Most of these purchases and sales relate to the NDTF.

The estimated fair values of short-term and long-term investments classified as available-for-sale are as follows (in millions):

Approximately $13 million and $21 million of losses are excluded from the above table as of December 31, 2006 and 2005, respectively, which relate to available-for-sale securities held in the NDTF. Pursuant to an order from the NCUC, Duke Energy Carolinas defers as a regulatory asset or regulatory liability all gains and losses associated with investments in the NDTF. As Duke Energy Carolinas has limited oversight over the day-to-day management of the NDTF investments, all losses during the years ended December 31, 2006 and 2005 related to NDTF holdings have been realized as a regulatory asset. At December 31, 2005, Duke Energy Carolinas had additional unrealized losses of approximately $2 million, primarily related to its captive insurance portfolio.

For the years ended December 31, 2006, 2005, and 2004 gains of approximately $0, $3 million and $3 million, respectively, were reclassified out of AOCI into earnings.

Duke Energy Carolinas contributed approximately $48 million in 2006, $48 million in 2005, and $329 million in 2004 to the NDTF. These contributions are presented in Purchases of available-for-sale securities within Cash Flows From Investing Activities on the Consolidated Statements of Cash Flows. At December 31, 2006 and 2005, gross unrealized holding gains related to the NDTF amounted to $472 million and $316 million, respectively.

As discussed in Note 1, on April 3, 2006, Duke Energy Carolinas transferred its membership interests in Spectra Energy Capital to Duke Energy. Since all goodwill recorded by Duke Energy Carolinas at the time of the transfer related to acquisitions of Spectra Energy Capital, all balances have been transferred to Duke Energy. As of December 31, 2005, goodwill was allocated to the following segments: Natural Gas Transmission ($3,512 million), International Energy ($256 million) and Crescent ($7 million).

Investments in affiliates that are not controlled by Duke Energy Carolinas, but over which it has significant influence, are accounted for using the equity method. Duke Energy Carolinas received distributions of $131 million in 2006 from those investments, which are included in Other assets within Cash Flows from Operating Activities on the accompanying Consolidated Statements of Cash Flows. Duke Energy Carolinas received distributions of $856 million in 2005. Of these distributions, $473 million are included in Other, assets within Cash Flows from Operating Activities on the accompanying Consolidated Statements of Cash Flows and $383 million are included in Distributions from Equity Investments within Cash Flows from Investing Activities on the accompanying Consolidated Statements of Cash Flows. Duke Energy Carolinas received distributions of $139 million in 2004, which are included in Other, assets within Cash Flows from Operating Activities on the accompanying Consolidated Statements of Cash Flows. For the year ended December 31, 2006, equity in earnings (losses) of unconsolidated affiliates recorded in Other Income and Expenses, net, within Income From Continuing Operations on the Consolidated Statements of Operations, was a loss of $2 million. For the period from January 1, 2006 through March 31, 2006 and the years ended December 31, 2005 and 2004, Duke Energy Carolinas recorded pre-tax equity in earnings (losses) of unconsolidated affiliates classified in Income From Discontinued Operations, net of tax, on the Consolidated Statements of Operations of $175 million in 2006, $479 million in 2005 and $161 million in 2004.

As of December 31, 2006 and 2005 Duke Energy Carolinas had investments in unconsolidated affiliates of $2 million and $1,933 million, respectively. Substantially all of Duke Energy Carolinas’ investments in unconsolidated affiliates were transferred in connection with Duke Energy Carolinas’ transfer of its membership interests in Spectra Energy Capital to Duke Energy on April 3, 2006 (see Note 1). The carrying amount of investments in affiliates approximated the amount of underlying equity in net assets.

In addition to the above, see Note 6 for net deferred tax liabilities which represent balances between Duke Energy Carolinas and its parent, Duke Energy. Duke Energy Carolinas is allocated its proportionate share of corporate governance and other costs by an unconsolidated affiliate. Corporate governance and other shared services costs are primarily allocations of corporate costs, such as human

resources, legal and accounting fees, as well as other third party costs. During the year ended December 31, 2006, Duke Energy Carolinas recorded governance expenses and shared services expenses of $408 million and $246 million, respectively. Additionally, Duke Energy Carolinas is charged a management fee by the same unconsolidated affiliate that amounted to $82 million for the year ended December 31, 2006. These amounts are recorded in Operation, maintenance and other within Operating Expenses on the Consolidated Statements of Operations. Included in these amounts are $17 million of management fees and $100 million and $35 million of corporate governance and shared services expenses, respectively, for the three months ended March 31, 2006 that are offset within Income from Discontinued Operations, net of tax, in the Consolidated Statements of Operations.

During the nine months ended December 31, 2006, Duke Energy Carolinas received a $200 million capital contribution from its parent, Duke Energy. In addition, on April 3, 2006, Duke Energy Carolinas transferred $761 million of cash of Spectra Energy Capital to its parent, Duke Energy, as a result of Duke Energy Carolinas transferring all of its membership interests in Spectra Energy Capital to Duke Energy. Additionally, during the nine months ended December 31, 2006, Duke Energy Carolinas converted approximately $496 million of advances from parent to equity.

Advance SC LLC, which provides funding for economic development projects, educational initiatives, and other programs, was formed during 2004. Duke Energy Carolinas made donations of approximately $24 million and $3 million to the nonconsolidated subsidiary in 2006 and 2005, respectively. Additionally, at December 31, 2006, Duke Energy Carolinas had a trade payable to Advance SC LLC of approximately $8 million.

The following related party transactions related to businesses that were transferred by Duke Energy Carolinas’ to Duke Energy as a result of the transfer of its membership interest in Spectra Energy Capital on April 3, 2006:

Outstanding notes receivable from unconsolidated affiliates were $0 and $50 million as of December 31, 2006 and 2005, respectively. Amounts are included in Notes Receivable on the Consolidated Balance Sheets. The balance outstanding as of December 31, 2005 represents International Energy’s $50 million note receivable from the Campeche project, a 50% owned joint venture.

In October 2005, Gulfstream issued $500 million aggregate principal amount of 5.56% Senior Notes due 2015 and $350 million aggregate principal amount of 6.19% Senior Notes due 2025. The proceeds were used by Gulfstream to pay off a construction loan and the balance of the proceeds, net of transaction costs, of approximately $620 million was distributed to the partners based upon their ownership percentage (approximately $310 million was received by Natural Gas Transmission and are included in Distributions from Equity Investments within Cash Flows from Investing Activities in the accompanying Consolidated Statements of Cash Flows).

In December 2005, Duke Energy Carolinas completed a 140 million Canadian dollars initial public offering on its Canadian income trust fund (the Income Fund) and sold 14 million Trust Units at an offering price of 10 Canadian dollars per Trust Unit. In January 2006, a subsequent greenshoe sale of 1.4 million additional Trust Units, pursuant to an overallotment option, were sold at a price of 10 Canadian dollars per Trust Unit. Subsequent to the January 2006 sale of additional Trust Units, Duke Energy Carolinas held an approximate 58% ownership interest in the businesses of the Income Fund. Proceeds of approximately 14 million Canadian dollars are included in Proceeds from Duke Energy Carolinas Income Fund within Cash Flows from Financing Activities in the Consolidated Statements of Cash Flows.

In February 2005, DCP Midstream, LLC (formerly Duke Energy Field Services, LLC (DEFS)) sold its wholly owned subsidiary Texas Eastern Products Pipeline Company, LLC (TEPPCO GP), which is the general partner of TEPPCO Partners, LP (TEPPCO LP), for approximately $1.1 billion and Duke Energy Carolinas sold its limited partner interest in TEPPCO LP for approximately $100 million. Prior to the completion of these sale transactions, Duke Energy Carolinas accounted for its investment in TEPPCO LP under the equity method of accounting. For the three months ended March 31, 2005, TEPPCO LP had operating revenues of approximately $1,524 million, operating expenses of approximately $1,463 million, operating income of approximately $61.2 million, income from continuing operations of approximately $46.3 million, and net income of approximately $47.4 million.

In July 2005, Duke Energy Carolinas completed the transfer of a 19.7% interest in DEFS to ConocoPhillips, Duke Energy Carolinas’ co-equity owner in DEFS, which reduced Duke Energy Carolinas’ ownership interest in DEFS from 69.7% to 50% and resulted in Duke Energy Carolinas and ConocoPhillips becoming equal 50% owners of DEFS. As a result of this transaction, Duke Energy Carolinas deconsolidated its investment in DEFS and subsequently accounted for the investment using the equity method of accounting through April 3, 2006. As discussed in Note 1, on April 3, 2006, Duke Energy Carolinas transferred all of its membership interests in Spectra Energy Capital, which included the investment in DEFS, to Duke Energy. Accordingly, all amounts discussed hereinafter recognized for the three months ended March 31, 2006 and the period from July 1, 2005 through December 31, 2005 related to DEFS are included in Income From Discontinued Operations, net of tax, on the Consolidated Statements of Operations. Duke Energy Carolinas’ 50% of equity in earnings of DEFS for the three months ended March 31, 2006 and the period from July 1, 2006 through December 31, 2006 was approximately $146 million and $292 million, respectively. During the three months ended March 31, 2006, Duke Energy Carolinas had gas sales to, purchases from, and other operating expenses from affiliates of DEFS of approximately $34 million, $8 million and $4 million, respectively. Between July 1, 2005 and December 31, 2005, Duke Energy had gas sales to, purchases from, and other operating revenues from affiliates of DEFS of approximately $67 million, $65 million and $12 million, respectively. As of December 31, 2005, Duke Energy had trade receivables from and trade payables to DEFS of approximately $18 million and $47 million, respectively Additionally, Duke Energy received approximately $90 million and $360 million for its share of distributions paid by DEFS in the three months ended March 31, 2006 and the period from July 1, 2005 through December 31, 2005, respectively. Of these distributions $90 million and $287 million were included in Other, assets within Cash Flows from Operating Activities for the years ended 2006 and 2005, respectively, and approximately $0 and $73 million were included in Distributions from Equity Investments within Cash Flows from Investing Activities for the years ended 2006 and 2005, respectively, within the accompanying Consolidated Statements of Cash Flows. Summary financial information for DEFS, which has been accounted for under the equity method since July 1, 2005 is as follows:

DEFS is a limited liability company which is a pass-through entity for U.S. income tax purposes. DEFS also owns corporations who file their own respective, federal, foreign and state income tax returns and income tax expense related to these corporations is included in the income tax expense of DEFS. Therefore, DEFS’ net income does not include income taxes for earnings which are pass-through to the members based upon their ownership percentage and Duke Energy Carolinas recognizes the tax impacts of its share of DEFS’ pass-through earnings in its income tax expense from continuing operations in the accompanying Consolidated Statements of Operations.

As discussed in Note 1, on April 3, 2006, Duke Energy Carolinas transferred all of its membership interests in Spectra Energy Capital to Duke Energy.

During 2002, Duke Energy Carolinas communicated a voluntary and involuntary severance program across all segments to align the business with market conditions during that period. Severance plans related to the program were amended effective August 1, 2004 and applied to individuals notified of layoffs between that date and January 1, 2006.

As discussed in Note 1, on April 3, 2006, Duke Energy Carolinas transferred all of its membership interests in Spectra Energy Capital to Duke Energy. The operations of Spectra Energy Capital are presented as discontinued operations for the period January 1, 2006 through March 31, 2006) and the years ended December 31, 2005 and 2004. No gain or loss or impairments were recognized on the disposition of Spectra Energy Capital as the transfer was among entities under common control.

The following table summarizes the results classified as Income from Discontinued Operations, net of tax, in the accompanying Consolidated Statements of Operations.

The following table presents the carrying values of the major classes of assets and associated liabilities held for sale in the accompanying Consolidated Balance Sheets as of December 31, 2006 and 2005. All amounts at December 31, 2005 relate to businesses of Spectra Energy Capital, which was transferred to Duke Energy as discussed in Note 1.

Summarized Balance Sheet Information for Assets and Associated Liabilities Held for Sale

The following significant transactions of Spectra Energy Capital, the impacts of which are included in Income from Discontinued Operations, net of tax on the Consolidated Statements of Income, occurred during the period from January 1, 2006 through April 3, 2006 and the years ended December 31, 2005 and 2004.

Acquisitions. During the first quarter of 2006, International Energy closed on two transactions which resulted in the acquisition of an additional 27% interest in the Aguaytia Integrated Energy Project (Aguaytia), located in Peru, for approximately $31 million (approximately $18 million net of cash acquired). The project’s scope includes the production and processing of natural gas, sale of liquefied petroleum gas (LPG) and NGLs and the generation, transmission and sale of electricity from a 177 megawatt power plant. These acquisitions increased International Energy’s ownership in Aguaytia to 66% and resulted in Duke Energy accounting for Aguaytia as a consolidated entity. Prior to the acquisition of this additional interest, Aguaytia was accounted for as an equity method investment. No goodwill was recorded as a result of this acquisition.

During the first quarter of 2006, Duke Energy Carolinas acquired the remaining 33 1/3% interest in Bridgeport Energy LLC (Bridgeport) from United Bridgeport Energy LLC (UBE) for approximately $71 million. No goodwill was recorded as a result of this acquisition. The assets and liabilities of Bridgeport were included as part of former DENA’s power generation assets which were sold to a subsidiary of LS Power Equity Partners (LS Power) (see below).

Dispositions. Natural Gas Transmission’s sale of certain Stone Mountain natural gas gathering system assets resulted in proceeds of $18 million (which is reflected in Net proceeds from the sales of equity investments and other assets, and sales of and collections on notes receivable within Cash Flows from Investing Activities in the Consolidated Statements of Cash Flows), and pre-tax gain of $5 million was recognized. In addition, Natural Gas Transmission’s sale of stock, received as consideration for the settlement of a customers’ transportation contract, resulted in proceeds of approximately $24 million (which is reflected in Other, assets within Cash Flows from Operating Activities in the Consolidated Statements of Cash Flows) and a pre-tax gain of $24 million.

For the period from January 1, 2006 to April 3, 2006, Crescent commercial and multi-family real estate sales resulted in $56 million of proceeds and $26 million of net pre-tax gains.

Other. As discussed below, during the third quarter of 2005, Duke Energy Carolinas’ Board of Directors authorized and directed management to execute the sale or disposition of substantially all of DENA’s remaining assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets. Approximately $160 million of losses were incurred from January 1, 2006 through April 3, 2006, the date of the transfer of Spectra Energy Capital to Duke Energy. Cash consideration paid to Barclays amounted to approximately $600 million in January 2006. Additionally, in January 2006 Barclays provided Duke Energy Carolinas with cash equal to the net cash collateral posted by DENA under the contracts of approximately $540 million. The novation or assignment of physical power contracts was subject to FERC approval, which was received in January 2006. See below for further discussions surrounding this transaction.

Field Services. Prior to Duke Energy Carolinas transferring its membership interests in Spectra Energy Capital to Duke Energy, approximately $24 million of realized and unrealized pre-tax losses related to the discontinuance of hedge accounting on certain contracts (see below) were recognized. Cash settlements on these contracts of approximately $50 million are classified as a component of net cash used in investing activities in the accompanying Consolidated Statements of Cash Flows.

Acquisitions. In August 2005, Natural Gas Transmission acquired natural gas storage and pipeline assets in Southwest Virginia and an additional 50% interest in Saltville Gas Storage LLC (Saltville Storage) from units of AGL Resources for approximately $62 million. This transaction increased Natural Gas Transmission’s ownership percentage of Saltville Storage to 100%. No goodwill was recorded as a result of this acquisition.

In August 2005, Natural Gas Transmission acquired the Empress System natural gas processing and NGL marketing business from ConocoPhillips for approximately $230 million as part of the Field Services ConocoPhillips transaction discussed further in the Dispositions section below. No goodwill was recorded as a result of this acquisition.

Dispositions. Significant sales of other assets and equity investments during 2005 are detailed as follows:

Additionally, in July 2005, Duke Energy Carolinas completed the agreement with ConocoPhillips, Duke Energy Carolinas’ co-equity owner in DEFS, to reduce Duke Energy Carolinas’ ownership interest in DEFS from 69.7% to 50% (the DEFS disposition transaction), which results in Duke Energy Carolinas and ConocoPhillips becoming equal 50% owners in DEFS. Duke Energy Carolinas has received, directly and indirectly through its ownership interest in DEFS, a total of approximately $1.1 billion from ConocoPhillips and DEFS, consisting of approximately $1.0 billion in cash and approximately $0.1 billion of assets. The DEFS disposition transaction resulted in a pre-tax gain of approximately $575 million. The DEFS disposition transaction includes the transfer to Duke Energy of DEFS’ Canadian natural gas gathering and processing facilities. Additionally, the DEFS disposition transaction included the acquisition of ConocoPhillips’ interest in the Empress System. Subsequent to the closing of the DEFS disposition transaction, effective on July 1, 2005, DEFS is no longer consolidated into Duke Energy Carolinas’ consolidated financial statements and is accounted for by Duke Energy Carolinas as an equity method investment. The Canadian natural gas gathering and processing facilities and the Empress System are included in the Natural Gas Transmission segment.

For the year ended December 31, 2005, Crescent’s commercial and multi-family real estate sales resulted in $372 million of proceeds and $191 million of net pre-tax gains. Sales included a large land sale in Lancaster County, South Carolina that resulted in $42 million of pre-tax gains, and several other “legacy” land sales. Additionally, Crescent had $45 million in pre-tax income related to a distribution from an interest in a portfolio of commercial office buildings. Additionally, Crescent sold three commercial properties resulting in sales proceeds of approximately $44 million.

Other. During the third quarter of 2005, Duke Energy Carolinas’ Board of Directors authorized and directed management to execute the sale or disposition of substantially all of former DENA’s remaining assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets. The former DENA assets to be divested include:

The results of operations of former DENA’s Western and Eastern United States generation assets, including related commodity contracts, certain contracts related to former DENA’s energy marketing and management activities and certain general and administrative costs, are required to be classified as discontinued operations for current and prior periods in the accompanying Consolidated Statements of Operations.

In connection with this exit plan, Duke Energy Carolinas recognized pre-tax losses of approximately $1.1 billion in, principally related to:

As of the September 2005 exit announcement date, management anticipated that additional charges would be incurred related to the exit plan, including termination costs for gas transportation, storage, structured power and other contracts of approximately $600 million to $800 million, which included approximately $40 million to $60 million of severance, retention and other transaction costs. Included in these amounts are the effects of former DENA’s November 2005 agreement to sell substantially all of its commodity contracts related to the Southeastern generation operations, which were substantially disposed of in 2004, certain commodity contracts related to former DENA’s Midwestern power generation facilities, and contracts related to former DENA’s energy marketing and

management activities. Excluded from the contracts sold to Barclays are commodity contracts associated with the near-term value of former DENA’s West and Northeastern generation assets and with remaining gas transportation and structured power contracts. Approximately $470 million was incurred during the year ended December 31, 2005,

Among other things, the agreement provides that all economic benefits and burdens under the contracts were transferred to Barclays. Cash consideration paid to Barclays amounted to approximately $100 million in 2005 and approximately $600 million in January 2006. Additionally, in January 2006 Barclays provided Duke Energy Carolinas with cash equal to the net cash collateral posted by former DENA under the contracts of approximately $540 million. The novation or assignment of physical power contracts was subject to FERC approval, which was received in January 2006.

In January 2006, Duke Energy Carolinas signed an agreement to sell to LS Power former DENA’s entire fleet of power generation assets outside the Midwest, representing approximately 6,100 megawatts of power generation located in the Western and Northeast United States. In May 2006, the transaction with LS Power closed.

Field Services. As a result of the transfer of 19.7% interest in DEFS to ConocoPhillips and the third quarter 2005 deconsolidation of its investment in DEFS (see above), Duke Energy Carolinas discontinued hedge accounting for certain contracts held by Duke Energy Carolinas related to Field Services’ commodity price risk, which were previously accounted for as cash flow hedges. These contracts were originally entered into as hedges of forecasted future sales by Field Services, and have been retained as undesignated derivatives. Since discontinuance of hedge accounting, these contracts have been marked-to-market in the Consolidated Statements of Operations. Approximately $314 million of realized and unrealized pre-tax losses related to these contracts were recognized in earnings by Duke Energy Carolinas for the year ended December 31, 2005. Cash settlements on these contracts since the deconsolidation of DEFS on July 1, 2005 of approximately $133 million are classified as a component of net cash used in investing activities in the accompanying Consolidated Statements of Cash Flows.

Impairments. International Energy. A $20 million other than temporary impairment in value of the Campeche investment was recognized during the third quarter of 2005 to write down the investment to its estimated fair value.

Field Services. During the year ended December 31, 2005, the Field Services business unit recorded a charge of approximately $120 million due to the reclassification into earnings of pre-tax unrealized losses from AOCI as a result of the discontinuance of certain cash flow hedges entered into hedge Field Services’ commodity price risk. See Note 8 for additional impacts of the deconsolidation of Crescent on the results of operations of Duke Energy Carolinas.

Crescent. In the third quarter of 2005, Crescent recognized pre-tax impairment charges of approximately $16 million related to a residential community near Hilton Head Island, South Carolina, that includes both residential lots and a golf club, to reduce the carrying value of the community to its estimated fair value. This community has incurred higher than expected costs and has been impacted by lower than anticipated sales volume. The fair value of the remaining community assets was determined based upon management’s estimate of discounted future cash flows generated from the development and sale of the community.

Acquisitions. In the second quarter of 2004, Field Services acquired gathering, processing and transmission assets in southeast New Mexico from ConocoPhillips for a total purchase price of approximately $80 million, consisting of $74 million in cash and the assumption of approximately $6 million of liabilities. As the acquired assets were not considered businesses under the guidance in EITF 98-3, no goodwill was recognized in connection with this transaction.

Dispositions. Significant sales of other assets in 2004 are detailed as follows:

Duke Energy Carolinas retained certain guarantees related to the sold assets. In conjunction with the sale, Duke Energy arranged a letter of credit with a face amount of $120 million in favor of Georgia Power Company, to secure obligations of a KGen subsidiary under a seven-year power sales agreement, commencing in May 2005, under which KGen will provide power from one of the plants to Georgia Power. Duke Energy Carolinas is the ultimate obligor to the letter of credit provider, but KGen has an obligation to reimburse Duke Energy Carolinas for any payments made by it under the letter of credit, as well as expenses incurred by Duke Energy Carolinas in connection with the letter of credit. This obligation was transferred to Duke Energy as part of the transfer of Spectra Energy Capital to Duke Energy on April 3, 2006.

For the year ended December 31, 2004, Crescent’s commercial and multi-family real estate sales resulted in $606 million of proceeds, and $192 million of net gains. Significant sales included commercial project sales, resulting primarily from the sale of a commercial project in the Washington, D.C. area in March; real estate sales due primarily to the sale of the Alexandria and Arlington land tracts in the Washington, D.C. area; and several large land tract sales.

Impairments. Field Services. In the third quarter of 2004, Field Services recorded impairments of approximately $22 million related to DEFS operating assets. Additionally, in the third quarter of 2004, Field Services recorded an impairment of approximately $23 million related to equity method investments at DEFS. The impairment charge was related to management’s assessment of the recoverability of some equity method investments. Field Services determined that these assets, which are located in the Gulf Coast, were impaired; therefore they were written down to fair value. Fair value was determined based on management’s best estimates of sales value and/or discounted future cash flow models.

Crescent. In the fourth quarter of 2004, Crescent recorded impairment charges of approximately $42 million related to two residential developments in Payson, Arizona, the Rim and Chaparral Pines, and one residential development in Austin, Texas, Twin Creeks. The impairment charges were related to long lived assets at the three properties. The developments have suffered from slower than anticipated absorption of available inventory. Fair value of the assets was determined based on management’s assessment of current operating results and discounted future cash flow models. Crescent also recorded bad debt charges of $8 million related to notes receivable due from Rim Golf Investor, LLC and Chaparral Pines Investor, LLC.

In September 2004, Field Services recorded a pre-tax impairment charge of approximately $23 million ($16 million net of minority interest) related to management’s current assessment of some additional gathering, processing, compression and transportation assets in Wyoming being held for sale. The estimated fair value of these assets less cost to sell was $27 million. In the first quarter of 2005, Field Services sold these assets for proceeds of $28 million, with the carrying value being approximately equal to the sales price.

In February 2004, Field Services sold gas gathering and processing plant assets in West Texas to a third party purchaser for a sales price of approximately $62 million, which approximated these assets’ carrying value.

International Energy. In order to eliminate exposure to international markets outside of Latin America and Canada, International Energy decided in 2003 to pursue a possible sale or IPO of International Energy’s Asia-Pacific power generation and natural gas transmission business (the Asia-Pacific Business). As a result of this decision, International Energy recorded an after tax loss of $233 million during the fourth quarter of 2003, which represented the excess of the carrying value over the estimated fair value of the business, less estimated costs to sell. In the first quarter of 2004, International Energy determined it was likely that a bid in excess of the originally determined fair value would be accepted and thus recorded a $238 million after tax gain related to International Energy’s Asia-Pacific Business which restored a loss recorded during the fourth quarter of 2003.

In the second quarter of 2004, International Energy completed the sale of the Asia-Pacific Business to Alinta Ltd. for a gross sales price of approximately $1.2 billion. This resulted in recording an additional $40 million after tax gain in the second quarter of 2004. International Energy received approximately $390 million of cash proceeds, net of approximately $840 million of debt retired (as a non-cash financing activity) as part of the Asia-Pacific Business.

International Energy held a receivable from Norsk Hydro ASA (Norsk) related to the 2003 sale of International Energy’s European business. In 2004, International Energy recorded a $14 million ($9 million after tax) allowance against the carrying value of the note based on management’s assessment of the probability of not collecting the entire note. In first quarter 2006, based on management’s best estimate of recoverability, International Energy recorded an allowance of approximately $19 million ($12 million after tax) against this receivable. During the second quarter of 2006, International Energy and Norsk signed a settlement agreement in which Norsk agreed to pay International Energy approximately $34 million in full settlement of International Energy’s receivable. In connection with this settlement, International Energy recorded an approximate $9 million write-up ($5 million after tax) of the receivable through a reduction in the valuation allowance. In July 2006, International Energy received the settlement proceeds.

Crescent. Crescent sold one multi-family, two residential and two commercial properties resulting in sales proceeds of approximately $52 million.

Other. For the year ended December 31, 2004, Duke Energy Carolinas’ discontinued operations also included sales and impairments of merchant power plants located in Washington (“Grays Harbor” plant), Nevada (“Moapa” plant) and New Mexico (“Luna” plant) (collectively, the deferred plants). Details are as follows:

Additionally, during 2004, the Western and Northeast operations had operating losses, which substantially offset the above 2004 gains. During 2004, Duke Energy Carolinas received approximately $58 million from the sale or collection of all of Duke Capital Partners LLC notes receivable. An immaterial after tax gain related to this transaction was recognized.

The decrease in property, plant and equipment at December 31, 2006 as compared to December 31, 2005 is primarily attributable to property, plant and equipment transferred to Duke Energy by Duke Energy Carolinas as a result of the transfer of its membership interests in Spectra Energy Capital on April 3, 2006 (see Note 1).

Capitalized interest, which includes the interest expense component of AFUDC, amounted to $12 million for 2006, $23 million for 2005, and $18 million for 2004.

During the year ended December 31, 2006, Duke Energy Carolinas’ consolidated debt decreased by approximately $10.8 billion compared to December 31, 2005, primarily due to the transfer of Spectra Energy Capital to Duke Energy on April 3, 2006 (see Note 1).

Unsecured Debt. At December 31, 2006, approximately $322 million of pollution control bonds and approximately $300 million of commercial paper, which are short-term obligations by nature, were classified as long-term debt on the Consolidated Balance Sheets due to Duke Energy Carolinas’ intent and ability to utilize such borrowings as long-term financing. Duke Energy Carolinas’ credit facilities with non-cancelable terms in excess of one year as of the balance sheet date give Duke Energy Carolinas the ability to refinance these short-term obligations on a long-term basis.

In October 2006, Duke Energy Carolinas issued $150 million in tax-exempt floating rate bonds. The bonds are structured as variable rate demand bonds, subject to weekly remarketing and bear a final maturity of 2031. The initial interest rate was set at 3.72%. The bonds are supported by an irrevocable 3-year direct-pay letter of credit and were issued through the North Carolina Capital Facilities Finance Agency to fund a portion of the environmental capital expenditures at the Marshall and Belews Creek Steam Stations.

Convertible Debt. As of December 31, 2006 and 2005, unsecured debt included $110 million and $742 million, respectively, of 1.75% convertible senior notes due in 2023. These senior notes, which were issued in May 2003, are convertible to Duke Energy common stock at a premium of 40% above the May 1, 2003 closing common stock market price of $16.85 per share. The senior notes outstanding as of December 31, 2006 are potentially convertible into approximately 4.7 million shares of common stock. The conversion of these senior notes into shares of Duke Energy common stock is contingent upon the occurrence of certain events during specified periods. These events include whether the price of Duke Energy common stock reaches specified thresholds, the credit rating of Duke Energy Carolinas falls below certain thresholds, the convertible notes are called for redemption by Duke Energy Carolinas, or specified transactions have occurred. In addition to the aforementioned events that could trigger early redemption, holders of the senior notes may require Duke Energy Carolinas to purchase all or a portion of their senior notes for cash on May 15, 2007, May 15, 2012, and May 15, 2017, at a price equal to the principal amount of the senior notes plus accrued interest, if any. Duke Energy Carolinas may redeem for cash all or a portion of the senior notes at any time on or after May 20, 2007, at a price equal to the sum of the issue price plus accrued interest, if any, on the redemption date. These convertible senior notes became convertible into shares of Duke Energy common stock

during fiscal quarters beginning April 1, 2006 due to the market price of Duke Energy common stock achieving a specified threshold for each respective quarter. Holders of the convertible senior notes were allowed to exercise their right to convert on or prior to December 31, 2006. During 2006, approximately 27 million shares of Duke Energy common stock were issued related to this conversion, which resulted in the retirement of approximately $632 million of convertible senior notes. During 2005, as a result of the same market price trigger, approximately 1.2 million shares of Duke Energy common stock were issued related to this conversion, which resulted in the retirement of approximately $28 million of convertible senior notes.

Secured Debt. Accounts Receivable Securitization. Duke Energy Carolinas securitizes certain accounts receivable through Duke Energy Receivables Finance Company, LLC (DERF), a bankruptcy remote, special purpose subsidiary. DERF is a wholly owned limited liability company with a separate legal existence from its parent, and its assets are not intended to be generally available to creditors of Duke Energy Carolinas. As a result of the securitization, Duke Energy Carolinas sells on a daily basis to DERF, certain accounts receivable arising from the sale of electricity and/or related services. In order to fund its purchases of accounts receivable, DERF has a $300 million secured credit facility, with a commercial paper conduit administered by Citicorp North America, Inc. which terminates in September 2008. The credit facility and related securitization documentation contain several covenants, including covenants with respect to the accounts receivable held by DERF as well as a covenant requiring that the ratio of Duke Energy Carolinas consolidated indebtedness to Duke Energy Carolinas consolidated capitalization not exceed 65%. As of December 31, 2006, the interest rate associated with the credit facility, which is based on commercial paper rates, was 5.8% and $300 million was outstanding under the credit facility. The securitization transaction was not structured to meet the criteria for sale treatment under SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities,” and accordingly is reflected as a secured borrowing in the Consolidated Financial Statements. As of December 31, 2006 and 2005, the $300 million outstanding balance of the credit facility was secured by approximately $476 million and $489 million, respectively, of accounts receivable held by DERF. The obligations of DERF under the credit facility are non-recourse to Duke Energy Carolinas.

Other Assets Pledged as Collateral. As of December 31, 2006, substantially all of Duke Energy Carolinas’ electric plant in service was subject to a mortgage lien securing the first and refunding mortgage bonds.

Floating Rate Debt. Unsecured debt, secured debt and other debt included approximately $922 million of floating-rate debt as of December 31, 2006, and $1.7 billion as of December 31, 2005. As of December 31, 2005, $488 million of Brazilian debt that is indexed annually to Brazilian inflation was included in floating rate debt. Floating-rate debt is primarily based on commercial paper rates or a spread relative to an index such as a London Interbank Offered Rate for debt denominated in U.S. dollars, and Banker’s Acceptances for debt denominated in Canadian dollars. As of December 31, 2006 and 2005, the average interest rate associated with floating-rate debt was approximately 5.0% and 6.4%, respectively.

Duke Energy Carolinas has the ability under certain debt facilities to call and repay the obligation prior to its scheduled maturity. Therefore, the actual timing of future cash repayments could be materially different than the above as a result of Duke Energy Carolinas’ ability to repay these obligations prior to their scheduled maturity.

Duke Energy Carolinas may be required to repay certain debt should the credit ratings at Duke Energy Carolinas fall to a certain level at Standard & Poor’s (S&P) or Moody’s Investor Service (Moody’s). As of December 31, 2006, Duke Energy Carolinas had $13 million of senior unsecured notes which mature serially through 2012 that may be required to be repaid if Duke Energy Carolinas’ senior unsecured

debt ratings fall below BBB- at S&P or Baa3 at Moody’s, and $23 million of senior unsecured notes which mature serially through 2016 that may be required to be repaid if Duke Energy Carolinas’ senior unsecured debt ratings fall below BBB at S&P or Baa2 at Moody’s. As of February 1, 2007, Duke Energy Carolinas’ senior unsecured credit rating was BBB at S&P and A3 at Moody’s.

Available Credit Facilities and Restrictive Debt Covenants. During the year ended December 31, 2006, Duke Energy Carolinas’ consolidated credit capacity decreased by approximately $2.5 billion compared to December 31, 2005 primarily due to the transfer of Spectra Energy Capital to Duke Energy on April 3, 2006 (see Note 1).

The issuance of commercial paper, letters of credit and other borrowings reduces the amount available under the available credit facilities.

Duke Energy Carolinas’ debt and credit agreements contain various financial and other covenants. Failure to meet those covenants beyond applicable grace periods could result in accelerated due dates and/or termination of the agreements. As of December 31, 2006, Duke Energy Carolinas was in compliance with those covenants. In addition, some credit agreements may allow for acceleration of payments or termination of the agreements due to nonpayment, or to the acceleration of other significant indebtedness of the borrower or some of its subsidiaries. None of the debt or credit agreements contain material adverse change clauses.

Other Loans. Duke Energy Carolinas had loans outstanding against the cash surrender value of the life insurance policies that it owns on the lives of its executives. These loans were transferred to Duke Energy as part of the transfer of Spectra Energy Capital to Duke Energy on April 3, 2006. The amounts outstanding as of December 31, 2005 were $552 million and were carried as a reduction of the related cash surrender value that is included in Other Assets on the Consolidated Balance Sheets.

As discussed in Note 1, on April 3, 2006, Duke Energy Carolinas transferred its membership interests in Spectra Energy Capital to Duke Energy. As a result, all commitments and contingencies related to Duke Energy or Spectra Energy Capital are no longer contingent obligations at Duke Energy Carolinas.

Duke Energy Carolinas carries, either directly or through Duke Energy’s current (and Duke Energy Carolinas’ former) captive insurance company, Bison, and its affiliates, insurance and reinsurance coverages consistent with companies engaged in similar commercial operations with similar type properties. Duke Energy Carolinas’ insurance coverage includes (1) commercial general public liability insurance for liabilities arising to third parties for bodily injury and property damage resulting from Duke Energy Carolinas’ operations; (2) workers’ compensation liability coverage to required statutory limits; (3) automobile liability insurance for all owned, non-owned and hired vehicles covering liabilities to third parties for bodily injury and property damage; (4) insurance policies in support of the indemnification provisions of Duke Energy Carolinas’ by-laws and (5) property insurance covering the replacement value of all real and personal property damage, excluding electric transmission and distribution lines, including damages arising from boiler and machinery breakdowns, earthquake, flood damage and extra expense. All coverages are subject to certain deductibles, terms and conditions common for companies with similar types of operations.

Duke Energy Carolinas also maintains excess liability insurance coverage above the established primary limits for commercial general liability and automobile liability insurance. Limits, terms, conditions and deductibles are comparable to those carried by other power companies of similar size.

The cost of Duke Energy Carolinas’ general insurance coverages continued to fluctuate over the past year reflecting the changing conditions of the insurance markets.

Duke Energy Carolinas owns and operates the McGuire and Oconee Nuclear Stations and operates and has a partial ownership interest in the Catawba Nuclear Station. The McGuire and Catawba Nuclear Stations have two nuclear reactors each and Oconee has three. Nuclear insurance includes: liability coverage; property, decontamination and premature decommissioning coverage; and business interruption and/or extra expense coverage. The other joint owners of the Catawba Nuclear Station reimburse Duke Energy Carolinas for certain expenses associated with nuclear insurance premiums. The Price-Anderson Act requires Duke Energy Carolinas to insure against public liability claims resulting from nuclear incidents to the full limit of liability, approximately $10.8 billion.

Primary Liability Insurance. Duke Energy Carolinas has purchased the maximum available private primary liability insurance as required by law, which is $300 million.

Excess Liability Program. This program currently provides approximately $10.5 billion of coverage through the Price-Anderson Act’s mandatory industry-wide excess secondary financial protection program of risk pooling. The $10.5 billion is the sum of the current potential cumulative retrospective premium assessments of $101 million per licensed commercial nuclear reactor. This would be increased by $101 million for each additional commercial nuclear reactor licensed, or reduced by $101 million for nuclear reactors no longer operational and may be exempted from the risk pooling program. Under this program, licensees could be assessed retrospective premiums to compensate for damages in the event of a nuclear incident at any licensed facility in the U.S. If such an incident should occur and public liability damages exceed primary insurances, licensees may be assessed up to $101 million for each of their licensed reactors, payable at a rate not to exceed $15 million a year per licensed reactor for each incident. The $101 million is subject to indexing for inflation and may be subject to state premium taxes.

Duke Energy Carolinas is a member of Nuclear Electric Insurance Limited (NEIL), which provides accidental outage insurance coverage for Duke Energy Carolinas’ nuclear facilities under three policy programs:

Primary Property Insurance. This policy provides $500 million of primary property damage coverage for each of Duke Energy Carolinas’ nuclear facilities.

Excess Property Insurance. This policy provides excess property, decontamination and decommissioning liability insurance: $2.25 billion for the Catawba Nuclear Station and $2.0 billion each for the Oconee and McGuire Nuclear Stations.

Accidental Outage Insurance. This policy provides business interruption and/or extra expense coverage resulting from an accidental outage of a nuclear unit. Each McGuire and Catawba unit is insured for up to $3.5 million per week, and the Oconee units are insured for up to $2.8 million per week. Coverage amounts decline if more than one unit is involved in an accidental outage. Initial coverage begins after a 12-week deductible period for Catawba and a 26-week deductible period for McGuire and Oconee and continues at 100% for 52 weeks and 80% for the next 110 weeks.

If NEIL’s losses exceed its reserves for any of the above three programs, Duke Energy Carolinas is liable for assessments of up to 10 times its annual premiums. The current potential maximum assessments are: Primary Property Insurance—$38 million, Excess Property Insurance—$46 million and Accidental Outage Insurance—$22 million.

The other joint owners of the Catawba Nuclear Station are obligated to assume their pro rata share of liability for retrospective premiums and other premium assessments resulting from the Price-Anderson Act’s excess secondary financial protection program of risk pooling, or the NEIL policies.

Duke Energy Carolinas is subject to federal, state and local regulations regarding air and water quality, hazardous and solid waste disposal and other environmental matters. These regulations can be changed from time to time, imposing new obligations on Duke Energy Carolinas.

Remediation activities. Like others in the power industry, Duke Energy Carolinas and its affiliates are responsible for environmental remediation at various contaminated sites. These include some properties that are part of ongoing Duke Energy Carolinas operations, sites formerly owned or used by Duke Energy Carolinas entities, and sites owned by third parties. Remediation typically involves management of contaminated soils and may involve groundwater remediation. Managed in conjunction with relevant federal, state and local agencies, activities vary with site conditions and locations, remedial requirements, complexity and sharing of responsibility. If remediation activities involve statutory joint and several liability provisions, strict liability, or cost recovery or contribution actions, Duke Energy Carolinas or its affiliates could potentially be held responsible for contamination caused by other parties. In some instances, Duke Energy Carolinas may share liability associated with contamination with other potentially responsible parties, and may also benefit from insurance policies or contractual indemnities that cover some or all cleanup costs. All of these sites generally are managed in the normal course of business or affiliate operations. Management believes that completion or resolution of these matters will have no material adverse effect on Duke Energy Carolinas’ consolidated results of operations, cash flows or financial position.

Clean Water Act. The U.S. Environmental Protection Agency’s (EPA’s) final Clean Water Act Section 316(b) rule became effective July 9, 2004. The rule established aquatic protection requirements for existing facilities that withdraw 50 million gallons or more of water per day from rivers, streams, lakes, reservoirs, estuaries, oceans, or other U.S. waters for cooling purposes. Eight of Duke Energy Carolinas’ eleven coal and nuclear-fueled generating facilities in North Carolina and South Carolina are affected sources under that rule. On January 25, 2007, the U.S. Court of Appeals for the Second Circuit issued its opinion in Riverkeeper, Inc. v. EPA, Nos. 04-6692-ag(L) et. al. (2d Cir. 2007) remanding most aspects of EPA’s rule back to the agency. The court effectively disallowed those portions of the rule most favorable to industry, and the decision creates a great deal of uncertainty regarding future requirements and their timing. While Duke Energy Carolinas is still unable to estimate costs to comply with EPA’s rule, it is expected that costs will increase as a result of the court’s decision. The magnitude of any such increase cannot be estimated at this time.

Clean Air Mercury Rule (CAMR) and Clean Air Interstate Rule (CAIR). The EPA finalized its CAMR and CAIR in May 2005. The CAMR limits total annual mercury emissions from coal-fired power plants across the United States through a two-phased cap-and-trade program. Phase 1 begins in 2010 and Phase 2 begins in 2018. The CAIR limits total annual and summertime NOx emissions and annual SO₂ emissions from electric generating facilities across the Eastern United States through a two-phased cap-and-trade program. Phase 1 begins in 2009 for NOx and in 2010 for SO₂. Phase 2 begins in 2015 for both NOx and SO₂.

The emission controls Duke Energy Carolinas is installing to comply with North Carolina clean air legislation will contribute significantly to achieving compliance with CAMR and CAIR requirements (see Note 4). Duke Energy Carolinas currently estimates that any additional costs it might incur to comply with Phase 1 of CAMR or CAIR will have no material adverse effect on its consolidated results of operations, cash flows or financial position. Duke Energy Carolinas currently estimates its CAIR Phase 2 compliance costs at approximately $150 million over the period 2010-2016. Duke Energy Carolinas is currently unable to estimate the cost of complying with Phase 2 of CAMR beyond 2016. Duke Energy Carolinas and others filed petitions with the U.S. Court of Appeals for the District Columbia Circuit requesting the Court to review certain elements of the EPA’s CAIR. Duke Energy Carolinas is seeking to have the EPA revise the method of allocating SO₂ emission allowances to entities under the rule.

Extended Environmental Activities, Accruals. Included in Other Current Liabilities and Other Deferred Credits and Other Liabilities on the Consolidated Balance Sheets were total accruals related to extended environmental-related activities of approximately $9 million and $6 million as of December 31, 2006 and 2005, respectively. These accruals represent Duke Energy Carolinas’ provisions for costs associated with remediation activities at some of its current and former sites, as well as other relevant environmental contingent liabilities. Management believes that completion or resolution of these matters will have no material adverse effect on Duke Energy Carolinas’ consolidated results of operations, cash flows or financial position.

New Source Review (NSR). In 1999-2000, the U.S. Justice Department, acting on behalf of the EPA, filed a number of complaints and notices of violation against multiple utilities across the country for alleged violations of the NSR provisions of the Clean Air Act (CAA). Generally, the government alleged that projects performed at various coal-fired units were major modifications, as defined in the CAA, and that the utilities violated the CAA when they undertook those projects without obtaining permits and installing emission controls for SO₂, NOx and particulate matter. The complaints seek (1) injunctive relief to require installation of pollution control technology on various allegedly violating generating units, and (2) unspecified civil penalties in amounts of up to $27,500 per day for each violation. A number of

Duke Energy Carolinas’ owned and operated plants have been subject to these allegations and lawsuits. Duke Energy Carolinas asserts that there were no CAA violations because the applicable regulations do not require permitting in cases where the projects undertaken are “routine” or otherwise do not result in a net increase in emissions.

In 2000, the government brought a lawsuit against Duke Energy Carolinas in the U.S. District Court in Greensboro, North Carolina. The EPA claims that 29 projects performed at 25 of Duke Energy Carolinas’ coal-fired units violate these NSR provisions. In August 2003, the trial Court issued a summary judgment opinion adopting Duke Energy Carolinas’ legal positions, and on April 15, 2004, the Court entered Final Judgment in favor of Duke Energy Carolinas. The government appealed the case to the U.S. Fourth Circuit Court of Appeals. On June 15, 2005, the Fourth Circuit ruled in favor of Duke Energy Carolinas and effectively adopted Duke Energy Carolinas’ view that permitting of projects is not required unless the work performed causes a net increase in the hourly rate of emissions. The Fourth Circuit did not reach the question of “routine”. The EPA sought rehearing in the Fourth Circuit, which was denied. Environmental intervenors in the case sought a writ of certiorari to the U.S. Supreme Court, which was granted. On November 1, 2006, oral arguments were made before the U.S. Supreme Court.

It is not possible to predict with certainty whether Duke Energy Carolinas will incur any liability or to estimate the damages, if any, that Duke Energy Carolinas might incur in connection with this matter.

Asbestos-related Injuries and Damages Claims. Duke Energy Carolinas has experienced numerous claims relating to damages for personal injuries alleged to have arisen from the exposure to or use of asbestos in connection with construction and maintenance activities conducted by Duke Energy Carolinas on its electric generation plants during the 1960s and 1970s. Duke Energy Carolinas has third-party insurance to cover losses related to these asbestos-related injuries and damages above a certain aggregate deductible. The insurance policy, including the policy deductible and reserves, provided for coverage to Duke Energy Carolinas up to an aggregate of $1.6 billion when purchased in 2000. Probable insurance recoveries related to this policy are classified in the Consolidated Balance Sheets as Other within Investments and Other Assets. Amounts recognized as reserves in the Consolidated Balance Sheets, which are not anticipated to exceed the coverage, are classified in Other Deferred Credits and Other Liabilities and Other Current Liabilities and are based upon Duke Energy Carolinas’ best estimate of the probable liability for future asbestos claims. These reserves are based upon current estimates and are subject to uncertainty. Factors such as the frequency and magnitude of future claims could change the current estimates of the related reserves and claims for recoveries reflected in the accompanying Consolidated Financial Statements. However, management of Duke Energy Carolinas does not currently anticipate that any changes to these estimates will have any material adverse effect on Duke Energy Carolinas’ consolidated results of operations, cash flows or financial position.

Other Litigation and Legal Proceedings. Duke Energy Carolinas and its subsidiaries are involved in other legal, tax and regulatory proceedings arising in the ordinary course of business, some of which involve substantial amounts. Management believes that the final disposition of these proceedings will not have a material adverse effect on Duke Energy Carolinas’ consolidated results of operations, cash flows or financial position.

Duke Energy Carolinas has exposure to certain legal matters that are described herein. As of December 31, 2006, Duke Energy Carolinas has recorded reserves of approximately $1.2 billion for these proceedings and exposures. Duke Energy Carolinas has insurance coverage for certain of these losses incurred. As of December 31, 2006, Duke Energy Carolinas has recognized approximately $1.0 billion of probable insurance recoveries related to these losses. These reserves represent management’s best estimate of probable loss as defined by SFAS No. 5, “Accounting for Contingencies.”

Duke Energy Carolinas expenses legal costs related to the defense of loss contingencies as incurred.

Other. Duke Energy Carolinas enters into various fixed-price, non-cancelable commitments to purchase or sell power (tolling arrangements or power purchase contracts) that may or may not be recognized on the Consolidated Balance Sheets.

Duke Energy Carolinas leases assets in several areas of its operations. Consolidated rental expense for operating leases classified in Income From Continuing Operations was $30 million in 2006, $39 million in 2005 and $45 million in 2004, which is included in Operation, Maintenance and Other on the Consolidated Statements of Operations. For the period from January 1, 2006 through March 31, 2006 and the years ended December 31, 2005 and 2004, Duke Energy Carolinas recorded pre-tax consolidated rental expense for

operating leases classified in Income From Discontinued Operations, net of tax, on the Consolidated Statements of Operations of $18 million in 2006, $80 million in 2005 and $79 million in 2004. Duke Energy Carolinas has no capital leases as of December 31, 2006. The following is a summary of future minimum lease payments under operating leases, which at inception had a noncancelable term of more than one year as of December 31, 2006:

As discussed in Note 1, on April 3, 2006, Duke Energy Carolinas transferred all of its membership interests in Spectra Energy Capital to Duke Energy. All financial and performance guarantees that existed at Duke Energy Carolinas prior to the transfer of its membership interest in Spectra Energy Capital to Duke Energy were structured such that either Duke Energy or Spectra Energy Capital served as guarantor. Accordingly, effective April 3, 2006, Duke Energy Carolinas has no remaining obligations under any material existing financial or performance guarantees.

Effective January 1, 2006, Duke Energy Carolinas adopted the provisions of SFAS No. 123(R). SFAS No. 123(R) establishes accounting for stock-based awards exchanged for employee and certain nonemployee services. Accordingly, for employee awards, equity classified stock-based compensation cost is measured at the grant date, based on the fair value of the award, and is recognized as expense over the requisite service period. Subsequent to April 2006, Duke Energy Carolinas is allocated stock-based compensation expense from Duke Energy as certain of its employees participate in Duke Energy’s stock-based compensation programs. Prior to the adoption of SFAS No. 123(R), Duke Energy Carolinas applied APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and FIN 44, “Accounting for Certain Transactions Involving Stock Compensation (an Interpretation of APB Opinion 25)” and provided the required pro forma disclosures of SFAS No. 123. Since the exercise price for all options granted under those plans was equal to the market value of the underlying common stock on the grant date, no compensation cost was recognized in the accompanying Consolidated Statements of Operations.

Duke Energy Carolinas elected to adopt the modified prospective application method as provided by SFAS No. 123(R), and accordingly, financial statement amounts from the prior periods presented in this Form 10-K have not been restated. There were no modifications to outstanding stock options prior to the adoption of SFAS 123(R).

Duke Energy Carolinas recorded stock-based compensation expense included in income from continuing operations for the years ended December 31, 2006, 2005 and 2004 as follows, the components of which are further described below:

As discussed in Note 1, on April 3, 2006, Duke Energy Carolinas transferred all of its membership interests in Spectra Energy Capital to Duke Energy. Accordingly, pre-tax stock-based compensation expense of approximately $10 million, $38 million and $21 million for the three months ended March 31, 2006 and the years ended December 31, 2005 and 2004, respectively, is included in Income From Discontinued Operations, net of tax, on the Consolidated Statements of Operations. The tax benefit associated with the amounts that are in Income From Discontinued Operations, net of tax, on the Consolidated Statements of Operations for the three months ended March 31, 2006 and the years ended December 31, 2005 and 2004 are approximately $4 million, $14 million and $8 million, respectively. The tax benefit in income from continuing operations associated with the recorded expense for the years ended December 31, 2006, 2005 and 2004 was approximately $5 million, $3 million and $2 million, respectively. There were no material differences in income from continuing operations, income tax expense, net income or cash flows from the adoption of SFAS No. 123(R).

The following table shows what earnings available for common stockholders would have been if Duke Energy Carolinas had applied the fair value recognition provisions of SFAS No. 123(R) to all stock-based compensation awards during prior periods.

Duke Energy’s 2006 Long-Term Incentive Plan (the 2006 Plan), approved by shareholders in October 2006, reserved 60 million shares of common stock for awards to employees and outside directors. Duke Energy’s 1998 Long-Term Incentive Plan, as amended (the 1998 Plan), reserved 60 million shares of common stock for awards to employees and outside directors. The 2006 Plan supersedes the 1998 Plan and no additional grants will be made from the 1998 Plan. Under the 2006 Plan and the 1998 Plan, the exercise price of each option granted cannot be less than the market price of Duke Energy’s common stock on the date of grant and the maximum option term is 10 years. The vesting periods range from immediate to five years.

On December 31, 2005 and 2004, Duke Energy Carolinas had approximately 22 million exercisable options with a $32 weighted-average exercise price. The total intrinsic value of options exercised during the three months ended March 31, 2006, the nine months ended December 31, 2006 and the years ended December 31, 2005 and 2004 was approximately $5 million, $2 million, $17 million and $7 million, respectively. Cash received by Duke Energy Carolinas from options exercised during the three months ended March 31, 2006 and the nine months ended December 31, 2006 was approximately $16 million and $10 million, respectively, with a related tax benefit of approximately $2 million and $1 million, respectively. At December 31, 2006, Duke Energy Carolinas had less than $1 million of future compensation cost which is expected to be recognized over a weighted-average period of less than a year.

There were no options granted to Duke Energy Carolinas employees during the years ended December 31, 2006, 2005 and 2004. The 2006 Plan allows for a maximum of 15 million shares of common stock to be issued by Duke Energy under various stock-based awards other than options and stock appreciation rights. The 1998 Plan allowed for a maximum of 12 million shares of common stock to be issued under various stock-based awards. Payments for cash settled awards during the period were immaterial.

Stock-based performance awards outstanding under the 1998 Plan generally vest over three years. Vesting for certain stock-based performance awards can occur in three years, at the earliest, if performance is met. Certain performance awards granted in 2006 contain market conditions based on the total shareholder return (TSR) of Duke Energy stock relative to a pre-defined peer group (relative TSR). These awards are valued using a path-dependent model that incorporates expected relative TSR into the fair value determination of Duke Energy’s performance-based share awards with the adoption of SFAS No. 123(R). The model uses three year historical volatilities and correlations for all companies in the pre-defined peer group, including Duke Energy, to simulate Duke Energy’s relative TSR as of the end of the performance period. For each simulation, Duke Energy’s relative TSR associated with the simulated stock price at the end of the performance period plus expected dividends within the period results in a value per share for the award portfolio. The average of these simulations is the expected portfolio value per share. Actual life to date results of Duke Energy’s relative TSR for each grant is incorporated within the model. Other awards not containing market conditions are measured at grant date price. Duke Energy awarded 281,160 shares (fair value of approximately $5 million, based on the market price of Duke Energy’s common stock at the grant date) to Duke Energy Carolinas employees in the year ended December 31, 2006, 1,275,020 shares (fair value of approximately $34 million, based on the market price of Duke Energy’s common stock at the grant date) in the year ended December 31, 2005, and 1,584,840 shares (fair value of approximately $34 million, based on the market price of Duke Energy’s common stock at the grant date) in the year ended December 31, 2004.

The following table summarizes information about stock-based performance awards outstanding at December 31, 2006:

The total fair value of the shares vested during the three months ended March 31, 2006 and the year ended December 31, 2005 was approximately $3 million in each period. No shares vested during the nine months ended December 31, 2006 or the year ended December 31, 2004. As of December 31, 2006, Duke Energy Carolinas had approximately $4 million of future compensation cost which is expected to be recognized over a weighted-average period of one year.

Phantom stock awards outstanding under the 1998 Plan generally vest over periods from immediate to five years. Duke Energy awarded 187,220 shares (fair value of approximately $5 million) based on the market price of Duke Energy’s common stock at the grant dates to Duke Energy Carolinas employees in the year ended December 31, 2006, 1,139,880 shares (fair value of approximately $31 million) in the year ended December 31, 2005, and 1,283,220 shares (fair value of approximately $27 million) in the year ended December 31, 2004.

The following table summarizes information about phantom stock awards outstanding at December 31, 2006:

The total fair value of the shares vested during the three months ended March 31, 2006, the nine months ended December 31, 2006 and the years ended December 31, 2005 and 2004 was approximately $12 million, $2 million, $10 million and $7 million, respectively. As of December 31, 2006, Duke Energy Carolinas had approximately $3 million of future compensation cost which is expected to be recognized over a weighted-average period of 3.3 years.

Other stock awards outstanding under the 1998 Plan generally vest over periods from three to five years. Duke Energy awarded 238,000 shares (fair value of approximately $7 million) based on the market price of Duke Energy’s common stock at the grant dates to Duke Energy Carolinas employees in the three months ended March 31, 2006, 47,000 shares (fair value of approximately $1 million) in the year ended December 31, 2005, and 169,160 shares (fair value of approximately $4 million) in the year ended December 31, 2004. There were no other stock awards granted to Duke Energy Carolinas employees in the nine months ended December 31, 2006.

The following table summarizes information about other stock awards outstanding at December 31, 2006:

The total fair value of the shares vested during the three months ended March 31, 2006, the nine months ended December 31, 2006 and the years ended December 31, 2005 and 2004 was less than $1 million, less than $1 million, approximately $1 million and approximately $1 million, respectively. As of December 31, 2006, Duke Energy Carolinas had approximately $6 million of future compensation cost which is expected to be recognized over a weighted-average period of 3.5 years.

In February 2005, Duke Energy Carolinas announced plans to execute up to approximately $2.5 billion in common stock repurchases over a three year period. In May 2005, Duke Energy Carolinas suspended additional repurchases, pending further assessment. At the time of suspension, Duke Energy Carolinas had repurchased approximately $933 million of common stock. In the first quarter of 2006, as a result of the March 10, 2006 shareholder approval of the Cinergy merger, Duke Energy Carolinas’ Board of Directors authorized the repurchase of up to an additional $1 billion of common stock under the previously announced share repurchase plan. Duke Energy Carolinas repurchased 2.4 million shares for total consideration of approximately $69 million during the three months ended March 31, 2006. The repurchases and corresponding commissions and other fees were recorded in Common Stockholders’ Equity as a reduction in Common Stock and Additional Paid-in Capital in 2006 and 2005.

On March 18, 2005, Duke Energy Carolinas entered into an accelerated share repurchase transaction whereby Duke Energy Carolinas repurchased and retired 30 million shares of its common stock from an investment bank at the March 18, 2005 closing price of $27.46 per share. Total consideration paid to repurchase the shares of approximately $834 million, including approximately $10 million in commissions and other fees, was recorded in Common Stockholders’ Equity as a reduction in Common Stock. Additionally, Duke Energy Carolinas entered into a separate open-market purchase plan on March 18, 2005 to repurchase up to an additional 20 million shares of its common stock, of which approximately 2.6 million shares were repurchased prior to the May 2005 suspension of the program at a weighted average price of $28.97 per share. As part of the accelerated share repurchase transaction, Duke Energy Carolinas simultaneously entered into a forward sale contract with the investment bank that was to mature no later than November 8, 2005. Under the terms of the forward sale contract, the investment bank was required to purchase, in the open market, 30 million shares of Duke Energy common stock during the term of the contract to fulfill its obligation related to the shares it borrowed from third parties and sold

to Duke Energy Carolinas. At settlement, Duke Energy Carolinas, at its option, was required to either pay cash or issue registered or unregistered shares of its common stock to the investment bank if the investment bank’s weighted average purchase price was higher than the March 18, 2005 closing price of $27.46 per share, or the investment bank was required to pay Duke Energy Carolinas either cash or shares of Duke Energy Carolinas common stock, at Duke Energy Carolinas’ option, if the investment bank’s weighted average price for the shares purchased was lower than the March 18, 2005 closing price of $27.46 per share. On September 22, 2005, Duke Energy Carolinas, at its option, paid approximately $25 million in cash to the investment bank to settle the forward sale contract as the investment bank had repurchased the full 30 million shares in the open market and fulfilled all of its obligations. The amount paid to the investment bank was based upon the difference between the investment bank’s weighted average price paid for the 30 million shares purchased of $28.42 per share and the March 18, 2005 closing price of $27.46 per share. Duke Energy Carolinas recorded the approximately $25 million paid at settlement in Common Stockholders’ Equity as a reduction in Common Stock. Total consideration paid to repurchase the shares of approximately $933 million, including commissions and other fees, was recorded in Common Stockholders’ Equity as a reduction in Common Stock and Additional Paid-in Capital.

In November 2004, Duke Energy Carolinas issued 18,693,000 shares of its common stock in the settlement of the forward-purchase contract component of its Equity Units issued in November 2001. Under the terms of the contract, the Equity Unit holders were required to purchase stock at the time of settlement rate based on the current market price of Duke Energy common stock at the time of the settlement with a floor and a ceiling. The rate was .6231 shares of stock per Equity Unit. Duke Energy Carolinas received $750 million in proceeds as a result of the settlement, which was included in Proceeds from the Issuances of Common Stock and Common Stock Related to Employee Benefit Plans on the Consolidated Statement of Cash Flows.

In May 2004, Duke Energy Carolinas issued 22,449,000 shares of its common stock in the settlement of the forward-purchase contract component of its Equity Units issued in March 2001. Under the terms of the contract, the Equity Unit holders were required to purchase common stock at a settlement rate based on the current market price of Duke Energy’s common stock at the time of settlement with a floor and a ceiling. The rate was 0.6414 shares of stock per Equity Unit. Duke Energy Carolinas received $875 million in proceeds as a result of the settlement, which was included in Proceeds from the Issuances of Common Stock and Common Stock Related to Employee Benefit Plans on the Consolidated Statement of Cash Flows.

Duke Energy also sponsors an employee savings plan that covers substantially all U.S. employees. In April 2004, Duke Energy stopped issuing shares under the plan and the plan began making open market purchases with cash provided by Duke Energy Carolinas. There were no issuances of common stock under the plan in either 2006 or 2005. Issuances of common stock under the plan were $51 million in 2004. Duke Energy also issues shares of its common stock to meet other employee benefit requirements. Issuances of common stock to meet other employee benefit requirements were approximately $16 million for the three months ended March 31, 2006, $39 million for 2005 and approximately $12 million for 2004.

See the Consolidated Statements of Common Stockholders’ Equity and Comprehensive Income for additional equity transactions.

Duke Energy U.S. Retirement Plans. As discussed in Note 1, on April 3, 2006, Duke Energy Carolinas transferred its membership interests in Spectra Energy Capital to Duke Energy. Effective as of the date of this transfer, Duke Energy Carolinas participates in the employee benefit plans of Duke Energy and is allocated costs of the plans in which Duke Energy Carolinas participates.

Duke Energy Carolinas participates in Duke Energy’s qualified non-contributory defined benefit retirement plans. The plans cover most U.S. employees using a cash balance formula. Under a cash balance formula, a plan participant accumulates a retirement benefit consisting of pay credits that are based upon a percentage (which may vary with age and years of service) of current eligible earnings and current interest credits.

Duke Energy’s policy is to fund amounts on an actuarial basis to provide assets sufficient to meet benefits to be paid to plan participants. Duke Energy Carolinas made voluntary contributions of approximately $0 in 2005 and $250 million in the fourth quarter of 2004 to its U.S. Plans.

Actuarial gains and losses are amortized over the average remaining service period of the active employees. The average remaining service period of the active employees covered by the qualified retirement plans is 11 years. Duke Energy determines the market-related value of plan assets using a calculated value that recognizes changes in fair value of the plan assets in a particular year on a straight-line basis over the next five years. Duke Energy uses a September 30 measurement date for its defined benefit retirement plans.

Westcoast Energy Inc. (Westcoast) Canadian Retirement Plans. Duke Energy Carolina’s transfer of its membership interests in Spectra Energy Capital (see above) to Duke Energy included the transfer of Westcoast’s accrued pension liabilities, accrued other post-retirement liabilities and minimum pension liability, as the obligations associated with the Westcoast plans exist at Duke Energy Carolinas’ parent company.

The Westcoast benefit plans are reported separately due to actuarial assumption differences. Westcoast and its subsidiaries maintain qualified and non-qualified contributory and non-contributory defined benefit (DB) and defined contribution (DC) retirement plans covering substantially all employees. The DB plans provide retirement benefits based on each plan participant’s years of service and final average earnings. Under the DC plans, company contributions are determined according to the terms of the plan and based on each plan participant’s age, years of service and current eligible earnings. Westcoast also provides non-registered defined benefit supplemental pensions to all employees who retire under a defined benefit registered pension plan and whose pension is limited by the maximum pension limits under the Income Tax Act (Canada).

Westcoast’s policy is to fund the DB plans on an actuarial basis and in accordance with Canadian pension standards legislation, in order to accumulate assets sufficient to meet benefits to be paid. Contributions to the DC plans are determined in accordance with the terms of the plan. Duke Energy Carolinas made contributions to the Westcoast DB plans of approximately $10 million for the three months ended March 31, 2006, $42 million in 2005 and $26 million in 2004. Duke Energy Carolinas also made contributions to the DC plans of $1 million for the three months ended March 31, 2006, $3 million in 2005 and $3 million in 2004.

Components of Net Periodic Pension Costs as allocated by Duke Energy: Qualified Pension Benefits (Income)

These amounts exclude pre-tax pension cost of $1 million for the three months ended March 31, 2006 and pre-tax pension income of $5 million and $14 million for the years ended December 31, 2005 and 2004, respectively, related to Spectra Energy Capital entities which are reflected in Income From Discontinued Operations, net of tax, in the Consolidated Statements of Operations (see Note 1).

The fair value of Duke Energy’s U.S. plan assets (excluding Cinergy plans) was $3,022 million as of September 30, 2006 and $2,948 million as of September 30, 2005. The projected benefit obligation of Duke Energy’s U.S. plan (excluding Cinergy plans) was $2,847 million as of September 30, 2006 and $2,853 million as of September 30, 2005. The accumulated benefit obligation of Duke Energy’s U.S. plan (excluding Cinergy plans) was $2,719 million at September 30, 2006 and $2,753 million at September 30, 2005.

The fair value of Westcoast’s plan assets was $475 million as of September 30, 2005. The projected benefit obligation of the Westcoast plan was $616 million as of September 30, 2005. The accumulated benefit obligation of the Westcoast plan was $562 million at September 30, 2005.

Qualified Pension Plans—Amounts Recognized in the Consolidated Balance Sheets Consist of:

As of December 31, 2006, Duke Energy Carolinas does not have any amounts reflected on its Consolidation Balance Sheets related to prepaid pension costs, accrued pension liabilities, or minimum pension liability as the obligations associated with the pension plans exist at Duke Energy Carolinas’ parent company, Duke Energy.

Duke Energy maintains, and Duke Energy Carolinas participates in, a non-qualified, non-contributory defined benefit retirement plan which covers certain U.S. executives. There are no plan assets. The projected benefit obligation for the Duke Energy U.S. plan (excluding Cinergy plans) was $84 million as of September 30, 2006 and $86 million as of September 30, 2005. The projected benefit obligation for the Westcoast plan was $84 million as of September 30, 2005

Components of Net Periodic Pension Costs as allocated by Duke Energy: Non-Qualified Pension Benefits

These amounts exclude pre-tax pension cost of $2 million, $9 million and $9 million for the years ended December 31, 2006, 2005 and 2004, respectively, related to Spectra Energy Capital entities which are reflected in Income From Discontinued Operations, net of tax, in the Consolidated Statements of Operations.

Non-Qualified Pension Plans—Amounts Recognized in the Consolidated Balance Sheets Consist of:

Duke Energy sponsors, and Duke Energy Carolinas participates in, an employee savings plan that covers substantially all U.S. employees. Duke Energy contributes a matching contribution equal to 100% of before-tax employee contributions, of up to 6% of eligible pay per period. Duke Energy Carolinas expensed pre-tax plan contributions, as allocated by Duke Energy, of $42 million in 2006, $41 million in 2005 and $38 million in 2004. These amounts exclude pre-tax expenses of $9 million for 2006, $20 million for 2005 and $19 million for 2004, which are reflected in Income From Discontinued Operations, net of tax, in the Consolidated Statements of Operations.

Duke Energy U.S. Other Post-Retirement Benefit Plans. In conjunction with Duke Energy, Duke Energy Carolinas provides some health care and life insurance benefits for retired employees on a contributory and non-contributory basis. Employees are eligible for these benefits if they have met age and service requirements at retirement, as defined in the plans.

These benefit costs are accrued over an employee’s active service period to the date of full benefits eligibility. The net unrecognized transition obligation is amortized over approximately 20 years. Actuarial gains and losses are amortized over the average remaining service period of the active employees. The average remaining service period of the active employees covered by the plan is 13 years.

Components of Net Periodic Other Post-Retirement Benefit Costs as allocated by Duke Energy

These amounts exclude pre-tax net periodic other post-retirement cost of $8 million, $27 million and $27 million for the three months ended March 31, 2006 and the years ended December 31, 2005 and 2004, respectively, related to Spectra Energy Capital entities which are reflected in Income From Discontinued Operations, net of tax, in the Consolidated Statements of Operations.

The fair value of Duke Energy’s plan assets (excluding Cinergy plans) was $237 million as of September 30, 2006 and $242 million as of September 30, 2005. The accumulated other post-retirement benefit obligation (excluding Cinergy plans) was $767 million at September 30, 2006 and $791 million at September 30, 2005. There were no plan assets for the Westcoast plan at September 30, 2005. The accumulated other post-retirement benefit obligation for the Westcoast plan was $117 million at September 30, 2005.

Other Post-Retirement Benefit Plans—Amounts Recognized in the Consolidated Balance Sheets Consist of:

As of December 31, 2006, Duke Energy Carolinas does not have any amounts reflected on its Consolidation Balance Sheets related to accrued other post-retirement liabilities as the obligations associated with the post-retirement plans exist at Duke Energy Carolinas’ parent company, Duke Energy.

The components of Other Income and Expenses, net on the Consolidated Statements of Operations for the years ended December 31, 2006, 2005 and 2004 are as follows:

During the first quarter of 2006, Duke Energy Carolinas recorded the following unusual or infrequently occurring item: an approximate $24 million pre-tax gain on the settlement of a customer’s transportation contract (see Note 13), which is included in Income From Discontinued Operations, net of tax, on the Consolidated Statements of Operations.

During the first quarter of 2005, Duke Energy Carolinas recorded the following unusual or infrequently occurring items, all of which are included in Income From Discontinued Operations, net of tax, on the Consolidated Statements of Operations: an approximate $0.9 billion (net of minority interest of approximately $0.3 billion) pre-tax gain on sale of DEFS’ wholly-owned subsidiary, TEPPCO GP (see Note 13); an approximate $100 million pre-tax gain on sale of Duke Energy Carolinas’ limited partner interest in TEPPCO LP (see Note 13); an approximate $21 million pre-tax gain on sale of former DENA’s partially completed Grays Harbor power plant in Washington State; an approximate $230 million of unrealized pre-tax losses on certain 2005 and 2006 derivative contracts hedging Field Services commodity price risk which were discontinued as cash flow hedges as a result of the anticipated deconsolidation of DEFS by Duke Energy Carolinas (see Note 13); and an approximate $30 million mutual liability adjustment related to Bison which was an immaterial correction of an accounting error related to prior periods.

During the third quarter of 2005, Duke Energy Carolinas recorded the following unusual or infrequently occurring items, all of which are included in Income From Discontinued Operations, net of tax, on the Consolidated Statements of Operations: an approximate $1.3 billion pre-tax charge for the impairment of assets and the discontinuance of hedge accounting for certain positions at former DENA, as a result of the decision to exit substantially all of former DENA’s remaining assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern Assets (see Note 13); an approximate $575 million pre-tax gain associated with

the transfer of 19.7% of Duke Energy Carolinas’ interest in DEFS to ConocoPhillips, Duke Energy Carolinas’ co-equity owner in DEFS, which reduced Duke Energy Carolinas’ ownership interest in DEFS from 69.7% to 50% (see Note 13); an approximate $105 million of unrealized and realized pre-tax losses on certain 2005 and 2006 derivative contracts hedging Field Services commodity price risk which were discontinued as cash flow hedges as a result of the deconsolidation of DEFS by Duke Energy Carolinas (see Note 13); and approximately $90 million of gains at Crescent due primarily to income related to a distribution from an interest in a portfolio of office buildings and a large land sale.

During the fourth quarter of 2005, Duke Energy Carolinas recorded the following unusual or infrequently occurring items, all of which are included in Income From Discontinued Operations, net of tax, on the Consolidated Statements of Operations: pre-tax gain of approximately $380 million, which reverses a portion of the third quarter former DENA impairment, attributable to the planned asset sales to LS Power; and pre-tax losses of approximately $475 million for portfolio exit costs including severance, retention and other transaction costs at former DENA (see Note 13).

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

Disclosure controls and procedures are controls and other procedures that are designed to ensure that information required to be disclosed by Duke Energy Carolinas in the reports it files or submits under the Securities Exchange Act of 1934 (Exchange Act) is recorded, processed, summarized, and reported, within the time periods specified by the Securities and Exchange Commission’s (SEC) rules and forms.

Disclosure controls and procedures include, without limitation, controls and procedures designed to provide reasonable assurance that information required to be disclosed by Duke Energy Carolinas in the reports it files or submits under the Exchange Act is accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

Under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, Duke Energy Carolinas has evaluated the effectiveness of its disclosure controls and procedures (as such term is defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act) as of December 31, 2006, and, based upon this evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that these controls and procedures are effective in providing reasonable assurance that information requiring disclosure is recorded, processed, summarized, and reported within the timeframe specified by the SEC’s rules and forms.

Under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, Duke Energy Carolinas has evaluated changes in internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the fiscal quarter ended December 31, 2006 and, other than the Duke Energy and Cinergy merger discussed below, found no change that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.

On April 3, 2006, the previously announced merger between Duke Energy and Cinergy was consummated. Duke Energy is in process of integrating Cinergy’s operations and has included Cinergy’s activity in its evaluation of internal control over financial reporting pursuant to Section 404 of the Sarbanes-Oxley Act of 2002. See Notes 1, 2 and 3 to the Consolidated Financial Statements for additional information relating to the merger.

The following table presents fees for professional services rendered by Deloitte & Touche LLP, and the member firms of Deloitte Touche Tohmatsu and their respective affiliates (collectively, “Deloitte”) for Duke Energy and its subsidiaries for 2006 and 2005:

To safeguard the continued independence of the independent auditor, the Duke Energy Audit Committee adopted a policy that prevents Duke Energy’s independent auditor from providing services to Duke Energy and its subsidiaries that are prohibited under Section 10A(g) of the Securities Exchange Act of 1934, as amended. This policy also provides that independent auditors are only permitted to provide services to Duke Energy and its subsidiaries that have been pre-approved by the Duke Energy Audit Committee. Pursuant to the policy, all audit services require advance approval by the Duke Energy Audit Committee. All other services by the independent auditor that fall within certain designated dollar thresholds, both per engagement as well as annual aggregate, have been pre-approved under the policy. Different dollar thresholds apply to the three categories of pre-approved services specified in the policy (Audit-Related services, Tax services and Other services). All services that exceed the dollar thresholds must be approved in advance by the Duke Energy Audit Committee. Pursuant to applicable provisions of the Securities Exchange Act of 1934, as amended, the Duke Energy Audit Committee has delegated approval authority to the Chairman of the Audit Committee. The Chairman has presented all approval decisions to the full Duke Energy Audit Committee. All engagements performed by the independent auditor in 2006 were approved by the Duke Energy Audit Committee pursuant to its pre-approval policy.

(a) Consolidated Financial Statements, Supplemental Financial Data and Supplemental Schedule included in Part II of this annual report are as follows:

Consolidated Statements of Operations for the Years Ended December 31, 2006, 2005 and 2004

Consolidated Statements of Cash Flows for the Years Ended December 31, 2006, 2005 and 2004

Consolidated Statements of Member’s/Common Stockholders’ Equity and Comprehensive Income for the Years ended December 31, 2006, 2005 and 2004

Quarterly Financial Data, as revised (unaudited, included in Note 23 to the Consolidated Financial Statements)

Consolidated Financial Statement Schedule II—Valuation and Qualifying Accounts and Reserves for the Years Ended December 31, 2006, 2005 and 2004

Separate Financial Statements of Subsidiaries Not Consolidated Pursuant to Rule 3-09 of Regulation S-X:

Consolidated Statements of Income for the Years Ended December 31, 2005, 2004 and 2003

Consolidated Statements of Cash Flows for the Years Ended December 31, 2005, 2004 and 2003

Consolidated Statements of Partners’ Capitol for the Years Ended December 31, 2005, 2004 and 2003

Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2005, 2004 and 2003

Consolidated Statements of Operations and Income for the Years Ended December 31, 2006 and 2005

Consolidated Statements of Cash Flows for the Years Ended December 31, 2006 and 2005

Consolidated Statements of Members’ Equity for the Years Ended December 31, 2006 and 2005

All other schedules are omitted because they are not required, or because the required information is included in the Consolidated Financial Statements or Notes.

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


DUKE ENERGY CAROLINAS, LLC (Registrant)

By:		/s/ JAMES E. ROGERS
		James E. Rogers Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.

We have audited the accompanying consolidated balance sheets of TEPPCO Partners, L.P. and subsidiaries as of December 31, 2005 and 2004, and the related consolidated statements of income, partners’ capital and comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2005. These consolidated financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of TEPPCO Partners, L.P. and subsidiaries as of December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2005, in conformity with U.S. generally accepted accounting principles.

As discussed in Note 20 to the consolidated financial statements, the Partnership has restated its consolidated balance sheet as of December 31, 2004, and the related consolidated statements of income, partners’ capital and comprehensive income, and cash flows for the years ended December 31, 2004 and 2003.

TEPPCO Partners, L.P. (the “Partnership”), a Delaware limited partnership, is a master limited partnership formed in March 1990. We operate through TE Products Pipeline Company, Limited Partnership (“TE Products”), TCTM, L.P. (“TCTM”) and TEPPCO Midstream Companies, L.P. (“TEPPCO Midstream”). Collectively, TE Products, TCTM and TEPPCO Midstream are referred to as the “Operating Partnerships.” Texas Eastern Products Pipeline Company, LLC (the “Company” or “General Partner”), a Delaware limited liability company, serves as our general partner and owns a 2% general partner interest in us.

On July 26, 2001, the Company restructured its general partner ownership of the Operating Partnerships to cause them to be indirectly wholly owned by us. TEPPCO GP, Inc. (“TEPPCO GP”), our subsidiary, succeeded the Company as general partner of the Operating Partnerships. All remaining partner interests in the Operating Partnerships not already owned by us were transferred to us. In exchange for this contribution, the Company’s interest as our general partner was increased to 2%. The increased percentage is the economic equivalent of the aggregate interest that the Company had prior to the restructuring through its combined interests in us and the Operating Partnerships. As a result, we hold a 99.999% limited partner interest in the Operating Partnerships and TEPPCO GP holds a 0.001% general partner interest. This reorganization was undertaken to simplify required financial reporting by the Operating Partnerships when the Operating Partnerships issue guarantees of our debt.

Through February 23, 2005, the General Partner was an indirect wholly owned subsidiary of Duke Energy Field Services, LLC (“DEFS”), a joint venture between Duke Energy Corporation (“Duke Energy”) and ConocoPhillips. Duke Energy held an interest of approximately 70% in DEFS, and ConocoPhillips held the remaining interest of approximately 30%. On February 24, 2005, the General Partner was acquired by DFI GP Holdings L.P. (formerly Enterprise GP Holdings L.P.) (“DFI”), an affiliate of EPCO, Inc. (“EPCO”), a privately held company controlled by Dan L. Duncan, for approximately $1.1 billion. As a result of the transaction, DFI owns and controls the 2% general partner interest in us and has the right to receive the incentive distribution rights associated with the general partner interest. In conjunction with an amended and restated administrative services agreement, EPCO performs all management, administrative and operating functions required for us, and we reimburse EPCO for all direct and indirect expenses that have been incurred in managing us. As a result of the sale of our General Partner, DEFS and Duke Energy continued to provide some administrative services for us for a period of up to one year after the sale, at which time, we assumed these services. In connection with us assuming the operations of certain of the TEPPCO Midstream assets from DEFS, certain DEFS employees became employees of EPCO effective June 1, 2005.

At formation in 1990, we completed an initial public offering of 26,500,000 units representing Limited Partner Interests (“Limited Partner Units”) at $10.00 per Limited Partner Unit. In connection with our formation, the Company received 2,500,000 Deferred Participation Interests (“DPIs”). Effective April 1, 1994, the DPIs were converted to Limited Partner Units, but they have not been listed for trading on the New York Stock Exchange. These Limited Partner Units were assigned to Duke Energy when ownership of the Company was transferred from Duke Energy to DEFS in 2000. On February 24, 2005, DFI entered into an LP Unit Purchase and Sale Agreement with Duke Energy and purchased these 2,500,000 Limited Partner Units for $104.0 million. As of December 31, 2005, none of these Limited Partner Units had been sold by DFI.

At December 31, 2005, 2004 and 2003, we had outstanding 69,963,554, 62,998,554 and 62,998,554 Limited Partner Units, respectively. At December 31, 2002, we had outstanding 3,916,547 Class B Limited Partner Units (“Class B Units”), which were issued to Duke Energy Transport and Trading Company, LLC (“DETTCO”) in connection with an acquisition of assets initially acquired in 1998. On April 2, 2003, we repurchased and retired all of the 3,916,547 previously outstanding Class B Units with proceeds from the issuance of additional Limited Partner Units (see Note 11). Collectively, the Limited Partner Units and Class B Units are referred to as “Units”.

As used in this Report, “we,” “us,” “our,” the “Partnership” and “TEPPCO” mean TEPPCO Partners, L.P. and, where the context requires, include our subsidiaries.

We restated our consolidated financial statements and related financial information for the years ended December 31, 2004 and 2003, for an accounting correction. In addition, the restatement adjustment impacted quarterly periods with the fiscal years ended December 31, 2005, 2004 and 2003. See Note 20 for a discussion of the restatement adjustment and the impact on previously issued financial statements.

We adhere to the following significant accounting policies in the preparation of our consolidated financial statements.

Basis of Presentation and Principles of Consolidation. Throughout the consolidated financial statements and accompanying notes, all referenced amounts related to prior periods reflect the balances and amounts on a restated basis. The financial statements include our accounts on a consolidated basis. We have eliminated all significant intercompany items in consolidation. We have reclassified

certain amounts from prior periods to conform to the current presentation. Our results for the years ended December 31, 2005 and 2004 reflect the operations and activities of Jonah Gas Gathering Company’s Pioneer plant as discontinued operations.

Use of Estimates. The preparation of financial statements in conformity with generally accepted accounting principles in the United States requires our management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Although we believe these estimates are reasonable, actual results could differ from those estimates.

Business Segments. We operate and report in three business segments: transportation and storage of refined products, liquefied petroleum gases (“LPGs”) and petrochemicals (“Downstream Segment”); gathering, transportation, marketing and storage of crude oil and distribution of lubrication oils and specialty chemicals (“Upstream Segment”); and gathering of natural gas, fractionation of natural gas liquids (“NGLs”) and transportation of NGLs (“Midstream Segment”). Our reportable segments offer different products and services and are managed separately because each requires different business strategies.

Our interstate transportation operations, including rates charged to customers, are subject to regulations prescribed by the Federal Energy Regulatory Commission (“FERC”). We refer to refined products, LPGs, petrochemicals, crude oil, NGLs and natural gas in this Report, collectively, as “petroleum products” or “products.”

Revenue Recognition. Our Downstream Segment revenues are earned from transportation and storage of refined products and LPGs, intrastate transportation of petrochemicals, sale of product inventory and other ancillary services. Transportation revenues are recognized as products are delivered to customers. Storage revenues are recognized upon receipt of products into storage and upon performance of storage services. Terminaling revenues are recognized as products are out-loaded. Revenues from the sale of product inventory are recognized when the products are sold.

Our Upstream Segment revenues are earned from gathering, transportation, marketing and storage of crude oil, and distribution of lubrication oils and specialty chemicals principally in Oklahoma, Texas, New Mexico and the Rocky Mountain region. Revenues are also generated from trade documentation and pumpover services, primarily at Cushing, Oklahoma, and Midland, Texas. Revenues are accrued at the time title to the product sold transfers to the purchaser, which typically occurs upon receipt of the product by the purchaser, and purchases are accrued at the time title to the product purchased transfers to our crude oil marketing company, TEPPCO Crude Oil, L.P. (“TCO”), which typically occurs upon our receipt of the product. Revenues related to trade documentation and pumpover fees are recognized as services are completed.

Except for crude oil purchased from time to time as inventory, our policy is to purchase only crude oil for which we have a market to sell and to structure sales contracts so that crude oil price fluctuations do not materially affect the margin received. As we purchase crude oil, we establish a margin by selling crude oil for physical delivery to third party users or by entering into a future delivery obligation. Through these transactions, we seek to maintain a position that is balanced between crude oil purchases and sales and future delivery obligations. However, certain basis risks (the risk that price relationships between delivery points, classes of products or delivery periods will change) cannot be completely hedged.

Our Midstream Segment revenues are earned from the gathering of natural gas, transportation of NGLs and fractionation of NGLs. Gathering revenues are recognized as natural gas is received from the customer. Transportation revenues are recognized as NGLs are delivered to customers. Revenues are also earned from the sale of condensate liquid extracted from the natural gas stream to an Upstream Segment marketing affiliate. Fractionation revenues are recognized ratably over the contract year as products are delivered. We generally do not take title to the natural gas gathered, NGLs transported or NGLs fractionated, with the exception of inventory imbalances discussed in “Natural Gas Imbalances.” Therefore, the results of our Midstream Segment are not directly affected by changes in the prices of natural gas or NGLs.

Cash and Cash Equivalents. Cash equivalents are defined as all highly marketable securities with maturities of three months or less when purchased. The carrying value of cash and cash equivalents approximate fair value because of the short term nature of these investments.

Allowance for Doubtful Accounts. We establish provisions for losses on accounts receivable if we determine that we will not collect all or part of the outstanding balance. Collectibility is reviewed regularly and an allowance is established or adjusted, as necessary, using the specific identification method. The following table presents the activity of our allowance for doubtful accounts for the years ended December 31, 2005, 2004 and 2003 (in thousands):

Inventories. Inventories consist primarily of petroleum products and crude oil, which are valued at the lower of cost (weighted average cost method) or market. Our Downstream Segment acquires and disposes of various products under exchange agreements. Receivables and payables arising from these transactions are usually satisfied with products rather than cash. The net balances of exchange receivables and payables are valued at weighted average cost and included in inventories. Inventories of materials and supplies, used for ongoing replacements and expansions, are carried at the lower of fair value or cost.

Property, Plant and Equipment. We record property, plant and equipment at its acquisition cost. Additions to property, plant and equipment, including major replacements or betterments, are recorded at cost. We charge replacements and renewals of minor items of property that do not materially increase values or extend useful lives to maintenance expense. Depreciation expense is computed on the straight-line method using rates based upon expected useful lives of various classes of assets (ranging from 2% to 20% per annum).

We evaluate impairment of long-lived assets in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of the carrying amount of assets to be held and used is measured by a comparison of the carrying amount of the asset to estimated future net cash flows expected to be generated by the asset. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the estimated fair value of the assets. Assets to be disposed of are reported at the lower of the carrying amount or estimated fair value less costs to sell.

Asset Retirement Obligations. In June 2001, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 143, Accounting for Asset Retirement Obligations. SFAS 143 requires us to record the fair value of an asset retirement obligation as a liability in the period in which we incur a legal obligation for the retirement of tangible long-lived assets. A corresponding asset is also recorded and depreciated over the life of the asset. After the initial measurement of the asset retirement obligation, the liability will be adjusted at the end of each reporting period to reflect changes in the estimated future cash flows underlying the obligation. Determination of any amounts recognized upon adoption is based upon numerous estimates and assumptions, including future retirement costs, future inflation rates and the credit-adjusted risk-free interest rates.

The Downstream Segment assets consist primarily of an interstate trunk pipeline system and a series of storage facilities that originate along the upper Texas Gulf Coast and extend through the Midwest and northeastern United States. We transport refined products, LPGs and petrochemicals through the pipeline system. These products are primarily received in the south end of the system and stored and/or transported to various points along the system per customer nominations. The Upstream Segment’s operations include purchasing crude oil from producers at the wellhead and providing delivery, storage and other services to its customers. The properties in the Upstream Segment consist of interstate trunk pipelines, pump stations, trucking facilities, storage tanks and various gathering systems primarily in Texas and Oklahoma. The Midstream Segment gathers natural gas from wells owned by producers and delivers natural gas and NGLs on its pipeline systems, primarily in Texas, Wyoming, New Mexico and Colorado. The Midstream Segment also owns and operates two NGL fractionator facilities in Colorado.

We have completed our assessment of SFAS 143, and we have determined that we are obligated by contractual or regulatory requirements to remove certain facilities or perform other remediation upon retirement of our assets. However, we are not able to reasonably determine the fair value of the asset retirement obligations for our trunk, interstate and gathering pipelines and our surface facilities, since future dismantlement and removal dates are indeterminate.

In order to determine a removal date for our gathering lines and related surface assets, reserve information regarding the production life of the specific field is required. As a transporter and gatherer of crude oil and natural gas, we are not a producer of the field reserves, and we therefore do not have access to adequate forecasts that predict the timing of expected production for existing reserves on those fields in which we gather crude oil and natural gas. In the absence of such information, we are not able to make a reasonable

estimate of when future dismantlement and removal dates of our gathering assets will occur. With regard to our trunk and interstate pipelines and their related surface assets, it is impossible to predict when demand for transportation of the related products will cease. Our right-of-way agreements allow us to maintain the right-of-way rather than remove the pipe. In addition, we can evaluate our trunk pipelines for alternative uses, which can be and have been found.

We will record such asset retirement obligations in the period in which more information becomes available for us to reasonably estimate the settlement dates of the retirement obligations. The adoption of SFAS 143 did not have an effect on our financial position, results of operations or cash flows.

Capitalization of Interest. We capitalize interest on borrowed funds related to capital projects only for periods that activities are in progress to bring these projects to their intended use. The weighted average rate used to capitalize interest on borrowed funds was 5.73%, 5.74% and 6.50% for the years ended December 31, 2005, 2004 and 2003, respectively. During the years ended December 31, 2005, 2004 and 2003, the amount of interest capitalized was $6.8 million, $4.2 million and $5.3 million, respectively.

Intangible Assets. Intangible assets on the consolidated balance sheets consist primarily of gathering contracts assumed in the acquisition of Jonah Gas Gathering System (“Jonah”) on September 30, 2001, and the acquisition of Val Verde Gathering System (“Val Verde”) on June 30, 2002, a fractionation agreement and other intangible assets (see Note 3). Included in equity investments on the consolidated balance sheets are excess investments in Centennial Pipeline LLC (“Centennial”) and Seaway Crude Pipeline Company (“Seaway”).

In connection with the acquisitions of Jonah and Val Verde, we assumed contracts that dedicate future production from natural gas wells in the Green River Basin in Wyoming, and we assumed fixed-term contracts with customers that gather coal bed methane (“CBM”) from the San Juan Basin in New Mexico and Colorado, respectively. The value assigned to these intangible assets relates to contracts with customers that are for either a fixed term or which dedicate total future lease production to the gathering system. These intangible assets are amortized on a unit-of-production basis, based upon the actual throughput of the system over the expected total throughput for the lives of the contracts. Revisions to the unit-of-production estimates may occur as additional production information is made available to us (see Note 3).

In connection with the purchase of the fractionation facilities in 1998, we entered into a fractionation agreement with DEFS. The fractionation agreement is being amortized on a straight-line basis over a period of 20 years, which is the term of the agreement with DEFS.

In connection with the acquisition of crude supply and transportation assets in November 2003, we acquired intangible customer contracts for $8.7 million, which are amortized on a unit-of-production basis (see Note 5).

In connection with the formation of Centennial, we recorded excess investment, the majority of which is amortized on a unit-of-production basis over a period of 10 years. In connection with the acquisition of our interest in Seaway, we recorded excess investment, which is amortized on a straight-line basis over a period of 39 years (see Note 3).

Goodwill. Goodwill represents the excess of purchase price over fair value of net assets acquired and is presented on the consolidated balance sheets net of accumulated amortization. We account for goodwill under SFAS No. 142, Goodwill and Other Intangible Assets, which was issued by the FASB in July 2001 (see Note 3). SFAS 142 prohibits amortization of goodwill and intangible assets with indefinite useful lives, but instead requires testing for impairment at least annually. SFAS 142 requires that intangible assets with definite useful lives be amortized over their respective estimated useful lives. Beginning January 1, 2002, effective with the adoption of SFAS 142, we no longer record amortization expense related to goodwill.

Environmental Expenditures. We accrue for environmental costs that relate to existing conditions caused by past operations. Environmental costs include initial site surveys and environmental studies of potentially contaminated sites, costs for remediation and restoration of sites determined to be contaminated and ongoing monitoring costs, as well as damages and other costs, when estimable. We monitor the balance of accrued undiscounted environmental liabilities on a regular basis. We record liabilities for environmental costs at a specific site when our liability for such costs is probable and a reasonable estimate of the associated costs can be made. Adjustments to initial estimates are recorded, from time to time, to reflect changing circumstances and estimates based upon additional information developed in subsequent periods. Estimates of our ultimate liabilities associated with environmental costs are particularly difficult to make with certainty due to the number of variables involved, including the early stage of investigation at certain sites, the lengthy time frames required to complete remediation alternatives available and the evolving nature of environmental laws and regulations.

The following table presents the activity of our environmental reserve for the years ended December 31, 2005, 2004 and 2003 (in thousands):

Natural Gas Imbalances. Gas imbalances occur when gas producers (customers) deliver more or less actual natural gas gathering volumes to our gathering systems than they originally nominated. Actual deliveries are different from nominated volumes due to fluctuations in gas production at the wellhead. If the customers supply more natural gas gathering volumes than they nominated, Val Verde and Jonah record a payable for the amount due to customers and also record a receivable for the same amount due from connecting pipeline transporters or shippers. To the extent that these amounts are not cashed out monthly on Val Verde, if the customers supply less natural gas gathering volumes than they nominated, Val Verde and Jonah record a receivable reflecting the amount due from customers and a payable for the same amount due to connecting pipeline transporters or shippers. We record natural gas imbalances using a mark-to-market approach.

Income Taxes. We are a limited partnership. As such, we are not a taxable entity for federal and state income tax purposes and do not directly pay federal and state income tax. Our taxable income or loss, which may vary substantially from the net income or net loss we report in our consolidated statements of income, is includable in the federal and state income tax returns of each unitholder. Accordingly, no recognition has been given to federal and state income taxes for our operations. The aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined as we do not have access to information about each unitholders’ tax attributes in the Partnership.

Use of Derivatives. We account for derivative financial instruments in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, and SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities, an amendment of FASB Statement No. 133. These statements establish accounting and reporting standards requiring that derivative instruments (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet at fair value as either assets or liabilities. The accounting for changes in the fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative.

Our derivative instruments consist primarily of interest rate swaps and contracts for the purchase and sale of petroleum products in connection with our crude oil marketing activities. Substantially all derivative instruments related to our crude oil marketing activities meet the normal purchases and sales criteria of SFAS 133, as amended, and as such, changes in the fair value of petroleum product purchase and sales agreements are reported on the accrual basis of accounting. SFAS 133 describes normal purchases and sales as contracts that provide for the purchase or sale of something other than a financial instrument or derivative instrument that will be delivered in quantities expected to be used or sold by the reporting entity over a reasonable period in the normal course of business.

For all hedging relationships, we formally document at inception the hedging relationship and its risk-management objective and strategy for undertaking the hedge, the hedging instrument, the item, the nature of the risk being hedged, how the hedging instrument’s effectiveness in offsetting the hedged risk will be assessed and a description of the method of measuring ineffectiveness. This process includes linking all derivatives that are designated as fair value or cash flow to specific assets and liabilities on the balance sheet or to specific firm commitments or forecasted transactions. We also formally assess, both at the hedge’s inception and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in fair values or cash flows of hedged items. If it is determined that a derivative is not highly effective as a hedge or that it has ceased to be a highly effective hedge, we discontinue hedge accounting prospectively.

For derivative instruments designated as fair value hedges, gains and losses on the derivative instrument are offset against related results on the hedged item in the statement of income. Changes in the fair value of a derivative that is highly effective and that is designated and qualifies as a fair value hedge, along with the loss or gain on the hedged asset or liability or unrecognized firm commitment of the hedged item that is attributable to the hedged risk, are recorded in earnings. Changes in the fair value of a derivative that is highly effective and that is designated and qualifies as a cash flow hedge are recorded in other comprehensive income to the extent that the derivative is effective as a hedge, until earnings are affected by the variability in cash flows of the designated hedged item. Hedge effectiveness is measured at least quarterly based on the relative cumulative changes in fair value between the derivative contract and the

hedged item over time. The ineffective portion of the change in fair value of a derivative instrument that qualifies as either a fair value hedge or a cash flow hedge is reported immediately in earnings.

According to SFAS 133, as amended, we are required to discontinue hedge accounting prospectively when it is determined that the derivative is no longer effective in offsetting changes in the fair value or cash flows of the hedged item, the derivative expires or is sold, terminated, or exercised, the derivative is de-designated as a hedging instrument, because it is unlikely that a forecasted transaction will occur, a hedged firm commitment no longer meets the definition of a firm commitment, or management determines that designation of the derivative as a hedging instrument is no longer appropriate.

When hedge accounting is discontinued because it is determined that the derivative no longer qualifies as an effective fair value hedge, we continue to carry the derivative on the balance sheet at its fair value and no longer adjust the hedged asset or liability for changes in fair value. The adjustment of the carrying amount of the hedged asset or liability is accounted for in the same manner as other components of the carrying amount of that asset or liability. When hedge accounting is discontinued because the hedged item no longer meets the definition of a firm commitment, we continue to carry the derivative on the balance sheet at its fair value, remove any asset or liability that was recorded pursuant to recognition of the firm commitment from the balance sheet, and recognize any gain or loss in earnings. When hedge accounting is discontinued because it is probable that a forecasted transaction will not occur, we continue to carry the derivative on the balance sheet at its fair value with subsequent changes in fair value included in earnings, and gains and losses that were accumulated in other comprehensive income are recognized immediately in earnings. In all other situations in which hedge accounting is discontinued, we continue to carry the derivative at its fair value on the balance sheet and recognize any subsequent changes in its fair value in earnings.

Fair Value of Financial Instruments. The carrying amount of cash and cash equivalents, accounts receivable, inventories, other current assets, accounts payable and accrued liabilities, other current liabilities and derivatives approximates their fair value due to their short-term nature. The fair values of these financial instruments are represented in our consolidated balance sheets.

Net Income Per Unit. Basic net income per Unit is computed by dividing net income, after deduction of the General Partner’s interest, by the weighted average number of Units outstanding (a total of 67.4 million Units, 63.0 million Units and 59.8 million Units for the years ended December 31, 2005, 2004 and 2003, respectively). The General Partner’s percentage interest in our net income is based on its percentage of cash distributions from Available Cash for each year (see Note 11). The General Partner was allocated $47.6 million (representing 29.27%) of net income for the year ended December 31, 2005, $40.0 million (representing 28.85%) of net income for the year ended December 31, 2004, and $33.7 million (representing 27.65%) of net income for the year ended December 31, 2003. The General Partner’s percentage interest in our net income increases as cash distributions paid per Unit increase, in accordance with our limited partnership agreement.

Diluted net income per Unit is similar to the computation of basic net income per Unit discussed above, except that the denominator is increased to include the dilutive effect of outstanding Unit options by application of the treasury stock method. For the year ended December 31, 2003, the denominator was increased by 11,878 Units. For the years ended December 31, 2005 and 2004, diluted net income per Unit equaled basic net income per Unit as all remaining outstanding Unit options were exercised during the third quarter of 2003 (see Note 13).

Unit Option Plan. We have not granted options for any periods presented. For options outstanding under the 1994 Long Term Incentive Plan (see Note 13), we followed the intrinsic value method of accounting for recognizing stock-based compensation expense. Under this method, we record no compensation expense for Unit options granted when the exercise price of the options granted is equal to, or greater than, the market price of our Units on the date of the grant. During the year ended December 31, 2003, all remaining outstanding Unit options were exercised.

In December 2002, SFAS No. 148, Accounting for Stock-Based Compensation – Transition and Disclosure was issued. SFAS 148 amends SFAS No. 123, Accounting for Stock-Based Compensation, and provides alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, SFAS 148 amends the disclosure requirements of SFAS 123 to require prominent disclosure in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. Certain of the disclosure modifications are required for fiscal years ending after December 15, 2002, and are included in Note 13.

Assuming we had used the fair value method of accounting for our Unit option plan, pro forma net income would equal reported net income for the years ended December 31, 2005, 2004 and 2003. Pro forma net income per Unit would equal reported net income per Unit for the periods presented. The adoption of SFAS 148 did not have an effect on our financial position, results of operations or cash flows.

New Accounting Pronouncements. In December 2004, the FASB issued SFAS No. 123(R), Share-Based Payment. SFAS 123(R) requires compensation costs related to share-based payment transactions to be recognized in the financial statements. With limited exceptions, the amount of the compensation cost is to be measured based on the grant-date fair value of the equity or liability instruments issued. In addition, liability awards are to be re-measured each reporting period. Compensation cost will be recognized over the period that an employee provides service in exchange for the award. SFAS 123(R) is a revision of SFAS No. 123, Accounting for Stock-Based Compensation, as amended by SFAS No. 148, Accounting for Stock-Based Compensation – Transition and Disclosure and supersedes Accounting Principles Board (“APB”) Opinion No. 25, Accounting for Stock Issued to Employees. SFAS 123(R) is effective for public companies as of the first interim or annual reporting period of the first fiscal year beginning after June 15, 2005. The Securities and Exchange Commission amended the implementation date of SFAS 123(R) to begin with the first interim or annual reporting period of the company’s first fiscal year beginning on or after June 15, 1005. As such, we will adopt SFAS 123(R) in the first quarter of 2006. Companies are permitted to adopt SFAS 123(R) prior to the extended date. All public companies that adopted the fair-value-based method of accounting must use the modified prospective transition method and may elect to use the modified retrospective transition method. We do not believe that the adoption of SFAS 123(R) will have a material effect on our financial position, results of operations or cash flows.

In November 2004, the Emerging Issues Task Force (“EITF”) reached consensus in EITF 03-13, Applying the Conditions in Paragraph 42 of FASB Statement No. 144, Accounting for Impairment or Disposal of Long-Lived Assets, in Determining Whether to Report Discontinued Operations, to clarify whether a component of an enterprise that is either disposed of or classified as held for sale qualifies for income statement presentation as discontinued operations. The FASB ratified the consensus on November 30, 2004. The consensus is to be applied prospectively with regard to a component of an enterprise that is either disposed of or classified as held for sale in reporting periods beginning after December 15, 2004. The consensus may be applied retrospectively for previously reported operating results related to disposal transactions initiated within an enterprise’s reporting period that included the date that this consensus was ratified. The adoption of EITF 03-13 did not have an effect on our financial position, results of operations or cash flows.

In March 2005, the FASB issued FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143 (“FIN 47”). FIN 47 clarifies that the term, conditional asset retirement obligation as used in SFAS No. 143, Accounting for Asset Retirement Obligations, refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional upon a future event that may or may not be within the control of the entity. Even though uncertainty about the timing and/or method of settlement exists and may be conditional upon a future event, the obligation to perform the asset retirement activity is unconditional. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. Uncertainty about the timing and/or method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability when sufficient information exists. The fair value of a liability for the conditional asset retirement obligation should be recognized when incurred generally upon acquisition, construction, or development or through the normal operation of the asset. SFAS 143 acknowledges that in some cases, sufficient information may not be available to reasonably estimate the fair value of an asset retirement obligation. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. FIN 47 is effective no later than the end of reporting periods ending after December 15, 2005, and early adoption of FIN 47 is encouraged. We adopted FIN 47 in the fourth quarter of 2005. The adoption of FIN 47 did not have a material effect on our financial position, results of operations or cash flows.

In June 2005, the EITF reached consensus in EITF 04-5, Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights, to provide guidance on how general partners in a limited partnership should determine whether they control a limited partnership and therefore should consolidate it. The EITF agreed that the presumption of general partner control would be overcome only when the limited partners have either of two types of rights. The first type, referred to as kick-out rights, is the right to dissolve or liquidate the partnership or otherwise remove the general partner without cause. The second type, referred to as participating rights, is the right to effectively participate in significant decisions made in the ordinary course of the partnership’s business. The kick-out rights and the participating rights must be substantive in order to overcome the presumption of general partner control. The consensus is effective for general partners of all new limited partnerships formed and for existing limited partnerships for which the partnership agreements are modified subsequent to the date of FASB ratification (June 29, 2005). For existing limited partnerships that have not been modified, the guidance in EITF 04-5 is effective no later than the beginning of the first reporting period in fiscal years beginning after December 15, 2005. We do not believe that the adoption of EITF 04-5 will have a material effect on our financial position, results of operations or cash flows.

In December 2004, the FASB issued SFAS No. 153, Exchanges of Nonmonetary Assets, an amendment of APB Opinion 29. SFAS 153 amends APB Opinion No. 29, Accounting for Nonmonetary Exchanges, to eliminate the exception for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial

substance. A nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. SFAS 153 is effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. We adopted SFAS 153 during the second quarter of 2005. The adoption of SFAS 153 did not have a material effect on our financial position, results of operations or cash flows.

In May 2005, the FASB issued SFAS No. 154, Accounting Changes and Error Corrections. SFAS 154 establishes new standards on accounting for changes in accounting principles. All such changes must be accounted for by retrospective application to the financial statements of prior periods unless it is impracticable to do so. SFAS 154 completely replaces APB Opinion No. 20, Accounting Changes, and SFAS No. 3, Reporting Accounting Changes in Interim Periods. However, it carries forward the guidance in those pronouncements with respect to accounting for changes in estimates, changes in the reporting entity, and the correction of errors. SFAS 154 is effective for accounting changes and error corrections made in fiscal years beginning after December 15, 2005, with early adoption permitted for changes and corrections made in years beginning after June 1, 2005. The application of SFAS 154 does not affect the transition provisions of any existing pronouncements, including those that are in the transition phase as of the effective date of SFAS 154. We do not believe that the adoption of SFAS 154 will have a material effect on our financial position, results of operations or cash flows.

In September 2005, the EITF reached consensus in EITF 04-13, Accounting for Purchases and Sales of Inventory with the Same Counterparty, to define when a purchase and a sale of inventory with the same party that operates in the same line of business should be considered a single nonmonetary transaction subject to APB Opinion No. 29, Accounting for Nonmonetary Transactions. Two or more inventory transactions with the same party should be combined if they are entered into in contemplation of one another. The EITF also requires entities to account for exchanges of inventory in the same line of business at fair value or recorded amounts based on inventory classification. The guidance in EITF 04-13 is effective for new inventory arrangements entered into in reporting periods beginning after March 15, 2006. We are currently evaluating what impact EITF 04-13 will have on our financial statements, but at this time we do not believe that the adoption of EITF 04-13 will have a material effect on our financial position, results of operations or cash flows.

Goodwill. Goodwill represents the excess of purchase price over fair value of net assets acquired and is presented on the consolidated balance sheets net of accumulated amortization. We account for goodwill under SFAS No. 142, Goodwill and Other Intangible Assets, which was issued by the FASB in July 2001. SFAS 142 prohibits amortization of goodwill and intangible assets with indefinite useful lives, but instead requires testing for impairment at least annually. We test goodwill and intangible assets for impairment annually at December 31.

To perform an impairment test of goodwill, we have identified our reporting units and have determined the carrying value of each reporting unit by assigning the assets and liabilities, including the existing goodwill and intangible assets, to those reporting units. We then determine the fair value of each reporting unit and compare it to the carrying value of the reporting unit. We will continue to compare the fair value of each reporting unit to its carrying value on an annual basis to determine if an impairment loss has occurred. There have been no goodwill impairment losses recorded since the adoption of SFAS 142.

The following table presents the carrying amount of goodwill at December 31, 2005 and 2004, by business segment (in thousands):

Other Intangible Assets. The following table reflects the components of intangible assets, including excess investments, being amortized at December 31, 2005 and 2004 (in thousands):

SFAS 142 requires that intangible assets with finite useful lives be amortized over their respective estimated useful lives. If an intangible asset has a finite useful life, but the precise length of that life is not known, that intangible asset shall be amortized over the best estimate of its useful life. At a minimum, we will assess the useful lives and residual values of all intangible assets on an annual basis to determine if adjustments are required. Amortization expense on intangible assets was $30.5 million, $32.2 million and $36.2 million for the years ended December 31, 2005, 2004 and 2003, respectively. Amortization expense on excess investments included in equity earnings was $4.8 million, $3.8 million and $4.0 million for the years ended December 31, 2005, 2004 and 2003, respectively.

The values assigned to our intangible assets for natural gas gathering contracts on the Jonah and the Val Verde systems are amortized on a unit-of-production basis, based upon the actual throughput of the systems compared to the expected total throughput for the lives of the contracts. On a quarterly basis, we may obtain limited production forecasts and updated throughput estimates from some of the producers on the systems, and as a result, we evaluate the remaining expected useful lives of the contract assets based on the best available information. During the fourth quarter of 2004 and the first and second quarters of 2005, certain limited production forecasts were obtained from some of the producers on the Jonah system related to future expansions of the system, and as a result, we increased our best estimate of future throughput on the system, which resulted in extensions in the remaining lives of the intangible assets. During the fourth quarter of 2004 and the third quarter of 2005, certain limited coal bed methane production forecasts were obtained from some of the producers on the Val Verde system whose contracts are included in the intangible assets. These forecasts indicated lower coal bed methane production estimates over the contract periods, and as a result, we decreased our best estimate of future throughput on the Val Verde system, which resulted in increases to amortization expense on the intangible assets. Further revisions to these estimates may occur as additional production information is made available to us.

The values assigned to our fractionation agreement and other intangible assets are generally amortized on a straight-line basis. Our fractionation agreement is being amortized over its contract period of 20 years. The amortization periods for our other intangible assets, which include non-compete and other agreements, range from 3 years to 15 years. The value of $8.7 million assigned to our crude supply and transportation intangible customer contracts is being amortized on a unit-of-production basis (see Note 5).

The value assigned to our excess investment in Centennial was created upon its formation. Approximately $30.0 million is related to a contract and is being amortized on a unit-of-production basis based upon the volumes transported under the contract compared to the guaranteed total throughput of the contract over a 10-year life. The remaining $3.4 million is related to a pipeline and is being amortized on a straight-line basis over the life of the pipeline, which is 35 years. The value assigned to our excess investment in Seaway was created upon acquisition of our 50% ownership interest in 2000. We are amortizing the $27.1 million excess investment in Seaway on a straight-line basis over a 39-year life related primarily to the life of the pipeline.

The following table sets forth the estimated amortization expense of intangible assets and the estimated amortization expense allocated to equity earnings for the years ending December 31 (in thousands):

In July 2000, we entered into an interest rate swap agreement to hedge our exposure to increases in the benchmark interest rate underlying our variable rate revolving credit facility. This interest rate swap matured in April 2004. We designated this swap agreement, which hedged exposure to variability in expected future cash flows attributed to changes in interest rates, as a cash flow hedge. The swap agreement was based on a notional amount of $250.0 million. Under the swap agreement, we paid a fixed rate of interest of 6.955% and received a floating rate based on a three-month U.S. Dollar LIBOR rate. Because this swap was designated as a cash flow hedge, the changes in fair value, to the extent the swap was effective, were recognized in other comprehensive income until the hedged interest costs were recognized in earnings. During the years ended December 31, 2004 and 2003, we recognized an increase in interest expense of $2.9 million and $14.4 million, respectively, related to the difference between the fixed rate and the floating rate of interest on the interest rate swap.

In October 2001, TE Products entered into an interest rate swap agreement to hedge its exposure to changes in the fair value of its fixed rate 7.51% Senior Notes due 2028. We designated this swap agreement as a fair value hedge. The swap agreement has a notional amount of $210.0 million and matures in January 2028 to match the principal and maturity of the TE Products Senior Notes. Under the swap agreement, TE Products pays a floating rate of interest based on a three-month U.S. Dollar LIBOR rate, plus a spread, and receives a fixed rate of interest of 7.51%. During the years ended December 31, 2005, 2004 and 2003, we recognized reductions in interest expense of $5.6 million, $9.6 million and $10.0 million, respectively, related to the difference between the fixed rate and the floating rate of interest on the interest rate swap. During the years ended December 31, 2005, 2004 and 2003, we measured the hedge effectiveness of this interest rate swap and noted that no gain or loss from ineffectiveness was required to be recognized. The fair value of this interest rate swap was a loss of approximately $0.9 million at December 31, 2005, and a gain of approximately $3.4 million at December 31, 2004.

During 2002, we entered into interest rate swap agreements, designated as fair value hedges, to hedge our exposure to changes in the fair value of our fixed rate 7.625% Senior Notes due 2012. The swap agreements had a combined notional amount of $500.0 million and matured in 2012 to match the principal and maturity of the Senior Notes. Under the swap agreements, we paid a floating rate of interest based on a U.S. Dollar LIBOR rate, plus a spread, and received a fixed rate of interest of 7.625%. These swap agreements were later terminated in 2002 resulting in gains of $44.9 million. The gains realized from the swap terminations have been deferred as adjustments to the carrying value of the Senior Notes and are being amortized using the effective interest method as reductions to future interest expense over the remaining term of the Senior Notes. At December 31, 2005, the unamortized balance of the deferred gains was $32.4 million. In the event of early extinguishment of the Senior Notes, any remaining unamortized gains would be recognized in the consolidated statement of income at the time of extinguishment.

During May 2005, we executed a treasury rate lock agreement with a notional amount of $200.0 million to hedge our exposure to increases in the treasury rate that was to be used to establish the fixed interest rate for a debt offering that was proposed to occur in the second quarter of 2005. During June 2005, the proposed debt offering was cancelled, and the treasury lock was terminated with a realized loss of $2.0 million. The realized loss was recorded as a component of interest expense in the consolidated statements of income in June 2005.

In connection with our acquisition of crude oil assets in 2000, we acquired an approximate 23.5% undivided joint interest in the Rancho Pipeline, which was a crude oil pipeline system from West Texas to Houston, Texas. In March 2003, the Rancho Pipeline ceased operations, and segments of the pipeline were sold to certain of the owners that previously held undivided interests in the pipeline. We acquired 241 miles of the pipeline in exchange for cash of $5.5 million and our interests in other portions of the Rancho Pipeline. We sold 183 miles of the segment we acquired to other entities for cash and assets valued at approximately $8.5 million. We recorded a net gain

of $3.9 million on the transactions in the second quarter of 2003. During the third quarter of 2004, we sold our remaining interest in the original Rancho Pipeline system for a net gain of $0.4 million. These gains are included in the gains on sales of assets in our consolidated statements of income in the 2004 period.

On November 1, 2003, we purchased crude supply and transportation assets along the upper Texas Gulf Coast for $21.0 million from Genesis Crude Oil, L.P. and Genesis Pipeline Texas, L.P. (“Genesis”). The transaction was funded with proceeds from our August 2003 equity offering (see Note 11). We allocated the purchase price, net of liabilities assumed, primarily to property, plant and equipment and intangible assets. The assets acquired included approximately 150 miles of small diameter trunk lines, 26,000 barrels per day of throughput and 12,000 barrels per day of lease marketing and supply business. We have integrated these assets into our South Texas pipeline system, which has allowed us to consolidate gathering and marketing assets in key operating areas in a cost effective manner and will provide future growth opportunities. Accordingly, the results of the acquisition are included in the consolidated financial statements from November 1, 2003.

The following table allocates the estimated fair value of the Genesis assets acquired on November 1, 2003 (in thousands):

On March 31, 2005, we purchased crude oil pipeline assets for $7.1 million from BP Pipelines (North America) Inc. (“BP”). The assets include approximately 158 miles of pipeline, which extend from Mexia, Texas, to the Houston, Texas, area and two stations in south Houston with connections to a BP pipeline that originates in south Houston. We funded the purchase through borrowings under our revolving credit facility. We allocated the purchase price to property, plant and equipment, and we accounted for the acquisition of these assets under the purchase method of accounting. We have integrated these assets into our South Texas pipeline system, included in our Upstream Segment, which will allow us to realize synergies within our existing asset base and will provide future growth opportunities.

On April 1, 2005, we purchased crude oil storage and terminaling assets in Cushing, Oklahoma, from Koch Supply & Trading, L.P. for $35.4 million. The assets consist of eight storage tanks with 945,000 barrels of storage capacity, receipt and delivery manifolds, interconnections to several pipelines, crude oil inventory and approximately 70 acres of land. We funded the purchase through borrowings under our revolving credit facility. We allocated the purchase price to property, plant and equipment and inventory, and we accounted for the acquisition of these assets under the purchase method of accounting. The storage and terminaling assets complement our existing infrastructure in Cushing and strengthen our gathering and marketing business in our Upstream Segment.

On July 12, 2005, we purchased a refined products terminal and truck loading rack in North Little Rock, Arkansas, for $6.9 million from ExxonMobil Corporation. The assets include three storage tanks and a two-bay truck loading rack. We funded the purchase through borrowings under our revolving credit facility. We allocated the purchase price to property, plant and equipment and inventory, and we accounted for the acquisition of these assets under the purchase method of accounting. The terminal serves the central Arkansas refined products market and complements our existing Downstream Segment infrastructure in North Little Rock, Arkansas.

On July 15, 2005, we acquired from Texas Genco, LLC (“Genco”) all of its interests in certain companies that own a 90-mile pipeline system and 5.5 million barrels of storage capacity for $62.1 million. We funded the purchase through borrowings under our revolving credit facility. We allocated the purchase price to property, plant and equipment, and we accounted for the acquisition of these assets under the purchase method of accounting. The assets of the purchased companies will be integrated into our Downstream Segment ori -

gin infrastructure in Texas City and Baytown, Texas. As a result of this acquisition, we initiated the expansion of refined products origin capabilities in the Houston and Texas City, Texas, areas. The integration and other system enhancements should be in service by the fourth quarter of 2006, at an estimated cost of $45.0 million. The strategic location of these assets, with refined products interconnections to major exchange terminals in the Houston area, will provide significant long-term value to our customers and our Texas Gulf Coast refining and logistics system.

On January 26, 2006, we announced the execution of a letter of intent to sell our ownership interest in the Pioneer silica gel natural gas processing plant located near Opal, Wyoming, together with Jonah’s rights to process natural gas originating from the Jonah and Pinedale fields, located in southwest Wyoming, to an affiliate of Enterprise Products Partners L.P. (“Enterprise”). On March 31, 2006, we sold the Pioneer plant to an affiliate of Enterprise for $38.0 million in cash. The Pioneer plant, included in our Midstream Segment, was not an integral part of our operations and natural gas processing is not a core business. The Pioneer plant was constructed as part of the Phase III expansion of the Jonah system and was completed during the first quarter of 2004. We have no continuing involvement in the operations or results of this plant. This transaction was reviewed and approved by the Audit and Conflicts Committee of the board of directors of our General Partner and of the general partner of Enterprise, and a fairness opinion was rendered by an independent third-party.

Condensed statements of income for the Pioneer plant, which is classified as discontinued operations, for the years ended December 31, 2005 and 2004, are presented below (in thousands):

Assets of the discontinued operations consisted of the following at December 31, 2005 and 2004 (in thousands):

Net cash flows from discontinued operations for the years ended December 31, 2005 and 2004, are presented below (in thousands):

Through one of our indirect wholly owned subsidiaries, we own a 50% ownership interest in Seaway. The remaining 50% interest is owned by ConocoPhillips. We operate the Seaway assets. Seaway owns a pipeline that carries mostly imported crude oil from a marine terminal at Freeport, Texas, to Cushing, Oklahoma, and from a marine terminal at Texas City, Texas, to refineries in the Texas City and Houston, Texas, areas. The Seaway Crude Pipeline Company Partnership Agreement provides for varying participation ratios throughout the life of Seaway. From June 2002 through May 2006, we receive 60% of revenue and expense of Seaway. Thereafter, we will receive 40% of revenue and expense of Seaway. During the years ended December 31, 2005, 2004 and 2003, we received distributions from Seaway of $24.7 million, $36.9 million and $22.7 million, respectively.

In August 2000, TE Products entered into agreements with Panhandle Eastern Pipeline Company (“PEPL”), a former subsidiary of CMS Energy Corporation, and Marathon Petroleum Company LLC (“Marathon”) to form Centennial. Centennial owns an interstate refined petroleum products pipeline extending from the upper Texas Gulf Coast to central Illinois. Through February 9, 2003, each participant owned a one-third interest in Centennial. On February 10, 2003, TE Products and Marathon each acquired an additional 16.7% interest in Centennial from PEPL for $20.0 million each, increasing their ownership percentages in Centennial to 50% each. During the year ended December 31, 2005, TE Products did not make any additional investments in Centennial. TE Products invested an additional $1.5 million and $24.0 million, respectively, in Centennial, in 2004 and 2003, which is included in the equity investment balance at December 31, 2005. The 2003 amount includes the $20.0 million paid for the acquisition of the additional ownership interest in Centennial. TE Products has not received any distributions from Centennial since its formation.

On January 1, 2003, TE Products and Louis Dreyfus Energy Services L.P. (“Louis Dreyfus”) formed Mont Belvieu Storage Partners, L.P. (“MB Storage”). TE Products and Louis Dreyfus each own a 50% ownership interest in MB Storage. MB Storage owns storage capacity at the Mont Belvieu fractionation and storage complex and a short haul transportation shuttle system that ties Mont Belvieu, Texas, to the upper Texas Gulf Coast energy marketplace. MB Storage is a service-oriented, fee-based venture serving the fractionation, refining and petrochemical industries with substantial capacity and flexibility for the transportation, terminaling and storage of NGLs, LPGs and refined products. MB Storage has no commodity trading activity. TE Products operates the facilities for MB Storage. Effective January 1, 2003, TE Products contributed property and equipment with a net book value of $67.1 million to MB Storage. Additionally, as of the contribution date, Louis Dreyfus had invested $6.1 million for expansion projects for MB Storage that TE Products was required to reimburse if the original joint development and marketing agreement was terminated by either party. This deferred liability was also contributed and credited to the capital account of Louis Dreyfus in MB Storage.

For the year ended December 31, 2005, TE Products received the first $1.7 million per quarter (or $6.78 million on an annual basis) of MB Storage’s income before depreciation expense, as defined in the operating agreement. For the year ended December 31, 2004, TE Products received the first $1.8 million per quarter (or $7.15 million on an annual basis) of MB Storage’s income before depreciation expense. TE Products’ share of MB Storage’s earnings is adjusted annually by the partners of MB Storage. Any amount of MB Storage’s annual income before depreciation expense in excess of $6.78 million for 2005 and $7.15 million for 2004 was allocated evenly between TE Products and Louis Dreyfus. Depreciation expense on assets each party originally contributed to MB Storage is allocated between TE Products and Louis Dreyfus based on the net book value of the assets contributed. Depreciation expense on assets constructed or acquired by MB Storage subsequent to formation is allocated evenly between TE Products and Louis Dreyfus. For the years ended December 31, 2005, 2004 and 2003, TE Products’ sharing ratio in the earnings of MB Storage was 64.2%, 69.4% and 70.4%, respectively. During the years ended December 31, 2005, 2004 and 2003, TE Products received distributions of $12.4 million, $10.3 million and $5.3 million, respectively, from MB Storage. During the years ended December 31, 2005, 2004 and 2003, TE Products contributed $5.6 million, $21.4 million and $2.5 million, respectively, to MB Storage. The 2005 contribution includes a combination of non-cash asset transfers of $1.4 million and cash contributions of $4.2 million. The 2004 contribution includes $16.5 million for the acquisition of storage and pipeline assets in April 2004. The remaining contributions have been for capital expenditures.

We use the equity method of accounting to account for our investments in Seaway, Centennial and MB Storage. Summarized combined financial information for Seaway, Centennial and MB Storage for the years ended December 31, 2005 and 2004, is presented below (in thousands):

Summarized combined balance sheet information for Seaway, Centennial and MB Storage as of December 31, 2005 and 2004, is presented below (in thousands):

The Partnership does not have any employees. We are managed by the Company, which, for all periods prior to February 23, 2005, was an indirect wholly owned subsidiary of DEFS. According to the Partnership Agreement, the Company was entitled to reimbursement of all direct and indirect expenses related to our business activities. As a result of the change in ownership of the General Partner on February 24, 2005, all of our management, administrative and operating functions are performed by employees of EPCO, pursuant to an administrative services agreement. We reimburse EPCO for the costs of its employees who perform operating functions for us and for costs related to its other management and administrative employees (see Note 1).

The following table summarizes the related party transactions with EPCO and affiliates and DEFS and affiliates for the periods indicated (in millions):

At December 31, 2005, we had a receivable from EPCO and affiliates of $4.3 million related to sales and transportation services provided to EPCO and affiliates. At December 31, 2005, we had a payable to EPCO and affiliates of $9.8 million related to direct payroll, payroll related costs and other operational related charges.

At December 31, 2004, we had a receivable from DEFS and affiliates of $10.5 million related to sales and transportation services provided to DEFS and affiliates. Included in this receivable balance from DEFS and affiliates at December 31, 2004, is a gas imbalance receivable of $0.9 million. At December 31, 2004, we had a payable to DEFS and affiliates of $22.4 million related to direct payroll, payroll related costs, management fees, and other operational related charges, including those for Jonah, Chaparral and Val Verde as described above. Included in this payable balance at December 31, 2004, is a gas imbalance payable to DEFS and affiliates of $3.2 million.

From February 24, 2005 through December 31, 2005, the majority of our insurance coverage, including property, liability, business interruption, auto and directors and officers’ liability insurance, was obtained through EPCO. From February 24, 2005 through December 31, 2005, we incurred insurance expense related to premiums charged by EPCO of $9.8 million. At December 31, 2005, we had insurance reimbursement receivables due from EPCO of $1.3 million.

Through February 23, 2005, we contracted with Bison Insurance Company Limited (“Bison”), a wholly owned subsidiary of Duke Energy, for a majority of our insurance coverage, including property, liability, auto and directors and officers’ liability insurance. Through February 23, 2005 and for the years ended December 31, 2004 and 2003, we incurred insurance expense related to premiums paid to Bison of $1.2 million, $6.5 million and $5.9 million, respectively. At December 31, 2004, we had insurance reimbursement receivables due from Bison of $5.2 million.

On April 2, 2003, we sold in an underwritten public offering 3.9 million Units at $30.35 per Unit. The proceeds from the offering, net of underwriting discount, totaled approximately $114.5 million, of which approximately $113.8 million was used to repurchase and retire all of the 3.9 million previously outstanding Class B Units held by DETTCO (see Note 11).

We own a 50% ownership interest in Seaway, and the remaining 50% interest is owned by ConocoPhillips (see Note 6). We operate the Seaway assets. During the years ended December 31, 2005, 2004 and 2003, we billed Seaway $8.5 million, $7.6 million and $7.4 million, respectively, for direct payroll and payroll related expenses for operating Seaway. Additionally, for each of the years ended December 31, 2005, 2004 and 2003, we billed Seaway $2.1 million for indirect management fees for operating Seaway. At December 31, 2005 and 2004, we had payable balances to Seaway of $0.6 million and $0.5 million, respectively, for advances Seaway paid to us as operator for operating costs, including payroll and related expenses and management fees.

TE Products has a 50% ownership interest in Centennial (see Note 6). TE Products has entered into a management agreement with Centennial to operate Centennial’s terminal at Creal Springs, Illinois, and pipeline connection in Beaumont, Texas. For each of the years ended December 31, 2005, 2004 and 2003, we recognized management fees of $0.2 million from Centennial, and actual operating expenses billed to Centennial were $3.7 million, $6.9 million and $4.4 million, respectively.

TE Products also has a joint tariff with Centennial to deliver products at TE Products’ locations using Centennial’s pipeline as part of the delivery route to connecting carriers. TE Products, as the delivering pipeline, invoices the shippers for the entire delivery rate, records only the net rate attributable to it as transportation revenues and records a liability for the amounts due to Centennial for its share of the tariff. In addition, TE Products performs ongoing construction services for Centennial and bills Centennial for labor and other costs to perform the construction. At December 31, 2005 and 2004, we had net payable balances of $1.4 million and $1.7 million, respectively, to Centennial for its share of the joint tariff deliveries and other operational related charges, partially offset by the reimbursement due to us for construction services provided to Centennial.

In January 2003, TE Products entered into a pipeline capacity lease agreement with Centennial for a period of five years that contains a minimum throughput requirement. For the years ended December 31, 2005, 2004 and 2003, TE Products incurred $5.9 million, $5.3 million and $3.8 million, respectively, of rental charges related to the lease of pipeline capacity on Centennial.

Effective January 1, 2003, TE Products entered into agreements with Louis Dreyfus to form MB Storage (see Note 6). TE Products operates the facilities for MB Storage. TE Products and MB Storage have entered into a pipeline capacity lease agreement, and for each of the years ended December 31, 2005, 2004 and 2003, TE Products recognized $0.1 million in rental revenue related to this lease agreement. During the years ended December 31, 2005, 2004 and 2003, TE Products also billed MB Storage $3.6 million, $3.2 million and $2.5 million, respectively, for direct payroll and payroll related expenses for operating MB Storage. At December 31, 2005 and 2004, TE Products had net receivable balances from MB Storage of $0.9 million and $1.3 million, respectively, for operating costs, including payroll and related expenses for operating MB Storage.

Inventories are valued at the lower of cost (based on weighted average cost method) or market. The costs of inventories did not exceed market values at December 31, 2005 and 2004. The major components of inventories were as follows (in thousands):

Major categories of property, plant and equipment for the years ended December 31, 2005 and 2004, were as follows (in thousands):

Depreciation expense, including impairment charges, on property, plant and equipment was $80.8 million, $80.7 million and $64.5 million for the years ended December 31, 2005, 2004 and 2003, respectively. During the fourth quarter of 2004, we wrote off approximately $2.1 million in assets taken out of service to depreciation expense.

In September 2005, our Todhunter facility, near Middletown, Ohio, experienced a propane release and fire at a dehydration unit within the storage facility. The facility is included in our Downstream Segment. The dehydration unit was destroyed due to the propane release and fire, and as a result, we wrote off the remaining book value of the asset of $0.8 million to depreciation and amortization expense during the third quarter of 2005.

We evaluate impairment of long-lived assets in accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. During the third quarter of 2005, our Upstream Segment was notified by a connecting carrier that the flow of its pipeline system would be reversed, which would directly impact the viability of one of our pipeline systems. This system, located in East Texas, consists of approximately 45 miles of pipeline, six tanks of various sizes and other equipment and asset costs. As a result of changes to the connecting carrier, we performed an impairment test of the system and recorded a $1.8 million non-cash impairment charge,

included in depreciation and amortization expense in our consolidated statements of income, for the excess carrying value over the estimated fair value of the system.

During the third quarter of 2005, we completed an evaluation of a crude oil system included in our Upstream Segment. The system, located in Oklahoma, consists of approximately six miles of pipelines, tanks and other equipment and asset costs. The usage of the system has declined in recent months as a result of shifting crude oil production into areas not supported by the system, and as such, it has become more economical to transport barrels by truck to our other pipeline systems. As a result, we performed an impairment test on the system and recorded a $0.8 million non-cash impairment charge, included in depreciation and amortization expense in our consolidated statements of income, for the excess carrying value over the estimated fair value of the system.

During the third quarter of 2004, we completed an evaluation of our marine terminal facility in the Beaumont, Texas, area. The facility consists primarily of a barge dock, a ship dock, four storage tanks and various segments of connecting pipelines and is included in our Downstream Segment. The evaluation indicated that the docks and other assets at the facility needed extensive work to continue to be commercially operational. As a result, we performed an impairment test on the entire marine facility and recorded a $4.4 million non-cash impairment charge, included in depreciation and amortization expense in our consolidated statements of income, for the excess carrying value over the estimated fair value of the facility.

Senior Notes. On January 27, 1998, TE Products completed the issuance of $180.0 million principal amount of 6.45% Senior Notes due 2008, and $210.0 million principal amount of 7.51% Senior Notes due 2028 (collectively the “TE Products Senior Notes”). The 6.45% TE Products Senior Notes were issued at a discount of $0.3 million and are being accreted to their face value over the term of the notes. The 6.45% TE Products Senior Notes due 2008 are not subject to redemption prior to January 15, 2008. The 7.51% TE Products Senior Notes due 2028, issued at par, may be redeemed at any time after January 15, 2008, at the option of TE Products, in whole or in part, at our election at the following redemption prices (expressed in percentages of the principal amount) if redeemed during the twelve months beginning January 15 of the years indicated:

and thereafter at 100% of the principal amount, together in each case with accrued interest at the redemption date.

The TE Products Senior Notes do not have sinking fund requirements. Interest on the TE Products Senior Notes is payable semiannually in arrears on January 15 and July 15 of each year. The TE Products Senior Notes are unsecured obligations of TE Products and rank pari passu with all other unsecured and unsubordinated indebtedness of TE Products. The indenture governing the TE Products Senior Notes contains covenants, including, but not limited to, covenants limiting the creation of liens securing indebtedness and sale and leaseback transactions. However, the indenture does not limit our ability to incur additional indebtedness. As of December 31, 2005, TE Products was in compliance with the covenants of the TE Products Senior Notes.

On February 20, 2002, we completed the issuance of $500.0 million principal amount of 7.625% Senior Notes due 2012. The 7.625% Senior Notes were issued at a discount of $2.2 million and are being accreted to their face value over the term of the notes. The Senior Notes may be redeemed at any time at our option with the payment of accrued interest and a make-whole premium determined by discounting remaining interest and principal payments using a discount rate equal to the rate of the United States Treasury securities of comparable remaining maturity plus 35 basis points. The indenture governing our 7.625% Senior Notes contains covenants, including, but not limited to, covenants limiting the creation of liens securing indebtedness and sale and leaseback transactions. However, the indenture does not limit our ability to incur additional indebtedness. As of December 31, 2005, we were in compliance with the covenants of these Senior Notes.

On January 30, 2003, we completed the issuance of $200.0 million principal amount of 6.125% Senior Notes due 2013. The 6.125% Senior Notes were issued at a discount of $1.4 million and are being accreted to their face value over the term of the notes. The Senior Notes may be redeemed at any time at our option with the payment of accrued interest and a make-whole premium determined by discounting remaining interest and principal payments using a discount rate equal to the rate of the United States Treasury securities of

comparable remaining maturity plus 35 basis points. The indenture governing our 6.125% Senior Notes contains covenants, including, but not limited to, covenants limiting the creation of liens securing indebtedness and sale and leaseback transactions. However, the indenture does not limit our ability to incur additional indebtedness. As of December 31, 2005, we were in compliance with the covenants of these Senior Notes.

The following table summarizes the estimated fair values of the Senior Notes as of December 31, 2005 and 2004 (in millions):

We have entered into interest rate swap agreements to hedge our exposure to changes in the fair value on a portion of the Senior Notes discussed above (see Note 4).

Revolving Credit Facility. On April 6, 2001, we entered into a $500.0 million revolving credit facility including the issuance of letters of credit of up to $20.0 million (“Three Year Facility”). The interest rate was based, at our option, on either the lender’s base rate plus a spread, or LIBOR plus a spread in effect at the time of the borrowings. The credit agreement for the Three Year Facility contained certain restrictive financial covenant ratios. During the first quarter of 2003, we repaid $182.0 million of the outstanding balance of the Three Year Facility with proceeds from the issuance of our 6.125% Senior Notes on January 30, 2003. On June 27, 2003, we repaid the outstanding balance under the Three Year Facility with borrowings under a new credit facility, and canceled the Three Year Facility.

On June 27, 2003, we entered into a $550.0 million unsecured revolving credit facility with a three year term, including the issuance of letters of credit of up to $20.0 million (“Revolving Credit Facility”). The interest rate is based, at our option, on either the lender’s base rate plus a spread, or LIBOR plus a spread in effect at the time of the borrowings. The credit agreement for the Revolving Credit Facility contains certain restrictive financial covenant ratios. Restrictive covenants in the Revolving Credit Facility limit our ability to, among other things, incur additional indebtedness, make distributions in excess of Available Cash (see Note 11) and complete mergers, acquisitions and sales of assets. We borrowed $263.0 million under the Revolving Credit Facility and repaid the outstanding balance of the Three Year Facility. On October 21, 2004, we amended our Revolving Credit Facility to (i) increase the facility size to $600.0 million, (ii) extend the term to October 21, 2009, (iii) remove certain restrictive covenants, (iv) increase the available amount for the issuance of letters of credit up to $100.0 million and (v) decrease the LIBOR rate spread charged at the time of each borrowing. On February 23, 2005, we amended our Revolving Credit Facility to remove the requirement that DEFS must at all times own, directly or indirectly, 100% of our General Partner, to allow for its acquisition by DFI (see Note 1). During the second quarter of 2005, we used a portion of the proceeds from the equity offering in May 2005 to repay a portion of the Revolving Credit Facility (see Note 11). On December 13, 2005, we again amended our Revolving Credit Facility as follows:

On December 31, 2005, $405.9 million was outstanding under the Revolving Credit Facility at a weighted average interest rate of 4.9%. At December 31, 2005, we were in compliance with the covenants of this credit agreement.

The following table summarizes the principal amounts outstanding under all of our credit facilities as of December 31, 2005 and 2004 (in thousands):

Letter of Credit. At December 31, 2005, we had an $11.5 million standby letter of credit in connection with crude oil purchases in the fourth quarter of 2005. This amount will be paid during the first quarter of 2006.

On August 7, 2003, we sold in an underwritten public offering 5.0 million Units at $34.68 per Unit. The proceeds from the offering, net of underwriting discount, totaled approximately $166.0 million. On August 19, 2003, 162,900 Units were sold upon exercise of the underwriters’ over-allotment option granted in connection with the offering on August 7, 2003. Proceeds from the over-allotment sale, net of underwriting discount, totaled $5.4 million. Approximately $53.0 million of the proceeds were used to repay indebtedness under our revolving credit facility and $21.0 million was used to fund the acquisition of the Genesis assets (see Note 5). The remaining amount was used primarily to fund revenue-generating and system upgrade capital expenditures and for general partnership purposes.

On May 5, 2005, we sold in an underwritten public offering 6.1 million Units at $41.75 per Unit. The proceeds from the offering, net of underwriting discount, totaled approximately $244.5 million. On June 8, 2005, 865,000 Units were sold upon exercise of the underwriters’ over-allotment option granted in connection with the offering on May 5, 2005. Proceeds from the over-allotment sale, net of underwriting discount, totaled $34.7 million. The proceeds were used to reduce indebtedness under our Revolving Credit Facility, to fund revenue generating and system upgrade capital expenditures and for general partnership purposes.

We make quarterly cash distributions of all of our Available Cash, generally defined as consolidated cash receipts less consolidated cash disbursements and cash reserves established by the General Partner in its sole discretion. Pursuant to the Partnership Agreement, the General Partner receives incremental incentive cash distributions when unitholders’ cash distributions exceed certain target thresholds as follows:

The following table reflects the allocation of total distributions paid during the years ended December 31, 2005, 2004 and 2003 (in thousands, except per Unit amounts):

On February 7, 2006, we paid a cash distribution of $0.675 per Unit for the quarter ended December 31, 2005. The fourth quarter 2005 cash distribution totaled $66.9 million.

As of December 31, 2005 and 2004, we had deficit balances of $61.5 million and $35.9 million, respectively, in our General Partner’s equity account. These negative balances do not represent an asset to us and do not represent an obligation of the General Partner to contribute cash or other property to us. The General Partner’s equity account generally consists of its cumulative share of our net income less cash distributions made to it plus capital contributions that it has made to us (see our Consolidated Statements of Partners’ Capital for a detail of the General Partner’s equity account). For the years ended December 31, 2005, 2004 and 2003, the General Partner was allocated $47.6 million (representing 29.27%), $40.0 million (representing 28.85%) and $33.7 million (representing 27.65%), respectively, of our net income and received $73.2 million, $66.9 million and $54.7 million, respectively, in cash distributions.

Capital Accounts, as defined under our Partnership Agreement, are maintained for our General Partner and our limited partners. The Capital Account provisions of our Partnership Agreement incorporate principles established for U.S. federal income tax purposes and are not comparable to the equity accounts reflected under accounting principles generally accepted in the United States in our financial statements. Under our Partnership Agreement, the General Partner is required to make additional capital contributions to us upon the issuance of any additional Units if necessary to maintain a Capital Account balance equal to 1.999999% of the total Capital Accounts of all partners. At December 31, 2005 and 2004, the General Partner’s Capital Account balance substantially exceeded this requirement.

Net income is allocated between the General Partner and the limited partners in the same proportion as aggregate cash distributions made to the General Partner and the limited partners during the period. This is generally consistent with the manner of allocating net income under our Partnership Agreement. Net income determined under our Partnership Agreement, however, incorporates principles established for U.S. federal income tax purposes and is not comparable to net income reflected under accounting principles generally accepted in the United States in our financial statements.

Cash distributions that we make during a period may exceed our net income for the period. We make quarterly cash distributions of all of our Available Cash, generally defined as consolidated cash receipts less consolidated cash disbursements and cash reserves established by the General Partner in its sole discretion. Cash distributions in excess of net income allocations and capital contributions during the years ended December 31, 2005 and 2004, resulted in a deficit in the General Partner’s equity account at December 31, 2005 and 2004. Future cash distributions that exceed net income will result in an increase in the deficit balance in the General Partner’s equity account.

According to the Partnership Agreement, in the event of our dissolution, after satisfying our liabilities, our remaining assets would be divided among our limited partners and the General Partner generally in the same proportion as Available Cash but calculated on a cumulative basis over the life of the Partnership. If a deficit balance still remains in the General Partner’s equity account after all allocations are made between the partners, the General Partner would not be required to make whole any such deficit.

Our primary market areas are located in the Northeast, Midwest and Southwest regions of the United States. We have a concentration of trade receivable balances due from major integrated oil companies, independent oil companies and other pipelines and wholesalers. These concentrations of customers may affect our overall credit risk in that the customers may be similarly affected by changes in economic, regulatory or other factors. We thoroughly analyze our customers’ historical and future credit positions prior to extending

credit. We manage our exposure to credit risk through credit analysis, credit approvals, credit limits and monitoring procedures, and for certain transactions may utilize letters of credit, prepayments and guarantees.

For each of the years ended December 31, 2005, 2004 and 2003, Valero Energy Corp. accounted for 14%, 16% and 16% of our total consolidated revenues, respectively. No other single customer accounted for 10% or more of our total consolidated revenues for the years ended December 31, 2005, 2004 and 2003.

The carrying amount of cash and cash equivalents, accounts receivable, inventories, other current assets, accounts payable and accrued liabilities, other current liabilities and derivatives approximates their fair value due to their short-term nature.

During 1994, the Company adopted the Texas Eastern Products Pipeline Company 1994 Long Term Incentive Plan (“1994 LTIP”). The 1994 LTIP provides certain key employees with an incentive award whereby a participant is granted an option to purchase Units. These same employees are also granted a stipulated number of Performance Units, the cash value of which may be used to pay for the exercise of the respective Unit options awarded. Under the provisions of the 1994 LTIP, no more than one million options and two million Performance Units may be granted.

When our calendar year earnings per unit (exclusive of certain special items) exceeds a stated threshold, each participant receives a credit to their respective Performance Unit account equal to the earnings per unit excess multiplied by the number of Performance Units awarded. The balance in the Performance Unit account may be used to offset the cost of exercising Unit options granted in connection with the Performance Units or may be withdrawn two years after the underlying options expire, usually 10 years from the date of grant. Any unused balance previously credited is forfeited upon termination. We accrue compensation expense for the Performance Units awarded annually based upon the terms of the plan discussed above.

Under the agreement for such Unit options, the options become exercisable in equal installments over periods of one, two, and three years from the date of the grant. At December 31, 2005, all options have been fully exercised. The Performance Unit account has a minimal liability balance which may be withdrawn by the participants after December 31, 2006.

A summary of Unit options granted under the terms of the 1994 LTIP is presented below:

We have not granted options for any periods presented. During the year ended December 31, 2003, all remaining outstanding Unit options were exercised. For options previously outstanding, we followed the intrinsic value method for recognizing stock-based compensation expense. The exercise price of all options awarded under the 1994 LTIP equaled the market price of our Units on the date of grant. Accordingly, we recognized no compensation expense at the date of grant. Had compensation expense been determined consistent with SFAS No. 123, Accounting for Stock-Based Compensation, no compensation expense would have been recognized for the years ended December 31, 2005, 2004 and 2003.

Effective September 1, 1999, the Company adopted the Texas Eastern Products Pipeline Company, LLC 1999 Phantom Unit Retention Plan (“1999 PURP”). Effective June 1, 2002, the Company adopted the Texas Eastern Products Pipeline Company, LLC 2002 Phantom Unit Retention Plan (“2002 PURP”). The 1999 PURP and the 2002 PURP provide key employees with incentive awards whereby a participant is granted phantom units. These phantom units are automatically redeemed for cash based on the vested portion of the fair market value of the phantom units at stated redemption dates. The fair market value of each phantom unit is equal to the closing price of a Unit as reported on the New York Stock Exchange on the redemption date.

Under the agreement for the phantom units, each participant will vest 10% of the number of phantom units initially granted under his or her award at the end of each of the first four years and will vest the final 60% at the end of the fifth year. Each participant is required to redeem their phantom units as they vest. They are also entitled to quarterly cash distributions equal to the product of the number of phantom units outstanding for the participant and the amount of the cash distribution that we paid per Unit to unitholders. We accrued

compensation expense annually based upon the terms of the 1999 PURP and 2002 PURP discussed above. At December 31, 2004, we had an accrued liability balance of $1.6 million for compensation related to the 1999 PURP and 2002 PURP. Due to a change of ownership as a result of the sale of our General Partner on February 24, 2005 (see Note 1), all outstanding units under both the 1999 PURP and the 2002 PURP fully vested and were redeemed by participants. As such, there were no outstanding units at December 31, 2005 under either the 1999 PURP or the 2002 PURP.

Effective January 1, 2000, the General Partner established the Texas Eastern Products Pipeline Company, LLC 2000 Long Term Incentive Plan (“2000 LTIP”) to provide key employees incentives to achieve improvements in our financial performance. Generally, upon the close of a three-year performance period, if the participant is then still an employee of the General Partner, the participant will receive a cash payment in an amount equal to (1) the applicable performance percentage specified in the award multiplied by (2) the number of phantom units granted under the award multiplied by (3) the average of the closing prices of a Unit over the ten consecutive trading days immediately preceding the last day of the performance period. Generally, a participant’s performance percentage is based upon the improvement of our Economic Value Added (as defined below) during a three-year performance period over the Economic Value Added during the three-year period immediately preceding the performance period. If a participant incurs a separation from service during the performance period due to death, disability or retirement (as such terms are defined in the 2000 LTIP), the participant will be entitled to receive a cash payment in an amount equal to the amount computed as described above multiplied by a fraction, the numerator of which is the number of days that have elapsed during the performance period prior to the participant’s separation from service and the denominator of which is the number of days in the performance period. Due to a change of ownership as a result of the sale of our General Partner on February 24, 2005, all outstanding units under the 2000 LTIP for plan years 2003 and 2004 were fully vested and redeemed by participants. As such, there were no outstanding units at December 31, 2005, for awards granted for the plan years ended December 31, 2004 and 2003. At December 31, 2005, phantom units outstanding for awards granted for the plan year ended December 31, 2005, were 23,400.

Economic Value Added means our average annual EBITDA for the performance period minus the product of our average asset base and our cost of capital for the performance period. For purposes of the 2000 LTIP for plan years 2000 through 2002, EBITDA means our earnings before net interest expense, depreciation and amortization and our proportional interest in EBITDA of our joint ventures as presented in our consolidated financial statements prepared in accordance with generally accepted accounting principles, except that at his discretion the Chief Executive Officer (“CEO”) of the Company may exclude gains or losses from extraordinary, unusual or non-recurring items. For the years ended December 31, 2005, 2004 and 2003, EBITDA means, in addition to the above definition of EBITDA, earnings before other income – net. Average asset base means the quarterly average, during the performance period, of our gross value of property, plant and equipment, plus products and crude oil operating oil supply and the gross value of intangibles and equity investments. Our cost of capital is approved by our CEO at the date of award grant.

In addition to the payment described above, during the performance period, the General Partner will pay to the participant the amount of cash distributions that we would have paid to our unitholders had the participant been the owner of the number of Units equal to the number of phantom units granted to the participant under this award. We accrue compensation expense annually based upon the terms of the 2000 LTIP discussed above. At December 31, 2005 and 2004, we had an accrued liability balance of $0.7 million and $2.4 million, respectively, for compensation related to the 2000 LTIP.

Effective January 1, 2005, the Company adopted the Texas Eastern Products Pipeline Company, LLC 2005 Phantom Unit Plan (“2005 PURP”) to provide key employees incentives to achieve improvements in our financial performance. Generally, upon the close of a three-year performance period, if the participant is then still an employee of the General Partner, the participant will receive a cash payment in an amount equal to (1) the grantee’s vested percentage multiplied by (2) the number of phantom units granted under the award multiplied by (3) the average of the closing prices of a Unit over the ten consecutive trading days immediately preceding the last day of the performance period. Generally, a participant’s vested percentage is based upon the improvement of our EBITDA (as defined below) during a three-year performance period over the target EBITDA as defined at the beginning of each year during the three-year performance period. EBITDA means our earnings before minority interest, net interest expense, other income – net, income taxes, depreciation and amortization and our proportional interest in EBITDA of our joint ventures as presented in our consolidated financial statements prepared in accordance with generally accepted accounting principles, except that at his discretion, our CEO may exclude gains or losses from extraordinary, unusual or non-recurring items. At December 31, 2005, phantom units outstanding for awards granted for the plan year ended December 31, 2005, were 53,600.

In addition to the payment described above, during the performance period, the General Partner will pay to the participant the amount of cash distributions that we would have paid to our unitholders had the participant been the owner of the number of Units equal to the number of phantom units granted to the participant under this award. We accrue compensation expense annually based upon the terms of the 2005 PURP discussed above. At December 31, 2005, we had an accrued liability balance of $0.7 million for compensation related to the 2005 PURP.

We use leased assets in several areas of our operations. Total rental expense for the years ended December 31, 2005, 2004 and 2003, was $24.0 million, $22.1 million and $18.8 million, respectively. The following table sets forth our minimum rental payments under our various operating leases for the years ending December 31 (in thousands):

The TEPPCO Retirement Cash Balance Plan (“TEPPCO RCBP”) was a non-contributory, trustee-administered pension plan. In addition, the TEPPCO Supplemental Benefit Plan (“TEPPCO SBP”) was a non-contributory, nonqualified, defined benefit retirement plan, in which certain executive officers participated. The TEPPCO SBP was established to restore benefit reductions caused by the maximum benefit limitations that apply to qualified plans. The benefit formula for all eligible employees was a cash balance formula. Under a cash balance formula, a plan participant accumulated a retirement benefit based upon pay credits and current interest credits. The pay credits were based on a participant’s salary, age and service. We used a December 31 measurement date for these plans.

On May 27, 2005, the TEPPCO RCBP and the TEPPCO SBP were amended. Effective May 31, 2005, participation in the TEPPCO RCBP was frozen, and no new participants were eligible to be covered by the plan after that date. Effective December 31, 2005, all plan benefits accrued were frozen, participants will not receive additional pay credits after that date, and all plan participants were 100% vested regardless of their years of service. The TEPPCO RCBP plan was terminated effective December 31, 2005, subject to IRS approval of plan termination, and plan participants will have the option to receive their benefits either through a lump sum payment in 2006 or through an annuity. For those plan participants who elect to receive an annuity, we will purchase an annuity contract from an insurance company in which the plan participant owns the annuity, absolving us of any future obligation to the participant. Participants in the TEPPCO SBP received pay credits through November 30, 2005, and received lump sum benefit payments in December 2005. Both the RCBP and SBP benefit payments are discussed below.

In June 2005, we recorded a curtailment charge of $0.1 million in accordance with SFAS No. 88, Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits, as a result of the TEPPCO RCBP and TEPPCO SBP amendments. As of May 31, 2005, the following assumptions were changed for purposes of determining the net periodic benefit costs for the remainder of 2005: the discount rate, the long-term rate of return on plan assets, and the assumed mortality table. The discount rate was decreased from 5.75% to 5.00% to reflect rates of returns on bonds currently available to settle the liability. The expected long-term rate of return on plan assets was changed from 8% to 2% due to the movement of plan funds from equity investments into short-term money market funds. The mortality table was changed to reflect overall improvements in mortality experienced by the general population. The curtailment charge arose due to the accelerated recognition of the unrecognized prior service costs. We recorded additional settlement charges of approximately $0.2 million in the fourth quarter of 2005 relating to the TEPPCO SBP. We expect to record additional settlement charges of approximately $4.0 million in 2006 relating to the TEPPCO RCBP for any existing unrecognized losses upon the plan termination and final distribution of the assets to the plan participants.

The components of net pension benefits costs for the TEPPCO RCBP and the TEPPCO SBP for the years ended December 31, 2005, 2004 and 2003, were as follows (in thousands):

We provided certain health care and life insurance benefits for retired employees on a contributory and non-contributory basis (“TEPPCO OPB”). Employees became eligible for these benefits if they met certain age and service requirements at retirement, as defined in the plans. We provided a fixed dollar contribution, which did not increase from year to year, towards retired employee medical costs. The retiree paid all health care cost increases due to medical inflation. We used a December 31 measurement date for this plan.

In May 2005, benefits provided to employees under the TEPPCO OPB were changed. Employees eligible for these benefits received them through December 31, 2005, however, effective December 31, 2005, these benefits were terminated. As a result of this change in benefits and in accordance with SFAS No. 106, Employers’ Accounting for Postretirement Benefits Other Than Pensions, we recorded a curtailment credit of approximately $1.7 million in our accumulated postretirement obligation which reduced our accumulated postretirement obligation to the total of the expected remaining 2005 payments under the TEPPCO OPB. The current employees participating in this plan were transferred to DEFS, who will continue to provide postretirement benefits to these retirees. We recorded a one-time settlement to DEFS in the third quarter of 2005 of $0.4 million for the remaining postretirement benefits.

The components of net postretirement benefits cost for the TEPPCO OPB for the years ended December 31, 2005, 2004 and 2003, were as follows (in thousands):

Effective June 1, 2005, the payroll functions performed by DEFS for our General Partner were transferred from DEFS to EPCO. For those employees who were receiving certain other postretirement benefits at the time of the acquisition of our General Partner by DFI, DEFS will continue to provide these benefits to those employees. Effective June 1, 2005, EPCO began providing certain other postretirement benefits to those employees who became eligible for the benefits after June 1, 2005, and will charge those benefit related costs to us. As a result of these changes, we recorded a $1.2 million reduction in our other postretirement obligation in June 2005.

We employed a building block approach in determining the long-term rate of return for plan assets. Historical markets were studied and long-term historical relationships between equities and fixed-income were preserved consistent with a widely accepted capital market principle that assets with higher volatility generate a greater return over the long run. Current market factors such as inflation and interest rates were evaluated before long-term capital market assumptions were determined. The long-term portfolio return was established via a building block approach with proper consideration of diversification and rebalancing. Peer data and historical returns were reviewed to check for reasonability and appropriateness.

The weighted average assumptions used to determine benefit obligations for the retirement plans and other postretirement benefit plans at December 31, 2005 and 2004, were as follows:

The weighted average assumptions used to determine net periodic benefit cost for the retirement plans and other postretirement benefit plans for the years ended December 31, 2005 and 2004, were as follows:

The following table sets forth our pension and other postretirement benefits changes in benefit obligation, fair value of plan assets and funded status as of December 31, 2005 and 2004 (in thousands):

We estimate the following benefit payments, which reflect expected future service, as appropriate, will be paid (in thousands):

We employed a total return investment approach whereby a mix of equities and fixed income investments were used to maximize the long-term return of plan assets for a prudent level of risk. Risk tolerance was established through careful consideration of plan liabilities, plan funded status and corporate financial condition. The investment portfolio contained a diversified blend of equity and fixed-income investments. Furthermore, equity investments were diversified across U.S. and non-U.S. stocks, both growth and value equity style, and small, mid and large capitalizations. Investment risk and return parameters were reviewed and evaluated periodically to ensure compliance with stated investment objectives and guidelines. This comprehensive review incorporated investment portfolio performance, annual liability measurements and periodic asset/liability studies.

The following table sets forth the weighted average asset allocations for the retirement plans and other postretirement benefit plans as of December 31, 2005 and 2004, by asset category (in thousands):

We do not expect to make further contributions to our retirement plans and other postretirement benefit plans in 2006.

DEFS also sponsored an employee savings plan, which covered substantially all employees. Effective February 24, 2005, in conjunction with the change in ownership of our General Partner, our participation in this plan ended. Plan contributions on behalf of the Company of $0.9 million, $3.5 million and $3.2 million were recognized for the period January 1, 2005 through February 23, 2005, and during the years ended December 31, 2004 and 2003, respectively.

In the fall of 1999 and on December 1, 2000, the General Partner and the Partnership were named as defendants in two separate lawsuits in Jackson County Circuit Court, Jackson County, Indiana, styled Ryan E. McCleery and Marcia S. McCleery, et al. v. Texas Eastern Corporation, et al. (including the General Partner and Partnership) and Gilbert Richards and Jean Richards v. Texas Eastern Corporation, et al. (including the General Partner and Partnership). In both cases, the plaintiffs contend, among other things, that we and other defendants stored and disposed of toxic and hazardous substances and hazardous wastes in a manner that caused the materials to be released into the air, soil and water. They further contend that the release caused damages to the plaintiffs. In their complaints, the plaintiffs allege strict liability for both personal injury and property damage together with gross negligence, continuing nuisance, trespass, criminal mischief and loss of consortium. The plaintiffs are seeking compensatory, punitive and treble damages. On January 27, 2005, we entered into Release and Settlement Agreements with the McCleery plaintiffs and the Richards plaintiffs dismissing all of these plaintiffs’ claims on terms that did not have a material adverse effect on our financial position, results of operations or cash flows. Although we did not settle with all plaintiffs and we therefore remain named parties in the Ryan E. McCleery and Marcia S. McCleery, et al. v. Texas Eastern Corporation, et al. action, a co-defendant has agreed to indemnify us for all remaining claims asserted against us. Consequently, we do not believe that the outcome of these remaining claims will have a material adverse effect on our financial position, results of operations or cash flows.

On December 21, 2001, TE Products was named as a defendant in a lawsuit in the 10th Judicial District, Natchitoches Parish, Louisiana, styled Rebecca L. Grisham et al. v. TE Products Pipeline Company, Limited Partnership. In this case, the plaintiffs contend that our pipeline, which crosses the plaintiffs’ property, leaked toxic products onto their property and, consequently caused damages to them. We have filed an answer to the plaintiffs’ petition denying the allegations, and we are defending ourselves vigorously against the lawsuit. The

plaintiffs have not stipulated the amount of damages they are seeking in the suit; however, this case is covered by insurance. We do not believe that the outcome of this lawsuit will have a material adverse effect on our financial position, results of operations or cash flows.

On April 2, 2003, Centennial was served with a petition in a matter styled Adams, et al. v. Centennial Pipeline Company LLC, et al. This matter involves approximately 2,000 plaintiffs who allege that over 200 defendants, including Centennial, generated, transported, and/or disposed of hazardous and toxic waste at two sites in Bayou Sorrell, Louisiana, an underground injection well and a landfill. The plaintiffs allege personal injuries, allergies, birth defects, cancer and death. The underground injection well has been in operation since May 1976. Based upon current information, Centennial appears to be a de minimis contributor, having used the disposal site during the two month time period of December 2001 to January 2002. Marathon has been handling this matter for Centennial under its operating agreement with Centennial. TE Products has a 50% ownership interest in Centennial. On November 30, 2004, the court approved a class settlement. The time period for parties to appeal this settlement expired in March 2005, and the class settlement became final. The terms of the settlement did not have a material adverse effect on our financial position, results of operations or cash flows.

In May 2003, the General Partner was named as a defendant in a lawsuit styled John R. James, et al. v. J Graves Insulation Company, et al. as filed in the first Judicial District Court, Caddo Parish, Louisiana. There are numerous plaintiffs identified in the action that are alleged to have suffered damages as a result of alleged exposure to asbestos-containing products and materials. According to the petition and as a result of a preliminary investigation, the General Partner believes that the only claim asserted against it results from one individual for the period from July 1971 through June 1972, who is alleged to have worked on a facility owned by the General Partner’s predecessor. This period represents a small portion of the total alleged exposure period from January 1964 through December 2001 for this individual. The individual’s claims involve numerous employers and alleged job sites. The General Partner has been unable to confirm involvement by the General Partner or its predecessors with the alleged location, and it is uncertain at this time whether this case is covered by insurance. Discovery is planned, and the General Partner intends to defend itself vigorously against this lawsuit. The plaintiffs have not stipulated the amount of damages that they are seeking in this suit. We are obligated to reimburse the General Partner for any costs it incurs related to this lawsuit. We cannot estimate the loss, if any, associated with this pending lawsuit. We do not believe that the outcome of this lawsuit will have a material adverse effect on our financial position, results of operations or cash flows.

On August 5, 2005, we were named as a third-party defendant in a matter styled ConocoPhillips, et al. v. BP Amoco Seaway Products Pipeline Company as filed in the 55^th Judicial District of Harris County, Texas. ConocoPhillips alleges a right to indemnity from BP Amoco Seaway Products Pipeline Company (“BP Amoco”) for tax liability incurred by ConocoPhillips as a result of the reverse merger of Seaway Pipeline Company (the “Original Seaway Partnership”). The reverse merger of the Original Seaway Partnership was undertaken in preparation for our purchase of ARCO Pipe Line Company pursuant to the Amended and Restated Purchase Agreement (the “Purchase Agreement”) dated May 10, 2000, between us and Atlantic Richfield Company. BP Amoco has claimed a right to indemnity from us under the Purchase Agreement should BP Amoco have any indemnity liability to ConocoPhillips. ConocoPhillips alleges the income tax liability to be approximately $4.0 million. On January 20, 2006, we entered into a settlement agreement with BP Amoco dismissing and resolving all of BP Amoco’s claims. The terms of the settlement did not have a material adverse effect on our financial position, results of operations or cash flows.

In 1991, we were named as a defendant in a matter styled Jimmy R. Green, et al. v. Cities Service Refinery, et al. as filed in the 26^th Judicial District Court of Bossier Parish, Louisiana. The plaintiffs in this matter reside or formerly resided on land that was once the site of a refinery owned by one of our co-defendants. The former refinery is located near our Bossier City facility. Plaintiffs have claimed personal injuries and property damage arising from alleged contamination of the refinery property. The plaintiffs have recently pursued certification as a class and have significantly increased their demand to approximately $175.0 million. This revised demand includes amounts for environmental restoration not previously claimed by the plaintiffs. We have never owned any interest in the refinery property made the basis of this action, and we do not believe that we contributed to any alleged contamination of this property. While we cannot predict the ultimate outcome, we do not believe that the outcome of this lawsuit will have a material adverse effect on our financial position, results of operations or cash flows.

In addition to the litigation discussed above, we have been, in the ordinary course of business, a defendant in various lawsuits and a party to various other legal proceedings, some of which are covered in whole or in part by insurance. We believe that the outcome of these lawsuits and other proceedings will not individually or in the aggregate have a future material adverse effect on our consolidated financial position, results of operations or cash flows.

Our operations are subject to federal, state and local laws and regulations governing the discharge of materials into the environment and various safety matters. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and

criminal penalties, imposition of injunctions delaying or prohibiting certain activities and the need to perform investigatory and remedial activities. We believe our operations have been and are in material compliance with applicable environmental and safety laws and regulations, and that compliance with existing environmental laws and regulations are not expected to have a material adverse effect on our competitive position, financial positions, results of operations or cash flows. However, risks of significant costs and liabilities are inherent in pipeline operations, and we cannot assure that significant costs and liabilities will not be incurred. Moreover, it is possible that other developments, such as increasingly strict environmental and safety laws and regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from our operations, could result in substantial costs and liabilities to us. At December 31, 2005 and 2004, we have an accrued liability of $2.4 million and $5.0 million, respectively, related to sites requiring environmental remediation activities.

On March 26, 2004, a decision in ARCO Products Co., et al. v. SFPP, Docket OR96-2-000, was issued by the FERC, which made several significant determinations with respect to finding “changed circumstances” under the Energy Policy Act of 1992 (“EP Act”). The decision largely clarifies, but does not fully quantify, the standard required for a complainant to demonstrate that an oil pipeline’s rates are no longer subject to the rate protection of the EP Act by demonstrating that a substantial change in circumstances has occurred since 1992 with respect to the basis of the rates being challenged. In the decision, the FERC found that a limited number of rate elements will significantly affect the economic basis for a pipeline company’s rates. The elements identified in the decision are volume changes, allowed total return and total cost-of-service (including major cost elements such as rate base, tax rates and tax allowances, among others). The FERC did reject, however, the use of changes in tax rates and income tax allowances as stand-alone factors. Judicial review of that decision, which has been sought by a number of parties to the case, is currently pending before the U.S. Court of Appeals for the District of Columbia Circuit. We have not yet determined the impact, if any, that the decision, if it is ultimately upheld, would have on our rates if they were reviewed under the criteria of this decision.

On July 20, 2004, the District of Columbia Circuit issued an opinion in BP West Coast Products LLC v. FERC. In reviewing a series of orders involving SFPP, L.P., the court held among other things that the FERC had not adequately justified its policy of providing an oil pipeline limited partnership with an income tax allowance equal to the proportion of its income attributable to partnership interests owned by corporate partners. Under the FERC’s initial ruling, SFPP, L.P. was permitted an income tax allowance on its cost-of-service filing for the percentage of its net operating (pre-tax) income attributable to partnership units held by corporations, and was denied an income tax allowance equal to the percentage attributable to partnership units held by non-corporate partners. The court remanded the case back to the FERC for further review. As a result of the court’s remand, on May 4, 2005, the FERC issued its Policy Statement on Income Tax Allowances, which permits regulated partnerships, limited liability companies and other pass-through entities an income tax allowance on their income attributable to any owner that has an actual or potential income tax liability on that income, regardless whether the owner is an individual or corporation. If there is more than one level of pass-through entities, the regulated company income must be traced to where the ultimate tax liability lies. The Policy Statement is to be applied in individual cases, and the regulated entity bears the burden of proof to establish the tax status of its owners. On December 16, 2005, the FERC issued the first of those decisions, in an order involving SFPP (the “SFPP Order”).

The SFPP Order confirmed that an MLP is entitled to a tax allowance with respect to partnership income for which there is an “actual or potential income tax liability” and determined that a unitholder that is required to file a Form 1040 or Form 1120 tax return that includes partnership income or loss is presumed to have an actual or potential income tax liability sufficient to support a tax allowance on that partnership income. The FERC also established certain other presumptions, including that corporate unitholders are presumed to be taxed at the maximum corporate tax rate of 35% while individual unitholders (and certain other types of unitholders taxed like individuals) are presumed to be taxed at a 28% tax rate. The SFPP Order remains subject to further administrative proceedings (including compliance filings by SFPP and possible rehearing requests), as well as potential judicial review. The ultimate outcome of the FERC’s inquiry on income tax allowance should not affect our current rates and rate structure because our rates are not based on cost-of-service methodology. However, the outcome of the income tax allowance would become relevant to us should we (i) elect in the future to use cost-of-service to support our rates, or (ii) be required to use such methodology to defend our indexed rates.

In 1994, the Louisiana Department of Environmental Quality (“LDEQ”) issued a compliance order for environmental contamination at our Arcadia, Louisiana, facility. In 1999, our Arcadia facility and adjacent terminals were directed by the Remediation Services Division of the LDEQ to pursue remediation of this contamination. Effective March 2004, we executed an access agreement with an adjacent industrial landowner who is located upgradient of the Arcadia facility. This agreement enables the landowner to proceed with remediation activities at our Arcadia facility for which it has accepted shared responsibility. At December 31, 2005, we have an accrued liability of $0.2 million for remediation costs at our Arcadia facility. We do not expect that the completion of the remediation program proposed to the LDEQ will have a future material adverse effect on our financial position, results of operations or cash flows.

On March 17, 2003, we experienced a release of 511 barrels of jet fuel from a storage tank at our Blue Island terminal located in Cook County, Illinois. As a result of the release, we have entered into an Agreed Order with the State of Illinois, which required us to conduct an environmental investigation. At this time, we have complied with the terms of the Agreed Order, and the results of the environmental investigation indicated there were no soil or groundwater impacts from the release. On August 30, 2005, a final settlement was reached with the State of Illinois. The settlement included the payment of a civil penalty of $0.1 million and the requirement that we make certain modifications to the equipment of the facility, none of which are expected to have a material adverse effect on our financial position, results of operations or cash flows.

On July 22, 2004, we experienced a release of approximately 12 barrels of jet fuel from a sump at our Lebanon, Ohio, terminal. The released jet fuel was contained within a storm water retention pond located on the terminal property. Six migratory waterfowl were affected by the jet fuel and were subsequently euthanized by or at the request of the United States Fish and Wildlife Service (“USFWS”). On October 1, 2004, the USFWS served us with a Notice of Violation, alleging that we violated 16 USC 703 of the Migratory Bird Treaty Act for the “take[ing] of migratory birds by illegal methods.” On February 7, 2005, we entered into a Memorandum of Understanding with the USFWS, settling all aspects of this matter. The terms of this settlement did not have a material effect on our financial position, results of operations or cash flows.

On July 27, 2004, we received notice from the United States Department of Justice (“DOJ”) of its intent to seek a civil penalty against us related to our November 21, 2001, release of approximately 2,575 barrels of jet fuel from our 14-inch diameter pipeline located in Orange County, Texas. The DOJ, at the request of the Environmental Protection Agency, is seeking a civil penalty against us for alleged violations of the Clean Water Act (“CWA”) arising out of this release. We are in discussions with the DOJ regarding this matter and have responded to its request for additional information. The maximum statutory penalty proposed by the DOJ for this alleged violation of the CWA is $2.1 million. We do not expect any civil penalty to have a material adverse effect on our financial position, results of operations or cash flows.

On September 18, 2005, a propane release and fire occurred at our Todhunter facility, near Middletown, Ohio. The incident resulted in the death of one of our employees. There were no other injuries. On or about February 22, 2006, we received verbal notification from a representative of the Occupational Safety and Health Administration that they intend to serve us with a citation arising out of this incident. At this time, we have not received any citation, and we cannot predict with certainty the amount of any fine or penalty associated with any such citation; however, we do not expect any fine or penalty to have a material adverse effect on our financial position, results of operations or cash flows.

Rates of interstate petroleum products and crude oil pipeline companies, like us, are currently regulated by the FERC primarily through an index methodology, which allows a pipeline to change its rates based on the change from year to year in the Producer Price Index for finished goods (“PPI Index”). Effective as of February 24, 2003, FERC Order on Remand modified the PPI Index from PPI – 1% to PPI. On April 22, 2003, several shippers filed a petition in the United States Court of Appeals for the District of Columbia Circuit (the “Court”), Flying J. Inc,. Lion Oil Company, Sinclair Oil Corporation and Tesoro Refining and Marketing Company vs. Federal Energy Regulatory Commission; Docket No. 03-1107, seeking a review of whether the FERC’s adoption of the PPI Index was reasonable and supported by the evidence. On April 9, 2004, the Court handed down a decision denying the shippers’ petition for review, stating the shippers failed to establish that any of the FERC’s methodological choices (or combination of choices) were both erroneous and harmful.

As an alternative to using the PPI Index, interstate petroleum products and crude oil pipeline companies may elect to support rate filings by using a cost-of-service methodology, competitive market showings (“Market-Based Rates”) or agreements between shippers and petroleum products and crude oil pipeline companies that the rate is acceptable.

Centennial entered into credit facilities totaling $150.0 million, and as of December 31, 2005, $150.0 million was outstanding under those credit facilities. TE Products and Marathon have each guaranteed one-half of the repayment of Centennial’s outstanding debt balance (plus interest) under a long-term credit agreement, which expires in 2024, and a short-term credit agreement, which expires in 2007. The guarantees arose in order for Centennial to obtain adequate financing, and the proceeds of the credit agreements were used to fund construction and conversion costs of its pipeline system. Prior to the expiration of the long-term credit agreement, TE Products could be relinquished from responsibility under the guarantee should Centennial meet certain financial tests. If Centennial defaults on its outstanding balance, the estimated maximum potential amount of future payments for TE Products and Marathon is $75.0 million each at December 31, 2005.

TE Products, Marathon and Centennial have entered into a limited cash call agreement, which allows each member to contribute cash in lieu of Centennial procuring separate insurance in the event of a third-party liability arising from a catastrophic event. There is an

indefinite term for the agreement and each member is to contribute cash in proportion to its ownership interest, up to a maximum of $50.0 million each. As a result of the catastrophic event guarantee, TE Products has recorded a $4.6 million obligation, which represents the present value of the estimated amount that we would have to pay under the guarantee. If a catastrophic event were to occur and we were required to contribute cash to Centennial, contributions exceeding our deductible might be covered by our insurance.

One of our subsidiaries, TCO, has entered into master equipment lease agreements with finance companies for the use of various equipment. We have guaranteed the full and timely payment and performance of TCO’s obligations under the agreements. Generally, events of default would trigger our performance under the guarantee. The maximum potential amount of future payments under the guarantee is not estimable, but would include base rental payments for both current and future equipment, stipulated loss payments in the event any equipment is stolen, damaged, or destroyed and any future indemnity payments. We carry insurance coverage that may offset any payments required under the guarantees.

On February 24, 2005, the General Partner was acquired from DEFS by DFI. The General Partner owns a 2% general partner interest in us and is the general partner of the Partnership. On March 11, 2005, the Bureau of Competition of the Federal Trade Commission (“FTC”) delivered written notice to DFI’s legal advisor that it was conducting a non-public investigation to determine whether DFI’s acquisition of the General Partner may substantially lessen competition. The General Partner is cooperating fully with this investigation.

Substantially all of the petroleum products that we transport and store are owned by our customers. At December 31, 2005, TCTM and TE Products had approximately 4.0 million barrels and 22.5 million barrels, respectively, of products in their custody that was owned by customers. We are obligated for the transportation, storage and delivery of such products on behalf of our customers. We maintain insurance adequate to cover product losses through circumstances beyond our control.

We carry insurance coverage consistent with the exposures associated with the nature and scope of our operations. Our current insurance coverage includes (1) commercial general liability insurance for liabilities to third parties for bodily injury and property damage resulting from our operations; (2) workers’ compensation coverage to required statutory limits; (3) automobile liability insurance for all owned, non-owned and hired vehicles covering liabilities to third parties for bodily injury and property damage, and (4) property insurance covering the replacement value of all real and personal property damage, including damages arising from earthquake, flood damage and business interruption/extra expense. For select assets, we also carry pollution liability insurance that provides coverage for historical and gradual pollution events. All coverages are subject to certain deductibles, limits or sub-limits and policy terms and conditions.

We also maintain excess liability insurance coverage above the established primary limits for commercial general liability and automobile liability insurance. Limits, terms, conditions and deductibles are commensurate with the nature and scope of our operations. The cost of our general insurance coverages has increased over the past year reflecting the changing conditions of the insurance markets. These insurance policies, except for the pollution liability policies, are through EPCO (see Note 7).

The amounts indicated below as “Partnership and Other” relate primarily to intersegment eliminations and assets that we hold that have not been allocated to any of our reporting segments.

Our Downstream Segment revenues are earned from transportation and storage of refined products and LPGs, intrastate transportation of petrochemicals, sale of product inventory and other ancillary services. The two largest operating expense items of the Downstream Segment are labor and electric power. We generally realize higher revenues during the first and fourth quarters of each year since our operations are somewhat seasonal. Refined products volumes are generally higher during the second and third quarters because of greater demand for gasolines during the spring and summer driving seasons. LPGs volumes are generally higher from November through March due to higher demand for propane, a major fuel for residential heating. Our Downstream Segment also includes the results of operations of the northern portion of the Dean Pipeline, which transports, refinery grade propylene from Mont Belvieu to Point Comfort, Texas. Our Downstream Segment also includes our equity investments in Centennial and MB Storage (see Note 6).

Our Upstream Segment revenues are earned from gathering, transportation, marketing and storage of crude oil and distribution of lubrication oils and specialty chemicals, principally in Oklahoma, Texas, New Mexico and the Rocky Mountain region. Marketing operations consist primarily of aggregating purchased crude oil along our pipeline systems, or from third party pipeline systems, and arranging the

necessary transportation logistics for the ultimate sale of the crude oil to local refineries, marketers or other end users. Our Upstream Segment also includes our equity investment in Seaway. Seaway consists of large diameter pipelines that transport crude oil from Seaway’s marine terminals on the U.S. Gulf Coast to Cushing, Oklahoma, a crude oil distribution point for the central United States, and to refineries in the Texas City and Houston areas.

Our Midstream Segment revenues are earned from the fractionation of NGLs in Colorado, transportation of NGLs from two trunkline NGL pipelines in South Texas, two NGL pipelines in East Texas and a pipeline system (Chaparral) from West Texas and New Mexico to Mont Belvieu; the gathering of natural gas in the Green River Basin in southwestern Wyoming, through Jonah, and the gathering of CBM and conventional natural gas in the San Juan Basin in New Mexico and Colorado, through Val Verde. On March 31, 2006, we sold our ownership interest in the Jonah Pioneer silica gel natural gas processing plant located near Opal, Wyoming to an affiliate of Enterprise for $38.0 million in cash (see Note 5 in the Notes to the Consolidated Financial Statements). Operating results of the Pioneer plant for the years ended December 31, 2005 and 2004 are shown as discontinued operations.

The tables below include financial information by reporting segment for the years ended December 31, 2005, 2004 and 2003 (in thousands):

The following table provides the total assets, capital expenditures and significant non-cash investing activities for each segment as of and for the years ended December 31, 2005, 2004 and 2003 (in thousands):

The following table reconciles the segments total earnings before interest to consolidated net income for the three years ended December 31, 2005, 2004 and 2003 (in thousands):

SFAS No. 130, Reporting Comprehensive Income requires certain items such as foreign currency translation adjustments, minimum pension liability adjustments and unrealized gains and losses on certain investments to be reported in a financial statement. As of and for the year ended December 31, 2005, the components of comprehensive income were due to crude oil hedges. The crude oil hedges mature in December 2006. While the crude oil hedges are in effect, changes in the fair values of the crude oil hedges, to the extent the hedges are effective, are recognized in other comprehensive income until they are recognized in net income in future periods. As of and for the year ended December 31, 2004, the components of comprehensive income were due to the interest rate swap related to our variable rate revolving credit facility, which was designated as a cash flow hedge. The interest rate swap matured in April 2004. While the interest rate swap was in effect, changes in the fair value of the cash flow hedge, to the extent the hedge was effective, were recognized in other comprehensive income until the hedge interest costs were recognized in net income.

The accumulated balance of other comprehensive income related to our cash flow hedges is as follows (in thousands):

Our significant operating subsidiaries, TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P., Jonah Gas Gathering Company and Val Verde Gas Gathering Company, L.P., have issued unconditional guarantees of our debt securities. The guarantees are full, unconditional, and joint and several. TE Products Pipeline Company, Limited Partnership, TCTM, L.P., TEPPCO Midstream Companies, L.P., Jonah Gas Gathering Company and Val Verde Gas Gathering Company, L.P. are collectively referred to as the “Guarantor Subsidiaries.”

The following supplemental condensed consolidating financial information reflects our separate accounts, the combined accounts of the Guarantor Subsidiaries, the combined accounts of our other non-guarantor subsidiaries, the combined consolidating adjustments and eliminations and our consolidated accounts for the dates and periods indicated. For purposes of the following consolidating information, our investments in our subsidiaries and the Guarantor Subsidiaries’ investments in their subsidiaries are accounted for under the equity method of accounting.

We are restating our previously reported consolidated financial statements for the fiscal years ended December 31, 2003 and 2004. For the impact of the restated consolidated financial results for the quarterly periods during the years ended December 31, 2005 and 2004, see Note 21. We have determined that our method of accounting for the $33.4 million excess investment in Centennial, previously described as an intangible asset with an indefinite life, and the $27.1 million excess investment in Seaway, previously described as equity method goodwill, was incorrect. Through our accounting for these excess investments in Centennial and Seaway as intangible assets with indefinite lives and equity method goodwill, respectively, we have been testing the amounts for impairment on an annual basis as opposed to amortizing them over a determinable life. We determined that it would be more appropriate to account for these excess investments as intangible assets with determinable lives. As a result, we made non-cash adjustments that reduced the net value of the excess investments in Centennial and Seaway, and increased amortization expense allocated to our equity earnings. The effect of this restatement caused a $3.8 million and $4.0 million reduction to net income as previously reported for the fiscal years ended December 31, 2004 and 2003, respectively. As a result of the accounting correction, net income for the fiscal year ended December 31, 2005, includes a charge of $4.8 million, of which $3.8 million relates to the first nine months. Additionally, partners’ capital at December 31, 2002, reflects a $2.5 million reduction representing the cumulative effect of this correction for fiscal years ended December 31, 2000 through 2002.

While we believe the impacts of these non-cash adjustments are not material to any previously issued financial statements, we determined that the cumulative adjustment for these non-cash items was too material to record in the fourth quarter of 2005, and therefore it was most appropriate to restate prior periods’ results. These non-cash adjustments had no effect on our operating income, compensation expense, debt balances or ability to meet all requirements related to our debt facilities. The restatement had no impact on total cash flows from operating activities, investing activities or financing activities. All amounts in the accompanying consolidated financial statements have been adjusted for this restatement.

We will continue to amortize the $30.0 million excess investment in Centennial related to a contract using units-of-production methodology over a 10-year life. The remaining $3.4 million related to a pipeline will continue to be amortized on a straight-line basis over 35 years. We will continue to amortize the $27.1 million excess investment in Seaway on a straight-line basis over a 39-year life related primarily to a pipeline.

The following tables summarize the impact of the restatement adjustment on previously reported balance sheet amounts for the year ended December 31, 2004, and income statement amounts and cash flow amounts for the years ended December 31, 2004 and 2003 (in thousands):

In January 2006, we entered into interest rate swaps with a total notional amount of $200.0 million, whereby we will receive a floating rate of interest and will pay a fixed rate of interest for a two-year term. These interest rate swaps were executed to decrease the exposure to potential increases in floating interest rates. Using the balances of outstanding debt at December 31, 2005, these interest rate swaps decrease the level of floating interest rate debt from 41% to 29% of total outstanding debt.

On February 13, 2006, we and an affiliate of Enterprise entered into a letter agreement related to an additional expansion (the “Jonah Expansion”) of the Jonah system (the “Letter Agreement”). The Jonah Expansion will consist of the installation of approximately 90,000 horsepower of gas turbine compression at a new compression station, related new piping and certain related facilities, which is expected to increase capacity of the Jonah system from 1.5 billion cubic feet per day to 2.0 billion cubic feet per day. We expect to enter into a joint venture (“Joint Venture”) agreement with Enterprise relating to the construction and financing of the Jonah Expansion. Enterprise will be responsible for all activities relating to the construction of the Jonah Expansion and will advance all amounts necessary to plan, engineer, construct or complete the Jonah Expansion (anticipated to be approximately $200.0 million). Such advance will constitute a subscription for an equity interest in the proposed Joint Venture (the “Subscription”). We expect the Jonah Expansion to be put into service in late 2006. We have the option to return to Enterprise up to 100% of the amount of the Subscription. If we return a portion of the Subscription to Enterprise, our relative interests in the proposed Joint Venture will be adjusted accordingly. The proposed Joint Venture will terminate without liability to either party if we return 100% of the Subscription.

The ratio of earnings to fixed charges is calculated using the Securities and Exchange Commission guidelines(a).

We have audited the accompanying consolidated balance sheets of DCP Midstream, LLC and subsidiaries as of December 31, 2006 and 2005, and the related consolidated statements of operations and comprehensive income, members’ equity, and cash flows for the years then ended. Our audits also included the financial statement schedule listed in the Index at Item 15. These consolidated financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of DCP Midstream, LLC and subsidiaries at December 31, 2006 and 2005, and the results of their operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

Basis of Presentation — DCP Midstream, LLC, formerly Duke Energy Field Services, LLC, with its consolidated subsidiaries, us, we, our, or the Company, is a joint venture owned 50% by Duke Energy Corporation, or Duke Energy, and 50% by ConocoPhillips. We operate in the midstream natural gas industry. Our primary operations consist of natural gas gathering, processing, compression, transportation and storage, and natural gas liquid, or NGL, fractionation, transportation, gathering, treating, processing and storage, as well as marketing, from which we generate revenues primarily by trading and marketing natural gas and NGLs. The Second Amended and Restated LLC Agreement dated July 5, 2005, as amended, or the LLC Agreement, limits the scope of our business to the midstream natural gas industry in the United States and Canada, the marketing of NGLs in Mexico, and the transportation, marketing and storage of other petroleum products, unless otherwise approved by our board of directors.

To support and facilitate our continued growth, we formed DCP Midstream Partners, LP, a master limited partnership, or DCP Partners, of which our subsidiary, DCP Midstream GP, LP, acts as general partner. In September 2005, DCP Partners filed a Registration Statement on Form S-1 with the Securities and Exchange Commission, or SEC, to register the initial public offering of its limited partnership units to the public. The initial public offering closed in December 2005. We own approximately 41% of the limited partnership interests in DCP Partners and a 2% general partnership interest. As the general partner of DCP Partners, we have responsibility for its operations. DCP Partners is accounted for as a consolidated subsidiary.

In July 2005, Duke Energy transferred a 19.7% interest in our Company to ConocoPhillips in exchange for direct and indirect monetary and non-monetary consideration, effectively decreasing Duke Energy’s membership interest in our Company to 50% and increasing ConocoPhillips’ membership interest in our Company to 50%, referred to as “the 50-50 Transaction.” Included in this transaction, we distributed to Duke Energy substantially all of our Canadian business, made a disproportionate cash distribution of approximately $1,100 million to Duke Energy using the proceeds from the sale of our general partner interest in TEPPCO and paid a $245 million proportionate distribution to Duke Energy and ConocoPhillips. In addition, ConocoPhillips contributed cash of $398 million to our Company. Under the terms of the amended and restated LLC Agreement, proceeds from this contribution were designated for the acquisition or improvement of property, plant and equipment. At December 31, 2006, there was no remaining restricted investment balance related to this contribution.

On June 28, 2006, Duke Energy’s board of directors approved a plan to create two separate publicly traded companies by spinning off Duke Energy’s natural gas businesses, including its 50% ownership interest in us, to Duke Energy shareholders. This transaction occurred on January 2, 2007. As a result of this transaction, we are no longer 50% owned by Duke Energy. Duke Energy’s 50% ownership interest in us was transferred to a new company, Spectra Energy Corp, or Spectra Energy. This transaction is referred to in this report as “the Spectra spin.” For the historical periods included in this report, references to Spectra Energy are interchangeable with Duke Energy. On a prospective basis, Spectra Energy refers to the newly formed public company.

We are governed by a five member board of directors, consisting of two voting members from each parent and our Chief Executive Officer and President, a non-voting member. All decisions requiring board of directors’ approval are made by simple majority vote of the board, but must include at least one vote from both a Spectra Energy (or Duke Energy prior to January 2, 2007) and ConocoPhillips board member. In the event the board cannot reach a majority decision, the decision is appealed to the Chief Executive Officers of both Spectra Energy and ConocoPhillips.

The consolidated financial statements include the accounts of the Company and all majority-owned subsidiaries where we have the ability to exercise control, variable interest entities where we are the primary beneficiary, and undivided interests in jointly owned assets. We also consolidate DCP Partners, which we control as the general partner and where the limited partners do not have substantive kick-out or participating rights. Investments in greater than 20% owned affiliates that are not variable interest entities and where we do not have the ability to exercise control, and investments in less than 20% owned affiliates where we have the ability to exercise significant influence, are accounted for using the equity method. Intercompany balances and transactions have been eliminated.

Use of Estimates — Conformity with accounting principles generally accepted in the United States of America 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.

Acquisitions — We consolidate assets and liabilities from acquisitions as of the purchase date, and include earnings from acquisitions in consolidated earnings subsequent to the purchase date. Assets acquired and liabilities assumed are recorded at estimated fair

values on the date of acquisition. If the acquisition constitutes a business, any excess purchase price over the estimated fair value of the acquired assets and liabilities is recorded as goodwill.

Reclassifications — Certain prior period amounts have been reclassified in the consolidated financial statements to conform to the current period presentation.

Cash and Cash Equivalents — Cash and cash equivalents includes all cash balances and highly liquid investments with an original maturity of three months or less.

Short-Term and Restricted Investments — We invest available cash balances in various financial instruments, such as tax-exempt debt securities, that have stated maturities of 20 years or more. These instruments provide for a high degree of liquidity through features, which allow for the redemption of the investment at its face amount plus earned income. As we generally intend to sell these instruments within one year or less from the balance sheet date, and as they are available for use in current operations, they are classified as current assets, unless otherwise restricted. We have classified all short-term and restricted debt investments as available-for-sale under Statement of Financial Accounting Standards, or SFAS, No. 115, “Accounting for Certain Investments in Debt and Equity Securities,” and they are carried at fair market value. Unrealized gains and losses on available-for-sale securities are recorded in the consolidated balance sheets as accumulated other comprehensive income (loss), or AOCI. No such gains or losses were deferred in AOCI at December 31, 2006 or 2005. The cost, including accrued interest on investments, approximates fair value, due to the short-term, highly liquid nature of the securities held by us and as interest rates are re-set on a daily, weekly or monthly basis.

Inventories — Inventories consist primarily of natural gas and NGLs held in storage for transportation and processing and sales commitments. Inventories are valued at the lower of weighted average cost or market. Transportation costs are included in inventory on the consolidated balance sheets.

Accounting for Risk Management and Hedging Activities and Financial Instruments — Each derivative not qualifying for the normal purchases and normal sales exception under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” or SFAS 133, as amended, is recorded on a gross basis in the consolidated balance sheets at its fair value as unrealized gains or unrealized losses on mark-to-market and hedging instruments. Derivative assets and liabilities remain classified in the consolidated balance sheets as unrealized gains or unrealized losses on mark-to-market and hedging instruments at fair value until the contractual delivery period impacts earnings.

We designate each energy commodity derivative as either trading or non-trading. Certain non-trading derivatives are further designated as either a hedge of a forecasted transaction or future cash flow (cash flow hedge), a hedge of a recognized asset, liability or firm commitment (fair value hedge), or a normal purchase or normal sale contract, while certain non-trading derivatives, which are related to asset based activity, are non-trading mark-to-market derivatives. For each of our derivatives, the accounting method and presentation in the consolidated statements of operations and comprehensive income are as follows:

^a Mark-to-market—An accounting method whereby the change in the fair value of the asset or liability is recognized in the consolidated statements of operations and comprehensive income in trading and marketing gains (losses) during the current period.

^b Hedge method—An accounting method whereby the change in the fair value of the asset or liability is recorded in the consolidated balance sheets as unrealized gains or unrealized losses on mark-to-market and hedging instruments. For cash flow hedges, there is no recognition in the consolidated statements of operations and comprehensive income for the effective portion until the service is provided

or the associated delivery period impacts earnings. For fair value hedges, the changes in the fair value of the asset or liability, as well as the offsetting changes in value of the hedged item, are recognized in the consolidated statements of operations and comprehensive income in the same category as the related hedged item.

^c Accrual method—An accounting method whereby there is no recognition in the consolidated balance sheets or consolidated statements of operations and comprehensive income for changes in fair value of a contract until the service is provided or the associated delivery period impacts earnings.

Cash Flow and Fair Value Hedges — For derivatives designated as a cash flow hedge or a fair value hedge, we maintain formal documentation of the hedge in accordance with SFAS 133. In addition, we formally assess, both at the inception of the hedge and on an ongoing basis, whether the hedge contract is highly effective in offsetting changes in cash flows or fair values of hedged items. All components of each derivative gain or loss are included in the assessment of hedge effectiveness, unless otherwise noted.

The fair value of a derivative designated as a cash flow hedge is recorded in the consolidated balance sheets as unrealized gains or unrealized losses on mark-to-market and hedging instruments. The effective portion of the change in fair value of a derivative designated as a cash flow hedge is recorded in the consolidated balance sheets as AOCI and the ineffective portion is recorded in the consolidated statements of operations and comprehensive income. During the period in which the hedged transaction impacts earnings, amounts in AOCI associated with the hedged transaction are reclassified to the consolidated statements of operations and comprehensive income in the same accounts as the item being hedged. We discontinue hedge accounting prospectively when it is determined that the derivative no longer qualifies as an effective hedge, or when it is probable that the hedged transaction will not 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. The derivative continues to be carried on the consolidated balance sheets at its fair value; however, subsequent changes in its fair value are recognized in current period earnings. Gains and losses related to discontinued hedges that were previously accumulated in AOCI will remain in AOCI until the hedged transaction impacts earnings, unless it is probable that the hedged transaction will not occur, in which case, the gains and losses that were previously deferred in AOCI will be immediately recognized in current period earnings.

For derivatives designated as fair value hedges, we recognize the gain or loss on the derivative instrument, as well as the offsetting changes in value of the hedged item in earnings in the current period. All derivatives designated and accounted for as fair value hedges are classified in the same category as the item being hedged in the consolidated statements of operations and comprehensive income.

Valuation — When available, quoted market prices or prices obtained through external sources are used to determine 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.

Values are adjusted to reflect the credit risk inherent in the transaction as well as the potential impact of liquidating open positions in an orderly manner over a reasonable time period under current conditions. Changes in market prices and management estimates directly affect the estimated fair value of these contracts. Accordingly, it is reasonably possible that such estimates may change in the near term.

Property, Plant and Equipment — Property, plant and equipment are recorded at original cost. Depreciation is computed using the straight-line method over the estimated useful lives of the assets. The costs of maintenance and repairs, which are not significant improvements, are expensed when incurred.

Asset retirement obligations associated with tangible long-lived assets are recorded at fair value in the period in which they are incurred, if a reasonable estimate of fair value can be made, and 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. We recognize a liability for conditional asset retirement obligations as soon as the fair value of the liability can be reasonably estimated. A conditional asset retirement obligation is defined as an unconditional legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity.

Impairment of Unconsolidated Affiliates — We evaluate our unconsolidated affiliates for impairment when events or changes in circumstances indicate, in management’s judgment, that the carrying value of such investments may have experienced an other than temporary decline in value. When evidence of loss in value has occurred, management compares the estimated fair value of the investment to the carrying value of the investment to determine whether any impairment has occurred. Management assesses the fair value of our unconsolidated affiliates using commonly accepted techniques, and may use more than one method, including, but not limited to,

recent third party comparable sales, internally developed discounted cash flow analysis and analysis from outside advisors. If the estimated fair value is less than the carrying value and management considers the decline in value to be other than temporary, the excess of the carrying value over the estimated fair value is recognized in the financial statements as an impairment loss.

Intangible Assets — Intangible assets consist of goodwill, and commodity sales and purchases contracts. Goodwill is the cost of an acquisition less the fair value of the net assets of the acquired business. Commodity sales and purchases contracts are amortized on a straight-line basis over the term of the contract, ranging from one to 25 years.

We evaluate goodwill for impairment annually in the third quarter, and whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount. Impairment testing of goodwill consists of a two-step process. The first step involves comparing the fair value of the reporting unit, to which goodwill has been allocated, with its carrying amount. If the carrying amount of the reporting unit exceeds its fair value, the second step of the process involves comparing the fair value and carrying value of the goodwill of that reporting unit. If the carrying value of the goodwill of a reporting unit exceeds the fair value of that goodwill, an impairment loss is recognized in an amount equal to the excess.

Impairment of Long-Lived Assets, Assets Held for Sale and Discontinued Operations — We evaluate whether the carrying value of long-lived assets, excluding goodwill, has been impaired when circumstances indicate the carrying value of those assets may not be recoverable. 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. We consider various factors when determining if these assets should be evaluated for impairment, including but not limited to:

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. Management assesses the fair value of long-lived assets using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales, internally developed discounted cash flow analysis and analysis from outside advisors. Significant changes in market conditions resulting from events such as the condition of an asset or a change in management’s intent to utilize the asset would generally require management to reassess the cash flows related to the long-lived assets.

We use the criteria in SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” or SFAS 144, to determine when an asset is classified as held for sale. Upon classification as held for sale, the long-lived asset is measured at the lower of its carrying amount or fair value less cost to sell, depreciation is ceased and the asset is separately presented on the consolidated balance sheets.

If an asset held for sale or sold (1) has clearly distinguishable operations and cash flows, generally at the plant level, (2) has direct cash flows of the held for sale or sold component that will be eliminated (from the perspective of the held for sale or sold component), and (3) if we are unable to exert significant influence over the disposed component, then the related results of operations for the current and prior periods, including any related impairments and gains or losses on sales are reflected as income from discontinued operations in the consolidated statements of operations and comprehensive income. If an asset held for sale or sold does not have clearly distinguishable operations and cash flows, impairments and gains or losses on sales are recorded as gain on sale of assets in the consolidated statements of operations and comprehensive income.

Unamortized Debt Premium, Discount and Expense — Premiums, discounts and expenses incurred with the issuance of long-term debt are amortized over the terms of the debt using the effective interest method. These premiums and discounts are recorded on the consolidated balance sheets as an offset to long-term debt. These expenses are recorded on the consolidated balance sheets as other non-current assets.

Distributions — Under the terms of the LLC Agreement, we are required to make quarterly distributions to Spectra Energy and ConocoPhillips based on allocated taxable income. The LLC Agreement provides for taxable income to be allocated in accordance with Internal Revenue Code Section 704(c). This Code Section accounts for the variation between the adjusted tax basis and the fair market value of assets contributed to the joint venture. The distribution is based on the highest taxable income allocated to either member with a minimum of each members’ tax, with the other member receiving a proportionate amount to maintain the ownership capital accounts at 50% for both Spectra Energy and ConocoPhillips. Prior to January 2, 2007, the capital accounts were maintained at 50% for both Duke Energy and ConocoPhillips, and prior to July 1, 2005, the capital accounts were maintained at 69.7% for Duke Energy and 30.3% for ConocoPhillips. During the years ended December 31, 2006 and 2005, we paid distributions of $650 million and $389 million, respectively, based on estimated annual taxable income allocated to the members according to their respective ownership percentages at the date the distributions became due.

Our board of directors determines the amount of the quarterly dividend to be paid to Spectra Energy (or Duke Energy prior to January 2, 2007) and ConocoPhillips, by considering net income, cash flow or any other criteria deemed appropriate. During the years ended December 31, 2006 and 2005, we paid total dividends of $801 million and $1,925 million, respectively. The $1,925 million paid during the year ended December 31, 2005, is comprised of a disproportionate cash distribution of approximately $1,100 million to Duke Energy using the proceeds from the sale of our general partner interest in TEPPCO as part of the 50-50 Transaction, a $245 million proportionate distribution to Duke Energy and ConocoPhillips as part of the 50-50 Transaction, and $580 million in proportionate distributions to Duke Energy and ConocoPhillips, which were allocated in accordance with our partners’ respective ownership percentages. The $801 million paid during the year ended December 31, 2006, is comprised of proportionate distributions to Duke Energy and ConocoPhillips, which were allocated in accordance with our partners’ respective ownership percentages. The LLC Agreement restricts payment of dividends except with the approval of both members.

DCP Partners considers the payment of a quarterly distribution to the holders of its common units and subordinated units, to the extent DCP Partners has sufficient cash from its operations after establishment of cash reserves and payment of fees and expenses, including payments to its general partner, a wholly-owned subsidiary of ours. There is no guarantee, however, that DCP Partners will pay the minimum quarterly distribution on the units in any quarter. DCP Partners will be prohibited from making any distributions to unitholders if it would cause an event of default, or an event of default exists, under its credit agreement. Our 41% limited partner interest in DCP Partners primarily consists of subordinated units. The subordinated units are entitled to receive the minimum quarterly distribution only after DCP Partners’ common unitholders have received the minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. The subordination period will end on December 31, 2010 if certain distribution tests are met and earlier if certain more stringent tests are met. At such time that the subordination period ends, the subordinated units will be converted to common units. During the year ended December 31, 2006, DCP Partners paid distributions of approximately $13 million to its public unitholders. We hold general partner incentive distribution rights, which entitle us to receive an increasing share of available cash when pre-defined distribution targets are achieved.

Foreign Currency Translation — We translated assets and liabilities of our Canadian operations, where the Canadian dollar was the functional currency, at the period-end exchange rates. Revenues and expenses were translated using average monthly exchange rates during the period, which approximates the exchange rates at the time of each transaction during the period. Foreign currency translation adjustments are included in the consolidated statements of comprehensive income. In July 2005, as part of the 50-50 Transaction, we distributed to Duke Energy substantially all of our Canadian business. As a result, there were no translation gains or losses in AOCI at December 31, 2006 and 2005.

Revenue Recognition — We generate the majority of our revenues from natural gas gathering, processing, compression, transportation and storage, and natural gas liquid, or NGL, fractionation, transportation, gathering, treating, processing and storage, as well as trading and marketing of natural gas and NGLs.

We obtain access to raw natural gas and provide our midstream natural gas services principally under contracts that contain a combination of one or more of the following arrangements.

Our trading and marketing of natural gas and NGLs, consists of physical purchases and sales, as well as derivative instruments.

We recognize revenue for sales and services under the four revenue recognition criteria, as follows:

Persuasive evidence of an arrangement exists — Our customary practice is to enter into a written contract, executed by both us and the customer.

Delivery — Delivery is deemed to have occurred at the time custody is transferred, or in the case of fee-based arrangements, when the services are rendered. To the extent we retain product as inventory, delivery occurs when the inventory is subsequently sold and custody is transferred to the third party purchaser.

The fee is fixed or determinable — We negotiate the fee for our services at the outset of our fee-based arrangements. In these arrangements, the fees are nonrefundable. For other arrangements, the amount of revenue, based on contractual terms, is determinable when the sale of the applicable product has been completed upon delivery and transfer of custody.

Collectability is probable — Collectability is evaluated on a customer-by-customer basis. New and existing customers are subject to a credit review process, which evaluates the customers’ financial position (for example, cash position and credit rating) and their ability to pay. If collectability is not considered probable at the outset of an arrangement in accordance with our credit review process, revenue is recognized when the fee is collected.

We generally report revenues gross in the consolidated statements of operations and comprehensive income, as we typically act as the principal in these transactions, take custody of the product, and incur the risks and rewards of ownership. Effective April 1, 2006, any new or amended contracts for certain sales and purchases of inventory with the same counterparty, when entered into in contemplation of one another, are reported net as one transaction. We recognize revenues for our NGL and residue gas derivative trading activities net in the consolidated statements of operations and comprehensive income as trading and marketing gains (losses). These activities include mark-to-market gains and losses on energy trading contracts, and the financial or physical settlement of energy trading contracts.

Revenue for goods and services provided but not invoiced is estimated each month and recorded along with related purchases of goods and services used but not invoiced. These estimates are generally based on estimated commodity prices, preliminary throughput measurements and allocations and contract data. There are no material differences between the actual amounts and the estimated amounts of revenues and purchases recorded at December 31, 2006 and 2005.

Gas and NGL Imbalance Accounting — Quantities of natural gas or NGLs over-delivered or under-delivered related to imbalance agreements with customers, producers or pipelines are recorded monthly as other receivables or other payables using current market prices or the weighted average prices of natural gas or NGLs at the plant or system. These balances are settled with deliveries of natural gas or NGLs, or with cash. Included in the consolidated balance sheets as accounts receivable — other as of December 31, 2006 and 2005 were imbalances totaling $45 million and $59 million, respectively. Included in the consolidated balance sheets as accounts payable — other, as of December 31, 2006 and 2005 were imbalances totaling $42 million at both periods.

Significant Customers — ConocoPhillips, an affiliated company, was a significant customer in both of the past two years. Sales to ConocoPhillips, including its 50% owned equity method investment, ChevronPhillips Chemical Company LLC, or CP Chem, totaled approximately $2,677 million during 2006 and $2,513 million during 2005.

Environmental Expenditures — Environmental expenditures are expensed or capitalized as appropriate, depending upon the future economic benefit. Expenditures that relate to an existing condition caused by past operations, and that do not generate current or future revenue, are expensed. Liabilities for these expenditures are recorded on an undiscounted basis when environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated. Environmental liabilities as of December 31, 2006 and 2005, included in the consolidated balance sheets, totaled $6 million for both periods recorded as other current liabilities, and totaled $6 million and $7 million, respectively, recorded as other long-term liabilities.

Stock-Based Compensation — Under our 2006 Long Term Incentive Plan, or 2006 Plan, equity instruments may be granted to our key employees. The 2006 Plan provides for the grant of Relative Performance Units, or RPU’s, Strategic Performance Units, or SPU’s, and Phantom Units. Prior to January 2, 2007, each of the above units constitutes a notional unit equal to the weighted average fair value of a common share or unit of ConocoPhillips, Duke Energy and DCP Partners, weighted 45%, 45% and 10%, respectively. Upon the Spectra spin, the 45% weighting attributable to Duke Energy will be valued as one common share of Duke Energy and one-half of one common share of Spectra Energy. The 2006 Plan also provides for the grant of DCP Partners’ Phantom Units, which constitute a notional unit equal to the fair value of DCP Partners’ common units. Each unit provides for the grant of dividend or distribution equivalent rights. The 2006 Plan is administered by the compensation committee of our board of directors. We first granted awards under the 2006 Plan during the second quarter of 2006.

Under DCP Partners’ Long Term Incentive Plan, or DCP Partners’ Plan, equity instruments may be granted to DCP Partners’ key employees. DCP Midstream GP, LLC adopted the DCP Partners’ Plan for employees, consultants and directors of DCP Midstream GP, LLC and its affiliates who perform services for DCP Partners. The DCP Partners’ Plan provides for the grant of unvested units, phantom units, unit options and substitute awards, and, with respect to unit options and phantom units, the grant of distribution equivalent rights. Subject to adjustment for certain events, an aggregate of 850,000 common units may be delivered pursuant to awards under the DCP Partners’ Plan. Awards that are canceled, forfeited or withheld to satisfy DCP Midstream GP, LLC’s tax withholding obligations are available for delivery pursuant to other awards. The DCP Partners’ Plan is administered by the compensation committee of DCP Midstream GP, LLC’s board of directors. DCP Partners first granted awards under this plan during the first quarter of 2006.

Through July 1, 2005, we accounted for stock-based compensation in accordance with the intrinsic value recognition and measurement principles of Accounting Principles Board, or APB, Opinion No. 25, or APB 25, “Accounting for Stock Issued to Employees,” and Financial Accounting Standards Board, or FASB, Interpretation No. 44, or FIN 44, “Accounting for Certain Transactions Involving Stock Compensation—an Interpretation of APB Opinion No. 25.” Under that method, compensation expense was measured as the intrinsic value of an award at the measurement dates. The intrinsic value of an award is the amount by which the quoted market price of the underlying stock exceeds the amount, if any, an employee would be required to pay to acquire the stock. Since the exercise price for all options granted under the plan was equal to the market value of the underlying common stock on the date of grant, no compensation expense has historically been recognized in the accompanying consolidated statements of operations and comprehensive income. Compensation expense for phantom stock awards and other stock awards was recorded from the date of grant over the required vesting period based on the market value of the awards at the date of grant. Compensation expense for stock-based performance awards was recorded over the required vesting period, and adjusted for increases and decreases in market value at each reporting date up to the measurement dates.

Under its 1998 Long-Term Incentive Plan, or 1998 Plan, Duke Energy granted certain of our key employees stock options, phantom stock awards, stock-based performance awards and other stock awards to be settled in shares of Duke Energy’s common stock. Upon execution of the 50-50 Transaction in July 2005, certain of our employees who had been issued awards under the 1998 Plan incurred a change in status from Duke Energy employees to non-employees. As a result, all outstanding stock-based awards were required to be remeasured as of July 2005 under EITF Issue No. 96-18, or EITF 96-18, “Accounting for Equity Instruments That Are Issued to Other Than Employees for Acquiring, or in Conjunction with Selling, Goods or Services,” using the fair value method prescribed in SFAS No. 123, “Accounting for Stock-Based Compensation,” or SFAS 123. Compensation expense is recognized prospectively beginning at the date of the change in status over the remaining vesting period based on the fair value of each award at each reporting date. The fair value of stock options is determined using the Black-Scholes option pricing model and the fair value of all other awards is determined based on the closing equity price at each measurement date.

Effective January 1, 2006, we adopted the provisions of SFAS No. 123(R) (Revised 2004) “Share-Based Payment,” or SFAS 123R, which establishes accounting for stock-based awards exchanged for employee and non-employee services. Accordingly, equity classified stock-based compensation cost is measured at grant date, based on the fair value of the award, and is recognized as expense over the requisite service period. Liability classified stock-based compensation cost is remeasured at each reporting date, and is recognized over the requisite service period.

We elected to adopt the modified prospective application method as provided by SFAS 123R and, accordingly, financial statement amounts for the prior periods presented in these consolidated financial statements have not been restated. Compensation expense for awards with graded vesting provisions is recognized on a straight-line basis over the requisite service period of each separately vesting portion of the award.

We recorded stock-based compensation expense for the years ended December 31, 2006 and 2005 as follows, the components of which are further described in Note 13:

The following table shows what net income would have been if the fair value recognition provisions of SFAS 123 had been applied to all stock-based compensation awards for the year ended December 31, 2005.

Accounting for Sales of Units by a Subsidiary — In December 2005, we formed DCP Partners through the contribution of certain assets and investments in unconsolidated affiliates in exchange for common units, subordinated units and a 2% general partner interest. Concurrent with the formation, we sold approximately 58% of DCP Partners to the public, through an initial public offering, for proceeds of approximately $206 million, net of offering costs. We account for sales of units by a subsidiary under Staff Accounting Bulletin No. 51, or SAB 51, “Accounting for Sales of Stock of a Subsidiary.” Under SAB 51, companies may elect, via an accounting policy decision, to record a gain or loss on the sale of common equity of a subsidiary equal to the amount of proceeds received in excess of the carrying value of the units sold. Under SAB 51, a gain on the sale of subsidiary equity cannot be recognized until multiple classes of outstanding securities convert to common equity. As a result, we have deferred approximately $150 million of gain on sale of common units in DCP Partners as other long-term liabilities in the consolidated balance sheets. We will recognize this gain in earnings upon conversion of all of our subordinated units in DCP Partners to common units.

Income Taxes — We are structured as a limited liability company, which is a pass-through entity for U.S. income tax purposes. We own a corporation that files its own federal, foreign and state corporate income tax returns. The income tax expense related to this corporation is included in our income tax expense, along with state, local, franchise and margin taxes of the limited liability company and other subsidiaries. In addition, until July 1, 2005, we had Canadian subsidiaries that were subject to Canadian income taxes.

We follow the asset and liability method of accounting for income taxes. Under the asset and liability method, deferred income taxes are recognized for the tax consequences of temporary differences between the financial statement carrying amounts and the tax basis of the assets and liabilities.

New Accounting Standards — SFAS No. 159 “The Fair Value Option for Financial Assets and Financial Liabilities—including an amendment of FAS 115,” or SFAS 159. In February 2007, the FASB issued SFAS 159, which allows entities to choose, at specified election dates, to measure eligible financial assets and liabilities at fair value that are not otherwise required to be measured at fair value. If a company elects the fair value option for an eligible item, changes in that item’s fair value in subsequent reporting periods must be recognized in current earnings. SFAS 159 also establishes presentation and disclosure requirements designed to draw comparison between entities that elect different measurement attributes for similar assets and liabilities. SFAS 159 is effective for us on January 1, 2008. We have not assessed the impact of SFAS 159 on our consolidated results of operations, cash flows or financial position.

SFAS No. 157 “Fair Value Measurements,” or SFAS 157. In September 2006, the FASB issued SFAS 157, which provides a single definition of fair value, together with a framework for measuring it, and requires additional disclosure about the use of fair value to measure assets and liabilities. SFAS 157 emphasizes that fair value is a market-based measurement, not an entity-specific measurement, and sets out a fair value hierarchy with the highest priority being quoted prices in active markets. Under SFAS 157, fair value measurements are disclosed by level within that hierarchy. SFAS 157 will apply whenever another standard requires (or permits) assets or liabilities to be measured at fair value. SFAS 157 does not expand the use of fair value to any new circumstances. SFAS 157 is effective for us on January 1, 2008. We have not assessed the impact of SFAS 157 on our consolidated results of operations, cash flows or financial position.

SFAS No. 154 “Accounting Changes and Error Corrections,” or SFAS 154. In June 2005, the FASB issued SFAS 154, a replacement of APB Opinion No. 20, or APB 20, “Accounting Changes” and SFAS No. 3, “Reporting Accounting Changes in Interim Financial Statements.” Among other changes, SFAS 154 requires that a voluntary change in accounting principle be applied retrospectively with all prior period financial statements presented under the new accounting principle, unless it is impracticable to do so. SFAS 154 also (1) provides that a change in depreciation or amortization of a long-lived nonfinancial asset be accounted for as a change in estimate (prospectively) that was effected by a change in accounting principle, and (2) carries forward without change the guidance within APB 20 for reporting the correction of an error in previously issued financial statements and a change in accounting estimate. The adoption of SFAS 154 on January 1, 2006, did not have a material impact on our consolidated results of operations, cash flows or financial position.

FIN No. 48 “Accounting for Uncertainty in Income Taxes—An Interpretation of FASB Statement 109,” or FIN 48. In July 2006, the FASB issued FIN 48, which clarifies the accounting for uncertainty in income taxes recognized in financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes.” FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The provisions of FIN 48 are effective for us on January 1, 2007. The adoption of FIN 48 is not expected to have a material impact on our combined results of operations, cash flows or financial position.

EITF Issue No. 04-13 “Accounting for Purchases and Sales of Inventory with the Same Counterparty,” or EITF 04-13. In September 2005, the FASB ratified the EITF’s consensus on Issue 04-13, which requires an entity to treat sales and purchases of inventory between the entity and the same counterparty as one transaction for purposes of applying APB Opinion No. 29 when such transactions are entered into in contemplation of each other. When such transactions are legally contingent on each other, they are considered to have been entered into in contemplation of each other. The EITF also agreed on other factors that should be considered in determining whether transactions have been entered into in contemplation of each other. EITF 04-13 was applied to new arrangements that we entered into after March 31, 2006. The adoption of EITF 04-13 did not have a material impact on our consolidated results of operations, cash flows or financial position.

Staff Accounting Bulletin No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements, or SAB 108 — In September 2006, the SEC issued SAB 108 to address diversity in practice in quantifying financial statement misstatements. SAB 108 requires entities to quantify misstatements based on their impact on each of their financial statements and related disclosures. SAB 108 is effective as of the end of our 2006 fiscal year, allowing a one-time transitional cumulative effect adjustment to retained earnings as of January 1, 2006 for errors that were not previously deemed material, but are material under the guidance in SAB 108. The adoption of SAB 108 did not have a material impact on our consolidated results of operations, cash flows or financial position.

Acquisition of Various Gathering, Transmission and Processing Assets — In the fourth quarter of 2005, we entered into an agreement to purchase certain Federal Energy Regulatory Commission, or FERC, regulated pipeline and compressor station assets in Kansas, Oklahoma and Texas for approximately $50 million. We did not receive regulatory approval from the FERC to purchase the assets as non-jurisdictional gathering, but we are proceeding to file with the FERC for a certificate to operate these assets as intrastate pipeline. This acquisition is expected to close in the second half of 2007.

Acquisition of Additional Equity Interests — In December 2006, we acquired an additional 33.33 % interest in Main Pass Oil Gathering Company, or Main Pass, for approximately $30 million. We now own 66.67% of Main Pass with one other partner. Main Pass is a joint venture whose primary operation is a crude oil gathering pipeline system in the Gulf of Mexico.

In November 2006, we purchased the remaining 16% minority interest in Dauphin Island Gathering Partners, or DIGP, for $7 million. DIGP was owned 84% by us prior to this transaction, and subsequent to this transaction, is owned 100% by us. DIGP owns gathering and transmission assets in the Gulf Coast.

In December 2005, we purchased an additional 6.67% interest in Discovery Producer Services, LLC, or Discovery, from Williams Energy, LLC for a purchase price of $13 million. Discovery is an unconsolidated affiliate, which, prior to this transaction, was 33.33% owned by us, and subsequent to this transaction is 40% owned by us. Discovery owns and operates an interstate pipeline, a condensate handling facility, a cryogenic gas processing plant and other gathering assets in deepwater offshore Louisiana.

Disposition of Various Gathering, Transmission and Processing Assets — In December 2005, based upon management’s assessment of the probable disposition of certain plant, gathering and transmission assets, we classified certain of these assets as held for sale, recorded in other non-current assets, consisting primarily of property, plant and equipment totaling $58 million at December 31, 2005. Assets at one location, totaling $48 million as of December 31, 2005, were sold in the first quarter of 2006 for $76 million and we recognized a gain of $28 million. Assets at another location, totaling $9 million as of December 31, 2005, were sold in the first quarter of 2006 for $9 million and we recognized no gain or loss.

In August 2005, we sold certain gas gathering facilities in Kansas and Oklahoma for a sales price of approximately $11 million. No gain or loss was recognized.

In February 2005, we exchanged certain processing plant assets in Wyoming for certain gathering assets and related gathering contracts in Oklahoma of equivalent fair value.

In February 2005, we sold certain gathering, compression, fractionation, processing plant and transportation assets in Wyoming for approximately $28 million.

Disposition of Equity Interests — In February 2005, we sold our general partner interest in TEPPCO to Enterprise GP Holdings L.P., an unrelated third party, for $1,100 million in cash and recognized a gain of $1,137 million. The cash proceeds from this transaction were received in February 2005 and loaned to Duke Energy and ConocoPhillips in amounts equal to their ownership percentages in the Company at that time. The loans were made under the terms of revolving credit facilities established in February 2005 with Duke Capital LLC, an affiliate of Duke Energy, and ConocoPhillips in the amounts of $767 million and $333 million, respectively. ConocoPhillips repaid its outstanding borrowings in full in March 2005. Duke Capital, LLC repaid its outstanding borrowings in full in July 2005.

Distribution of Canadian Business to Duke Energy — In July 2005, as part of the 50-50 Transaction, we distributed to Duke Energy substantially all of our Canadian business. These assets comprised a component of the Company for purposes of reporting discontinued operations. The results of operations and cash flows related to these assets have been reclassified to discontinued operations for all periods presented. The following is a summary of the net assets distributed to Duke Energy on the closing date of July 1, 2005 (millions):

We routinely sell assets that comprise a component of the Company, and are recorded as discontinued operations, but are not individually significant. The results of operations and cash flows related to these assets have been reclassified to discontinued operations for all periods presented.

There were no assets accounted for as discontinued operations for the year ended December 31, 2006. The following table sets forth selected financial information associated with assets accounted for as discontinued operations for the year ended December 31, 2005:

The following table represents the unrealized gains and unrealized losses on mark-to-market and hedging instruments with affiliates as of December 31:

The following table summarizes the transactions with Duke Energy, ConocoPhillips, and other unconsolidated affiliates as described below for the years ended December 31:

Services Agreement — Under a services agreement, Duke Energy and certain of its subsidiaries provided us with various staff and support services, including information technology products and services, payroll, employee benefits, property taxes, media relations, printing and records management. Additionally, we used other Duke Energy services subject to hourly rates, including legal, insurance, internal audit, tax planning, human resources and security departments.

In connection with the Spectra spin, we will need to transfer responsibility for all services previously provided to us by Duke Energy to our corporate operations, or transition these services either to Spectra or to third party service providers.

Included on the consolidated balance sheets in other non-current assets—affiliates as of December 31, 2006, are insurance recovery receivables of $47 million, and included in accounts receivable—affiliates as of December 31, 2006 and 2005, are other receivables of $8 million and $39 million, respectively, from an insurance provider that is a subsidiary of Duke Energy. During the years ended December 31, 2006 and 2005, we recorded hurricane related business interruption insurance recoveries of $1 million and $3 million, respectively, included in the consolidated statements of operations and comprehensive income as sales of natural gas and petroleum products.

In the fourth quarter of 2006, an insurance provider that is a subsidiary of Duke Energy agreed to settle an insurance claim, related to a damaged underground storage facility, for approximately $21 million. We had recorded a receivable in 2005 related to this claim for approximately $4 million. Upon receipt of the cash in December 2006, we relieved the receivable and recorded business interruption insurance recoveries of approximately $16 million, included in the consolidated statements of operations and comprehensive income as transportation, storage and processing.

Commodity Transactions — We sell a portion of our residue gas and NGLs to, purchase raw natural gas and other petroleum products from, and provide gathering and transportation services to Duke Energy and Spectra Energy and their subsidiaries. Management anticipates continuing to purchase and sell these commodities and provide these services to Spectra Energy in the ordinary course of business.

Long-term NGLs Purchases Contract and Transactions — We sell a portion of our residue gas and NGLs to ConocoPhillips and CP Chem, a 50% equity investment of ConocoPhillips (see Note 1). In addition, we purchase raw natural gas from ConocoPhillips. Under the NGL Output Purchase and Sale Agreement, or the CP Chem NGL Agreement, between us and CP Chem, CP Chem has the right to purchase at index-based prices substantially all NGLs produced by our various processing plants located in the Mid-Continent and Permian Basin regions, and the Austin Chalk area, which include approximately 40% of our total NGL production. The CP Chem NGL Agreement also grants CP Chem the right to purchase at index-based prices certain quantities of NGLs produced at processing plants that are acquired and/or constructed by us in the future in various counties in the Mid-Continent and Permian Basin regions, and the Austin Chalk area. The primary term of the agreement is effective until January 1, 2015. We anticipate continuing to purchase and sell these commodities and provide these services to ConocoPhillips and CP Chem in the ordinary course of business.

In February 2005, we sold our general partner interest in TEPPCO to Enterprise GP Holdings L.P., an unrelated third party, for $1,100 million in cash and recognized a gain of $1,137 million. The cash proceeds from this transaction were received in February 2005 and loaned to Duke Energy and ConocoPhillips in amounts equal to their ownership percentages in the Company at that time. The loans were made under the terms of revolving credit facilities established in February 2005 with Duke Capital LLC, an affiliate of Duke Energy, and ConocoPhillips in the amounts of $767 million and $333 million, respectively. ConocoPhillips repaid their outstanding borrowings in full in March 2005. Duke Capital LLC repaid their outstanding borrowings in full in July 2005.

We sell a portion of our residue gas and NGLs to, purchase raw natural gas and other petroleum products from, and provide gathering and transportation services to, unconsolidated affiliates. We anticipate continuing to purchase and sell these commodities and provide these services to unconsolidated affiliates in the ordinary course of business.

Revenue for goods and services provided but not invoiced to affiliates is estimated each month and recorded along with related purchases of goods and services used but not invoiced. These estimates are generally based on estimated commodity prices, preliminary throughput measurements and allocations and contract data. Actual invoices for the current month are issued in the following month and differences from estimated amounts are recorded. There are no material differences from the actual amounts invoiced subsequent to year end relating to estimated revenues and purchases recorded at December 31, 2006 and 2005.

Short-term and restricted investments — At December 31, 2006 and 2005, we had $437 million and $627 million, respectively, of short-term investments. These instruments are classified as available-for-sale securities under SFAS 115 as management does not intend to hold them to maturity nor are they bought and sold with the objective of generating profits on short-term differences in price. The carrying value of these instruments approximates their fair value as the interest rates re-set on a daily, weekly or monthly basis.

In July 2005, ConocoPhillips contributed cash of $398 million to our Company. This cash was invested in financial instruments as described above. Under the terms of the amended and restated LLC Agreement, however, proceeds from this contribution were designated for the acquisition or improvement of property, plant and equipment. As this cash was to be used to acquire non-current assets, we had $0 and $264 million, respectively, classified as a long-term asset, as restricted investments, on the consolidated balance sheets

at December 31, 2006 and 2005. At December 31, 2006 and 2005, we had restricted investments of $102 million and $100 million, respectively, consisting of collateral for DCP Partners’ term loan.

Property, plant and equipment by classification was as follows as of December 31:

Depreciation expense for 2006 and 2005 was $275 million and $278 million, respectively. Interest capitalized on construction projects in 2006 and 2005, was approximately $3 million and $2 million, respectively. At December 31, 2006, we had non-cancelable purchase obligations of approximately $27 million for capital projects expected to be completed in 2007. In addition, property, plant and equipment includes $10 million and $13 million of non-cash additions for the years ended December 31, 2006 and 2005, respectively.

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

We perform an annual goodwill impairment test, and update the test during interim periods if events or circumstances occur that would more likely than not reduce the fair value of a reporting unit below its carrying amount. We use a discounted cash flow analysis supported by market valuation multiples to perform the assessment. Key assumptions in the analysis include the use of an appropriate discount rate, estimated future cash flows and an estimated run rate of general and administrative costs. In estimating cash flows, we incorporate current market information, as well as historical and other factors, into our forecasted commodity prices.

We completed our annual goodwill impairment test as of August 31, 2006. We also tested goodwill for impairment in July 2005 upon the distribution of substantially all of our Canadian business to Duke Energy, in conjunction with the 50-50 Transaction. These goodwill

impairment tests were performed by comparing our reporting units’ estimated fair values to their carrying, or book, values. These valuations indicated our reporting units’ fair values were in excess of their carrying, or book, values; therefore, we have determined that there is no indication of impairment. There were no impairments of goodwill for the years ended December 31, 2006 and 2005.

During 2005, we recorded an adjustment to properly account for deferred taxes established as a result of purchase business combinations that occurred during 2001. As a result of this adjustment, goodwill and deferred income tax liabilities decreased by approximately $11 million and $3 million, respectively, and property, plant and equipment, net, increased by $8 million.

In July 2005, as part of the 50-50 Transaction, we distributed to Duke Energy substantially all of our Canadian business. Included in the distribution was $18 million of goodwill, which was determined based on the relative fair value of the Canadian business to the fair value of the Natural Gas Services reporting unit.

The gross carrying amount and accumulated amortization for commodity sales and purchases contracts are as follows for the years ended December 31:

During the years ended December 31, 2006 and 2005, we recorded amortization expense associated with commodity sales and purchases contracts of $9 million. The remaining amortization periods for these intangibles range from less than one year to 20 years with a weighted average remaining period of approximately 7 years.

Estimated amortization for these contracts for the next five years and thereafter is as follows:

We have investments in the following unconsolidated affiliates accounted for using the equity method:

Discovery Producer Services LLC — Discovery Producer Services LLC, or Discovery, owns and operates a 600 MMcf/d interstate pipeline, a condensate handling facility, a cryogenic gas processing plant, and other gathering assets in deepwater offshore Louisiana. In December 2005, we acquired an additional 6.67% interest in Discovery from Williams Energy, LLC for a purchase price of $13 million, bringing our total ownership to 40%. The deficit between the carrying amount of the investment and the underlying equity of Discovery of $49 million at December 31, 2006, is associated with, and is being depreciated over the life of, the underlying long-lived assets of Discovery.

Main Pass Oil Gathering Company — In December 2006, we acquired an additional 33.33% interest in Main Pass, a joint venture whose primary operation is a crude oil gathering pipeline system in the Main Pass East and Viosca Knoll Block areas in the Gulf of Mexico. We now own 66.67% of Main Pass with one other partner. Since Main Pass is not a variable interest entity, and we do not have the ability to exercise control, we continue to account for Main Pass under the equity method. The excess of the carrying amount of the investment over the underlying equity of Main Pass of $12 million at December 31, 2006, is associated with, and is being depreciated over the life of, the underlying long-lived assets of Main Pass.

Sycamore Gas System General Partnership — Sycamore Gas System General Partnership, or Sycamore, is a partnership formed for the purpose of constructing, owning and operating a gas gathering and compression system in Carter County, Oklahoma. The excess of the carrying amount of the investment over the underlying equity of Sycamore of $9 million at December 31, 2006, is associated with, and is being depreciated over the life of, the underlying long-lived assets of Sycamore.

Mont Belvieu I — Mont Belvieu I owns a 150 MBbl/d fractionation facility in the Mont Belvieu, Texas Market Center. The deficit between the carrying amount of the investment and the underlying equity of Mont Belvieu I of $11 million at December 31, 2006, is associated with, and is being depreciated over the life of, the underlying long-lived assets of Mont Belvieu I.

Tri-States NGL Pipeline, LLC — Tri-States NGL Pipeline, LLC, or Tri-States, owns 169 miles of NGL pipeline, extending from a point near Mobile Bay, Alabama to a point near Kenner, Louisiana. The deficit between the carrying amount of the investment and the underlying equity of Tri-States of $3 million at December 31, 2006, is associated with, and is being depreciated over the life of, the underlying long-lived assets of Tri-States. We own less than 20% interest in this Partnership, however, we exercise significant influence, therefore, this

investment is accounted for under the equity method of accounting in accordance with APB Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock.”

Black Lake Pipe Line Company — Black Lake Pipe Line Company, or Black Lake, owns a 317 mile long NGL pipeline, with a current capacity of approximately 40 MBbl/d. The pipeline receives NGLs from a number of gas plants in Louisiana and Texas. The NGLs are transported to Mont Belvieu fractionators. The deficit between the carrying amount of the investment and the underlying equity of Black Lake of $7 million at December 31, 2006, is associated with, and is being depreciated over the life of, the underlying long-lived assets of Black Lake.

Fox Plant, LLC — In May 2006, we purchased the remaining 50% interest in Fox Plant, LLC, a limited liability company formed for the purpose of constructing, owning, and operating a gathering facility and gas processing plant in Carter County, Oklahoma. Subsequent to May 2006, Fox Plant, LLC was accounted for as a consolidated subsidiary. Fox Plant, LLC is included in other unconsolidated affiliates in the above table as of December 31, 2005.

TEPPCO Partners, L.P. — In February 2005, we sold our general partner interest in TEPPCO to Enterprise GP Holdings L.P., an unrelated third party, for $1,100 million in cash and recognized a gain of $1,137 million.

Equity in earnings of unconsolidated affiliates amounted to the following for the years ended December 31:

The following summarizes combined financial information of unconsolidated affiliates for the years ended and as of December 31:

We have determined the following fair value amounts using available market information and appropriate valuation methodologies. Considerable judgment is required, however, in interpreting market data to develop the estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that we could realize in a current market exchange. The use of different market assumptions and/or estimation methods may have a material effect on the estimated fair value amounts.

The fair value of short-term investments, restricted investments, accounts receivable and accounts payable are not materially different from their carrying amounts because of the short-term nature of these instruments or the stated rates approximating market rates. Unrealized gains and unrealized losses on mark-to-market and hedging instruments are carried at fair value.

The estimated fair values of current debt, including current maturities of long-term debt, and long-term debt, with the exception of DCP Partners’ long-term debt, are determined by prices obtained from market quotes. The carrying value of DCP Partners’ long-term debt approximates fair value, as the interest rate is variable and reflects current market conditions.

Our asset retirement obligations relate primarily to the retirement of various gathering pipelines and processing facilities, obligations related to right-of-way easement agreements, and contractual leases for land use. We recognize the fair value of a liability for an asset retirement obligation 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.

We identified various assets as having an indeterminate life, for which there is no requirement to establish a fair value for future retirement obligations associated with such assets. These assets include certain pipelines, gathering systems and processing facilities. A liability for these asset retirement obligations will be recorded only if and when a future retirement obligation with a determinable life is identified. These assets have an indeterminate life because they are owned and will operate for an indeterminate future period when properly maintained. Additionally, if the portion of an owned plant containing asbestos were to be modified or dismantled, we would be legally required to remove the asbestos. We currently have no plans to take actions that would require the removal of the asbestos in these assets. Accordingly, the fair value of the asset retirement obligation related to this asbestos cannot be estimated and no obligation has been recorded.

The asset retirement obligation is adjusted each quarter for any liabilities incurred or settled during the period, accretion expense and any revisions made to the estimated cash flows. The following table summarizes changes in the asset retirement obligation, included in other long-term liabilities in the consolidated balance sheets, for the years ended December 31:

Debt Securities — In October 2006, we issued $300 million principal amount of 6.45% Senior Notes due 2036, or the 6.45% Notes, for proceeds of approximately $297 million (net of related offering costs). The 6.45% Notes mature and become due and payable on November 3, 2036. We will pay interest semiannually on May 3 and November 3 of each year, commencing May 3, 2007. The proceeds from this offering were used to repay our 5.75% Senior Notes that matured on November 15, 2006.

In October 2005, we issued $200 million principal amount of 5.375% Senior Notes Due 2015, or 5.375% Notes, for proceeds of $197 million (net of related offering costs). The 5.375% Notes mature on October 15, 2015. We pay interest semiannually on April 15 and October 15 of each year, commencing April 15, 2006. The proceeds from this offering were used to repay the August 2005 term loan facility discussed below.

In August 2005, we repaid the $600 million 7.5% Notes that were due on August 16, 2005. We repaid a portion of this debt with available cash and proceeds from the issuance of commercial paper, and refinanced a portion of this debt with the August 2005 term loan facility discussed below.

The debt securities mature and become payable on the respective due dates, and are not subject to any sinking fund provisions. Interest is payable semiannually. The debt securities are unsecured and are redeemable at our option.

Credit Facilities with Financial Institutions — On April 29, 2005, we entered into a credit facility, or the Facility, to replace a $250 million 364-day facility that was terminated on April 29, 2005. The Facility is used to support our commercial paper program, and for working capital and other general corporate purposes. In December 2005, we amended the Facility to amend the definition of consolidated capitalization to include minority interest, which is referred to in these financial statements as non-controlling interest. In October 2006, we amended the Facility to modify the change of control provisions to allow for the Spectra spin, to extend the maturity April 29, 2012, to amend the pricing, to remove the interest coverage covenant and to incorporate other minor revisions. Any outstanding borrowings under the Facility at maturity may, at our option, be converted to an unsecured one-year term loan. The Facility is a $450 million revolving credit facility, all of which can be used for letters of credit. The Facility requires us to maintain at all times a debt to total capitalization ratio of less than or equal to 60%. Draws on the Facility bear interest at a rate equal to, at our option and based on our current debt rating, either (1) LIBOR plus 0.35% per year for the initial 50% usage or LIBOR plus 0.45% per year if usage is greater than 50% or (2) the higher of (a) the Wachovia Bank prime rate per year and (b) the Federal Funds rate plus 0.5% per year. The Facility incurs an annual facility fee of 0.1% based on our credit rating on the drawn and undrawn portions. As of December 31, 2006, there were no borrowings or commercial paper outstanding, and there was approximately $5 million in letters of credit drawn against the Facility. As of December 31, 2005, there were no borrowings or commercial paper outstanding, and there were no letters of credit drawn against the Facility.

In August 2005, we entered into a credit agreement, or the Term Loan Facility, where we made a one-time request to borrow $200 million in the form of a term loan. We used this Term Loan Facility to repay a portion of our $600 million 7.5% Notes that matured on August 16, 2005. The Term Loan Facility was repaid in October 2005 with proceeds from the 5.375% Notes.

On December 7, 2005, DCP Partners entered into a 5-year credit agreement, or the DCP Partners’ Credit Agreement, with a $250 million revolving credit facility and a $100 million term loan facility. The DCP Partners’ Credit Agreement matures on December 7, 2010. At December 31, 2006 and 2005, there was $168 million and $110 million, respectively, outstanding on the revolving credit facility and $100 million outstanding on the term loan facility. The term loan facility is fully collateralized by investments in high-grade securities, which are classified as restricted investments on the accompanying consolidated balance sheet. Outstanding letters of credit on the DCP Partners’ Credit Agreement were less than $1 million as of December 31, 2006, and there were no letters of credit outstanding at December 31, 2005. The DCP Partners’ Credit Agreement requires DCP Partners to maintain at all times (commencing with the quarter ending March 31, 2006) a leverage ratio (the ratio of DCP Partners’ consolidated indebtedness to its consolidated EBITDA, in each case as is defined by the DCP Partners’ Credit Agreement) of less than or equal to 4.75 to 1.0 (and on a temporary basis for not more than three consecutive quarters following the acquisition of assets in the midstream energy business of not more than 5.25 to 1.0); and maintain at the end of each fiscal quarter an interest coverage ratio (defined to be the ratio of adjusted EBITDA, as defined by the DCP Partners’ Credit Agreement to be earnings before interest, taxes and depreciation and amortization and other non-cash adjustments, for the four most recent quarters to interest expense for the same period) of greater than or equal to 3.0 to 1.0. Indebtedness under the revolving credit facility bears interest, at our option, at either (1) the higher of Wachovia Bank’s prime rate or the federal funds rate plus 0.50% or (2) LIBOR plus an applicable margin, which ranges from 0.27% to 1.025% dependent upon the leverage level or credit rating. As of December 31, 2006, the $100 million term loan facility bears interest at LIBOR plus a rate per annum of 0.15%. The revolving credit facility incurs an annual facility fee of 0.08% to 0.35%, depending on the applicable leverage level or debt rating. This fee is paid on drawn and undrawn portions of the revolving credit facility.

Approximate future maturities of long-term debt in the year indicated are as follows at December 31, 2006:

12. Risk Management and Hedging Activities, Credit Risk and Financial Instruments

Commodity price risk — Our principal operations of gathering, processing, compression, transportation and storage of natural gas, and the accompanying operations of fractionation, transportation, gathering, treating, processing, storage and trading and marketing of NGLs create commodity price risk exposure due to market fluctuations in commodity prices, primarily with respect to the prices of NGLs, natural gas and crude oil. As an owner and operator of natural gas processing and other midstream assets, we have an inherent exposure to market variables and commodity price risk. The amount and type of price risk is dependent on the underlying natural gas contracts entered into to purchase and process raw natural gas. Risk is also dependent on the types and mechanisms for sales of natural gas and NGLs, and related products produced, processed, transported or stored.

Energy trading (market) risk — Certain of our subsidiaries are engaged in the business of trading energy related products and services, including managing purchase and sales portfolios, storage contracts and facilities, and transportation commitments for products. These energy trading operations are exposed to market variables and commodity price risk with respect to these products and services, and we may enter into physical contracts and financial instruments with the objective of realizing a positive margin from the purchase and sale of commodity-based instruments.

Interest rate risk — We enter into debt arrangements that have either fixed or floating rates, therefore we are exposed to market risks related to changes in interest rates. We periodically use interest rate swaps to hedge interest rate risk associated with our debt. Our primary goals include (1) maintaining an appropriate ratio of fixed-rate debt to floating-rate debt; (2) reducing volatility of earnings resulting from interest rate fluctuations; and (3) locking in attractive interest rates based on historical rates.

Credit risk — Our principal customers range from large, natural gas marketing services to industrial end-users for our natural gas products and services, as well as large multi-national petrochemical and refining companies, to small regional propane distributors for our NGL products and services. Substantially all of our natural gas and NGL sales are made at market-based prices. Approximately 40% of our NGL production is committed to ConocoPhillips and CP Chem under an existing 15-year contract, which expires in 2015. This concentration of credit risk may affect our overall credit risk, in that these customers may be similarly affected by changes in economic, regulatory or other factors. Where exposed to credit risk, we analyze the counterparties’ financial condition prior to entering into an agreement, establish credit limits and monitor the appropriateness of these limits on an ongoing basis. We may use master collateral agreements to mitigate credit exposure. Collateral agreements provide for a counterparty to post cash or letters of credit for exposure in excess of the established threshold. The threshold amount represents an open credit limit, determined in accordance with our credit policy. The collateral agreements also provide that the inability to post collateral is sufficient cause to terminate a contract and liquidate all positions. In addition, our standard gas and NGL sales contracts contain adequate assurance provisions, which allow us to suspend deliveries and cancel agreements, or continue deliveries to the buyer after the buyer provides security for payment in a satisfactory form.

As of December 31, 2006, we held cash or letters of credit of $83 million to secure future performance of financial or physical contracts, and had deposited with counterparties $7 million of such collateral to secure our obligations to provide future services or to perform under financial contracts. Collateral amounts held or posted may be fixed or may vary, depending on the value of the underlying contracts, and could cover normal purchases and sales, trading and hedging contracts. In many cases, we and our counterparties’ publicly disclose credit ratings, which may impact the amounts of collateral requirements.

Physical forward contracts and financial derivatives are generally cash settled at the expiration of the contract term. These transactions are generally subject to specific credit provisions within the contracts that would allow the seller, at its discretion, to suspend deliveries, cancel agreements or continue deliveries to the buyer after the buyer provides security for payment satisfactory to the seller.

Commodity hedging strategies — Historically, we have used commodity cash flow hedges, as specifically defined in SFAS 133, to reduce the potential negative impact that commodity price changes could have on our earnings and our ability to adequately plan for cash needed for debt service, capital expenditures and tax distributions. Our current strategy is to use cash flow hedges only for commodity price risk related to DCP Partners’ operations. Some of the assets operated by DCP Partners generate cash flows that are subject to volatility from fluctuating commodity prices. As a publicly traded master limited partnership, an important component of the strategy of DCP Partners is to generate consistent cash flow from its operations in order to pay distributions to its unitholders. For operations other than those of DCP Partners, we do not currently anticipate using cash flow hedges in the near future, because management believes cash flows will be sufficient to fund our business.

Commodity cash flow hedges — We have executed a series of derivative financial instruments, which have been designated as cash flow hedges of the price risk associated with forecasted sales of natural gas, NGLs and condensate through 2010, and the price risk associated with forecasted sales of condensate during 2011, related to assets of DCP Partners. Because of the strong correlation between NGL prices and crude oil prices, and the lack of liquidity in the NGL financial market, we have used crude oil swaps to hedge NGL price risk.

For the year ended December 31, 2006, amounts recognized as comprehensive income in the consolidated statements of operations and comprehensive income for changes in the fair value of these hedge instruments were gains of $4 million, and amounts recognized for the effects of any ineffectiveness were insignificant for the year ended December 31, 2006. For the year ended December 31, 2005, amounts recognized in the consolidated statements of operations and comprehensive income for changes in the fair value of these hedge instruments and for the effects of any ineffectiveness were not significant. During the year ended December 31, 2006, we reclassified $1 million in net gains (net of minority interest of $2 million) to the consolidated statements of operations and comprehensive income as a result of settlements. No derivative gains or losses were reclassified from AOCI to current period earnings as a result of a change in the probability of forecasted transactions occurring, which would cause us to discontinue hedge treatment. The deferred balance in AOCI was a gain of $3 million at December 31, 2006, and was insignificant at December 31, 2005. As of December 31, 2006, $1 million of deferred net gains on derivative instruments in AOCI are expected to be reclassified into earnings during the next 12 months

as the hedged transactions impact earnings; however, due to the volatility of the commodities markets, the corresponding value in AOCI is subject to change prior to its reclassification into earnings.

Commodity fair value hedges — We use fair value hedges to hedge exposure to changes in the fair value of an asset or a liability (or an identified portion thereof) that is attributable to fixed price risk. We may hedge producer price locks (fixed price gas purchases) and market locks (fixed price gas sales) to reduce our exposure to fixed price risk via swapping the fixed price risk for a floating price position (New York Mercantile Exchange or index based).

For the years ended December 31, 2006 and 2005, the gains or losses representing the ineffective portion of our fair value hedges were not significant. All components of each derivative’s gain or loss are included in the assessment of hedge effectiveness, unless otherwise noted. We did not have any firm commitments that no longer qualified as fair value hedge items and, therefore, did not recognize an associated gain or loss.

Interest rate cash flow hedges — During 2006, DCP Partners entered into interest rate swap agreements to convert $125 million of the indebtedness on their revolving credit facility to a fixed rate obligation, thereby reducing the exposure to market rate fluctuations. All interest rate swaps expire on December 7, 2010 and re-price prospectively approximately every 90 days. The differences to be paid or received under the interest rate swap agreements are recognized as an adjustment to interest expense. The interest rate swap agreements have been designated as cash flow hedges, and effectiveness is determined by matching the principal balance and terms with that of the specified obligation. The effective portions of changes in fair value are recognized in AOCI in the accompanying consolidated balance sheets. For the year ended December 31, 2006, amounts recognized in the consolidated statements of operations and comprehensive income for changes in the fair value of these hedge instruments were not significant, and there was no ineffectiveness recorded for the year ended December 31, 2006. At December 31, 2006, the gains deferred in AOCI related to these swaps were insignificant. At December 31, 2006, the amount of deferred net gains on derivative instruments in AOCI that are expected to be reclassified into earnings during the next 12 months as the hedged transactions occur are insignificant; however, due to the volatility of the interest rate markets, the corresponding value in AOCI is subject to change prior to its reclassification into earnings.

Prior to issuing fixed rate debt in August 2000, we entered into, and terminated, treasury locks and interest rate swaps to lock in the interest rate prior to it being fixed at the time of debt issuance. The losses realized on these agreements, which were terminated in 2000, are deferred into AOCI and amortized against interest expense over the life of the respective debt. The amount amortized to interest expense during the years ended December 31, 2006 and 2005, was $1 million for both periods. The deferred balance was a loss of $7 million and $8 million at December 31, 2006 and 2005, respectively. Approximately $1 million of deferred net losses related to these instruments in AOCI are expected to be reclassified into earnings during the next 12 months as the underlying hedged interest expense transaction occurs.

Interest rate fair value hedges — In October 2001, we entered into an interest rate swap to convert $250 million of fixed-rate debt securities, which were issued in August 2000, to floating rate debt. The interest rate fair value hedge was at a floating rate based on a six-month LIBOR, which was re-priced semiannually through the date of maturity, August 2005.

In August 2003, we entered into two additional interest rate swaps to convert $100 million of fixed-rate debt securities issued in August 2000 to floating rate debt. These interest rate fair value hedges are at a floating rate based on six-month LIBOR, which is re-priced semiannually through 2030. The swaps meet conditions, which permit the assumption of no ineffectiveness, as defined by SFAS 133. As such, for the life of the swaps no ineffectiveness will be recognized. As of December 31, 2006 and 2005, the fair value of the interest rate swaps was a $4 million and $8 million asset, respectively, which is included in the consolidated balance sheets as unrealized gains or losses on mark-to-market and hedging instruments with offsets to the underlying debt included in current maturities of long-term debt and long-term debt.

Commodity derivatives — trading and marketing — Our trading and marketing program is designed to realize margins related to fluctuations in commodity prices and basis differentials, and to maximize the value of certain storage and transportation assets. Certain of our subsidiaries are engaged in the business of trading energy related products and services including managing purchase and sales portfolios, storage contracts and facilities, and transportation commitments for products. These energy trading operations are exposed to market variables and commodity price risk with respect to these products and services, and may enter into physical contracts and financial instruments with the objective of realizing a positive margin from the purchase and sale of commodity-based instruments. We manage our trading and marketing portfolio with strict policies, which limit exposure to market risk, and require daily reporting to

management of potential financial exposure. These policies include statistical risk tolerance limits using historical price movements to calculate daily value at risk.

DCP Midstream, LLC Long-Term Incentive Plan, or 2006 Plan — Relative Performance Units — RPU’s generally cliff vest at the end of eight years, consisting of a three year performance period and a five year deferral period. The number of RPU’s that will ultimately vest range from 0% to 200% of the outstanding RPU’s, depending on the achievement of specified performance targets over a three year period ending on December 31, 2008. The final performance payout is determined by the compensation committee of our board of directors. At the end of the performance period, based on the market value of the RPU’s, we will create an account for each grantee in our deferred compensation plan. Payment of the grantee’s deferred compensation account will occur after a five year deferral period, the value of which is based on the value of the participant’s investment elections during the deferral period. Each RPU includes a dividend or distribution equivalent right, which will be paid in cash at the end of the performance period. Expense related to the RPUs for the year ended December 31, 2006, was not significant. At December 31, 2006, there was approximately $1 million of unrecognized compensation expense related to the RPU’s, which was calculated using an estimated forfeiture rate of 64%, and is expected to be recognized over a weighted-average period of 7.0 years. The following tables presents information related to RPUs:

Strategic Performance Units — SPU’s generally cliff vest at the end of three years. The number of SPU’s that will ultimately vest range from 0% to 150% of the outstanding SPU’s, depending on the achievement of specified performance targets over a three year period ending on December 31, 2008. The final performance payout is determined by the compensation committee of our board of directors. Each SPU includes a dividend or distribution equivalent right, which will be paid in cash at the end of the performance period. Expense related to the SPUs for the year ended December 31, 2006, was approximately $1 million. At December 31, 2006 there was approximately $3 million of unrecognized compensation expense related to the SPU’s, which was calculated using estimated forfeiture rates ranging from 12% to 32%, and is expected to be recognized over a weighted-average period of 2.0 years. The following tables presents information related to SPUs:

The estimate of RPU’s and SPU’s that are expected to vest is based on highly subjective assumptions that could potentially change over time, including the expected forfeiture rate and achievement of performance targets. Therefore the amounts of unrecognized compensation expense noted above does not necessarily represent the value that will ultimately be realized in our consolidated statements of operations and comprehensive income.

Phantom Units — Phantom Units generally cliff vest at the end of five years. Each Phantom Unit includes a dividend or distribution equivalent right, which is paid quarterly in arrears. Expense related to the Phantom Units for the year ended December 31, 2006, was not significant. At December 31, 2006 there was approximately $1 million of unrecognized compensation expense related to the Phantom Units, which was calculated using an estimated forfeiture rate of 19%, and is expected to be recognized over a weighted-average period of 4.0 years. The following table presents information related to Phantom Units:

DCP Partners’ Phantom Units — The DCP Partners’ Phantom Units constitute a notional unit equal to the fair value of a common unit of DCP Partners, which generally cliff vest at December 31, 2008. Each DCP Partners’ Phantom Unit includes a distribution equivalent right, which is paid quarterly in arrears. Expense related to the DCP Partners’ Phantom Units for the year ended December 31, 2006, was not significant. At December 31, 2006 there was approximately $1 million of unrecognized compensation expense related to the DCP Partners’ Phantom Units, which was calculated using estimated forfeiture rates ranging from 12% to 32%, and is expected to be recognized over a weighted-average period of 2.0 years. The following table presents information related to the DCP Partners’ Phantom Units:

During the year ended December 31, 2006, no awards under the 2006 Plan were forfeited, vested or settled.

DCP Partners’ Long-Term Incentive Plan, or DCP Partners’ Plan — Performance Units — Performance Units generally cliff vest at the end of a three year performance period. The number of Performance Units that will ultimately vest range from 0% to 150% of the outstanding Performance Units, depending on the achievement of specified performance targets over a three year period ending on December 31, 2008. The final performance percentage payout is determined by the compensation committee of DCP Partners’ board of directors. Each Performance Unit includes a distribution equivalent right, which will be paid in cash at the end of the performance period. Expense related to the Performance Units for the year ended December 31, 2006, was not significant. At December 31, 2006, there was approximately $1 million of unrecognized compensation expense related to the Performance Units, which is expected to be recognized over a weighted-average period of 2.0 years. The following tables presents information related to the Performance Units:

The estimate of Performance Units that are expected to vest is based on highly subjective assumptions that could potentially change over time, including the expected forfeiture rate and achievement of performance targets. Therefore the amount of unrecognized compensation expense noted above does not necessarily represent the value that will ultimately be realized in our consolidated statements of operations and comprehensive income.

Phantom Units — Of the Phantom Units, 16,700 units will vest upon the three year anniversary of the grant date and 8,000 units vest ratably over three years. Each Phantom Unit includes a distribution equivalent right which is paid quarterly in arrears. Expense related to the Phantom Units for the year ended December 31, 2006, was not significant. At December 31, 2006, estimated unrecognized compensation expense related to the Phantom Units was not significant. The following tables presents information related to the Phantom Units:

The estimate of Phantom Units that are expected to vest is based on highly subjective assumptions that could potentially change over time, including the expected forfeiture rate. Therefore the amount of unrecognized compensation expense noted above does not necessarily represent the value that will ultimately be realized in our consolidated statements of operations and comprehensive income.

All awards issued under the 2006 Plan and the DCP Partners’ Plan are intended to be settled in cash upon vesting. Compensation expense is recognized ratably over each vesting period, and will be remeasured quarterly for all awards outstanding until the units are vested. The fair value of all awards is determined based on the closing price of the relevant underlying securities at each measurement date. During the year ended December 31, 2006, no awards were vested or settled.

Duke Energy 1998 Plan — Under its 1998 Plan, Duke Energy granted certain of our key employees stock options, phantom stock awards, stock-based performance awards and other stock awards to be settled in shares of Duke Energy’s common stock. Upon execution of the 50-50 Transaction in July 2005, our employees incurred a change in status from Duke Energy employees to non-employees. As a result, we ceased accounting for these awards under APB 25 and FIN 44, and began accounting for these awards in accordance with EITF 96-18, using the fair value method prescribed in SFAS 123. No awards have been and we do not expect to settle any awards granted under the 1998 Plan with cash.

Stock Options — Under the 1998 Plan, the exercise price of each option granted could not be less than the market price of Duke Energy’s common stock on the date of grant. Vesting periods range from immediate to four years with a maximum option term of 10 years. Effective July 1, 2005, these options were accounted for in accordance with EITF 96-18, using the fair value method prescribed in SFAS 123. As a result, compensation expense subsequent to July 1, 2005, is recognized based on the change in the fair value of the stock options at each reporting date until vesting.

The following tables show information regarding options to purchase Duke Energy’s common stock granted to our employees.

The total intrinsic value of options exercised during the year ended December 31, 2006 and 2005, was approximately $3 million and $2 million, respectively. As of December 31, 2006, all compensation expense related to these awards has been recognized.

Stock-Based Performance Awards — Stock-based performance awards outstanding under the 1998 Plan vest over three years if certain performance targets are achieved. Duke Energy awarded 160,910 shares during the year ended December 31, 2005. There were no stock-based performance awards granted during the year ended December 31, 2006.

The following table summarizes information about stock-based performance awards activity during the year ended December 31, 2006:

As of December 31, 2006, the estimated unrecognized compensation expense related to these awards was approximately $1 million, which is expected to be recognized over a weighted-average period of less than 1 year. No awards were granted, vested or canceled during the year ended December 31, 2006.

Phantom Stock Awards — Phantom stock awards outstanding under the 1998 Plan vest over periods from one to five years. Duke Energy awarded 128,850 shares during the year ended December 31, 2005. There were no phantom stock awards granted during the year ended December 31, 2006.

The following table summarizes information about phantom stock awards activity during the year ended December 31, 2006:

The total fair value of the phantom stock awards that vested during the year ended December 31, 2006 and 2005 was approximately $2 million and less than $1 million, respectively. As of December 31, 2006, the estimated unrecognized compensation expense related to these awards was approximately $1 million, which is expected to be recognized over a weighted-average period of 2.7 years. No awards were granted or canceled during the year ended December 31, 2006.

Other Stock Awards—Other stock awards outstanding under the 1998 Plan vest over periods from one to five years. Duke Energy granted 3,000 other stock awards during the year ended December 31, 2005. There were no other stock awards granted during the year ended December 31, 2006.

The following table summarizes information about other stock awards activity during the year ended December 31, 2006:

The total fair value of the other stock awards that vested during the years ended December 31, 2006 and 2005 was not significant. As of December 31, 2006, the estimated unrecognized compensation expense related to these awards was not significant, and is expected to be recognized over a weighted-average period of less than 1 year. No awards were granted or canceled during the year ended December 31, 2006.

All Company employees who are 18 years old and work at least 20 hours per week are eligible for participation in our 401(k) and retirement plan, to which we contributed 4% of each eligible employee’s qualified earnings, through December 31, 2006. Effective January 1, 2007, we began contributing a range of 4% to 7% of each eligible employee’s qualified earnings, based on years of service. Additionally, we match employees’ contributions in the plan up to 6% of qualified earnings. During 2006 and 2005, we expensed plan contributions of $15 million.

We offer certain eligible executives the opportunity to participate in the DCP Midstream LP’s Non-Qualified Executive Deferred Compensation Plan. This plan allows participants to defer current compensation on a pre-tax basis and to receive tax deferred earnings on such contributions. The plan also has make-whole provisions for plan participants who may otherwise be limited in the amount that we can contribute to the 401(k) plan on the participant’s behalf. All amounts contributed to or earned by the plan’s investments are held in a trust account for the benefit of the participants. The trust and the liability to the participants are part of our general assets and liabilities, respectively.

We are structured as a limited liability company, which is a pass-through entity for United States income tax purposes. We own a corporation that files its own federal, foreign and state corporate income tax returns. The income tax expense related to this corporation is included in our income tax expense, along with state, local, franchise, and margin taxes of the limited liability company and other subsidiaries. In addition, until July 1, 2005, we had Canadian subsidiaries that were subject to Canadian income taxes. Taxes associated with these subsidiaries have been reclassified to discontinued operations for year ended December 31, 2005.

In May 2006, the State of Texas enacted a new margin-based franchise tax law that replaces the existing franchise tax. This new tax is commonly referred to as the Texas margin tax. Corporations, limited partnerships, limited liability companies, limited liability partnerships and joint ventures are examples of the types of entities that are subject to the new tax.

As a result of the change in Texas franchise law, our tax status in the state of Texas has changed from non-taxable to taxable. The tax is considered an income tax for purposes of adjustments to the deferred tax liability. The tax is determined by applying a tax rate to a base that considers both revenues and expenses. The Texas margin tax becomes effective for franchise tax reports due on or after January 1, 2008. The 2008 tax will be based on revenues earned during the 2007 fiscal year.

The Texas margin tax is assessed at 1% of taxable margin apportioned to Texas. We have computed taxable margin as total revenue less cost of goods sold. Based on information currently available, we recorded a deferred tax liability of $18 million in 2006. The deferred tax liability is recorded as non-current in the consolidated balance sheets as of December 31, 2006, and as a non-cash offset to income tax expense in the consolidated statements of operations and comprehensive income for the year ended December 31, 2006.

Temporary differences for our gross deferred tax assets of $4 million primarily relate to basis differences between property, plant and equipment, and investments in unconsolidated affiliates. Temporary differences for our gross deferred tax liabilities of $17 million primarily relate to basis differences between property, plant and equipment.

Our effective tax rate differs from statutory rates, primarily due to our being structured as a limited liability company, which is a pass-through entity for United States income tax purposes, while being treated as a taxable entity in certain states.

Litigation — The midstream industry has seen a number of class action lawsuits involving royalty disputes, mismeasurement and mispayment allegations. Although the industry has seen these types of cases before, they were typically brought by a single plaintiff or small group of plaintiffs. A number of these cases are now being brought as class actions. We are currently named as defendants in some of these cases. Management believes we have meritorious defenses to these cases and, therefore, will continue to defend them vigorously. These class actions, however, can be costly and time consuming to defend. We are also a party to various legal, administrative and regulatory proceedings that have arisen in the ordinary course of our business.

In December 2006, El Paso E&P Company, L.P., or El Paso, filed a lawsuit against one of our subsidiaries, DCP Assets Holding, LP and an affiliate of DCP Midstream GP, LP, in District Court, Harris County, Texas. The litigation stems from an ongoing commercial dispute involving DCP Midstream Partners’ Minden processing plant that dates back to August 2000. El Paso claims damages, including interest, in the amount of $6 million in the litigation, the bulk of which stems from audit claims under our commercial contract. It is not possible to predict whether we will incur any liability or to estimate the damages, if any, we might incur in connection with this matter. Management does not believe the ultimate resolution of this issue will have a material adverse effect on our consolidated results of operations, financial position or cash flows.

In November 2006, we received a demand associated with the alleged migration of acid gas from a storage formation into a third party producing formation. The plaintiff seeks a broad array of remedies, including a purchase of the plaintiff’s lease rights. We conducted an investigation using a geotechnical consulting firm and believe that acid gas is migrating from the storage formation into the producing formation. We could be liable for damages related to the diminution in market value to the leases, if any, caused by the migration of the acid gas. At this time, it is not possible to predict the ultimate damages, if any, that we might incur in connection with this matter.

Management currently believes that these matters, taken as a whole, and after consideration of amounts accrued, insurance coverage and other indemnification arrangements, will not have a material adverse effect upon our consolidated results of operations, financial position or cash flows.

General Insurance — In 2005, we carried all of our insurance coverage with an affiliate of Duke Energy. Beginning in 2006, we elected to carry only property and excess liability insurance coverage with an affiliate of Duke Energy and an affiliate of ConocoPhillips, however, effective August 2006, we no longer carry insurance coverage with an affiliate of Duke Energy. Our remaining insurance coverage is with an affiliate of ConocoPhillips and a third party insurer. Our insurance coverage includes (1) commercial general public liability insurance for liabilities arising to third parties for bodily injury and property damage resulting from our operations; (2) workers’ compensation liability coverage to required statutory limits; (3) automobile liability insurance for all owned, non-owned and hired vehicles covering liabilities to third parties for bodily injury and property damage, and (4) property insurance covering the replacement value of all real and personal property damage, including damages arising from boiler and machinery breakdowns, earthquake, flood damage and business

interruption/extra expense. All coverages are subject to certain deductibles, terms and conditions common for companies with similar types of operations. Property insurance deductibles are currently $1 million for onshore or non-hurricane related incidents or up to $5 million per occurrence for hurricane related incidents. We also maintain excess liability insurance coverage above the established primary limits for commercial general liability and automobile liability insurance. Casualty insurance deductibles are currently $1 million per occurrence. The cost of our general insurance coverages increased over the past year reflecting the adverse conditions of the insurance markets.

During the third quarter of 2004, certain assets, located in the Gulf Coast, were damaged as a result of hurricane Ivan. The resulting losses are expected to be covered by insurance, subject to applicable deductibles for property and business interruption. Insurance recovery receivables related to hurricane Ivan included on the consolidated balance sheets in other non-current assets—affiliates as of December 31, 2006, are $25 million, and included in accounts receivable—affiliates as of December 31, 2006 and 2005, are $3 million and $28 million, respectively, from an insurance provider that is a subsidiary of Duke Energy.

During the third quarter of 2005, hurricanes Katrina and Rita forced us to temporarily shut down our operations at certain assets located in Alabama, Louisiana, Texas and New Mexico, however, substantially all of our facilities have resumed pre-hurricane levels of capacity utilization. Several of our assets sustained property damage, including some of our operating equipment on a platform in the Gulf of Mexico. A portion of the resulting lost revenues and property damages are covered by our insurance, subject to applicable deductibles. The financial impact of recent hurricanes has increased market rates for insurance coverage; however, these increases did not have a material adverse effect on our consolidated results of operations, financial position or cash flows. Insurance recovery receivables related to hurricane Katrina included on the consolidated balance sheets in other non-current assets—affiliates as of December 31, 2006 are $21 million, and included in accounts receivable—affiliates as of December 31, 2006 and 2005, are $2 million and $5 million, respectively, from an insurance provider that is a subsidiary of Duke Energy. Included in other non-current assets—affiliates as of December 31, 2006, are insurance recovery receivables related to hurricane Rita of $1 million at December 31, 2006. The balance at December 31, 2005, was not significant. Based on recent negotiations, we have reclassified a portion of these hurricane insurance receivables as non-current at December 31, 2006.

During the years ended December 31, 2006 and 2005, we recorded business interruption insurance recoveries related to these hurricanes of $1 million and $3 million, respectively, in the consolidated statements of operations and comprehensive income as sales of natural gas and petroleum products.

Environmental — The operation of pipelines, plants and other facilities for gathering, transporting, processing, treating, or storing natural gas, NGLs and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of these facilities, we must comply with United States laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and disposal, and other environmental matters. The cost of planning, designing, constructing and operating pipelines, plants, and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements, the issuance of injunctions or restrictions on operation. Management believes that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on our consolidated results of operations, financial position or cash flows.

On July 20, 2006, the State of New Mexico Environment Department issued Compliance Orders to us that list air quality violations during the past five years at three of our owned or operated facilities in New Mexico. The orders allege a number of violations related to excess emissions from January 2001 to date and further require us to install flares for smokeless operations and to use the flares only for emergency purposes. The Compliance Orders seek a civil penalty but did not request a specific amount. We intend to contest these allegations. Management does not believe this will result in a material impact on our consolidated results of operations, cash flows or financial position.

Other Commitments and Contingencies — We utilize assets under operating leases in several areas of operations. Consolidated rental expense, including leases with no continuing commitment, amounted to $37 million and $36 million in 2006 and 2005, respectively. Rental expense for leases with escalation clauses is recognized on a straight line basis over the initial lease term.

Minimum rental payments under our various operating leases in the year indicated are as follows at December 31, 2006:

In September 2005, we signed a corporate guaranty, which was amended in December 2005 upon our purchase of an additional interest in the related unconsolidated affiliate, pursuant to which we are the guarantor of a maximum of $10 million of construction obligations. The original guaranty was $22 million as of December 31, 2005, and was reduced by construction payments of $12 million during the year ended December 31, 2006. The guaranty will expire upon completion and payment for construction of a pipeline expected to be completed during 2007. The fair value of this guarantee is not significant to our consolidated results of operations, financial position or cash flows.

We periodically enter into agreements for the acquisition or divestiture of assets. These agreements contain indemnification provisions that may provide indemnity for environmental, tax, employment, outstanding litigation, breaches of representations, warranties and covenants, or other liabilities related to the assets being acquired or divested. Claims may be made by third parties under these indemnification agreements for various periods of time depending on the nature of the claim. The effective periods on these indemnification provisions generally have terms of one to five years, although some are longer. Our maximum potential exposure under these indemnification agreements can vary depending on the nature of the claim and the particular transaction. We are unable to estimate the total maximum potential amount of future payments under indemnification agreements due to several factors, including uncertainty as to whether claims will be made under these indemnities. At both December 31, 2006 and 2005, we had a liability of approximately $1 million recorded for known liabilities related to outstanding indemnification provisions.

In March 2007, DCP Midstream Partners entered into a definitive agreement to acquire certain gathering and compression assets located in southern Oklahoma from Anadarko Petroleum Corporation, or Anadarko, for approximately $180 million, subject to customary closing conditions and certain regulatory approvals. DCP Midstream Partners paid an earnest deposit of $9 million when they entered into this agreement. If Anadarko terminates because DCP Midstream Partners materially breaches their representations, warranties or covenants under this agreement, Anadarko may retain this earnest deposit as liquidated damages. This deposit will be applied against the purchase price at the closing of this transaction, which is expected to occur in the second quarter of 2007. The remaining purchase price is expected to be funded by the issuance of DCP Midstream Partners’ partnership units and by proceeds from DCP Midstream Partners’ credit facility.

On January 24, 2007, DCP Partners announced the declaration of a cash distribution of $0.43 per unit, payable on February 14, 2007, to unitholders of record on February 7, 2007.

On January 2, 2007, Duke Energy created two separate publicly traded companies by spinning off their natural gas businesses, including their 50% ownership interest in us, to Duke Energy shareholders. As a result of this transaction, we are no longer 50% owned by Duke Energy. Duke Energy’s 50% ownership interest in us was transferred to a new company, Spectra Energy. We do not expect this transaction to have a material effect on our operations.

On January 1, 2007, we changed our name from Duke Energy Field Services, LLC to DCP Midstream, LLC, to coincide with the Spectra spin.

Exhibits filed herewith are designated by an asterisk (*). All exhibits not so designated are incorporated by reference to a prior filing, as indicated. Items constituting management contracts or compensatory plans or arrangements are designated by a double asterisk (**).

The total amount of securities of the registrant or its subsidiaries authorized under any instrument with respect to long-term debt not filed as an exhibit does not exceed 10% of the total assets of the registrant and its subsidiaries on a consolidated basis. The registrant agrees, upon request of the Securities and Exchange Commission, to furnish copies of any or all of such instruments to it.


North Carolina		56-0205520
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

526 South Church Street, Charlotte, North Carolina		28202-1803
(Address of principal executive offices)		(Zip Code)


Item		Page
PART I.

1.	BUSINESS	3

	GENERAL	3

	ENVIRONMENTAL MATTERS	4

1A.	RISK FACTORS	4

1B.	UNRESOLVED STAFF COMMENTS	9

2.	PROPERTIES	9

3.	LEGAL PROCEEDINGS	9

PART II.

5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	10

7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	11

7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	15

8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	16

9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	77

9A.	CONTROLS AND PROCEDURES	77

PART III.

14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	78

PART IV.

15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	79

	SIGNATURES	80

	EXHIBIT INDEX


	Years Ended December 31,
	2006		2005			Increase (Decrease)
Operating revenues	$	5,442	$	5,432		$	10
Operating expenses		4,353		4,183			170
Gains on sales of other assets and other, net		—		7			(7	)

Operating income		1,089		1,256			(167	)
Other income and expenses, net		98		15			83
Interest expense		299		292			7
Income tax expense from continuing operations		287		330			(43	)

Income from continuing operations		601		649			(48	)
Income from discontinued operations, net of tax		186		1,179			(993	)
Cumulative effect of change in accounting principle, net of tax		—		(4	)		4

Net income	$	787	$	1,824		$	(1,037	)


	Years Ended December 31,
	2006		2005			2004
Operating Revenues—Regulated Electric	$	5,442	$	5,432		$	5,070

Operating Expenses
Operation, maintenance and other		1,675		1,664			1,521
Fuel used in electric generation and purchased power		1,475		1,248			1,206
Depreciation and amortization		897		962			863
Property and other taxes		306		309			282
Total operating expenses		4,353		4,183			3,872
Gains on Sales of Other Assets and Other, net		—		7			3
Operating Income		1,089		1,256			1,201
Other Income and Expenses, net		98		15			11
Interest Expense		299		292			302
Income From Continuing Operations Before Income Taxes		888		979			910
Income Tax Expense from Continuing Operations		287		330			253
Income From Continuing Operations		601		649			657
Income From Discontinued Operations, net of tax		186		1,179			833
Income Before Cumulative Effect of Change in Accounting Principle		787		1,828			1,490
Cumulative Effect of Change in Accounting Principle, net of tax and minority interest		—		(4	)		—
Net Income		787		1,824			1,490
Dividends and Premiums on Redemption of Preferred and Preference Stock		—		12			9
Earnings Available For Member’s/Common Stockholders	$	787	$	1,812		$	1,481


	December 31,
	2006		2005
ASSETS
Current Assets
Cash and cash equivalents	$	38	$	511
Short-term investments		221		632
Receivables (net of allowance for doubtful accounts of $5 at December 31, 2006 and $127 at December 31, 2005)		679		2,580
Inventory		554		863
Assets held for sale		—		1,528
Unrealized gains on mark-to-market and hedging transactions		8		87
Other		208		1,756
Total current assets		1,708		7,957
Investments and Other Assets
Investments in unconsolidated affiliates		2		1,933
Nuclear decommissioning trust funds		1,775		1,504
Goodwill		—		3,775
Notes receivable		—		138
Unrealized gains on mark-to-market and hedging transactions		—		62
Assets held for sale		—		3,597
Investments in residential, commercial and multi-family real estate (net of accumulated depreciation of $17 at December 31, 2005)		—		1,281
Other		1,084		2,743
Total investments and other assets		2,861		15,033
Property, Plant and Equipment
Cost		22,660		40,823
Less accumulated depreciation and amortization		8,341		11,623
Net property, plant and equipment		14,319		29,200
Regulatory Assets and Deferred Debits
Deferred debt expense		193		269
Regulatory assets related to income taxes		396		1,338
Other		620		926
Total regulatory assets and deferred debits		1,209		2,533
Total Assets	$	20,097	$	54,723


												Accumulated Other Comprehensive Income (Loss)
	Common Stock Shares		Member’s Equity			Common Stock			Retained Earnings			Foreign Currency Adjustments (a)			Net Gains (Losses) on Cash Flow Hedges			Minimum Pension Liability Adjustment			Other			Total
Balance December 31, 2003	911		$	—		$	9,513		$	4,066		$	315		$	298		$	(444	)	$	—		$	13,748
Net income	—			—			—			1,490			—			—			—			—			1,490
Other Comprehensive Income
Foreign currency translation adjustments	—			—			—			—			279			—			—			—			279
Foreign currency translation adjustments reclassified into earnings as a result of the sale of Asia-Pacific Business	—			—			—			—			(54	)		—			—			—			(54	)
Net unrealized gains on cash flow hedges (b)	—			—			—			—			—			311			—			—			311
Reclassification into earnings from cash flow hedges (c)	—			—			—			—			—			(83	)		—			—			(83	)
Minimum pension liability adjustment (d)	—			—			—			—			—			—			28			—			28

Total comprehensive income																									1,971
Dividend reinvestment and employee benefits	5			—			128			—			—			—			—			—			128
Equity offering	41			—			1,625			—			—			—			—			—			1,625
Common stock dividends	—			—			—			(1,018	)		—			—			—			—			(1,018	)
Preferred and preference stock dividends	—			—			—			(9	)		—			—			—			—			(9	)
Other capital stock transactions, net	—			—			—			(4	)		—			—			—			—			(4	)
Balance December 31, 2004	957		$	—		$	11,266		$	4,525		$	540		$	526		$	(416	)	$	—		$	16,441
Net income	—			—			—			1,824			—			—			—			—			1,824
Other Comprehensive Income
Foreign currency translation adjustments (a)	—			—			—			—			306			—			—			—			306
Net unrealized gains on cash flow hedges (b)	—			—			—			—			—			413			—			—			413
Reclassification into earnings from cash flow hedges (c)	—			—			—			—			—			(1,026	)		—			—			(1,026	)
Minimum pension liability adjustment (d)	—			—			—			—			—			—			356			—			356
Other (e)	—			—			—			—			—			—			—			17			17

Total comprehensive income																									1,890
Dividend reinvestment and employee benefits	3			—			85			—			—			—			—			—			85
Stock repurchase	(33	)		—			(933	)		—			—			—			—			—			(933	)
Conversion of debt	1			—			28			—			—			—			—			—			28
Common stock dividends	—			—			—			(1,093	)		—			—			—			—			(1,093	)
Preferred and preference stock dividends	—			—			—			(12	)		—			—			—			—			(12	)
Other capital stock transactions, net	—			—			—			33			—			—			—			—			33
Balance December 31, 2005	928		$	—		$	10,446		$	5,277		$	846		$	(87	)	$	(60	)	$	17		$	16,439
Net income	—			429			—			358			—			—			—			—			787
Other Comprehensive Income
Foreign currency translation adjustments	—			—			—			—			59			—			—			—			59
Net unrealized gains on cash flow hedges (b)	—			—			—			—			—			7			—			—			7
Reclassification into earnings from cash flow hedges (c)	—			—			—			—			—			12			—			—			12
Other (e)	—			—			—			—			—			—			—			16			16
Inter-company Transfers (f)	—			—			—			—			(905	)		64			60			(33	)		(814	)

Total comprehensive income																									67
Dividend reinvestment and employee benefits	1			—			22			—			—			—			—			—			22
Stock repurchase	(2	)		—			(69	)		—			—			—			—			—			(69	)
Common stock dividends	—			—			—			(289	)		—			—			—			—			(289	)
Conversion of Duke Energy Carolinas to a limited liability company	(927	)		15,745			(10,399	)		(5,346	)		—			—			—			—			—
Transfer of equity interest to Duke Capital	—			(11,556	)		—			—			—			—			—			—			(11,556	)
Capital contributions from parent	—			200			—			—			—			—			—			—			200
Conversion of debt to equity	—			632			—			—			—			—			—			—			632
Tax benefit due to conversion of debt to equity	—			34			—			—			—			—			—			—			34
Inter-company advance forgiveness	—			496			—			—			—			—			—			—			496
Other	—			4			—			—			—			—			—			—			4
Balance December 31, 2006	—		$	5,984		$	—		$	—		$	—		$	(4	)	$	—		$	—		$	5,980


	December 31,
	2006		2005
	(in millions)
Materials and supplies	$	329	$	434
Natural gas		—		269
Coal held for electric generation		225		115
Petroleum products		—		45

Total inventory	$	554	$	863


	Year Ended December 31, 2006		Year Ended December 31, 2005		Year Ended December 31, 2004
	(in millions)
Excise Taxes	$	123	$	121	$	116


	Unaffiliated Revenues		Segment EBIT/ Consolidated Earnings from Continuing Operations before Income Taxes			Depreciation and Amortization^(b)		Capital and Investment Expenditures^(b)		Segment Assets^(c)
	(in millions)
Year Ended December 31, 2006
Franchised Electric	$	5,442	$	1,391		$	897	$	1,768	$	20,097
Total reportable segments		5,442		1,391			897		1,768		20,097
Other		—		(284	)		—		—		—
Interest expense		—		(299	)		—		—		—
Interest income		—		80			—		—		—
Total consolidated	$	5,442	$	888		$	897	$	1,768	$	20,097

Year Ended December 31, 2005
Franchised Electric	$	5,432	$	1,495		$	962	$	1,350	$	18,739
Natural Gas Transmission		—		—			—		—		18,823
Field Services^(f)		—		—			—		—		1,377
Commercial Power^(e)		—		—			—		—		1,619
International Energy		—		—			—		—		2,962
Crescent		—		—			—		—		1,507
Total reportable segments		5,432		1,495			962		1,350		45,027
Other^(e)		—		(211	)		—		—		9,402
Eliminations and reclassifications		—		—			—		—		294
Interest expense		—		(292	)		—		—		—
Interest income and other^(d)		—		(13	)		—		—		—
Total consolidated	$	5,432	$	979		$	962	$	1,350	$	54,723

Year Ended December 31, 2004
Franchised Electric	$	5,070	$	1,467		$	863	$	1,126	$	18,062
Natural Gas Transmission		—		—			—		—		17,783
Field Services^(f)		—		—			—		—		6,265
Commercial Power^(e)		—		—			—		—		1,726
International Energy		—		—			—		—		3,058
Crescent		—		—			—		—		1,317
Total reportable segments		5,070		1,467			863		1,126		48,211
Other^(e)		—		(259	)		—		—		7,139
Eliminations and reclassifications		—		—			—		—		420
Interest expense		—		(302	)		—		—		—
Interest income and other^(d)		—		4			—		—		—
Total consolidated	$	5,070	$	910		$	863	$	1,126	$	55,770


	U.S.		Canada		Latin America		Other Foreign		Consolidated
	(in millions)
2006
Consolidated revenues^(a)	$	5,442	$	—	$	—	$	—	$	5,442
Consolidated long-lived assets		16,612		—		—		—		16,612
2005
Consolidated revenues^(a)	$	5,432	$	—	$	—	$	—	$	5,432
Consolidated long-lived assets		29,658		10,544		2,241		228		42,671
2004
Consolidated revenues^(a)	$	5,070	$	—	$	—	$	—	$	5,070
Consolidated long-lived assets		30,960		9,902		2,136		233		43,231


	As of December 31,
	2006		2005		Recovery/Refund Period Ends
	(in millions)
Regulatory Assets^(a)
Net regulatory asset related to income taxes^(b)	$	396	$	1,338	^(l	⁾
ARO costs^(c)		463		546	2043
Deferred debt expense^(d)		141		166	2039
Vacation accrual^(c)		77		80	2007
Under-recovery of fuel costs^(f)(i)		61		—	2008
Regional Transmission Organization (RTO)^(q)		41		41	^(o	⁾
Other^(c)		28		148	^(p	⁾

Total Regulatory Assets	$	1,207	$	2,319

Regulatory Liabilities^(a)
Removal costs^(d)(h)	$	1,433	$	1,670	⁽ⁿ	⁾
Other deferred tax credits^(d)(f)(h)		—		8	^(f	⁾
Nuclear property and liability reserves^(d)(h)		173		167	2043
Purchased capacity costs ^(e)(j)		107		121	^(k	⁾
Demand-side management costs^(e)(h)		78		59	^(m	⁾
Over-recovery of fuel costs^(f)(g)		—		76	NA
North Carolina clean air compliance^(d)(h)		—		164	2011
Other^(h)		18		73	^(p	⁾

Total Regulatory Liabilities	$	1,809	$	2,338


	Ownership Share		Property, Plant, and Equipment		Accumulated Depreciation		Construction Work in Progress
	(in millions)
Catawba Nuclear Station (Units 1 and 2)	12.5	%	$	563	$	302	$	10


	For the Years Ended December 31,
	2006			2005			2004
	(in millions)
Current income taxes
Federal	$	290		$	372		$	127
State		48			61			32

Total current income taxes		338			433			159

Deferred income taxes
Federal		(41	)		(86	)		167
State		(1	)		(7	)		(62	)

Total deferred income taxes		(42	)		(93	)		105

Investment tax credit amortization		(9	)		(10	)		(11	)

Total income tax expense from continuing operations		287			330			253

Total income tax expense from discontinued operations		120			521			307
Total income tax benefit from cumulative effect of change in accounting principle		—			(1	)		—

Total income tax expense presented in Consolidated Statements of Operations	$	407		$	850		$	560


	Years Ended December 31,
	2006			2005
	(in millions)
Balance as of January 1,	$	2,058		$	1,926
Liabilities transferred to Duke Energy^(a)		(29	)		—
Liabilities settled		(6	)		(46	)
Accretion expense		139			131
Revisions in estimated cash flows		—			12
Adoption of FIN 47		—			35

Balance as of December 31,	$	2,162		$	2,058


Unit		Expiration Year
McGuire 1		2041
McGuire 2		2043
Catawba 1		2043
Catawba 2		2043
Oconee 1 and 2		2033
Oconee 3		2034


	December 31, 2006
	(in millions)
Other current assets—prepayment to Duke Energy^(a)	$	123
Other current assets—due from Duke Energy^(b)		24
Other current assets—due from Cinergy^(b)		3
Other current liabilities—due to Duke Energy Registration Services.^(c)		(316	)


	Three-months Ended March 31, 2006		Six-months Ended December 31, 2005
	(in millions)
Operating revenues	$	3,309	$	7,463
Operating expenses	$	2,994	$	6,814
Operating income	$	315	$	649
Net income	$	291	$	584


	December 31, 2005
	(in millions)
Current assets	$	2,706
Non-current assets	$	5,005
Current liabilities	$	3,068
Non-current liabilities	$	2,038
Minority interest	$	95


Severance Reserve	Balance at January 1, 2006		Provision/ Adjustments^(c) (d)		Noncash Adjustments^(e)			Cash Reductions^(f)			Balance at December 31, 2006
	(in millions)
Natural Gas Transmission	$	3	$	—	$	(3	)	$	—		$	—
Other		28		75		(28	)		(51	)		24

Total^(a)	$	31	$	75	$	(31	)	$	(51	)	$	24


	Balance at January 1, 2005		Provision/ Adjustments^(c)		Noncash Adjustments			Cash Reductions			Balance at December 31, 2005
Franchised Electric	$	4	$	—	$	(2	)	$	(2	)	$	—
Natural Gas Transmission		6		1		(1	)		(3	)		3
Field Services^(b)		—		1		(1	)		—			—
International Energy		1		—		(1	)		—			—
Other		4		26		—			(2	)		28

Total^(a)	$	15	$	28	$	(5	)	$	(7	)	$	31


	Balance at January 1, 2004		Provision/ Adjustments^(c)		Noncash Adjustments			Cash Reductions			Balance at December 31, 2004
Franchised Electric	$	60	$	—	$	(6	)	$	(50	)	$	4
Natural Gas Transmission		29		1		(6	)		(18	)		6
Field Services^(b)		6		1		—			(7	)		—
International Energy		6		—		(4	)		(1	)		1
Other		49		3		(5	)		(43	)		4

Total^(a)	$	150	$	5	$	(21	)	$	(119	)	$	15


			Operating Income
	Operating Revenues		Pre-tax Earnings		Income Tax Expense		Income From Discontinued Operations, Net of Tax
	(in millions)
Twelve Months Ended December 31, 2006
Spectra Energy Capital	$	2,275	$	306	$	120	$	186
Twelve Months Ended December 31, 2005
Spectra Energy Capital	$	13,381	$	1,700	$	521	$	1,179
Twelve Months Ended December 31, 2004
Spectra Energy Capital	$	17,551	$	1,140	$	307	$	833


	December 31, 2006		December 31, 2005
	(in millions)
Current assets	$	—	$	1,528
Investments and other assets		—		2,059
Property, plant and equipment, net		—		1,538

Total assets held for sale	$	—	$	5,125

Current liabilities	$	—	$	1,488
Long-term debt		—		61
Deferred credits and other liabilities		—		2,024

Total liabilities associated with assets held for sale	$	—	$	3,573


	Estimated Useful Life	December 31,
	Estimated Useful Life	2006			2005
	(Years)	(in millions)
Land	—	$	311		$	571
Plant—Regulated
Electric generation, distribution and transmission^(a)	20 – 125		19,874			18,935
Natural gas transmission and distribution	20 – 82		—			10,810
Gathering and processing facilities^(a)	20 – 25		—			1,570
Other buildings and improvements^(a)	16 – 90		336			388
Plant—Unregulated
Electric generation, distribution and transmission^(a)	20 – 125		—			3,869
Natural gas transmission and distribution	20 – 82		—			32
Gathering and processing facilities	20 – 25		—			678
Other buildings and improvements^(a)	16 – 90		—			27
Nuclear fuel	4		890			890
Equipment^(a)	3 – 40		207			669
Vehicles	3 – 25		25			125
Construction in process	—		677			946
Other^(a)	5 – 122		340			1,313

Total property, plant and equipment			22,660			40,823
Total accumulated depreciation—regulated^{(b), (c)}			(8,332	)		(10,721	)
Total accumulated depreciation—unregulated^(c)			(9	)		(902	)

Total net property, plant and equipment		$	14,319		$	29,200


	Weighted- Average Rate		Year Due	December 31,
	Weighted- Average Rate		Year Due	2006			2005
				(in millions)
Unsecured debt	5.8	%	2007 – 2032	$	3,105		$	12,600
Secured debt	5.8	%	2008		300			1,570
First and refunding mortgage bonds	4.6	%	2008 – 2027		1,214			1,214
Capital leases					—			10
Other debt^(a)	4.0	%	2010 – 2031		328			208
Commercial paper^(b)	5.4	%			300			383
Fair value hedge carrying value adjustment			2008 – 2032		31			58
Unamortized debt discount and premium, net					(8	)		(13	)

Total debt^(c)					5,270			16,030
Current maturities of long-term debt					(226	)		(1,400	)
Short-term notes payable and commercial paper^(d)					—			(83	)

Total long-term debt				$	5,044		$	14,547


				Amounts Outstanding
	Expiration Date	Credit Facilities Capacity		Commercial Paper		Letters of Credit		Total
Duke Energy Carolinas, LLC
$600 multi-year syndicated^{(a), (b), (c)}	June 2011			$	300	$	4	$	304
$75 three-year bi-lateral^{(a), (b)}	September 2009
$75 three-year bi-lateral^{(a), (b)}	September 2009

Total ^(d)		$	750	$	300	$	4	$	304


	Operating Leases
	(in millions)
2007	$	28
2008		33
2009		31
2010		30
2011		9
Thereafter		97

Total future minimum lease payments	$	228


	Year ended December 31, 2005			Year ended December 31, 2004
	(in millions, except per share amounts)
Earnings Available For Member’s/Common Stockholders, as reported	$	1,812		$	1,481

Add: stock-based compensation expense included in reported earnings available to common stockholders, net of related tax effects		30			16
Deduct: total stock-based compensation expense determined under fair value-based method for all awards, net of related tax effects		(32	)		(27	)

Pro forma earnings available for Member’s / Common Stockholders, net of related tax effects	$	1,810		$	1,470


	Options (in thousands)		Weighted- Average Exercise Price		Weighted- Average Remaining Life (in years)	Aggregate Intrinsic Value (in millions)
Outstanding at December 31, 2005	25,506		$	29
Granted	—			—
Exercised	(715	)		22
Forfeited or expired	(490	)		30

Outstanding at March 31, 2006	24,301			30	4.9	$	97
Options held by Spectra Energy Capital employees	(18,850	)		29
Granted	—			—
Exercised	(383	)		25
Forfeited or expired	(643	)		31

Outstanding at December 31, 2006	4,425			31	4.1	$	24

Exercisable at December 31, 2006	4,201		$	32	4.0	$	20

Options Expected to Vest	217		$	14	6.2	$	4


	Shares		Weighted Average Grant Date Fair Value
Number of Stock-based Performance Awards:
Outstanding at December 31, 2005	2,940,768		$	25
Granted	—			—
Vested	(114,000	)		27
Forfeited	(52,786	)		25
Canceled	—			—
Outstanding at March 31, 2006	2,773,982			25

Performance awards held by Spectra Energy Capital employees	(2,174,793	)		25
Granted	281,160			18
Vested	—			—
Forfeited	(190,626	)		22
Canceled	—			—

Outstanding at December 31, 2006	689,723		$	22

Stock-based Performance Awards Expected to Vest	661,237		$	22


	Shares		Weighted Average Grant Date Fair Value
Number of Phantom Stock Awards:
Outstanding at December 31, 2005	2,517,020		$	25
Granted	—			—
Vested	(493,329	)		25
Forfeited	(19,352	)		25
Canceled	—			—

Outstanding at March 31, 2006	2,004,339			25
Phantom Stock Awards held by Spectra Energy Capital employees	(1,585,440	)		25
Granted	187,220			29
Vested	(85,769	)		26
Forfeited	(105,272	)		26
Canceled	—			—

Outstanding at December 31, 2006	415,078		$	26

Phantom Stock Awards Expected to Vest	397,935		$	26


	Shares		Weighted Average Grant Date Fair Value
Number of Other Stock Awards:
Outstanding at December 31, 2005	178,337		$	25
Granted	238,000			28
Vested	(18,630	)		24
Forfeited	—			—
Canceled	—			—

Outstanding at March 31, 2006	397,707			27
Other stock awards held by Spectra Energy Capital employees	(104,307	)		26
Granted	—			—
Vested	(2,000	)		29
Forfeited	—			—
Canceled	—			—

Outstanding at December 31, 2006	291,400		$	27

Other Stock Awards Expected to Vest	270,332		$	27


	Duke Energy Carolinas
	For the Years Ended December 31,
	2006			2005			2004
	(in millions)
Service cost benefit earned during the year	$	43		$	40		$	40
Interest cost on projected benefit obligation		103			105			107
Expected return on plan assets		(121	)		(123	)		(127	)
Amortization of prior service cost		(4	)		(4	)		(4	)
Amortization of net transition asset		—			—			—
Curtailment (gain) / loss		—			—			(2	)
Amortization of loss		41			26			13

Net periodic pension costs / (income)	$	62		$	44		$	27


	Duke Energy U.S.		West- coast
	As of December 31,
	2005		2005
	(in millions)
Accrued pension liability	$	—	$	(76	)
Intangible asset		—		7
Pre-funded pension costs		747		—
Deferred income tax asset		—		25
Accumulated other comprehensive income		—		46

Net amount recognized	$	747	$	2


	Duke Energy Carolinas
	For the Years Ended December 31,
	2006		2005		2004
	(in millions)
Service cost benefit earned during the year	$	—	$	—	$	—
Interest cost on projected benefit obligation		2		2		2
Expected return on plan assets		—		—		—
Amortization of prior service cost		1		1		1
Amortization of net transition (asset)/liability		—		1		1
Curtailment (gain) / loss		—		—		2
Amortization of loss		—		—		—

Net periodic pension costs	$	3	$	4	$	6


	Duke Energy U.S.			Westcoast
	As of December 31,
	2005			2005
	(in millions)
Accrued pension liability^(a)	$	(83	)	$	(81	)
Pre-funded pension costs		—			—
Accumulated other comprehensive income		—			21

Net amount recognized	$	(83	)	$	(60	)


	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Total
	(In millions)
2006
Operating revenues	$	1,289	$	1,281	$	1,601	$	1,271	$	5,442
Operating income		318		159		422		190		1,089
Net income		358		51		230		148		787

2005
Operating revenues	$	1,263	$	1,231	$	1,616	$	1,322	$	5,432
Operating income		277		202		582		195		1,256
Net income		868		309		41		606		1,824