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, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

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,” “target,” 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 year ended December 31, 2005 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.

At December 31, 2007, Duke Energy Carolinas operated one business segment, Franchised Electric, which is considered a reportable business segment under Statement of Financial Accounting Standards (SFAS) No. 131, “Disclosures about Segments of an Enterprise and Related Information.” For additional information about this business segment, including financial and geographical information, see Note 4 to the Consolidated Financial Statements, “Business Segments.”

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 2.3 million residential, commercial and industrial customers over 99,000 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 6 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 limited liability company. 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 5 and 15 to the Consolidated Financial Statements, “Regulatory Matters,” and “Commitments and Contingencies—Environmental,” respectively.

Except to the extent discussed in Note 5 to the Consolidated Financial Statements, “Regulatory Matters,” and Note 15 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 Duke Energy Carolinas’ 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 and by state public utility commissions under laws regulating Duke Energy Carolinas’ businesses. 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.

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

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, cash flows or financial position.

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 failure to adequately execute and manage its significant construction plans, as well as the risk of recovering such costs in an untimely manner, which could materially impact Duke Energy Carolinas’ results of operations, cash flows or financial position.

During the five-year period from 2008 to 2012, Duke Energy Carolinas anticipates capital expenditures of approximately $2 billion to $3 billion annually. The completion of Duke Energy Carolinas’ anticipated capital investment projects in existing and new generation facilities is subject to many construction and development risks, including risks related to financing, obtaining and complying with terms of permits, meeting construction budgets and schedules, and satisfying operating and environmental performance standards. Moreover, Duke Energy Carolinas’ ability to recover these costs in a timely manner could materially impact Duke Energy’s consolidated results of operations, cash flows or financial position.

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 in the future.

If the rating agencies were to rate Duke Energy Carolinas below investment grade, Duke Energy Carolinas’ borrowing costs would increase, perhaps significantly. In addition, Duke Energy Carolinas 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 Duke Energy Carolinas short-term debt rating were to fall, Duke Energy Carolinas’ 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’ results of operations, cash flows or financial position.

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; general capital market conditions; 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 capital expansion, improvements or acquisitions that Duke Energy Carolinas may otherwise rely on for future growth.

Duke Energy Carolinas has borrowing capacity under Duke Energy’s 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 at either Duke Energy or Duke Energy Carolinas 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 its proportionate share of the cost of these plans by 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 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 that could significantly impact Duke Energy Carolinas’ allocated costs, as discussed above, Duke Energy could be required to fund its plans with significant amounts of cash. Duke Energy Carolinas’ proportionate share of such cash funding obligations could have a material impact on Duke Energy Carolinas’ results of operations, cash flows or financial position.

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, including claims for bodily damages alleged to have arisen prior to 1985 from the exposure to or use of asbestos at electric generation plants of Duke Energy Carolinas. 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’ results of operations, cash flows or financial position.

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.

Factors that could impact sales volumes, generation of electricity and market prices at which Duke Energy Carolinas is able to sell electricity are as follows:

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 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 could be 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.

New laws or regulations could have a negative impact on Duke Energy Carolinas’ results of operations, cash flows or financial position.

There is growing consensus that some form of regulation will be forthcoming at the federal level with respect to greenhouse gas emissions (including carbon dioxide). 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’ results of operations, cash flows or financial position, 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, 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 that 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, 2007, 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 3,262 MW. The stations are located in North Carolina and South Carolina.

In addition, as of December 31, 2007, Duke Energy Carolinas owned approximately 13,000 conductor miles of electric transmission lines, including 600 miles of 525 kilovolts, 2,600 miles of 230 kilovolts, 6,700 miles of 100 to 161 kilovolts, and 3,100 miles of 13 to 69 kilovolts. Duke Energy Carolinas also owned approximately 99,000 conductor miles of electric distribution lines, including 66,000 miles of overhead lines and 33,000 miles of underground lines, as of December 31, 2007. As of December 31, 2007, the electric transmission and distribution systems had approximately 1,500 substations.

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 5 to the Consolidated Financial Statements, “Regulatory Matters” and Note 15 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, primarily to provide funding support for Duke Energy’s dividend. The ability to pay this distribution was principally obtained from net cash provided by operating activities from Duke Energy Carolinas’ continuing operations. During the three months ended March 31, 2006 and the year ended December 31, 2005, 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 to provide funding support for Duke Energy’s dividend.

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 and Notes for the years ended December 31, 2007, 2006 and 2005.

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 year ended December 31, 2005 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 $69 million increase in Duke Energy Carolinas’ income from continuing operations was primarily due to the following factors:

Other Income and Expenses, net. The decrease is primarily due to interest earned and received in 2006 from taxing authorities for income tax positions related to prior periods. This decrease was partially offset by an increase in the equity component of allowance for funds used during construction (AFUDC) earned from additional capital spending for ongoing construction projects.

Income Tax Expense from Continuing Operations. The increase was primarily due to the increase in pre-tax income.

The $117 million decrease in Duke Energy Carolinas’ net income for the year ended December 31, 2007 as compared to the year ended December 31, 2006 is due primarily to the inclusion in Income From Discontinued Operations, net of tax, of operations of Spectra Energy Capital, which were transferred from Duke Energy Carolinas to Duke Energy on April 3, 2006, in the year ended December 31, 2006. This decrease was partially offset by the increase in income from continuing operations, as discussed above.

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. Within the industrial sector, Duke Energy Carolinas is affected by overall market conditions, including the continued general decline in the textile industry, as well as softening in housing-related industries, and these trends are expected to continue into 2008. Duke Energy Carolinas will continue to provide strong cash flows from operations, which will help fund the capital spending program in 2008. Changes in weather, wholesale power market prices, service area economy, generation availability and changes to the regulatory environment would impact future financial results for Duke Energy Carolinas.

The impact of the North Carolina rate order resulting from the 2007 rate review ordered by the NCUC will also affect income for 2008 and future years. Particularly, retail base rates were lowered by $287 million, which was primarily offset by the elimination of clean air legislation amortization. For 2008 only, the NCUC also allowed a one-time increment rider of $80 million related to merger savings.

Legislation enacted in both North Carolina and South Carolina in 2007 will allow Duke Energy Carolinas to recover from retail customers more of the costs incurred for purchases of power and reagents needed to meet customer demand. Various regulatory activities will continue in 2008, including a review of Duke Energy Carolinas’ proposed cost recovery methodology related to energy efficiency programs. Decisions on 2007 filings for certification for new generation are also expected.

The Southeastern United States continues to experience severe drought conditions brought about by a significant shortage of rainfall in the past several months. As a result of these conditions, water supplies in the reservoirs and lake systems that support many of Duke Energy Carolinas’ hydroelectric, nuclear, and fossil electric generation plants have declined and could continue to decline in the absence of more normal levels of rainfall. Duke Energy Carolinas is analyzing long-term weather forecasts and developing plans to mitigate any potential operational impacts that continued severe drought conditions could cause; however, at this time we cannot determine if such impacts will have a material effect on Duke Energy Carolinas.

During the five-year period from 2008 to 2012, Duke Energy Carolinas anticipates capital expenditures of approximately $2 billion to $3 billion annually. 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 6,600 megawatts over the next ten years. Duke Energy Carolinas plans to meet this additional demand through a diverse portfolio consisting of new generating capacity, including generation from renewable power sources and energy efficiency. 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. Duke Energy Carolinas received approval from the NCUC in 2007 to construct one new coal unit at its existing Cliffside facility in North Carolina. Other significant expansion projects may include a new nuclear power plant in Cherokee County, South Carolina and new combined cycle units at Buck and Dan River. Costs related to environmental spending are expected to decrease substantially after 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 4.0 times for 2007 and 3.2 times for 2006.

Global Climate Change. A majority of the public and policymakers now believe that the Earth’s climate is changing, caused in part by greenhouse gases emitted into the atmosphere from human activities. Although there is still much to learn about the causes and long-term effects of climate change, many advocate taking steps now to begin reducing emissions with the aim of stabilizing the atmospheric concentration of greenhouse gases at a level that avoids the potentially worst-case effects of climate change.

Greenhouse gas emissions are produced from a wide variety of human activities. The U.S. EPA publishes an inventory of these emissions annually. Carbon dioxide (CO₂), an essential trace gas, is a by-product of fossil fuel combustion and currently accounts for about 85% of U.S. greenhouse gas emissions. Duke Energy Carolinas currently accounts for about 0.7% of total U.S. CO₂ emissions, and about 0.6% of total U.S. greenhouse gas emissions.

Duke Energy Carolinas is adding tens of thousands of new customers annually to its customer base of more than 2.3 million and making long-term decisions for how best to meet its customers’ growing demand for electricity. Duke Energy Carolinas is moving ahead on multiple fronts—energy efficiency, renewable energy, advanced nuclear power, advanced clean-coal and high-efficiency natural gas electric generating plants, and retirement of older less efficient coal-fired power plants. Duke Energy Carolinas needs regulatory certainty regarding U.S. climate change policy as it makes these investment decisions.

Duke Energy Carolinas’ cost of complying with any federal greenhouse gas emissions law that may be enacted will depend on the design details of the program. The major design elements of a greenhouse gas cap-and-trade program that will most influence Duke Energy Carolinas’ compliance costs include the required levels and timing of the cap, which will drive emission allowance prices, the emission sources covered under the cap, the number of allowances that Duke Energy Carolinas is allocated on a year-to-year basis, the type of and effectiveness of the cost control mechanism employed by the program, and the availability and cost of technologies that Duke Energy Carolinas can deploy to lower its emissions. Although it is likely that Congress will adopt some form of mandatory greenhouse gas emission reduction legislation in the future, the timing and specific requirements of any such legislation are highly uncertain, which means that potential future compliance costs for Duke Energy Carolinas are also highly uncertain.

The 110^th Congress is currently considering several potential U.S. policy responses to the climate change issue. In 2007, nearly a dozen bills were introduced in the Senate calling for mandatory limits on U.S. greenhouse gas emissions through use of a cap-and-trade

program. The key differences in the bills are the sources whose emissions would be regulated, the rate at which emissions would be required to be reduced, the number of emission allowances that would be distributed at no cost to sources whose emissions would be regulated, and the method of protecting the economy from potentially high and unexpected program costs.

On December 5, 2007, the Senate Environment and Public Works Committee reported out S. 2191—America’s Climate Security Act of 2007—sponsored by Senators Joseph Lieberman of Connecticut and John Warner of Virginia. The bill, which now awaits Senate floor action, proposes an economy-wide greenhouse gas reduction program to begin in 2012. Several bills have also been introduced in the House of Representatives but none has yet received subcommittee or committee approval. It is unlikely that legislation establishing a mandatory federal greenhouse gas emission reduction program will be enacted in 2008.

Duke Energy Carolinas supports the enactment of federal greenhouse gas cap-and-trade legislation that would apply to all parts of the economy, including power generation, industrial and commercial sources, and motor vehicles. To permit the economy to adjust rationally to the policy, legislation should establish a long-term program that first slows the growth of emissions, stops them and then transitions to a gradually declining emissions cap as new lower-and non-emitting technologies are developed and become ready for wide-scale deployment.

New technologies for reducing CO₂emissions from coal—chief among them carbon capture and sequestration—are not expected to be developed and ready for deployment by 2012 when the Lieberman-Warner legislation, if passed, would take effect. This would pose a challenge to Duke Energy Carolinas’ ability to utilize all of its current coal-fired generating capacity if the legislation is enacted in its current form. This could challenge Duke Energy Carolinas’ ability to meet the growing electricity demand of its customers at a reasonable cost. Duke Energy Carolinas’ deployment of renewable generation, along with its customer energy-efficiency initiative would help, but would not be enough. If the cap is too stringent in the early years of the program, Duke Energy Carolinas’ compliance options could be limited to purchasing emission allowances and/or relying on existing natural gas generation to replace coal generation. Achieving a large fuel switch from coal to natural gas in less than four years is not practical and, on a national scale, is not good public policy. Such a shift would significantly increase natural gas prices, posing an economic hardship to millions of natural gas customers.

Compliance cost estimates are very sensitive to various highly uncertain assumptions, including allowance prices. Under the proposed S. 2191 legislation, estimated costs of purchasing allowances in 2012, in addition to those allocated at no cost, to cover Duke Energy Carolinas’ projected emissions could range from about $330 million to $1.0 billion. Actual costs could be higher or lower than these estimates. Duke Energy Carolinas would seek to recover its compliance costs through appropriate regulatory mechanisms in the jurisdictions in which it operates. Under a compliance scenario where Duke Energy Carolinas continues to purchase allowances to meet its compliance obligation, annual allowance purchase costs would increase over time as the number of allowances Duke Energy Carolinas is allocated under the proposed legislation decreases and allowance prices increase as the cap tightens.

At some point in the future it would be expected that Duke Energy Carolinas would begin replacing existing coal-fired generation with new lower-and zero-emitting generation technologies, and/or installing new carbon capture and sequestration technology on existing coal-fired generating plants to reduce emissions when technologies become available. It is not possible at this time, however, to predict with certainty what new technologies might be developed, when they will be ready to be deployed, or what their costs will be. There is also uncertainty as to how or when certain non-technical issues that could affect the cost and availability of new technologies might be resolved by regulators. Duke Energy Carolinas is currently focused on advanced nuclear generation and capture and storage retrofit technology for existing pulverized coal-fired generation as promising new technologies for generating electricity with lower or no CO₂ emissions.

In addition to relying on new technologies to reduce its CO₂ emissions, Duke Energy Carolinas is seeking regulatory approval for a first-of-its-kind innovative approach in the utility industry to help meet growing customer demand with new and creative ways to increase energy efficiency, thereby reducing demand (Save-A-Watt) instead of relying almost exclusively on new power plants to generate electricity.

Credit Implications of Climate Change Legislation. A credit rating agency recently announced that climate-change policies eventually could carry significant credit implications for the U.S. electric utility industry, which includes Duke Energy Carolinas. While the agency stated on February 26, 2008 that it had not lowered any utility company ratings due solely to the sizable capital expenditures needed to reduce emission levels, rating actions could result. The agency cited a utility’s financing plan and its ability to recover such costs from its ratepayers as the biggest factors in considering whether environmental-related capital expenditures negatively affect a utility’s credit quality. Duke Energy Carolinas’ cannot predict with any certainty what actions, if any, this or other credit rating agencies may take. A downgrade in Duke Energy Carolinas’ credit rating could adversely affect its ability to access capital at competitive rates and its ability to finance its operations and implement its strategies could be adversely affected.

For additional information on other issues related to Duke Energy Carolinas, see Note 5 to the Consolidated Financial Statements, “Regulatory Matters,” and Note 15 to the Consolidated Financial Statements, “Commitments and Contingencies.”

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 cost tracking and recovery mechanisms in its retail jurisdictions. Duke Energy Carolinas does have exposure to the impact of market fluctuations in the prices 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 9 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 separate from 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 generation portfolio not utilized to serve native load or committed load is subject to commodity price fluctuations, although the impact on the Consolidated Statements of Operations reported earnings is partially offset by mechanisms in the regulated jurisdictions that result in the sharing of net profits from these activities with retail customers. Based on a sensitivity analysis as of December 31, 2007 and 2006, it was estimated that a ten percent price change per mega-watt hour in forward wholesale power prices would have a corresponding effect on Duke Energy Carolinas’ pre-tax income of approximately $7 million in 2008 and would have had a $14 million impact in 2007, respectively, excluding the impact of mark-to-market changes on undesignated hedges relating to periods in excess of one year from the respective date.

Normal Purchases and Normal Sales. Duke Energy Carolinas enters into 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 Derivatives Implementation Group Issue C15, “Scope Exceptions: Normal Purchases and Normal Sales Exception for Option-Type Contracts and Forward Contracts in Electricity.” 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. As of December 31, 2007 and 2006, pre-tax income for 2008 and 2007 was not expected to be materially impacted by exposures to other commodities’ price changes since most of the commodity price risk is minimized by regulatory treatment for commodity transactions.

The commodity price sensitivity 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 immaterial and are typically 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 United States. Duke Energy Carolinas has concentrations of receivables from the electric utilities sector. 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. 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 has a third-party insurance policy to cover certain losses related to asbestos-related injuries and damages above an aggregate self insured retention of $476 million. Through December 31, 2007, Duke Energy Carolinas has made approximately $460 million in payments that apply to this retention. The insurance policy limit for potential insurance recoveries for indemnification and medical cost claim payments is $1,107 million in excess of the self insured retention. Probable insurance recoveries of approximately $1,040 million and $1,020 million related to this policy are classified in the Consolidated Balance Sheets primarily in Other within Investments and Other Assets as of December 31, 2007 and 2006, respectively. Duke Energy Carolinas is not aware of any uncertainties regarding the legal sufficiency of insurance claims or any significant solvency concerns related to the insurance carrier.

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 a percentage 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, 9, and 14 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, 2007, it was estimated that if market interest rates average 1% higher (lower) in 2008 than in 2007, interest expense, net of offsetting impacts in interest income, would increase (decrease) by approximately $12 million. Comparatively, based on a sensitivity analysis as of December 31, 2006, had interest rates averaged 1% higher (lower) in 2007 than in 2006, it was estimated that interest expense, net of offsetting impacts in interest income, would have increased (decreased) by approximately $7 million. These amounts were 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, 2007 and 2006. The increase in interest rate sensitivity is primarily due to an increase in commercial paper and variable rate pollution control bonds and a decrease in cash and short-term investment balances. 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 8 to the Consolidated Financial Statements, “Asset Retirement Obligations.”) As of December 31, 2007 and 2006, these funds were invested primarily in domestic and international equity securities, debt securities, fixed-income securities, cash and cash equivalents and short-term investments. 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 Statements of Operations as changes in the fair value of these investments are deferred as regulatory assets or regulatory liabilities pursuant to an order by the NCUC. Earnings or losses of the fund will ultimately impact the amount of costs recovered through Duke Energy Carolinas’ rates.

Duke Energy Carolinas proportionate share of Duke Energy’s costs of providing non-contributory defined benefit retirement and other post-retirement 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 and Financial Condition, Quantitative and Qualitative Disclosures About Market Risk.”

We have audited the accompanying consolidated balance sheets of Duke Energy Carolinas and subsidiaries (the “Company”) as of December 31, 2007 and 2006, 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, 2007. Our audits also included the 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 and subsidiaries at December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007, 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.

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.

All common stock transactions prior to March 31, 2006 included in the Statement of Member’s Equity/Common Stockholders’ Equity relate to common stock of Duke Energy.

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.

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 Financial Statements 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 Cash. At December 31, 2007 and 2006, Duke Energy Carolinas had approximately $68 million and $46 million, respectively, of restricted cash related primarily to proceeds from debt issuances that are held in trust for the purpose of funding future environmental construction or maintenance expenditures. This amount is reflected in Other Investments and Other Assets on the Consolidated Balance Sheets.

Short-term Investments. Duke Energy Carolinas periodically 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 have historically provided 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 minimal 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 net cash used in investing activities in the accompanying Consolidated Statements of Cash Flows.

Inventory. Inventory consists of materials and supplies, and coal held for electric generation. Inventory is recorded primarily using the average cost method.

Cost-Based Regulation. Duke Energy Carolinas accounts for certain of 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 in a future period 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. Additionally, management continually assesses whether any regulatory liabilities have been incurred. Based on this continual assessment, management believes the existing regulatory assets are probable of recovery and that no regulatory liabilities, other than those recorded, have been incurred. 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 5.

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 management activities, which may include 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”, as amended (SFAS No. 133), are recorded on the Consolidated Balance Sheets at their fair value. Cash inflows and outflows related to derivative instruments, except those that contain financing elements and those related to net investment hedges and other investing activities, are reflected as a component of net cash provided by operating activities in the accompanying Consolidated Statements of Cash Flows. Cash inflows and outflows related to derivative instruments containing financing elements are a component of net cash provided by / (used in) financing activities in the accompanying Consolidated Statements of Cash Flows while cash inflows and outflows related to net investment hedges and derivatives related to other investing activities are a component of net cash used in investing activities in the accompanying Consolidated Statements of Cash Flows.

Normal Purchases and Normal Sales. 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.

MTM is an accounting term used by Duke Energy Carolinas to refer to derivative contracts for which an asset or liability is recognized at fair value and the change in fair value of that asset or liability is recognized in the Consolidated Statements of Operations. As this term is not explicitly defined within GAAP, Duke Energy Carolinas’ application of this term could differ from that of other companies.

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. 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 holdings of the NDTF have been recognized as a regulatory asset. Pursuant to an order from the North Carolinas Utility Commission (NCUC), Duke Energy Carolinas defers as a regulatory asset or regulatory liability all realized and unrealized gains and losses associated with investments in the NDTF 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 (including the NDTF) are presented on a gross basis within net cash used in investing activities in the accompanying Consolidated Statements of Cash Flows.

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 (see “Deferred Returns and Allowance for Funds Used During Construction (AFUDC),” discussed below). The cost of renewals and betterments that extend the useful life of property, plant and equipment are also capitalized. The cost of repairs, replacements and major maintenance projects, which do not extend the useful life or increase the expected output of property, plant and equipment, is expensed as incurred. Depreciation is generally computed over the estimated useful life of the asset using the straight-line method. The composite weighted-average depreciation rates, excluding nuclear fuel, were approximately 3% for 2007, 2006 and 2005.

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, or retires or sells non-regulated properties, the cost is removed from the property account and the related accumulated depreciation and amortization accounts are reduced. Any gain or loss is recorded in earnings, unless otherwise required by the applicable regulatory body.

Duke Energy Carolinas recognizes asset retirement obligations (ARO) 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. The term conditional asset retirement obligation as used in SFAS No. 143 and FIN 47 refers to a 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. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and (or) method of settlement. Thus, the timing and (or) method of settlement may be conditional on a future event. 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. See Note 8 for further information.

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 carrying value of the asset 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 may 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 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 Emerging Issues Task Force (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, are classified as held for sale or have been wound down 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. See Note 2 for discussion of discontinued operations.

Other Current and Non-Current Liabilities. At December 31, 2007, approximately $1,528 million and $1,433 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 15.

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. The amortization expense is recorded in continuing operations as Interest expense in the Consolidated Statements of Operations. The amortization expense is reflected as Depreciation and amortization within Net cash provided by operating activities on the Consolidated Statements of Cash Flows.

Loss Contingencies. Duke Energy Carolinas is involved in certain legal and environmental matters that arise in the normal course of business. Loss contingencies are accounted for under SFAS No. 5, “Accounting for Contingencies,” (SFAS No. 5). Under SFAS No. 5, contingent losses are recorded when it is determined that it is probable that a loss has occurred and the amount of the loss can be reasonably estimated. When a range of the probable loss exists and no amount within the range is a better estimate than any other amount, Duke Energy Carolinas records a loss contingency at the minimum amount in the range. Unless otherwise required by GAAP, legal fees are expensed as incurred. See Note 15 for further information.

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 on an undiscounted basis 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.

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)). SFAS No. 123(R) establishes accounting for stock-based awards, including stock options, 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. Share-based 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. See Note 16 for further information.

Duke Energy Carolinas elected to adopt the modified prospective application method as provided by SFAS No. 123(R), and accordingly, financial statement amounts for the year ended December 31, 2005 have not been restated. There were no modifications to outstanding stock options prior to the adoption of SFAS No. 123(R).

Effective with the transfer of Spectra Energy Capital to Duke Energy on April 3, 2006, Duke Energy Carolinas is allocated its proportionate share of stock-based compensation expense by its parent, Duke Energy.

Prior to 2006, Duke Energy Carolinas applied Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees,” (APB No. 25) and FIN 44, “Accounting for Certain Transactions Involving Stock Compensation (an Interpretation of APB Opinion 25)” (FIN No. 44) 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 for the year ended December 31, 2005. See Note 16 for further information.

Revenue Recognition and Unbilled Revenue. Revenues on sales of electricity are recognized when either the service is provided or the product is delivered. Unbilled revenues are estimated by applying an average revenue per kilowatt hour for all customer classes to the number of estimated kilowatt hours delivered but not billed. The amount of unbilled revenues can vary significantly period to period as a result of factors including seasonality, weather, customer usage patterns and customer mix. Unbilled revenues at December 31, 2007 and 2006, which are recorded as Receivables in Duke Energy Carolinas’ Consolidated Balance Sheets, were approximately $221 million and $212 million, respectively.

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. The amount of deferred return expense included in Other Income and Expenses, net was $15 million in 2007, $15 million in 2006 and $13 million in 2005.

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 primarily in the depreciation provision. The total amount of AFUDC included within income from continuing operations in the Consolidated Statements of Operations was $69 million in 2007, which consisted of an after-tax equity component of $47 million and a before-tax interest expense component of $22 million. The total amount of AFUDC included within income from continuing operations in 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 within income from continuing operations in 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 preceding amounts exclude AFUDC of approximately $22 million and $17 million for the years ended December 31, 2006 and 2005, respectively, which relate to operations transferred to Duke Energy on April 3, 2006 and are included in Income From Discontinued Operations, net of tax, on the Consolidated Statements of Operations.

Accounting For Purchases and Sales of Emission Allowances. Duke Energy Carolinas recognizes emission allowances in earnings as they are consumed or sold. 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 net cash used in 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 uncertain tax positions in accordance with FIN 48, “Accounting For Uncertainty in Income Taxes—an Interpretation of FASB Statement 109,” (FIN 48), which was adopted by Duke Energy Carolinas on January 1, 2007. Duke Energy Carolinas records unrecognized tax benefits for positions taken or expected to be taken on tax returns, including the decision to exclude certain income or transactions from a return, when a more-likely-than-not threshold is met for a tax position and management believes that the position will be sustained upon examination by the taxing authorities. Management evaluates each position based solely on the technical merits and facts and circumstances of the position, assuming the position will be examined by a taxing authority having full knowledge of all relevant information. In accordance with FIN 48, Duke Energy Carolinas records the largest amount of the unrecognized tax benefit that is greater than 50% likely of being realized upon settlement or effective settlement. Management considers a tax position effectively settled for the purpose of recognizing previously unrecognized tax benefits when the following conditions exist: (i) the taxing authority has completed its examination procedures, including all appeals and administrative reviews that the taxing authority is required and expected to perform for the tax positions, (ii) Duke Energy Carolinas does not intend to appeal or litigate any aspect of the tax position included in the completed examination, and (iii) it is remote that the taxing authority would examine or reexamine any aspect of the tax position. See Note 7 for further information.

Duke Energy Carolinas records, as it relates to taxes, interest expense as Interest Expense and interest income and penalties in Other Income and Expenses, net, in the Consolidated Statements of Operations.

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 years ended December 31, 2007, 2006, and 2005 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’ reportable business segment. SFAS No. 131 also establishes standards and related disclosures about the way the operating segments were determined, including 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 4.

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, debt restricted for qualified capital and maintenance expenditures 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, general liability insurance proceeds are included as a component of operating activities while insurance proceeds from damaged property are included as a component of investing activities). Proceeds from debt issued with restrictions to fund future capital and maintenance expenditures are

presented on a gross basis, with the debt proceeds classified as a financing cash inflow and the changes in the restricted funds held in trust presented 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 pro forma effects of adopting FIN 47 are not presented due to the immaterial impact on the Consolidated Statements of Operations and Consolidated Balance Sheets.

New Accounting Standards. The following new accounting standards were adopted by Duke Energy Carolinas during the year ended December 31, 2007 and the impact of such adoption, if applicable, has been presented in the accompanying Consolidated Financial Statements:

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. 140). 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 was 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 had been bifurcated prior to the effective date, for which the effect is to be reported as a cumulative-effect adjustment to beginning retained earnings. The adoption of SFAS No. 155 did not have a material impact on Duke Energy Carolinas’ consolidated results of operations, cash flows or financial position.

FIN No. 48, “Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109” (FIN 48). In July 2006, the FASB issued FIN 48, which 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 of a tax benefit in Duke Energy Carolinas’ financial statements. FIN 48 prescribes the 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 adopted FIN 48 effective January 1, 2007. See Note 7 for additional information.

FASB Staff Position (FSP) No. FIN 48-1, Definition of “Settlement” in FASB Interpretation No. 48 (FSP No. FIN 48-1). In May, 2007, the FASB staff issued FSP No. FIN 48-1 which clarifies the conditions under FIN 48 that should be met for a tax position to be considered effectively settled with the taxing authority. Duke Energy Carolinas’ adoption of FIN 48 as of January 1, 2007 was consistent with the guidance in this FSP.

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 GAAP. 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 was effective for Duke Energy Carolinas as

of January 1, 2007. As discussed in Note 16, effective with the spin-off of Spectra Energy on January 2, 2007, all previously granted Duke Energy Carolinas long-term incentive plan equity awards were modified to equitably adjust the awards. As the modifications to the equity awards were made solely to reflect the spin-off, no change in the recognition or the measurement (due to a change in classification) of those instruments resulted.

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 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. Share-based 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 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 16.

Staff Accounting Bulletin (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 Securities and Exchange Commission (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 ending 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 a material impact on Duke Energy Carolinas’ consolidated results of operations, cash flows or financial position.

The following new accounting standard was 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:

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. 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.

The following new accounting standards have been issued, but have not yet been adopted by Duke Energy Carolinas as of December 31, 2007:

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. The application of SFAS No. 157 may change Duke Energy Carolinas’ current practice for measuring fair values under other accounting pronouncements that require fair value measurements. For Duke Energy Carolinas, SFAS No. 157 is effective as of January 1, 2008. In February 2008, the FASB issued FSP No. 157-2, which delays the effective date of SFAS No. 157 for one year for nonfinancial assets and liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis. Duke Energy Carolinas does not expect to report any material cumulative-effect adjustment to beginning retained earnings as is required by SFAS No. 157 for certain limited matters. Duke Energy Carolinas continues to monitor additional proposed interpretative guidance regarding the application of SFAS No. 157. To date, no matters have been identified regarding implementation of SFAS No. 157 that would have any material impact on Duke Energy Carolinas’ consolidated results of operations 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 Carolinas, 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 does not currently have any financial assets or financial liabilities for which the provisions of SFAS No. 159 have been elected. However, in the future, Duke Energy Carolinas may elect to measure certain financial instruments at fair value in accordance with this standard.

SFAS No. 141 (revised 2007), “Business Combinations” (SFAS No. 141R). In December 2007, the FASB issued SFAS No. 141R, which replaces SFAS No. 141, “Business Combinations.” SFAS No. 141R retains the fundamental requirements in SFAS No. 141 that the acquisition method of accounting be used for all business combinations and that an acquirer be identified for each business combination. This statement also establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any noncontrolling (minority) interests in an acquiree, and any goodwill acquired in a business combination or gain recognized from a bargain purchase. For Duke Energy Carolinas, SFAS No. 141R must be applied prospectively to business combinations for which the acquisition date occurs on or after January 1, 2009. The impact to Duke Energy Carolinas of applying SFAS No. 141(R) for periods subsequent to implementation will be dependent upon the nature of any transactions within the scope of SFAS No. 141(R).

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 year ended December 31, 2005. 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 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 year ended December 31, 2005.

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 and natural gas liquids (NGL) 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 33¹/3% interest in Bridgeport Energy LLC from United Bridgeport Energy LLC 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 Duke Energy North America’s (DENA) power generation assets which were sold to a subsidiary of LS Power Equity Partners (LS Power) (see below).

Dispositions. The 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 a pre-tax gain of $5 million. In addition, the 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 further below in “Year Ended December 31, 2005,” during the third quarter of 2005, Duke Energy’s 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. 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 Bank, PLC (Barclays) related to the sale of certain commodity contracts, as discussed further below, 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 former DENA under the contracts of approximately $540 million. The novation or assignment of these physical power contracts was subject to the Federal Energy Regulatory Commission (FERC) approval, which was received in January 2006. Additionally, 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. This transaction closed in May 2006, with the proceeds being received by Duke Energy. See below for further discussions surrounding this transaction.

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 storage and pipeline assets in Southwest Virginia and an additional 50% interest in Saltville Gas Storage LLC (Saltville Storage) were acquired from units of AGL Resources for approximately $62 million. This transaction increased the ownership percentage of Saltville Storage to 100%. No goodwill was recorded as a result of this acquisition.

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

Dispositions. In February 2005, DCP Midstream sold its wholly owned subsidiary Texas Eastern Productions Pipeline Company, LLC (TEPPCO GP), which is the general partner of TEPPCO Partners, LP (TEPPCO LP), for approximately $1.1 billion and Duke Energy sold its limited partner interest in TEPPCO LP for approximately $100 million, in each case to Enterprise GP Holdings LP, an unrelated third party. These transactions resulted in pre-tax gains of $1.2 billion, excluding Minority Interest Expense of $343 million to reflect ConocoPhillips’ proportionate share in the pre-tax gain on sale of TEPPCO GP.

Additionally, in July 2005, Duke Energy Carolinas completed the agreement with ConocoPhillips, Duke Energy Carolinas’ co-equity owner in DCP Midstream, to reduce Duke Energy Carolinas’ ownership interest in DCP Midstream from 69.7% to 50% (the DCP Midstream disposition transaction), which resulted in Duke Energy Carolinas and ConocoPhillips becoming equal 50% owners in DCP Midstream. Duke Energy Carolinas received, directly and indirectly through its ownership interest in DCP Midstream, a total of approximately $1.1 billion from ConocoPhillips and DCP Midstream, consisting of approximately $1.0 billion in cash and approximately $0.1 billion of assets. The DCP Midstream disposition transaction resulted in a pre-tax gain of approximately $575 million. The DCP Midstream disposition transaction includes the transfer to Duke Energy of DCP Midstream’s Canadian natural gas gathering and processing facilities. Additionally, the DCP Midstream disposition transaction included the acquisition of ConocoPhillips’ interest in the Empress System. Subsequent to the closing of the DCP Midstream disposition transaction, effective on July 1, 2005, DCP Midstream was no longer consolidated into Duke Energy Carolinas’ consolidated financial statements and was accounted for by Duke Energy Carolinas as an equity method investment up until the April 3, 2006 transfer of all of its membership interests in Spectra Energy Capital to Duke Energy. The Canadian natural gas gathering and processing facilities and the Empress System were included in the Natural Gas Transmission segment.

In December 2005, the Duke Energy Carolinas Income Fund (Income Fund), a Canadian income trust fund, was created to acquire all of the common shares of Duke Energy Midstream Services Canada Corporation (Duke Energy Midstream) from a subsidiary of Duke Energy. The Income Fund sold an approximate 40% ownership interest in Duke Energy Midstream for approximately $110 million, which was included in Proceeds from Duke Energy Income Fund within Cash Flows from Financing activities on the Consolidated Statements of Cash Flows. In January 2006, a subsequent greenshoe sale of additional ownership interests, pursuant to an overallotment option, in the Income Fund were sold for approximately $10 million.

In December 2005, Commercial Power recorded a $75 million charge related to the termination of structured power contracts in the Southeast.

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.

Exiting of Former DENA Businesses Outside the Midwest. 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 that were divested included:

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, were classified as discontinued operations for all 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, 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. Approximately $470 million was incurred during the year ended December 31, 2005.

Included in these aforementioned amounts were the effects of former DENA’s November 2005 agreement to sell to Barclays 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 were commodity contracts associated with the near-term value of former DENA’s West and Northeastern generation assets and remaining gas transportation and structured power contracts. Among other things, the agreement provided 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.

See “For the Period January 1, 2006 through April 3, 2006” above for further information related to the sale of former DENA assets.

DCP Midstream Discontinuance of Hedge Accounting Upon Deconsolidation. As a result of the transfer of 19.7% interest in DCP Midstream to ConocoPhillips and the third quarter 2005 deconsolidation of its investment in DCP Midstream (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. Duke Energy Carolinas recognized approximately $314 million of realized and unrealized pre-tax losses related to these contracts during the year ended December 31, 2005. Cash settlements on these contracts since the deconsolidation of DCP Midstream 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 segment 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.

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.

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,” 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 merger between Duke Energy and Cinergy was consummated (see Note 1 for additional information). See Note 5 for discussion of regulatory impacts of the merger to Duke Energy Carolinas.

In the fourth quarter of 2006, Duke Energy Carolinas acquired an 825 megawatt power plant located in Rockingham County, North Carolina, from Dynegy 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 required approvals by the NCUC, FERC and the U.S. Federal Trade Commission (FTC). 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 2 for discussion of businesses acquired during the three months ended March 31, 2006 and the year ended December 31, 2005 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.

Duke Energy Carolinas operates one business segment, Franchised Electric, which is considered a reportable business segment under SFAS No. 131. Franchised Electric generates, transmits, distributes and sells electricity and conducts operations through Duke Energy Carolinas, which consists of the regulated electric utility businesses in North Carolina and South Carolina. Duke Energy Carolinas’ chief operating decision maker regularly reviews financial information about the business unit in deciding how to allocate resources and evaluate performance. There is no aggregation within the Franchised Electric business segment.

Prior to Duke Energy’s merger with Cinergy on April 3, 2006, Duke Energy Carolinas operated the following reportable business segments: Franchised Electric, Natural Gas Transmission, Field Services, International Energy and Crescent Resources, LLC (Crescent). As described in Note 1, on April 3, 2006, Duke Energy Carolinas transferred to Duke Energy its membership interests in Spectra Energy Capital (see Note 1), which included all reportable business segments except for Franchised Electric, as well as certain operations within Other, as discussed below. Accordingly, the results of operations of Spectra Energy Capital 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 year ended December 31, 2005.

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 within income from continuing operations, 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 were transferred to Duke Energy on April 3, 2006 and, therefore, 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 year ended December 31, 2005.

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.

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. See Note 1 for further information.

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 HC (subsequently renamed Duke Energy Corporation). As a condition to the merger approval, the Public Service Commission of South Carolina (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 HC and/or Duke Energy Carolinas to meet additional conditions. Key elements of these conditions include:

Used Nuclear Fuel. Under provisions of the Nuclear Waste Policy Act of 1982, Duke Energy Carolinas contracted with the Department of Energy (DOE) for the disposal of used nuclear fuel. The DOE failed to begin accepting used nuclear fuel on January 31, 1998, the date specified by the Nuclear Waste Policy Act and in Duke Energy Carolinas’ contract with the DOE. Duke Energy Carolinas will continue to safely manage its used nuclear fuel until the DOE accepts it. 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 used 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 used fuel storage capacity. The matter was stayed pending the result of ongoing settlement negotiations between Duke Energy Carolinas and the DOE. 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 5, 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. The settlement agreement resulted in a pre-tax earnings impact of approximately $26 million during the year ended December 31, 2007, of which approximately $19 million and $7 million were recorded as an offset to Fuel Used in Electric Generation and Purchased Power, and Operation, Maintenance and Other, respectively, in the Consolidated Statements of Operations, with the remaining impact reflected within Inventory and Property, Plant and Equipment in the Consolidated Balance Sheets.

Other Regulatory Matters. Rate Related Information. The NCUC and PSCSC approve rates for retail electric and gas services 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 froze 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 (NO_x) 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 $1,050 million from inception, with approximately $187 million, $225 million and $311 million recorded during the years ended December 31, 2007, 2006 and 2005, respectively. As of December 31,

2007, cumulative expenditures totaled approximately $1,246 million, with $418 million, $403 million and $310 million incurred during the years ended December 31, 2007, 2006 and 2005, respectively, which 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 $2.0 billion. Actual costs may be higher or lower than the estimate based on changes in construction costs and Duke Energy Carolinas’ continuing analysis of its overall environmental compliance plan. As required by the legislation, the NCUC considered the reasonableness of Duke Energy Carolinas’ environmental compliance plan and the method for recovery of the remaining costs in a proceeding it initiated and consolidated with a review of Duke Energy Carolinas’ base rates (see “Duke Energy Carolinas Rate Case” below). Additionally, federal and state 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 Duke Energy Carolinas’ coal-fired power plants.

Duke Energy Carolinas’ Rate Case. In June 2007, Duke Energy Carolinas filed an application with the NCUC seeking authority to increase its rates and charges for electric service in North Carolina effective January 1, 2008. This application complied with a condition imposed by the NCUC in approving the Cinergy merger. On October 5, 2007, Duke Energy Carolinas filed an Agreement and Stipulation of Partial Settlement (Partial Settlement), a settlement agreement among Duke Energy Carolinas, the NCUC Public Staff, the North Carolina Attorney General’s Office, Carolina Utility Customers Association Inc., Carolina Industrial Group for Fair Utility Rates III and Wal-Mart Stores East LP, for consideration by the NCUC. The Partial Settlement, which includes Duke Energy Carolinas and all intervening parties to the rate case, reflected agreements on all but a few issues in these matters, including two significant issues. The two significant issues related to the treatment of ongoing merger cost savings resulting from the Cinergy merger and the proposed amortization of Duke Energy Carolinas’ development costs related to GridSouth Transco, LLC (GridSouth), a Regional Transmission Organization (RTO) planned by Duke Energy Carolinas and other utility companies as a result of previous FERC rulemakings, which was suspended in 2002 and discontinued in 2005 as a result of regulatory uncertainty. The Partial Settlement and the remaining disputed issues were presented to the NCUC for a ruling.

The Partial Settlement reflected an agreed to reduction in net revenues and pre-tax cash flows of approximately $210 million and corresponding rate reductions of 12.7% to the industrial class, 5.05% – 7.34% to the general class and 3.85% to the residential class of customers with an effective date of January 1, 2008. Under the Partial Settlement, effective January 1, 2008, Duke Energy Carolinas discontinued the amortization of the environmental compliance costs pursuant to North Carolina clean air legislation discussed above and began capitalizing all environmental compliance costs above the cumulative amortization charge of $1.05 billion as of December 31, 2007. Over the past five years, the average annual clean air amortization was $210 million. The Partial Settlement was designed to enable Duke Energy Carolinas to earn a rate of return of 8.57% on a North Carolina retail jurisdictional rate base and an 11% return on the common equity component of the approved capital structure, which consists of 47% debt and 53% common equity. As part of the settlement, Duke Energy Carolinas agreed to alter the then existing BPM profit sharing arrangement that currently included a provision to share 50% 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. Under the Partial Settlement, Duke Energy Carolinas will share 90% of the North Carolina retail allocation of the profits from BPM transactions beginning January 1, 2008.

The NCUC issued its Order Approving Stipulation and Deciding Non-Settled Issues on December 20, 2007. The NCUC approved the Partial Settlement in its entirety. The merger savings rider and GridSouth cost matters are discussed in detail below. For the remaining non-settled issues, the NCUC decided in Duke Energy Carolinas’ favor. With respect to the non-settled issues, the Order required that Duke Energy Carolinas’ test period operating costs reflect an annualized level of the merger cost savings actually experienced in the test period in keeping with traditional principles of ratemaking. The NCUC explained that because rates should be designed to recover a reasonable and prudent level of ongoing expenses, Duke Energy Carolinas’ annual cost of service and revenue requirement should reflect, as closely as possible, Duke Energy Carolinas’ actual costs. However, the NCUC recognized that its treatment of merger savings would not produce a fair result. Therefore, the NCUC preliminarily concluded that it would reconsider certain language in its 2006 merger order in order to allow it to authorize a 12-month increment rider of approximately $80 million designed to provide a more equitable sharing of the actual merger savings achieved on an ongoing basis. Additionally, the NCUC concluded that approximately $30 million of costs incurred through June 2002 in connection with GridSouth and deferred by Duke Energy Carolinas, were reasonable and prudent and approved a ten-year amortization, retroactive to June 2002. As a result of the retroactive impact of the Order, Duke Energy Carolinas recorded an approximate $17 million charge to write-off a portion of the Gridsouth costs in 2007. The NCUC did not allow Duke Energy Carolinas a return on the GridSouth investments. As a result of its decision on the non-settled issues, the NCUC ordered an additional reduction in

annual revenues of approximately $54 million, offset by its preliminary authorization of a 12-month, $80 million increment rider, as discussed above. The Order ultimately resulted in an overall average rate decrease of 5% in 2008, increasing to 7% upon expiration of this one-time rate rider. On February 18, 2008, the NCUC issued an order confirming their preliminary conclusion regarding the merger savings rider. This order reaffirmed the prior tentative conclusion that the provisions of the Merger Order will not produce a fair sharing of the benefits of estimated merger savings between ratepayers and shareholders and that, for that reason, Duke Energy Carolinas should be authorized to implement a 12-month increment rider to collect $80 million.

On December 12, 2007, the PSCSC directed the South Carolina Office of Regulatory Staff (ORS) to provide a written report concerning the NCUC’s resolution of Duke Energy Carolinas rate application and its relevance to Duke Energy Carolinas’ rates in South Carolina. On January 31, 2008, the ORS filed its report with the PSCSC, which concluded that the outcome of the North Carolina rate case had no bearing on Duke Energy Carolinas rates in South Carolina. The PSCSC has not yet responded to the report filed by the ORS.

The NCUC has requested that the Public Staff perform a review of Duke Energy Carolinas pension and other post-retirement benefit plan costs, as well as Duke Energy’s funding of the plans. At this time, Duke Energy Carolinas does not anticipate that the outcome of this review will have a material impact on its financial position, results of operations or cash flows.

North Carolina Drought Recovery. On March 4, 2008, Duke Energy Carolinas announced that due to persistent drought conditions it has purchased up to 520 MW of additional generating capacity to help ensure customer electricity needs are met during 2008. In addition, Duke Energy Carolinas filed an application with the NCUC to recover the North Carolina retail allocable portion of costs associated with the purchase of this power.

Energy Efficiency. In May 2007, Duke Energy Carolinas filed an energy efficiency plan with the NCUC that recognizes energy efficiency as a reliable, valuable resource that is a “fifth fuel,” that should be part of the portfolio available to meet customers’ growing need for electricity along with coal, nuclear, natural gas, and renewable energy. The plan would compensate Duke Energy Carolinas for verified reductions in energy use and be available to all customer groups. The plan contains proposals for several different energy efficiency programs, and links energy savings to retiring older coal plants. Customers would pay for energy efficiency programs with an energy efficiency rider that would be included in their power bill and adjusted annually. The energy efficiency rider would be based on the avoided cost of generation not needed as a result of the success of Duke Energy Carolinas’ energy efficiency efforts. The plan is consistent with Duke Energy Carolinas’ public commitment to invest 1% of its annual retail revenues from the sale of electricity in energy efficiency programs subject to the appropriate regulatory treatment of Duke Energy Carolinas’ energy efficiency investments. A hearing is scheduled for June 2008.

On September 28, 2007, Duke Energy Carolinas filed an application with the PSCSC seeking approval to implement new energy efficiency programs in South Carolina. Duke Energy Carolinas’ South Carolina application is based on the application filed in North Carolina. In advance of the evidentiary hearing held February 5-6, 2008, Duke Energy Carolinas reached a settlement agreement with the South Carolina ORS, Wal-Mart, Piedmont Natural Gas and the South Carolina Energy Users Committee. Certain environmental groups that were also interveners in the proceeding did not join any of the settlements. This agreement calls for Duke Energy Carolinas to bear the cost of the programs and allow for recovery of 85% of the avoided generation costs. It is uncertain whether the PSCSC will rule on the application.

Implementation of these plans is subject to approval from the NCUC and PSCSC. As a result, Duke Energy Carolinas is not able to estimate the impact this plan might have on its consolidated results of operations, cash flows, or financial position.

New Legislation. South Carolina passed new energy legislation which became effective May 3, 2007. 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 NO_x control technologies and the cost of certain emission allowances used to meet environmental requirements. The cost of reagents for Duke Energy Carolinas in 2008 is expected to be approximately $30 million. With the enactment of this legislation, Duke Energy Carolinas will be allowed to recover the South Carolina portion of these costs, incurred on or after May 3, 2007, through the fuel clause. The legislation also includes provisions to provide assurance of cost recovery related to a utility’s incurrence of project 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 baseload generation in rates during construction. The North Carolina General Assembly also passed comprehensive energy legislation in July 2007 that was signed into law by the Governor on August 20, 2007. The North Carolina legislation allows utilities to recover the costs of reagents and certain purchased power costs. Like the South Carolina legislation, the North Carolina legislation provides cost recovery assurance for nuclear project development costs as well as baseload generation construction costs. A utility may include financing costs related to

construction work in progress for baseload plants in a rate case. The North Carolina legislation also establishes a renewable portfolio standard for electric utilities at 3% of energy output in 2012, rising gradually to 12.5% by 2021, and grants the NCUC authority to approve a rate rider to compensate utilities for energy efficiency programs that they implement. On August 23, 2007, the NCUC initiated a rulemaking proceeding to adopt new rules and modify existing rules, as appropriate, to implement the legislation. The NCUC issued its order adopting final rules on February 29, 2008. At this time, Duke Energy Carolinas is not able to estimate the impact these legislative initiatives might have on its consolidated results of operations, cash flows, or financial position.

Other. Duke Energy Carolinas is engaged in planning efforts to meet projected load growth in its service territories. 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 had 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. In May 2007, Duke Energy Carolinas announced its intent to purchase Southern Company’s 500 MW interest in the proposed William States Lee III Nuclear Station, making the plant’s total output available to Duke Energy Carolinas’ electric customers. On December 13, 2007, Duke Energy Carolinas filed an application with the Nuclear Regulatory Commission (NRC) for a combined Construction and Operating License (COL) for two Westinghouse AP1000 (advanced passive) reactors at the Cherokee County, South Carolina site. Each reactor is capable of producing approximately 1,117 MW. Submitting the COL application does not commit Duke Energy Carolinas to build nuclear units. On February 27, 2008, Duke Energy Carolinas received confirmation from the NRC that its COL application has been accepted and docketed for the next stage of review. Also, on December 7, 2007, Duke Energy Carolinas filed applications with the NCUC and the PSCSC for approval of Duke Energy Carolinas’ decision to incur development costs associated with the proposed William States Lee III Nuclear Station. The NCUC had previously approved Duke Energy Carolinas’ decision to incur the North Carolina allocable share of up to $125 million in development costs through 2007. The new requests cover a total of up to $230 million in development costs through 2009, which is comprised of $70 million incurred through December 31, 2007 plus an additional $160 million of anticipated costs in 2008 and 2009. The PSCSC has scheduled an evidentiary hearing on Duke Energy Carolinas’ application for April 17, 2008, and the NCUC has scheduled an evidentiary hearing for April 29, 2008.

On June 2, 2006, Duke Energy Carolinas 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. On February 28, 2007, the NCUC issued a notice of decision approving the construction of one unit at the Cliffside Steam Station. On March 21, 2007, the NCUC issued its Order, which explained the basis for its decision to approve construction of one unit, with an approved cost estimate of $1.93 billion (including AFUDC), and certain conditions including providing for updates on construction cost estimates. A group of environmental interveners filed a motion and supplemental motion for reconsideration in April 2007 and May 2007, respectively. Duke Energy Carolinas opposed the motions and the NCUC denied the motions for reconsideration in June 2007. On January 31, 2008, Duke Energy Carolinas filed its updated cost estimate of $1.8 billion (excluding approximately $0.6 billion of AFUDC) for the approved new Cliffside Unit 6. Duke Energy Carolinas believes that the overall cost of Cliffside Unit 6 will be reduced by approximately $125 million in federal advanced clean coal tax credits. On July 11, 2007, Duke Energy Carolinas entered into an engineering, procurement, construction and commissioning services agreement, valued at approximately $1.3 billion, with an affiliate of The Shaw Group, Inc., of which approximately $950 million relates to participation in the construction of Cliffside Unit 6, with the remainder related to a flue gas desulfurization system on an existing unit at Cliffside.

On January 29, 2008, the North Carolina Department of Environment and Natural Resources (DENR) issued a final air permit for the new Cliffside Unit 6. On October 11, 2007, the environmental group N.C. WARN and two individual N.C. WARN members filed a petition against the DENR contesting the issuance of a wastewater discharge permit to Duke Energy Carolinas for the Cliffside Steam Station. A hearing on the NPDES permit contested case is scheduled for the week of March 3, 2008.

On June 29, 2007, Duke Energy Carolinas filed with the NCUC preliminary CPCN information to construct a 600-800 MW combined cycle natural gas-fired generating facility at its existing Dan River Steam Station, as well as updated preliminary CPCN information to construct a 600-800 MW combined cycle natural gas-fired generating facility at its existing Buck Steam Station. On December 14, 2007, Duke Energy Carolinas filed CPCN applications for the two combined cycle facilities. The NCUC has consolidated its consideration of the two CPCN applications and scheduled an evidentiary hearing on the applications for March 11, 2008.

FERC Issues 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. NERC has filed over 100 proposed reliability standards with FERC. On March 16, 2007, FERC issued a final rule establishing mandatory,

enforceable reliability standards for the nation’s bulk power system. In the final rule, FERC approved 83 of the 107 mandatory reliability standards submitted by the NERC and compliance with these standards became mandatory on June 18, 2007. FERC has been considering the remaining 24 proposed standards for approval on an item by item basis. In the interim, compliance with the remaining standards is expected to continue on a voluntary basis as good utility practice. 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.

Open Access Transmission Tariff. On February 15, 2007, the FERC issued a Final Rule (Order 890) in its Open Access Transmission Tariff rulemaking. On March 19, 2007, Duke Energy Carolinas filed a request for rehearing and clarification with regards to this order. There are fourteen specific areas where clarification and rehearing would greatly assist Transmission Providers understanding and implementation of the new rules. On December 28, 2007, the FERC issued Order 890-A, in which it largely reaffirmed the findings of issued Order 890. At this time, Duke Energy Carolinas does not believe that the order will have a material impact on its 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, 2007, Duke Energy Carolinas’ share in the Catawba jointly-owned plant was 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 facility is included within the corresponding line on the Consolidated Statements of Operations. Each participant in the jointly owned facility must provide its own financing.

The taxable income of Duke Energy Carolinas is reflected in Duke Energy’s U.S. federal and state income tax returns. 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 and 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.

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 from Continuing Operations (Statutory Rate Reconciliation)

The manufacturing deduction was created by the American Job Creation Act of 2004 (the Act). The Act provides a deduction for income from qualified domestic production activities. During the years ended December 31, 2006 and 2005, the Act provided for a 3% deduction on qualified production activities. During the year ended December 31, 2007, the deduction increased to 6% on qualified production activities.

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

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

On January 1, 2007, Duke Energy Carolinas adopted FIN 48. The following table shows the impacts of adoption of FIN 48 on Duke Energy Carolinas’ Consolidated Balance Sheets.

Effective with the adoption of FIN 48 on January 1, 2007, Duke Energy Carolinas recognized approximately $54 million of accrued interest receivable, which reflects all interest related to income taxes, and no amounts related to penalties.

The following table details the changes in Duke Energy Carolinas’ unrecognized tax benefits from January 1, 2007 to December 31, 2007.

At December 31, 2007, Duke Energy Carolinas has approximately $109 million of unrecognized tax benefit that, if recognized, would affect the effective tax rate. It is reasonably possible that up to approximately $100 million in currently recorded unrecognized tax benefits related to prior open tax years could change within the next twelve months, although Duke Energy Carolinas is unable to further estimate the amount of potential change at this time. Duke Energy Carolinas expects in the next twelve months to decide whether or not to contest a ruling by the taxing authority that denied its position.

Duke Energy Carolinas is assessing certain other tax matters which do not represent tax positions under FIN 48 and which could result in gains in future periods. However, the timing and amounts of any such potential gains are not currently estimable.

During the year ended December 31, 2007, Duke Energy Carolinas recognized net interest income of approximately $40 million. At December 31, 2007, Duke Energy Carolinas had approximately $34 million accrued for interest receivable, which reflects all interest related to income taxes, and no amount accrued for the payment of penalties.

In June 2001, the FASB issued SFAS No. 143, which was adopted by Duke Energy Carolinas on January 1, 2003. SFAS No. 143 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 increases to the carrying amount of the associated asset.

Asset retirement obligations at Duke Energy Carolinas relate primarily to the decommissioning of nuclear power facilities, obligations related to asbestos removal and landfills at fossil generation facilities.

The adoption of SFAS No. 143 had no impact on the income of the regulated electric 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. The adoption of FIN 47 had no impact on the income of the regulated electric 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 that were included in the transfer of Spectra Energy Capital to Duke Energy on April 3, 2006, a net-of-tax cumulative effect adjustment of approximately $4 million was recorded in 2005 as a reduction in earnings (see Note 1).

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.

Accretion expense for the years ended December 31, 2007 and 2006 has been deferred as regulatory assets and liabilities in accordance with SFAS No. 71 and the approvals of both the NCUC and PSCSC, as discussed above.

Upon adoption of SFAS No. 143, Duke Energy Carolinas classifies 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. Duke Energy Carolinas does not accrue the estimated cost of removal when no legal obligation associated with retirement or removal exists for any non-regulated assets. The total amount of removal costs included in Other Deferred Credits and Other Liabilities on the Consolidated Balance Sheets was $1,528 million and $1,433 million as of December 31, 2007 and 2006, respectively.

Nuclear Decommissioning Costs. 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, 2007 and 2006, 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 each of the years ended December 31, 2007 and 2006, $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 $1,929 million as of December 31, 2007 and $1,775 million as of December 31, 2006. These amounts are reflected as Nuclear Decommissioning Trust Funds within Investments and Other Assets in the Consolidated Balance Sheets. The fair value of assets legally restricted for the purpose of settling asset retirement obligations associated with nuclear decommissioning was $1,551 million as of December 31, 2007 and $1,421 million as of December 31, 2006.

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 Catawba Nuclear Station Units 1 and 2 until 2043 and McGuire Nuclear Station Unit 1 and 2 until 2041 and 2043, respectively. In 2000, Duke Energy Carolinas was granted a renewed operating license for the Oconee Nuclear Station Units 1 and 2 until 2033 and Unit 3 until 2034.

9. 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, natural gas 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, which may include swaps, futures, forwards, options and swaptions. Duke Energy Carolinas’ derivative portfolio carrying value as of December 31, 2007 and 2006 was a net liability of approximately $12 million and a net asset of $3 million, respectively. The amounts represent the combination of derivative balances presented as other current assets, other current liabilities and other deferred credits and other liabilities on Duke Energy Carolinas’ Consolidated Balance Sheets.

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. As of December 31, 2007, Duke Energy Carolinas’ hedging activities did not extend beyond 2008.

The ineffective portion of commodity cash flow hedges resulted in an immaterial amount in 2007 and a pre-tax gain of $1 million in 2006 and is reported primarily in Operating Revenue -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 2007 and 2006.

As of December 31, 2007, $1 million of pre-tax deferred net gains on derivative instruments related to commodity cash flow hedges accumulated on the Consolidated Balance Sheets in Accumulated Other Comprehensive Income (Loss) (AOCI) 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 Derivatives 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 31 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 a percentage 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 2007, 2006, and 2005.

As of December 31, 2007, $2 million of pre-tax deferred losses on derivative instruments related to interest rate cash flow hedges accumulated on the Consolidated Balance Sheet in AOCI are expected to be recognized in earnings during the next twelve months as the hedged transactions occur. However, due to the volatility of interest rates, the corresponding value in AOCI for open hedges 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 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 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 of the amounts of additional collateral to be posted. If Duke Energy Carolinas were to 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.

Financial Instruments. The fair value of financial instruments, excluding derivatives included elsewhere in this Note, are 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, 2007 and 2006, 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 and/or because the stated rates approximate market rates.

Short-term investments. At December 31, 2007 and 2006 Duke Energy Carolinas had $0 and $221 million, respectively, of short-term investments consisting primarily of highly liquid tax-exempt debt securities. As discussed in Note 1, these securities frequently have stated maturities of 10 to 20 years or more; however, these instruments have historically provided 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. The holding period for these securities has typically been less than 1 year, but can be impacted by liquidity factors in the financial markets. 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. During the years ended December 31, 2007, 2006 and 2005, Duke Energy Carolinas purchased short-term investments of approximately $6,779 million, $19,482 million and $38,535 million, respectively, and received proceeds on sales of approximately $6,946 million, $19,915 and $38,386 million, respectively.

Other Long-term investments. Duke Energy Carolinas invests in debt and equity securities that are held in the NDTF (see Notes 8 and 9 for further information). These investments are classified as available-for-sale under SFAS No. 115 and, therefore, are carried at estimated fair value based on quoted market prices. Since management does not intend to use these investments in current operations, these investments are classified as long-term. Prior to the transfer of Spectra Energy Capital to Duke Energy on April 3, 2006, Duke Energy Carolinas also had investments in the captive insurance investment portfolio.

As of December 31, 2007 and 2006, Duke Energy Carolina’s NDTF held investments with a fair market value of approximately $1,929 million and $1,775 million, respectively. 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. 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, 2007 and 2006 related to holdings of the NDTF have been recognized as a regulatory asset.

The cost of securities sold is determined using the specific identification method. During the years ended December 31, 2007, 2006 and 2005, Duke Energy Carolinas purchased long-term investments of approximately $1,276 million, $1,141 million and $1,782 million, respectively, and received proceeds on sales of approximately $1,228 million, $1,056 and $1,745 million, respectively. Most of these purchases and sales relate to the NDTF. Purchases for the years ended December 31, 2007, 2006 and 2005 include contributions to the NDTF of approximately $48 million in each year pursuant to an order by the NCUC (see Note 8). The remaining investment activity relates primarily to purchases and sales within the NDTF.

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

For the years ended December 31, 2007, and 2006, there were no gains reclassified out of AOCI into earnings. For the year ended December 31, 2005 gains of approximately $3 million were reclassified out of AOCI into earnings, which is included in Income from Discontinued Operations, net of tax, on the Consolidated Statements of Operations.

Debt securities held at December 31, 2007 mature as follows: $15 million in less than one year, $75 million in one to five years, $117 million in six to ten years and $273 million thereafter.

The fair values and gross unrealized losses of available-for-sale equity and debt securities which are in an unrealized loss position, including securities held in the NDTF, summarized by investment type and length of time that the securities have been in a continuous loss position, are as follows at December 31, 2007 and 2006.

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. 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). Duke Energy Carolinas had investments in unconsolidated affiliates of approximately $2 million at both December 31, 2007 and 2006. Equity in earnings of unconsolidated affiliates included in Income From Continuing Operations was immaterial in each of the years ended December 31, 2007, 2006 and 2005.

For the period from January 1, 2006 through March 31, 2006 and the year ended December 31, 2005, Duke Energy Carolinas recorded pre-tax equity in earnings of unconsolidated affiliates classified in Income From Discontinued Operations, net of tax, on the Consolidated Statements of Operations of $175 million and $479 million, respectively. During the three months ended March 31, 2006, Duke Energy Carolinas received distributions of $131 million from those investments, which are included in Other, assets within net cash provided by operating activities on the accompanying Consolidated Statements of Cash Flows. Duke Energy Carolinas received distributions of $856 million during the year ended December 31, 2005. Of these distributions, $473 million are included in Other, assets within net cash provided by operating activities on the accompanying Consolidated Statements of Cash Flows and $383 million are included in Distributions from Equity Investments within net cash used in investing activities on the accompanying Consolidated Statements of Cash Flows.

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, 2007, Duke Energy Carolinas recorded governance expenses and shared services expenses of approximately $175 million and $614 million, respectively. Additionally, Duke Energy Carolinas is charged a management fee by the same unconsolidated affiliate that amounted to approximately $77 million for the year ended December 31, 2007. During the year ended December 31, 2006, Duke Energy Carolinas recorded governance expenses and shared services expenses of approximately $408 million and $246 million, respectively. The increase in the governance and shared services expenses is primarily driven by Duke Energy’s spin-off of Spectra Energy Corp. on January 2, 2007, as more governance costs are allocated to Duke Energy Carolinas post-spin, and the transfer of certain employees from Duke Energy Carolinas to other Duke Energy business units. Additionally, Duke Energy Carolinas is charged a management fee by the same unconsolidated affiliate that amounted to approximately $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 approximately $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 years ended December 31, 2007, 2006 and 2005, Duke Energy Carolinas recorded expenses of approximately $25 million per year related to insurance premiums paid to Bison, Duke Energy’s captive insurance company.

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 $8 million and $24 million to the nonconsolidated subsidiary in 2007 and 2006, respectively. Additionally, at December 31, 2007, Duke Energy Carolinas had a trade payable to Advance SC LLC of approximately $11 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:

In October 2005, Gulfstream Natural Gas System, LLC (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 2005, DCP Midstream formed DCP Midstream Partners, LP (a master limited partnership). DCP Midstream Partners, LP (DCPLP) completed an initial public offering (IPO) transaction in December 2005 that resulted in net proceeds of approximately $210 million. As a result, DCP Midstream had a 42 percent ownership interest in DCPLP, consisting of a 40 percent limited partner ownership interest and a 2 percent general partner ownership interest. DCP Midstream’s ownership interest in the general partner of DCPLP is 100 percent. The gain on the IPO transaction was deferred by DCP Midstream until DCP Midstream converts its subordinated units in DCPLP to common units.

In July 2005, Duke Energy Carolinas completed the transfer of a 19.7% interest in DCP Midstream to ConocoPhillips, Duke Energy Carolinas’ co-equity owner in DCP Midstream, which reduced Duke Energy Carolinas’ ownership interest in DCP Midstream from 69.7% to 50% and resulted in Duke Energy Carolinas and ConocoPhillips becoming equal 50% owners of DCP Midstream. As a result of this transaction, Duke Energy Carolinas deconsolidated its investment in DCP Midstream 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 DCP Midstream, to Duke Energy. Duke Energy Carolinas’ 50% of equity in earnings of DCP Midstream included in Income From Discontinued Operations, net of tax, for the three months ended March 31, 2006 and the period from July 1, 2005 through December 31, 2005 was approximately $146 million and $292 million, respectively. See summary condensed financial information for DCP Midstream below. During the three months ended March 31, 2006, Duke Energy Carolinas had gas sales to, purchases from and other operating expenses from affiliates of DCP Midstream 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 DCP Midstream of approximately $67 million, $65 million and $12 million, respectively. Additionally, Duke Energy Carolinas received approximately $90 million and $360 million for its share of distributions paid by DCP Midstream during 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 Net cash provided by operating activities on the Consolidated Statements of Cash Flows for the years ended 2006 and 2005, respectively, and approximately $0 and $73 million were included in Distributions from Equity Investments within Net cash used in investing activities on the Consolidated Statements of Cash Flows for the years ended 2006 and 2005, respectively.

In February 2005, DCP Midstream sold its wholly owned subsidiary TEPPCO GP, which is the general partner of TEPPCO LP, for approximately $1.1 billion and Duke Energy sold its limited partner interest in TEPPCO LP for approximately $100 million, in each case to Enterprise GP Holdings LP, an unrelated third party. These transactions resulted in pre-tax gains of approximately $1.8 billion. For the three months ended March 31, 2005, TEPPCO LP reported operating revenues of approximately $1,524 million, operating expenses of approximately $1,463 million, operating income of approximately $61 million, income from continuing operations of approximately $46 million, and net income of approximately $47 million.

Summary financial information for DCP Midstream, which had been accounted for under the equity method from July 1, 2005 is as follows:

DCP Midstream is a limited liability company which is a pass-through entity for U.S. income tax purposes. DCP Midstream 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 DCP Midstream. Therefore, DCP Midstream’s net income does not include income taxes for earnings which are pass-through to the members based upon their ownership percentage and Duke Energy recognized the tax impacts of its share of DCP Midstream’s pass-through earnings in Income From Discontinued Operations, net of tax, in the accompanying Consolidated Statements of Operations.

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

Duke Energy Carolinas did not record any amounts for severance in Income From Continuing Operations during the years ended December 31, 2007 and 2005. During the year ended December 31, 2006, Duke Energy Carolinas recorded severance amounts in Income from Continuing Operations of approximately $72 million, primarily due to voluntary and involuntary severance related to Duke Energy’s merger with Cinergy (see Note 1). For the years ended December 31, 2006 and 2005, Duke Energy Carolinas recorded severance expense within Income from Discontinued Operations, net of tax, in the Consolidated Statements of Operations of approximately $3 million and $28 million, respectively, all of which related to businesses transferred to Duke Energy on April 3, 2006.

Post-Retirement Benefits. In July 2007, Duke Energy Carolinas offered a voluntary early retirement incentive plan to approximately 1,100 eligible employees. The special termination benefit that was offered was a healthcare reimbursement account that could be used by participants for reimbursement of qualifying medical expenses. There were no severance benefits offered in connection with this plan. The window for acceptance of these voluntary termination benefits closed on August 15, 2007. During the year ended December 31, 2007, approximately 170 employees accepted the offer and, pursuant to SFAS No. 88, “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits,” Duke Energy Carolinas recorded a charge of approximately $6 million related to this voluntary plan.

Capitalized interest, which primarily represents the interest expense component of AFUDC, amounted to $22 million for 2007, $12 million for 2006, and $9 million for 2005.

Unsecured Debt. At both December 31, 2007 and 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 June 2007, Duke Energy Carolinas issued $500 million principal amount of 6.10% senior unsecured notes due June 1, 2037. The net proceeds from the issuance were used to redeem commercial paper that was issued to repay the outstanding $249 million 6.6% Insured Quarterly Senior Notes due 2022 on April 30, 2007, and approximately $110 million of convertible senior notes discussed below. The remainder was used for general purposes.

In November 2007, Duke Energy Carolinas issued $100 million in tax-exempt floating-rate bonds. The bonds are structured as insured auction rate securities, subject to an auction process every 35 days and bear a final maturity of 2040. The initial interest rate was set at 3.65%. The bonds were issued through the North Carolina Capital Facilities Finance Agency to fund a portion of the environmental capital expenditures at the Belews Creek and Allen Steam Stations.

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 Senior Notes. In May 2003, Duke Energy issued approximately $770 million of 1.75% convertible senior notes that were convertible into 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 conversion of these senior notes into shares of Duke Energy common stock was contingent upon the occurrence of certain events during specified periods. These events included whether the price of Duke Energy common stock reached specified thresholds, the credit rating of Duke Energy Carolinas fell below certain thresholds, the convertible notes were called for redemption by Duke Energy Carolinas, or specified transactions had occurred. In addition to the aforementioned events that could trigger early redemption, holders of the senior notes could 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. Additionally, Duke Energy Carolinas could 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.

During 2006, as a result of the market price of Duke Energy common stock achieving a specified threshold, approximately 27 million shares of common stock were issued related to conversions by holders of the convertible senior notes, which resulted in the retirement of approximately $632 million of convertible senior notes. At December 31, 2006, unsecured debt included approximately $110 million of these convertible senior notes.

On May 15, 2007, pursuant to the terms of the debt agreement, substantially all of the holders of the Duke Energy convertible senior notes required Duke Energy Carolinas to repurchase the balance then outstanding at a price equal to 100% of the principal amount plus accrued interest. In May 2007, Duke Energy Carolinas repurchased approximately $110 million of the convertible senior notes. At December 31, 2007, all convertible senior notes have been redeemed.

Secured Debt. In January 2008, Duke Energy Carolinas issued $900 million principal amount of mortgage refunding bonds, of which $400 million carries an interest rate of 5.25% due January 15, 2018 and $500 million carries an interest rate of 6.00% and matures January 15, 2038. Proceeds from the issuance will be used to fund capital expenditures and for general corporate purposes, including the repayment of commercial paper.

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, on a daily basis Duke Energy Carolinas sells certain accounts receivable, arising from the sale of electricity and/or related services as part of Duke Energy Carolinas’ franchised electric business, to DERF. 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 2009. 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, 2007 and 2006, the interest rate associated with the credit facility, which is based on commercial paper rates, was 5.3% and 5.8%, respectively, and $300 million was outstanding under the credit facility as of both dates. 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 Balance Sheets. As of December 31, 2007

and 2006, the $300 million outstanding balance of the credit facility was secured by approximately $532 million and $476 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, 2007, substantially all of Duke Energy Carolinas’ electric plants in service are mortgaged under the indenture relating to Duke Energy Carolinas’.

Floating Rate Debt. Unsecured debt, secured debt and other debt included approximately $1,022 million of floating-rate debt as of December 31, 2007, and $922 million as of December 31, 2006. 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, 2007 and 2006, the average interest rate associated with floating-rate debt was approximately 4.8% and 5.0%, 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 Investors Service (Moody’s). As of December 31, 2007, Duke Energy Carolinas had $10 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 $21 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, 2008, Duke Energy Carolinas’ senior unsecured credit rating was A- at S&P and A3 at Moody’s.

Available Credit Facilities and Restrictive Debt Covenants. In June 2007, Duke Energy closed on the syndication of an amended and restated credit facility, replacing the existing credit facilities totaling $2.65 billion with a 5-year, $2.65 billion master credit facility. Duke Energy Carolinas has a borrowing sub limit under the master credit facility of $800 million. Concurrent with the syndication of the master credit facility, Duke Energy established a new $1.5 billion commercial paper program and increased the commercial paper program at Duke Energy Carolinas from $650 million to $700 million. At December 31, 2007, Duke Energy Carolinas had $450 million of commercial paper and $7 million of letters of credit outstanding that were backstopped by this facility.

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

Duke Energy’s credit agreements contain various financial and other covenants, including, but not limited to, a covenant regarding the debt-to-total capitalization ratio at Duke Energy Carolinas to not exceed 65%. Additionally, 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, 2007, Duke Energy and Duke Energy Carolinas were in compliance with all covenants. In addition, some credit agreements may allow for acceleration of payments or termination of the agreements due to nonpayment, or 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 Matters. In October 2007, Duke Energy filed a registration statement (Form S-3) with the SEC. Under this Form S-3, which is uncapped, Duke Energy and certain subsidiaries, including Duke Energy Carolinas, may issue debt in the future at amounts, prices and with terms to be determined at the time of future offerings.

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 litigation matters and claims related to Duke Energy or Spectra Energy Capital are no longer contingent obligations at Duke Energy Carolinas.

Duke Energy Carolinas carries insurance and reinsurance coverages either directly or through Duke Energy’s current (and Duke Energy Carolinas’ former) captive insurance company, Bison, and its affiliates, 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 energy 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 public liability 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 liability insurance, 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 assessment and rate are 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 property and 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 $1.0 billion each for the Oconee and McGuire Nuclear Stations. The Oconee and McGuire Nuclear Stations also share an additional $1.0 billion insurance limit above this excess. This shared limit is not subject to reinstatement in the event of a loss.

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. The McGuire and Catawba policy limit is $490 million and the Oconee policy limit is $392 million.

In the event of large industry losses, NEIL’s Board of Directors may assess Duke Energy Carolinas for amounts up to 10 times its annual premiums. The current potential maximum assessments are: Primary Property Insurance—$38 million, Excess Property Insurance—$43 million and Accidental Outage Insurance—$22 million.

Pursuant to regulations of the NRC, each company’s property damage insurance policies provide that all proceeds from such insurance be applied, first, to place the plant in a safe and stable condition after an accident, and second, to decontaminate before any proceeds can be used for decommissioning, plant repair or restoration.

In the event of a loss, the amount of insurance available might not be adequate to cover property damage and other expenses incurred. Uninsured losses and other expenses, to the extent not recovered by other sources, could have a material adverse effect on Duke Energy Carolinas’ results of operations, cash flows or financial position.

The maximum assessment amounts include 100% of Duke Energy Carolinas’ potential obligation to NEIL for the Catawba Nuclear Station. However, 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. Duke Energy Carolinas is 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 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. Duke Energy Carolinas believes that completion or resolution of these matters will have no material adverse effect on its consolidated results of operations, cash flows or financial position.

Clean Water Act 316(b). The U.S. Environmental Protection Agency (EPA) finalized its cooling water intake structures rule in July 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 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. Duke Energy Carolinas is still unable to estimate costs to comply with the EPA’s rule, although 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 was to have limited total annual mercury emissions from coal-fired power plants across the United States through a two-phased cap-and-trade program beginning in 2010. The CAIR limits total annual and summertime NO_x 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 NO_x and in 2010 for SO₂. Phase 2 begins in 2015 for both NO_x 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 CAIR requirements (see Note 5).

On February 8, 2008 the U.S. Court of Appeals for the District of Columbia issued its opinion in New Jersey v. EPA, No. 05-1097 vacating the CAMR. The decision creates uncertainty regarding future mercury emission reduction requirements and their timing. Barring reversal of the decision if appealed, there will be a delay in the implementation of federal mercury requirements for existing coal-fired power plants while EPA conducts a new rulemaking. Duke Energy Carolinas is unable to estimate the costs to comply with a new EPA rule, although 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.

Coal Combustion Product (CCP) Management. Duke Energy Carolinas currently estimates that it will spend approximately $130 million over the period 2008-2012 to install synthetic caps and liners at existing and new CCP landfills and to convert CCP handling systems from wet to dry systems.

Extended Environmental Activities and Accruals. Included in Other Deferred Credits and Other Liabilities and Other Current Liabilities on the Consolidated Balance Sheets were total accruals related to extended environmental-related activities of approximately $9 million as of December 31, 2007 and 2006, 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. Duke Energy Carolinas believes that completion or resolution of these matters will have no material impact on its 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 alleges 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 the best available emission controls for SO₂, NO_x and particulate matter. The complaints seek injunctive relief to require installation of pollution control technology on various allegedly violating generating units, and 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 in the Carolinas violate these NSR provisions. In August 2003, the trial court issued a summary judgment opinion adopting Duke Energy Carolinas’ legal positions on the standard to be used for measuring an increase in emissions, and granted judgment in favor of Duke Energy Carolinas. The trial court’s decision was appealed and ultimately reversed and remanded for trial by the United States Supreme Court. At trial, Duke Energy Carolinas will continue to assert that the projects were routine or not projected to increase emissions. No trial date has been set.

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. Ultimate resolution of this matter, even in settlement, could have a material adverse effect on Duke Energy Carolinas’ consolidated results of operations, cash flows or financial position. However, Duke Energy Carolinas will pursue appropriate regulatory treatment for any costs incurred in connection with such resolution.

Cherokee County Property Litigation. Duke Energy Carolinas filed suit in July 2005 seeking specific performance of its asserted contract to purchase approximately 2,000 acres of land in Cherokee County, South Carolina and asking for a declaratory judgment to establish that a contract for sale existed. Defendants counterclaimed for slander of title and abuse of process. In December 2005, the court dismissed Duke Energy Carolinas’ claims and Defendants’ amended their counterclaims. As amended, Defendants’ counterclaims alleged slander of title, abuse of process, tortuous interference with prospective contracts of others in the energy market and tortuous interference with contract. A hearing on Duke Energy Carolinas’ Motion for Summary Judgment was held in April 2007 and the judge ruled in May 2007 dismissing Defendants’ slander of title claims. On May 30, 2007, the parties settled this matter. The resolution of this matter did not have a material effect on Duke Energy Carolinas’ consolidated results of operations, cash flows or financial position.

Asbestos-related Injuries and Damages Claims. Duke Energy Carolinas has experienced numerous claims for indemnification and medical cost reimbursement relating to damages for bodily 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 prior to 1985.

Amounts recognized as asbestos-related reserves related to Duke Energy Carolinas in the Consolidated Balance Sheets totaled approximately $1,082 million and $1,159 million as of December 31, 2007 and 2006, respectively, and are classified in Other Deferred Credits and Other Liabilities and Other Current Liabilities. These reserves are based upon the minimum amount in Duke Energy’s best estimate of the range of loss of $1,082 million to $1,350 million for current and future asbestos claims through 2027. The reserves balance of $1,082 million as of December 31, 2007 consists of approximately $182 million related to known claimants and approximately $900 million related to unknown claimants. Management believes that it is possible there will be additional claims filed against Duke Energy Carolinas after 2027. In light of the uncertainties inherent in a longer-term forecast, management does not believe that they can reasonably estimate the indemnity and medical costs that might be incurred after 2027 related to such potential claims. Asbestos-related loss estimates incorporate anticipated inflation, if applicable, and are recorded on an undiscounted basis. These reserves are based upon current estimates and are subject to greater uncertainty as the projection period lengthens. A significant upward or downward trend in the number of claims filed, the nature of the alleged injury, and the average cost of resolving each such claim could change our estimated liability, as could any substantial adverse or favorable verdict at trial. A federal legislative solution, further state tort reform or structured settlement transactions could also change the estimated liability. Given the uncertainties associated with projecting matters into the future and numerous other factors outside our control, management believes that it is possible Duke Energy Carolinas may incur asbestos liabilities in excess of the recorded reserves.

Duke Energy Carolinas has a third-party insurance policy to cover certain losses related to its asbestos-related injuries and damages above an aggregate self insured retention of $476 million. Through December 31, 2007, Duke Energy Carolinas has made approximately $460 million in payments that apply to this retention. The insurance policy limit for potential insurance recoveries for indemnification and medical cost claim payments is $1,107 million in excess of the self insured retention. Probable insurance recoveries of approximately $1,040 million and $1,020 million related to this policy are classified in the Consolidated Balance Sheets primarily in Other within Investments and Other Assets as of December 31, 2007 and 2006, respectively. Duke Energy Carolinas is not aware of any uncertainties regarding the legal sufficiency of insurance claims or any significant solvency concerns related to the insurance carrier.

Other Litigation and Legal Proceedings. Duke Energy Carolinas is involved in other legal, tax and regulatory proceedings arising in the ordinary course of business, some of which involve substantial amounts. Duke Energy Carolinas believes that the final disposition of these proceedings will not have a material adverse effect on its 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, 2007 and 2006, Duke Energy Carolinas has recorded reserves, including reserves related to the aforementioned asbestos-related injuries and damages claims, of approximately $1.1 billion and $1.2 billion, respectively, for these proceedings and exposures. Duke Energy Carolinas has insurance coverage for certain of these losses incurred. These reserves represent management’s best estimate of probable loss as defined by SFAS No. 5. As of December 31, 2007, Duke Energy Carolinas has recognized approximately $1,040 million of probable insurance recoveries related to these losses.

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 included in income from continuing operations was $48 million in 2007, $30 million in 2006 and $39 million in 2005, which is included in Operation, Maintenance and Other on the Consolidated Statements of Operations. Consolidated rental expense for operating leases included in Income From Discontinued Operations, net of tax, was $18 million for the period from January 1, 2006 through March 31, 2006 and $80 million in 2005. Duke Energy Carolinas has no capital leases as of December 31, 2007. 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, 2007:

Beginning in 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 program. 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. Prior to the adoption of SFAS No. 123(R), Duke Energy Carolinas applied APB No. 25 and FIN No. 44, 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 year ended December 31, 2005 have not been restated. There were no modifications to outstanding stock options prior to the adoption of SFAS No. 123(R).

The following table shows what earnings available to member’s/common stockholders would have been if Duke Energy 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. The 2006 Plan supersedes Duke Energy’s 1998 Long-term Incentive Plan, as amended (the 1998 Plan), and no additional grants will be made from the 1998 Plan. Under the 2006 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 January 2, 2007, Spectra Energy was spun off by Duke Energy to its shareholders. In connection with this transaction, Duke Energy distributed substantially all the shares of common stock of Spectra Energy to Duke Energy shareholders. The distribution ratio approved by Duke Energy’s Board of Directors was one-half share of Spectra Energy common stock for every share of Duke Energy common stock.

Effective with the spin-off, all previously granted Duke Energy long-term incentive plan equity awards were split into Duke Energy and Spectra Energy equity-related awards, consistent with the spin-off conversion ratio. Each equity award (stock option, phantom share, performance share and restricted stock award) was split into two awards: a Duke Energy award (issued by Duke Energy in Duke Energy shares) and a Spectra Energy award (issued by Spectra Energy in Spectra Energy shares). The number of shares covered by the adjusted Duke Energy award equals the number of shares covered by the original award, and the number of shares covered by the Spectra Energy award equals the number of shares that would have been received in the spin-off by a non-employee shareholder (which reflected the one-half share of Spectra Energy common stock for every share of Duke Energy common stock distribution ratio for Spectra Energy shares).

Stock option exercise prices were adjusted using a formula approved by the Duke Energy Compensation Committee that was designed to preserve the exercise versus market price spread (whether “in the money” or “out of the money”) of each option. All equity award adjustments were designed to equalize the fair value of each award before and after the spin-off. Accordingly, no material incremental compensation expense was recognized as a result of the equity award adjustments.

Duke Energy Carolinas’ future stock-based compensation expense will not be significantly impacted by the equity award adjustments that occurred as a result of the spin-off. Stock-based compensation expense recognized in future periods will correspond to the unrecognized compensation expense as of the date of the spin-off. Unrecognized compensation expense as of the date of the spin-off reflects the unamortized balance of the original grant date fair value of the equity awards held by Duke Energy employees (regardless of whether those awards are linked to Duke Energy stock or Spectra Energy stock).

Duke Energy Carolinas recorded pre-tax stock-based compensation expense included in Income From Continuing Operations for the years ended December 31, 2007, 2006 and 2005 as follows, the components of which are further described below:

The tax benefit associated with the recorded expense in Income From Continuing Operations for the years ended December 31, 2007, 2006 and 2005 was approximately $3 million, $5 million and $3 million, respectively. There were no material differences in income from continuing operations, income tax expense, net income, cash flows, or basic and diluted earnings per share from the adoption of SFAS No. 123(R).

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 and $38 million is included in Income From Discontinued Operations, net of tax, on the Consolidated Statements of Operations related to the three months ended

March 31, 2006 and the year ended December 31, 2005, respectively. The tax benefit associated with 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 year ended December 31, 2005 is approximately $4 million and $14 million, respectively.

There were no options granted to Duke Energy Carolinas employees during the years ended December 31, 2007, 2006 and 2005.

The following table summarizes information about outstanding Duke Energy stock options held by Duke Energy Carolinas employees at December 31, 2007:

On December 31, 2006 and 2005, Duke Energy Carolinas’ exercisable options were approximately 4 million and 22 million, respectively, with a weighted-average exercise price of $18 for both years. The total intrinsic value of options exercised during the years ended December 31, 2007, 2006 and 2005 was approximately $2 million, $7 million and $17 million, respectively. Of the $7 million intrinsic value of options exercised during 2006, approximately $5 million related to the three months ended March 31, 2006 and approximately $2 million related to the nine months ended December 31, 2006. Cash received by Duke Energy from options exercised during the years ended December 31, 2007, 2006 and 2005 was approximately $4 million, $26 million and $40 million, respectively, with a related tax benefit of approximately $1 million, $3 million and $6 million, respectively.

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. Payments for cash settled awards during the year ended December 31, 2007 were immaterial.

Phantom stock awards outstanding under the 2006 Plan generally vest over periods from immediate to three years. Phantom stock awards outstanding under the 1998 Plan generally vest over periods from immediate to five years. Duke Energy awarded 257,510 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, 2007, 187,220 shares (fair value of approximately $5 million, based on the market price of Duke Energy’s common stock at the grant date) in the year ended December 31, 2006, and 1,139,880 shares (fair value of approximately $31 million) in the year ended December 31, 2005.

The following table summarizes information about phantom stock awards outstanding at December 31, 2007:

The total fair value of the shares vested during the years ended December 31, 2007, 2006 and 2005 was approximately $4 million, $14 million and $10 million, respectively. Of the $14 million of shares vested during 2006, approximately $12 million vested during the three months ended March 31, 2006 and approximately $2 million vested during the nine months ended December 31, 2006. As of December 31, 2007, Duke Energy had approximately $2 million of future compensation cost which is expected to be recognized over a weighted-average period of 2.6 years.

Stock-based awards outstanding under the 2006 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 2007 and 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 317,460 shares (fair value of approximately $5 million) to Duke Energy Carolinas employees in the year ended December 31, 2007, 281,160 shares (fair value of approximately $5 million) in the year ended December 31, 2006, and 1,275,020 shares (fair value of approximately $34 million) in the year ended December 31, 2005.

The following table summarizes information about stock-based performance awards outstanding at December 31, 2007:

The total fair value of the shares vested during the years ended December 31, 2007, 2006 and 2005 was approximately $5 million, $3 million and $3 million, respectively. All of the shares in 2006 vested during the three months ended March 31, 2006. As of December 31, 2007, Duke Energy had approximately $2 million of future compensation cost which is expected to be recognized over a weighted-average period of 1.2 years.

Other stock awards outstanding under the 1998 Plan generally vest over periods from three to five years. There were no other stock awards issued during the year ended December 31, 2007. 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 date) to Duke Energy Carolinas employees in the year ended December 31, 2006, and 47,000 shares (fair value of approximately $1 million, based on the market price of Duke Energy’s common stock at the grant date) in the year ended December 31, 2005.

The following table summarizes information about other stock awards outstanding at December 31, 2007:

The total fair value of the shares vested during the years ended December 31, 2007, 2006 and 2005 was less than $1 million, less than $1 million and approximately $1 million, respectively. As of December 31, 2007, Duke Energy Carolinas had approximately $3 million of future compensation cost which is expected to be recognized over a weighted-average period of 2.8 years.

Duke Energy 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 Carolina’s transfer of its membership interests in Spectra Energy Capital to Duke Energy, as discussed above, included the transfer of the Westcoast Energy Inc. (Westcoast) Canadian Retirement Plans accrued pension liabilities and accrued other post-retirement liabilities.

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 did not make any contributions to Duke Energy’s defined benefit plans during the years ended December 31, 2007, 2006 or 2005. Duke Energy Carolinas made contributions to the Westcoast defined benefit plans of approximately $10 million for the three months ended March 31, 2006 and $42 million in the year ended December 31, 2005. Duke Energy Carolinas also made contributions to the Westcoast defined contribution plans of $1 million for the three months ended March 31, 2006 and $3 million in the year ended December 31, 2005.

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 adopted the recognition and disclosure provisions of SFAS No. 158 “Employer’s Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R)” (SFAS No. 158), effective December 31, 2006. Duke Energy adopted the change in measurement date transition requirements of SFAS No. 158 effective January 1, 2007 by remeasuring plan assets and benefit obligations as of that date. Previously, Duke Energy used a September 30 measurement date for its defined benefit and other post-retirement plans.

Since the obligations of the qualified pension plans, non-qualified pension plans and other post-retirement benefit plans exist at Duke Energy, Duke Energy Carolinas does not have any amounts reflected on its Consolidated Balance Sheets within regulatory assets or liabilities, prepaid benefit costs, accrued pension liabilities or AOCI.

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 $35 million in 2007, $42 million in 2006 and $41 million in 2005. These amounts exclude pre-tax expenses of $9 million for the three months ended March 31, 2006 and $20 million for the year ended December 31, 2005, which are reflected in Income From Discontinued Operations, net of tax, in the Consolidated Statements of Operations.

Components of Net Periodic Pension Costs as allocated by Duke Energy: Qualified Pension Plans

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 for the year ended December 31, 2005 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 plan assets (excluding Cinergy plans) was $2,621 million as of December 31, 2007 and $3,022 million as of September 30, 2006. The projected benefit obligation of Duke Energy’s plan (excluding Cinergy plans) was $2,360 million as of December 31, 2007 and $2,847 million as of December 31, 2006. The accumulated benefit obligation of Duke Energy’s plan (excluding Cinergy plans) was $2,251 million as of December 31, 2007 and $2,719 million as of December 31, 2006. The decrease in plan assets, projected benefit obligation and accumulated benefit obligation at December 31, 2007 as compared to December 31, 2006 relates to the transfer of a portion of Duke Energy’s pension assets and obligation to Spectra Energy Corp as a result of the spin-off of Duke Energy’s natural gas businesses to shareholders on January 2, 2007. This transaction had no impact on the obligation of Duke Energy to Duke Energy Carolinas’ participants.

Net periodic pension expense included in income from continuing operations was approximately $2 million, $3 million and $4 million for the years ended December 31, 2007, 2006 and 2005, respectively. These amounts exclude pre-tax pension cost of $2 million for the three months ended March 31, 2006 and $9 million for the year ended December 31, 2005 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).

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 12 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 and $27 million for the three months ended March 31, 2006 and the year ended December 31, 2005 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 components of Other Income and Expenses, net on the Consolidated Statements of Operations for the years ended December 31, 2007, 2006 and 2005 are as follows:

For information on subsequent events related to regulatory matters, debt and credit facilities and commitments and contingencies, see Notes 5, 14 and 15, respectively.

During the first quarter of 2007, Duke Energy Carolinas recorded the following unusual or infrequently occurring items: approximate $26 million pre-tax gain related to a settlement with the Department of Justice resolving used nuclear fuel litigation against the DOE (see Note 5).

There were no unusual or infrequently occurring items during the second or third quarters of 2007.

During the fourth quarter of 2007, Duke Energy Carolinas recorded the following unusual or infrequently occurring item: an approximate $17 million pre-tax impairment charge related to a write-off of a portion of the investment in the GridSouth RTO (see Note 5).

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 2), which is included in Income From Discontinued Operations, net of tax, on the Consolidated Statements of Operations.

There were no unusual or infrequently occurring items during the second, third or fourth quarters of 2006.

The valuation and reserve amounts above do not include unrecognized tax benefits amounts or deferred tax asset valuation allowance amounts.

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, 2007, 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 of compliance.

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, 2007 and have concluded that no change has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.

Duke Energy Carolinas’ management is responsible for establishing and maintaining an adequate system of internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Our internal control system was designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes, in accordance with generally accepted accounting principles. Because of inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies and procedures may deteriorate.

Duke Energy Carolinas’ management, including our Chief Executive Officer and Chief Financial Officer, has conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2007 based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2007.

This annual report does not include an attestation report of Deloitte & Touche LLP, Duke Energy Carolinas’ registered independent public accounting firm, regarding internal control over financial reporting. Management’s report was not subject to attestation by Deloitte & Touche LLP pursuant to temporary rules of the SEC that permit Duke Energy Carolinas to provide only management’s report in this annual report.

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 Carolinas, LLC and its subsidiaries for 2007 and 2006:

To safeguard the continued independence of the independent auditor, the Duke Energy Audit Committee adopted a policy that provides that the independent public accountants are only permitted to provide services to Duke Energy Carolina, LLC that have been pre-approved by the Duke Energy Audit Committee. Pursuant to the policy, detailed audit services, audit-related services, tax services and certain other services have been specifically pre-approved up to certain fee limits. In the event that the cost of any of these services may exceed the pre-approved limits, the Duke Energy Audit Committee must pre-approve the service. All other services that are not prohibited pursuant to the SEC’s or other applicable regulatory bodies’ rules of regulations must be specifically pre-approved by the Duke Energy Audit Committee. All services performed in 2007 by the independent public accountant were approved by the Duke Energy Audit Committee pursuant to its pre-approval policy.

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

Consolidated Statements of Operations for the Years Ended December 31, 2007, 2006 and 2005

Consolidated Statements of Cash Flows for the Years Ended December 31, 2007, 2006 and 2005

Consolidated Statements of Member’s/Common Stockholders’ Equity and Comprehensive Income for the Years ended December 31, 2007, 2006 and 2005

Quarterly Financial Data, as revised (unaudited, included in Note 20 to the Consolidated Financial Statements)

Consolidated Financial Statement Schedule II—Valuation and Qualifying Accounts and Reserves for the Years Ended December 31, 2007, 2006 and 2005

(b) 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’ Capital for the Years Ended December 31, 2005, 2004 and 2003

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

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

Consolidated Statements of Operations and Comprehensive 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

Consolidated Financial Statement Schedule II of DCP Midstream, LLC—Consolidated Valuation and Qualifying Accounts and Reserves 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 years 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:

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.

During the year ended December 31, 2007, we distributed $1,364 million to Spectra Energy and ConocoPhillips, and DCP Partners distributed $44 million to its unitholders. On January 24, 2008, DCP Partners announced the declaration of a cash distribution of $0.57 per unit, payable on February 14, 2008, to unitholders of record on February 7, 2008.

In September 2007, we issued $450 million principal amount of 6.75% Senior Notes due 2037, or the 6.75% Notes, for proceeds of approximately $444 million (net of related offering costs). The 6.75% Notes mature and become due and payable on September 15, 2037. We will pay interest semiannually on March 15 and September 15 of each year, commencing March 15, 2008. The proceeds of this offering were used to fund the Momentum Energy Group, Inc. or MEG, acquisition.

On August 29, 2007, we acquired the stock of MEG for approximately $635 million plus closing adjustments of approximately $8 million. MEG owns assets in the Fort Worth, Piceance and Powder River producing basins. Concurrent with this transaction, DCP Partners acquired certain subsidiaries of MEG from us for $165 million plus closing adjustments of approximately $10 million, subject to final closing adjustments. These subsidiaries of MEG own assets in the Piceance Basin, including a 70% operated interest in the 31-mile Collbran Valley Gas Gathering joint venture in western Colorado, assets in the Powder River Basin, including the 1,324-mile Douglas gas gathering system, and other facilities in Wyoming. We ultimately funded our portion of this acquisition with the 6.75% Notes, as well as cash on hand. DCP Partners financed this transaction with $120 million of revolver and term loan borrowings under DCP Partners’ Amended Credit Agreement, the issuance of approximately $100 million of common units through a private placement (described in the next sentence) with certain institutional inventors and cash on hand. In August 2007, DCP Partners sold 2,380,952 common limited partner units in a private placement, pursuant to a common unit purchase agreement with private owners of MEG or affiliates of such owners, at $42.00 per unit, or approximately $100 million in the aggregate.

In July 2007, we contributed to DCP Partners a 25% limited liability company interest in DCP East Texas Holdings, LLC, our 40% limited liability company interest in Discovery Producer Services LLC, and a derivative instrument, for aggregate consideration of $244 million in cash, including $1 million for net working capital and other adjustments, $27 million in common units and $1 million in general partner equivalent units. We own the remaining 75% limited liability company interest in East Texas Holdings, LLC, while third parties still own the other 60% limited liability interest in Discovery Producer Services LLC. DCP Partners financed the cash portion of this transaction with borrowings under DCP Partners’ existing credit agreement. We will continue to operate these assets and these assets will continue to be included in our financial statements, along with DCP Partners.

In June 2007, DCP Partners entered into a private placement agreement with a group of institutional investors for $130 million, representing 3,005,780 common limited partner units at a price of $43.25 per unit, and received proceeds of $129 million, net of offering costs. DCP Partners used a portion of the net proceeds of this private placement to pay down a portion of the debt associated with the acquisition from Anadarko Petroleum Corporation of assets in southern Oklahoma, and used the remaining portion of the net proceeds to fund future capital expenditures, including the MEG acquisition.

In June 2007, DCP Partners entered into an Amended and Restated Credit Agreement, or DCP Partners’ Amended Credit Agreement, which amended DCP Partners’ Credit Agreement. This new 5-year DCP Partners’ Amended Credit Agreement consists of a $600 million revolving credit facility and a $250 million term loan facility, and matures on June 21, 2012. The amendment also improved pricing and certain other terms and conditions of DCP Partners’ Credit Agreement.

In May 2007, DCP Partners acquired certain gathering and compression assets located in southern Oklahoma, as well as related commodity purchase contracts, from Anadarko Petroleum Corporation for approximately $181 million.

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 (**). Portions of the exhibit designated by a triple asterisk (***) have been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment pursuant to Rule 24b-2 under the Securities and Exchange Act of 1934.

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)


Large accelerated filer ¨		Accelerated filer ¨
Non-accelerated filer x		Smaller reporting company ¨
(Do not check if a smaller reporting company)


Item		Page
PART I.

1.	BUSINESS	3

	GENERAL	3

	ENVIRONMENTAL MATTERS	5

1A.	RISK FACTORS	6

1B.	UNRESOLVED STAFF COMMENTS	10

2.	PROPERTIES	10

3.	LEGAL PROCEEDINGS	11

PART II.

5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	12

7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	13

7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	19

8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	20

9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	75

9A.	CONTROLS AND PROCEDURES	75

PART III.

14.	PRINCIPAL ACCOUNTING FEES AND SERVICES	76

PART IV.

15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	77

	SIGNATURES	78

	EXHIBIT INDEX	E-1


	Years Ended December 31,
	2007		2006		Increase (Decrease)
Operating revenues	$	5,812	$	5,442	$	370
Operating expenses		4,586		4,353		233
Gains on sales of other assets and other, net		2		—		2

Operating income		1,228		1,089		139
Other income and expenses, net		76		98		(22	)
Interest expense		292		299		(7	)

Income from continuing operations before income taxes		1,012		888		124
Income tax expense from continuing operations		342		287		55

Income from continuing operations		670		601		69
Income from discontinued operations, net of tax		—		186		(186	)

Net income	$	670	$	787	$	(117	)


	Years Ended December 31,
	2007		2006		2005
Operating Revenues-Regulated Electric	$	5,812	$	5,442	$	5,432
Operating Expenses
Operation, maintenance and other		1,727		1,675		1,664
Fuel used in electric generation and purchased power		1,632		1,475		1,248
Depreciation and amortization		904		897		962
Property and other taxes		323		306		309
Total operating expenses		4,586		4,353		4,183
Gains on Sales of Other Assets and Other, net		2		—		7
Operating Income		1,228		1,089		1,256
Other Income and Expenses, net		76		98		15
Interest Expense		292		299		292
Income From Continuing Operations Before Income Taxes		1,012		888		979
Income Tax Expense from Continuing Operations		342		287		330
Income From Continuing Operations		670		601		649
Income From Discontinued Operations, net of tax		—		186		1,179
Income Before Cumulative Effect of Change in Accounting Principle		670		787		1,828
Cumulative Effect of Change in Accounting Principle, net of tax and minority interest		—		—		(4	)
Net Income		670		787		1,824
Dividends and Premiums on Redemption of Preferred and Preference Stock		—		—		12
Earnings Available For Member's/Common Stockholders	$	670	$	787	$	1,812


Term or Acronym		Definition
AFUDC		Allowance for Funds Used During Construction

AOCI		Accumulated Other Comprehensive Income

APB		Accounting Principles Board

Bison		Bison Insurance Company Limited

BPM		Bulk Power Marketing

CAA		Clean Air Act

CAIR		Clean Air Interstate Rule

Campeche		Compañía de Servicios de Compresión de Campeche, S.A. de C.V.

CAMR		Clean Air Mercury Rule

Cinergy		Cinergy Corp.

CO₂		Carbon Dioxide

COL		Combined Construction and Operating License

CPCN		Certificate of Public Convenience and Necessity

DCP Midstream		DCP Midstream, LLC (formerly Duke Energy Field Services)

DEI		Duke Energy International, LLC

DEM		Duke Energy Merchants, LLC

DENA		Duke Energy North America

DENR		Department of Environment and Natural Resources

DETM		Duke Energy Trading and Marketing, LLC

DOE		United States Department of Energy

DOJ		Department of Justice

DSM		Demand Side Management

Duke Energy		Duke Energy Corporation (collectively with its subsidiaries)

Duke Energy Carolinas		Duke Energy Carolinas, LLC

EITF		Emerging Issues Task Force

EPA		Environmental Protection Agency

FASB		Financial Accounting Standards Board

FEED		Front End Engineering and Design Study

FERC		Federal Energy Regulatory Commission

FIN		Financial Accounting Standards Board Interpretation

FSP		Financial Accounting Standards Board Staff Position

FTC		United States Federal Trade Commission

GAAP		United States Generally Accepted Accounting Principles

IRS		Internal Revenue Service

ISO		Independent Transmission System Operator

LS Power		LS Power Equity Partners

MW		Megawatt


Term or Acronym		Definition

NCUC		North Carolina Utilities Commission

NDTF		Nuclear Decommissioning Trust Funds

NERC		North American Electric Reliability Council

NOx		Nitrogen oxide

NRC		Nuclear Regulatory Commission

OCC		Office of the Ohio Consumers’ Counsel

PSCSC		Public Service Commission of South Carolina

SAB		Staff Accounting Bulletin

SEC		Securities and Exchange Commission

SFAS		Securities and Exchange Commission Statement of Financial Accounting Standards

SO₂		Sulfur dioxide

Spectra Energy		Spectra Energy Corporation

Spectra Capital		Spectra Energy Capital LLCC (formerly Duke Capital LLC)

TEPPCO GP		Texas Eastern Products Pipeline Company, LLC

TEPPCO LP		TEPPCO Partners, LP

Westcoast		Westcoast Energy, Inc.


	December 31,
	2007		2006
ASSETS
Current Assets
Cash and cash equivalents	$	21	$	38
Short-term investments		—		221
Receivables (net of allowance for doubtful accounts of $6 at December 31, 2007 and $5 at December 31, 2006)		783		679
Inventory		590		554
Other		169		292
Total current assets		1,563		1,784
Investments and Other Assets
Nuclear decommissioning trust funds		1,929		1,775
Other		1,323		1,090
Total investments and other assets		3,252		2,865
Property, Plant and Equipment
Cost		24,593		22,660
Less accumulated depreciation and amortization		9,227		8,341
Net property, plant and equipment		15,366		14,319
Regulatory Assets and Deferred Debits
Deferred debt expense		184		193
Regulatory assets related to income taxes		408		396
Other		531		540
Total regulatory assets and deferred debits		1,123		1,129
Total Assets	$	21,304	$	20,097


												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, 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
Intercompany 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 in Spectra Energy Capital, LLC	—			(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
Intercompany advance forgiveness	—			496			—			—			—			—			—			—			496
Other	—			4			—			—			—			—			—			—			4
Balance December 31, 2006	—		$	5,984		$	—		$	—		$	—		$	(4	)	$	—		$	—		$	5,980
Net income	—			670			—			—			—			—			—			—			670
Other Comprehensive Income
Foreign currency translation adjustments	—			—			—			—			—			—			—			—			—
Net unrealized losses on cash flow hedges^(b)	—			—			—			—			—			(7	)		—			—			(7	)
Reclassification into earnings from cash flow hedges^(c)	—			—			—			—			—			(10	)		—			—			(10	)

Total comprehensive income	—			—			—			—			—			—			—			—			653
Balance December 31, 2007	—		$	6,654		$	—		$	—		$	—		$	(21	)	$	—		$	—		$	6,633


	December 31,
	2007		2006
	(in millions)
Materials and supplies	$	366	$	329
Coal held for electric generation		224		225

Total inventory	$	590	$	554


	Year Ended December 31, 2007		Year Ended December 31, 2006		Year Ended December 31, 2005
	(in millions)
Excise Taxes	$	132	$	123	$	121


			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


	Unaffiliated Revenues		Segment EBIT/ Consolidated Income from Continuing Operations before Income Taxes			Depreciation and Amortization^(b)		Capital and Investment Expenditures^(b)		Segment Assets^(c)
	(in millions)
Year Ended December 31, 2007
Franchised Electric	$	5,812	$	1,518		$	904	$	1,734	$	21,304
Total reportable segments		5,812		1,518			904		1,734		21,304
Other		—		(259	)		—		—		—
Interest expense		—		(292	)		—		—		—
Interest income		—		45			—		—		—
Total consolidated	$	5,812	$	1,012		$	904	$	1,734	$	21,304

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


	U.S.		Canada		Latin America		Other Foreign		Consolidated
	(in millions)
2007
Consolidated revenues^(a)	$	5,812	$	—	$	—	$	—	$	5,812
Consolidated long-lived assets		17,810		—		—		—		17,810
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


	As of December 31,
	2007		2006		Recovery/Refund Period Ends
	(in millions)
Regulatory Assets^(a)
Net regulatory asset related to income taxes^(c)	$	408	$	396	⁽ⁱ	⁾
ARO costs^(b)		489		463	2043
Deferred debt expense^(c)		139		141	2039
Vacation accrual^(e)		63		77	2008
Under-recovery of fuel costs⁽ⁿ⁾		89		61	2009
Regional Transmission Organization (RTO)^(b)(m)		22		41	^(m	⁾
Other^(b)		12		28	^(l	⁾

Total Regulatory Assets	$	1,222	$	1,207

Regulatory Liabilities^(a)
Removal costs^(c)(f)	$	1,528	$	1,433	^(k	⁾
Nuclear property and liability reserves^(c)(f)		179		173	2043
Demand-side management costs^(d)(f)		96		78	^(j	⁾
Purchased capacity costs^(d)(g)		90		107	^(h	⁾
Other^(f)		66		18	^(l	⁾

Total Regulatory Liabilities	$	1,959	$	1,809


	Ownership Share		Property, Plant, and Equipment		Accumulated Depreciation		Construction Work in Progress
	(in millions)
Catawba Nuclear Station (Units 1 and 2)	12.5	%	$	559	$	307	$	10


	For the Years Ended December 31,
	2007			2006			2005
	(in millions)
Current income taxes
Federal	$	147		$	290		$	372
State		21			48			61

Total current income taxes^(a)		168			338			433

Deferred income taxes
Federal		149			(41	)		(86	)
State		33			(1	)		(7	)

Total deferred income taxes		182			(42	)		(93	)

Investment tax credit amortization		(8	)		(9	)		(10	)

Total income tax expense from continuing operations		342			287			330

Total income tax expense from discontinued operations		—			120			521
Total income tax benefit from cumulative effect of change in accounting principle		—			—			(1	)

Total income tax expense included in Consolidated Statements of Operations	$	342		$	407		$	850


	Increase/ (Decrease)
	(in millions)
Liabilities
Other Deferred Credits and Other Liabilities^(a)	$	55
Deferred Income Taxes		(30	)
Taxes Payable		(25	)

Total^(b)	$	—


	Increase/ (Decrease)
	(in millions)
Unrecognized Tax Benefits—January 1, 2007	$	179

Unrecognized Tax Benefits Changes
Gross increases—tax positions in prior periods	$	17
Gross decreases—tax positions in prior periods		(7	)
Gross increases—current period tax positions		1
Settlements		(1	)

Total Changes^(a)	$	10
Unrecognized Tax Benefits—December 31, 2007	$	189


Jurisdiction		Tax Years
Federal		1999 and after
State		Majority closed through 2001 except for certain refund claims for tax years 1978-2001 and any adjustments related to open federal years


	Years Ended December 31,
	2007			2006
	(in millions)
Balance as of January 1,	$	2,162		$	2,058
Accretion expense		150			139
Liabilities transferred to Duke Energy^(a)		—			(29	)
Liabilities settled		(8	)		(6	)
Liabilities added due to regulatory requirements		2			—

Balance as of December 31,	$	2,306		$	2,162


	As of December 31, 2007
	Fair Value		Unrealized Loss Position >12 months		Unrealized Loss Position <12 months
	(in millions)
Equity securities	$	169	$	—	$	(21	)
Corporate Debt securities		16		—		(1	)
Municipal bonds		58		—		(1	)
Other		39		—		(1	)

Total	$	282	$	—	$	(24	)


	As of December 31, 2006
	Fair Value		Unrealized Loss Position >12 months			Unrealized Loss Position <12 months
	(in millions)
Equity securities	$	65	$	(6	)	$	(4	)
Municipal bonds		178		(1	)		(1	)
Other		32		(1	)		—

Total	$	275	$	(8	)	$	(5	)


	December 31, 2007			December 31, 2006
	(in millions)			(in millions)
Other current assets—due from affiliated companies^(a)	$	21		$	150
Other current liabilities—due to affiliated companies^(b)		(264	)		(316	)
Net deferred tax liabilities—due to Duke Energy^(c)		(2,334	)		(2,188	)


	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


Severance Reserve	Balance at January 1, 2007		Provisions^(a)		Noncash Adjustments			Cash Reductions			Balance at December 31, 2007
	(in millions)
Other	$	24	$	—	$	—		$	(19	)	$	5


	Balance at January 1, 2006		Provisions^(a)(b)		Noncash Adjustments^(c)			Cash Reductions^(d)			Balance at December 31, 2006
Natural Gas Transmission	$	3	$	—	$	(3	)	$	—		$	—
Other		28		75		(28	)		(51	)		24

Total	$	31	$	75	$	(31	)	$	(51	)	$	24


	Balance at January 1, 2005		Provisions^(a)		Noncash Adjustments			Cash Reductions			Balance at December 31, 2005
Franchised Electric and Gas	$	4	$	—	$	(2	)	$	(2	)	$	—
Natural Gas Transmission		6		1		(1	)		(3	)		3
Field Services		—		1		(1	)		—			—
International Energy		1		—		(1	)		—			—
Other		4		26		—			(2	)		28

Total	$	15	$	28	$	(5	)	$	(7	)	$	31


	Estimated Useful Life	December 31,
	Estimated Useful Life	2007			2006
	(Years)	(in millions)
Land	—	$	316		$	311
Plant—Regulated
Electric generation, distribution and transmission	20 – 125		21,215			19,874
Other buildings and improvements	30 – 90		344			336
Nuclear fuel	5		864			890
Equipment	8 – 33		193			207
Vehicles	5 – 25		22			25
Construction in process	—		1,294			677
Other	5 – 33		345			340

Total property, plant and equipment^(a)			24,593			22,660
Total accumulated depreciation^(a)(b)			(9,227	)		(8,341	)

Total net property, plant and equipment		$	15,366		$	14,319


	Weighted- Average Rate		Year Due	December 31,
	Weighted- Average Rate		Year Due	2007			2006
				(in millions)
Unsecured debt	6.0	%	2008 – 2037	$	3,131		$	3,105
Secured debt	5.7	%	2009		300			300
First and refunding mortgage bonds	4.6	%	2008 – 2027		1,214			1,214
Other debt^(a)	3.8	%	2010 – 2040		427			328
Commercial paper^(b)	5.3	%			450			300
Fair value hedge carrying value adjustment					28			31
Unamortized debt discount and premium, net					(7	)		(8	)

Total debt					5,543			5,270
Current maturities of long-term debt					(810	)		(226	)
Short-term commercial paper^(c)					(150	)		—

Total long-term debt				$	4,583		$	5,044


	Operating Leases
	(in millions)
2008	$	72
2009		41
2010		39
2011		17
2012		14
Thereafter		130

Total future minimum lease payments	$	313


	Year ended December 31, 2005
	(in millions)
Earnings Available For member’s/common stockholders, as reported	$	1,812

Add: stock-based compensation expense included in reported earnings available to common stockholders, net of related tax effects		30
Deduct: total stock-based compensation expense determined under fair value-based method for all awards, net of related tax effects		(32	)

Pro forma earnings available for member’s/common stockholders, net of related tax effects	$	1,810


	Options (in thousands)		Weighted- Average Exercise Price^(a)		Weighted- Average Remaining Life (in years)	Aggregate Intrinsic Value (in millions)
Outstanding at December 31, 2006	4,425		$	18	4.1	$	24
Exercised	(320	)		13
Transferred, forfeited or expired	(692	)		18

Outstanding at December 31, 2007	3,413			18	3.3	$	12

Exercisable at December 31, 2007	3,413		$	18	3.3	$	12


	Shares		Weighted Average Grant Date Fair Value
Number of Phantom Stock Awards:
Outstanding at December 31, 2006	415,078		$	26
Granted	257,510			20
Vested	(174,036	)		23
Forfeited/Transferred	(247,338	)		23

Outstanding at December 31, 2007	251,214		$	23

Phantom Stock Awards Expected to Vest	239,206		$	23


	Shares		Weighted Average Grant Date Fair Value
Number of Stock-based Performance Awards:
Outstanding at December 31, 2006	689,723		$	22
Granted	317,460			15
Vested	(227,082	)		21
Forfeited/Transferred	(398,800	)		20

Outstanding at December 31, 2007	381,301		$	19

Stock-based Performance Awards Expected to Vest	363,075		$	19


	Shares		Weighted Average Grant Date Fair Value
Number of Other Stock Awards:
Outstanding at December 31, 2006	291,400		$	27
Vested	(20,800	)		22
Forfeited/Transferred	(78,400	)		28

Outstanding at December 31, 2007	192,200		$	28

Other Stock Awards Expected to Vest	181,129		$	28


	For the years ended December 31,
	2007			2006		2005
	(in millions)
Income/(Expense)
Interest income^(a)	$	45		$	80	$	5
Deferred returns and AFUDC equity		32			15		9
Other		(1	)		3		1

Total	$	76		$	98	$	15