Exhibit 99.1

December 14, 2006

Dear Duke Energy Corporation Shareholder:

We are pleased to inform you that on December 8, 2006, the board of directors of Duke Energy Corporation (“Duke Energy”) approved the distribution of all the shares of common stock of Spectra Energy Corp (“Spectra Energy”), a wholly-owned subsidiary of Duke Energy, to Duke Energy shareholders. Spectra Energy holds or will hold all of the assets and liabilities associated with Duke Energy’s natural gas business, including its transmission and storage, distribution, and gathering and processing businesses.

This distribution is to be made pursuant to a plan initially approved by our board of directors on June 27, 2006 to separate Duke Energy’s natural gas business from the rest of Duke Energy’s businesses. Upon the distribution, Duke Energy shareholders will own 100% of the common stock of the company being distributed. Duke Energy’s board of directors believes that creating a separate gas company will increase value to, and is in the best interests of, our shareholders.

The distribution of Spectra Energy common stock will occur prior to the opening of the market on January 2, 2007 by way of a pro rata dividend to Duke Energy shareholders of record on the record date of the distribution. Each Duke Energy shareholder will be entitled to receive 0.5 shares of Spectra Energy common stock for each share of Duke Energy common stock held by such shareholder at the close of business on December 18, 2006, the record date of the distribution. The Spectra Energy common stock will be issued in book-entry form only, which means that no physical stock certificates will be issued. No fractional shares of Spectra Energy common stock will be issued. If you would otherwise have been entitled to a fractional share of Spectra Energy common stock in the distribution, you will receive the cash value of such fractional share instead.

Shareholder approval of the distribution is not required, and you are not required to take any action to receive your Spectra Energy common stock. The distribution is intended to be tax-free for U.S. federal income tax purposes to Duke Energy shareholders, except for cash received in lieu of any fractional share interests.

Following the distribution, you will own shares in both Duke Energy and Spectra Energy. The number of Duke Energy shares you own will not change as a result of this distribution. Duke Energy’s common stock will continue to trade on the New York Stock Exchange under the symbol “DUK”. We have applied to have Spectra Energy’s common stock listed on the New York Stock Exchange under the ticker symbol “SE”.

The information statement, which is being mailed to all holders of Duke Energy common stock on the record date for the distribution, describes the distribution in detail and contains important information about Spectra Energy, its business, financial condition and operations. We urge you to read the information statement carefully.

We want to thank you for your continued support of Duke Energy and we look forward to your future support of Spectra Energy.

Sincerely,

Paul M. Anderson	James E. Rogers
Chairman	President and Chief Executive Officer

December 14, 2006

Dear Future Spectra Energy Shareholder:

It is our pleasure to welcome you as a shareholder of our company, Spectra Energy Corp (“Spectra Energy”). We are excited about our future as one of North America’s leading midstream natural gas companies, consisting of our transmission and storage, distribution, and gathering and processing businesses.

We operate primarily in three sectors of the natural gas industry. We provide:

• transportation and storage of natural gas to customers in the Eastern and Southeastern United States, the Maritime Provinces and the Pacific Northwest in the United States and Canada, and in Ontario in Canada through approximately 17,500 miles of natural gas transmission pipelines;

• natural gas sales and distribution service to retail customers in Ontario, and natural gas gathering and processing services to customers in Western Canada; and

• natural gas gathering and processing and natural gas liquids distribution services in the United States through our 50% investment in Duke Energy Field Services, one of the largest natural gas liquids producers in North America.

Upon completion of the distribution, we will be a separate, publicly-traded company with approximately $6.5 billion in pro forma equity, and approximately $21.4 billion in pro forma assets owned, managed and administered, each as of September 30, 2006. For the year ended December 31, 2005, on a pro forma basis we generated revenues of approximately $4.1 billion, operating income of approximately $1.3 billion, and income from continuing operations of approximately $502 million. For the nine months ended September 30, 2006, we generated on a pro forma basis revenues of approximately $3.4 billion, operating income of approximately $1.0 billion and income from continuing operations of $637 million.

We have applied to have our common stock listed on the New York Stock Exchange under the symbol ”SE”.

We invite you to learn more about Spectra Energy by reviewing the enclosed information statement. We urge you to read the information statement carefully. We look forward to our future and to your support as a holder of Spectra Energy common stock.

Sincerely,

Paul M. Anderson	Fred J. Fowler
Chairman	President and Chief Executive Officer

Information Statement

Distribution of

Common Stock of

SPECTRA ENERGY CORP

by

DUKE ENERGY CORPORATION

to Duke Energy Corporation Shareholders

This information statement is being furnished in connection with the distribution by Duke Energy Corporation (“Duke Energy”) to its shareholders of all of the shares of common stock of Spectra Energy Corp (“Spectra Energy”), par value $0.001. We are a wholly-owned subsidiary of Duke Energy that holds or will hold all of the assets and liabilities associated with Duke Energy’s natural gas transmission and storage, distribution, and gathering and processing businesses. To implement the distribution, Duke Energy will distribute all of the shares of our common stock on a pro rata basis to the holders of Duke Energy common stock as of the record date. Each of you, as a holder of Duke Energy common stock, will receive 0.5 shares of Spectra Energy common stock for each share of Duke Energy common stock that you held at the close of business on December 18, 2006, the record date for the distribution. The distribution will be made prior to the opening of the market on January 2, 2007. Immediately after the distribution is completed, Spectra Energy will be a separate, publicly-traded company.

No vote of Duke Energy shareholders is required in connection with this distribution. We are not asking you for a proxy and you are requested not to send us a proxy.

No consideration is to be paid by Duke Energy shareholders in connection with this distribution. Duke Energy shareholders will not be required to pay any consideration for the shares of our common stock they receive in the distribution, and they will not be required to surrender or exchange shares of their Duke Energy common stock or take any other action in connection with the distribution.

All of the outstanding shares of our common stock are currently owned by Duke Energy. Accordingly, there currently is no public trading market for our common stock. We have filed an application to list our common stock on the New York Stock Exchange under the ticker symbol “SE”. Assuming that our common stock is approved for listing on the New York Stock Exchange, we anticipate that a limited market, commonly known as a “when-issued” trading market, for our common stock will develop on or shortly before the record date for the distribution and will continue up to and through the distribution date, and we anticipate that “regular-way” trading of our common stock will begin on the first trading day following the distribution date.

In reviewing this information statement, you should carefully consider the matters described under the caption “ Risk Factors” beginning on page 21 of this information statement.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of any of the securities of Spectra Energy, or determined whether this information statement is truthful or complete. Any representation to the contrary is a criminal offense.

This information statement does not constitute an offer to sell or the solicitation of an offer to buy any securities.

The date of this information statement is December 14, 2006.

This information statement was first mailed to Duke Energy shareholders on or about December 21, 2006.

TABLE OF CONTENTS

Summary	1
Risk Factors	21
Forward-Looking Statements	31
The Separation	33
Dividend Policy	44
Unaudited Pro Forma Financial Information of Spectra Energy	45
Selected Historical Consolidated Financial Data of Duke Capital LLC	67
Management’s Discussion and Analysis of Results of Operations and Financial Condition of Duke Capital LLC	68
Business	141
Environmental Matters	165
Employees, Properties and Facilities, Government Regulation and Legal Proceedings	167
Management	172
Security Ownership of Certain Beneficial Owners and Management	191
Certain Relationships and Related Party Transactions	193
Description of Spectra Energy Stock	200
Description of Material Indebtedness	207
Where You Can Find More Information	210
Index to Consolidated Financial Statements	F-1
Report of Independent Registered Public Accounting Firm and Financial Statements of Spectra Energy Corp	F-2
Report of Independent Registered Public Accounting Firm and Financial Statements of Duke Capital LLC	F-7
Interim Consolidated Financial Statements of Duke Capital LLC	F-100
Report of Independent Auditors of Duke Energy Field Services, LLC	F-146
Report of Independent Registered Public Accounting Firm and Financial Statements of TEPPCO Partners, L.P.	F-183

TRADEMARKS AND SERVICE MARKS

We own or have rights to use certain trademarks, trade names and logos in conjunction with our business. Some of the trademarks that we own or have rights to use that appear in this information statement include Spectra Energy Corp, PanEnergy, Algonquin Gas Transmission Company, Texas Eastern Transmission Corporation and Maritimes & Northeast. Certain other trademarks, trade names and logos of third parties may appear in this information statement. The display of such third parties’ trademarks, trade names and logos is for informational purposes only, and is not intended for marketing or promotional purposes or as an endorsement of their business or of any of their products or services.

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SUMMARY

This summary highlights selected information from this information statement relating to our company, our separation from Duke Energy and the distribution of our common stock by Duke Energy to its shareholders. For a more complete understanding of our business and the separation and distribution, you should carefully read the entire information statement.

Except as otherwise indicated or unless the context otherwise requires, the information included in this information statement assumes the completion of the separation and all the other transactions referred to in this information statement in connection with the separation and distribution. Except as otherwise indicated or unless the context otherwise requires, “Spectra Energy,” “we,” “us,” “our” and “our company” refer to Spectra Energy Corp and its subsidiaries following the separation from Duke Energy. “Duke Energy Corporation” and “Duke Energy” refer to Duke Energy Corporation and its consolidated subsidiaries, “Duke Capital” refers to Duke Capital LLC and “DEFS” refers to Duke Energy Field Services, LLC. Following the separation, Duke Capital will change its name to Spectra Energy Capital and DEFS will change its name to DCP Midstream. Unless otherwise indicated, information is presented as of December 14, 2006.

Our Company

We own and operate a large and diversified portfolio of complementary natural gas-related energy assets and are one of North America’s leading midstream natural gas companies. We operate in three segments of the natural gas industry: Transmission and Storage, Distribution, and Gathering and Processing. We intend to expand and optimize our current assets, construct new assets and make strategic acquisitions with an experienced management team dedicated to a growth strategy.

For the year ended December 31, 2005, we generated, on a pro forma basis, revenues of approximately $4.1 billion, operating income of approximately $1.3 billion and income from continuing operations of approximately $502 million. For the nine months ended September 30, 2006, we generated on a pro forma basis, revenues of approximately $3.4 billion, operating income of approximately $1.0 billion and income from continuing operations of approximately $637 million.

Transmission and Storage. Through our interests in five U.S. pipeline systems and three Canadian pipeline systems, we own and operate one of the largest long-haul natural gas pipeline networks in North America.

• Our pipeline systems consist of approximately 17,500 miles of transmission pipelines. These systems receive natural gas from major North American producing regions for delivery to markets primarily in the Mid-Atlantic, New England and Southeastern states; Ontario, Alberta; and the Pacific Northwest. In 2005, our proportional throughput (the volume of natural gas carried through a pipeline over a period of time) for our pipelines totaled 3,410 trillion British thermal units (TBtu).

• Our diversified customer base includes local distribution companies, electric power generators, industrial, commercial and other end-use customers. Our transmission services are generally provided under long-term contracts with reservation-based rates that do not vary with throughput volumes.

• We also own and/or have interests in underground natural gas storage facilities with net working gas capacity of approximately 110 billion cubic feet (Bcf) that operate in conjunction with our transmission pipelines to provide high value storage services to customers along our pipeline network.

Distribution. We provide natural gas sales and distribution service to end use customers in Ontario through our Union Gas Limited subsidiary.

• Union Gas has approximately 1.3 million residential, commercial and industrial customers in 400 communities throughout Northern, Southwestern and Eastern Ontario.

• Union Gas’ system consists of approximately 35,000 miles of distribution pipelines and underground natural gas storage facilities with working capacity of approximately 150 Bcf.

• Union Gas also provides a portion of the storage, transportation and related services discussed above to utilities and other industry participants in the natural gas markets of Ontario, Quebec and the Central and Eastern United States.

Gathering and Processing. We own and operate natural gas processing plants and gathering pipelines in Western Canada. We also have a 50% ownership interest in Duke Energy Field Services LLC, or DEFS, which is one of the largest natural gas liquids producer in North America. The remaining 50% interest in DEFS is owned by ConocoPhillips.

• We own or operate a large natural gas gathering and processing system in Western Canada, approximately 2,500 miles of gathering pipelines and 17 gas processing plants with total contractible capacity of approximately 2.7 Bcf of gas per day, including our 46% interest in Duke Energy Income Fund, a Canadian Income Trust.

• We own the Empress system, which extracts, stores, transports, distributes and markets natural gas liquids, or NGLs, in Canada and the United States. Total processing capacity of the Empress system is 2.4 Bcf of gas per day.

• DEFS owns or operates approximately 56,000 miles of gathering and transmission pipe and processes natural gas at 54 facilities in major producing regions in the United States, including DEFS’ 42.7% interest in DCP Midstream Partners, L.P.

• DCP Midstream Partners, L.P. and Duke Energy Income Fund were recently formed through the contribution of gathering and processing assets with the objective of utilizing their tax-advantaged cost of capital in order to support further growth in cash flow and earnings for us and our affiliates.

We expect to manage our business in four reportable segments: Gas Transmission—U.S., Gas Distribution, Gas Transmission and Processing—Western Canada, and Field Services. These business segments generally align with the natural gas industry segments in which we operate, although our Gas Transmission and Processing—Western Canada segment is organized on a geographical basis and therefore contains both transmission and gathering and processing operations. In addition, our Gas Distribution segment also provides transmission and storage services. The remainder of our business operations are expected to be presented as “Other,” which consists of certain realized and unrealized mark-to-market hedges that expire in 2006, unallocated corporate costs and other businesses.

Our Business Strategies

Our primary business objective is to provide value added, reliable and safe services to our customers, which we believe will create opportunities to deliver increased dividends per share and value to our shareholders. We intend to accomplish this objective by executing the following overall business strategies:

• capitalize on the size and attributes of our existing assets;

• pursue organic growth, expansion projects, strategic acquisitions and other business opportunities arising in our market and supply areas;

• continue to develop operational efficiencies among our existing assets;

• utilize tax-efficient financial structures, such as a Master Limited Partnership, or “MLP” (a publicly-traded limited partnership) and Canadian Income Trusts (a publicly traded investment trust in Canada that holds income-producing assets), to improve our cost of capital, optimize returns on the assets we hold and finance portfolio growth;

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• continue our focus on operational excellence including safety, reliability, compliance and stringent cost management; and

• retain and enhance our customer and other stakeholder relationships.

Through the continued execution of these strategies, we expect to grow and strengthen the overall business, capture new growth opportunities and deliver value to our stakeholders.

Our Strengths

We believe that we are well positioned to execute our primary business objective and business strategies successfully because of the following competitive strengths:

• our gathering and processing and gas transmission systems are among the largest in North America;

• we are strategically positioned to expand our operations through capital investment;

• we supply natural gas to the fastest growing markets in North America;

• we have a strategically-positioned pipeline asset base with diverse sources of gas supply;

• cash flows in our natural gas transmission and distribution segments are relatively stable due to the regulated nature of these businesses;

• we have financial flexibility to pursue growth opportunities;

• we have a strong focus on customer and other stakeholder relationships; and

• we have a strong and experienced management team and work force.

Summary of Risk Factors

An investment in our common stock involves risks associated with our business, regulatory and legal matters. The following list of risk factors is not exhaustive. Please read carefully the risks relating to these and other matters described under “Risk Factors” beginning on page 21.

Risks Relating to Our Business

• Reductions in demand for natural gas, or low levels in the market prices of commodities affects our operations and cash flows.

• The lack of available natural gas resources may cause our customers to contract with alternative suppliers, which could materially adversely affect our sales, earnings, and cash flow.

• The long-term financial condition of our business is dependent on the continued availability of natural gas reserves.

• Our investments and projects located in Canada expose us to fluctuations in currency rates that may adversely affect our cash flows and results of operations.

• Our natural gas gathering and processing operations are subject to commodity price market risk which could result in economic losses in our earnings and cash flows.

• Our business is subject to extensive regulation that affects our operations and costs.

• Our transmission and storage, distribution, and gathering and processing activities involve numerous risks that may result in accidents or otherwise negatively affect our operations.

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• We are involved in numerous legal proceedings, the outcome of which are uncertain, and resolution adverse to us could negatively affect our cash flows, financial condition, or results of operations.

Risks Relating to the Separation

• We may be unable to achieve some or all of the benefits that we expect to achieve from our separation from Duke Energy.

• We are being separated from Duke Energy, our parent company, and, therefore, we have no operating history as a separate, publicly-traded company.

• We may be unable to make, on a timely or cost-effective basis, the changes necessary to operate as a separate, publicly-traded company, and we may experience increased costs after the separation or as a result of the separation.

• Our agreements with Duke Energy may not reflect terms that would have resulted from arm’s-length negotiations among unaffiliated third parties.

• We will be responsible for certain contingent and other corporate liabilities related to the natural gas transmission and storage, distribution, and gathering and processing businesses of Duke Energy.

Risks Relating to Our Common Stock

• There is no existing market for our common stock and a trading market that will provide you with adequate liquidity may not develop for our common stock. In addition, once our common stock begins trading, the market price of our shares may fluctuate widely.

• Substantial sales of our common stock may occur in connection with this distribution, which could cause our stock price to decline.

• Provisions in our certificate of incorporation, by-laws and of Delaware law may prevent or delay an acquisition of our company, which could decrease the trading price of our common stock.

• Although Spectra Energy currently anticipates paying dividends, there cannot be any assurance that dividends will be paid.

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The Separation

On June 27, 2006, the board of directors of Duke Energy unanimously authorized management of Duke Energy to pursue a plan to separate its natural gas transmission and storage, distribution, and gathering and processing businesses from the rest of Duke Energy, which we refer to as “the separation” in this information statement. The separation will occur through a distribution to Duke Energy’s shareholders of all of the shares of common stock of Spectra Energy, which will hold all of the assets and liabilities of the natural gas transmission and storage, distribution, and gathering and processing businesses of Duke Energy.

We have entered into a Separation and Distribution Agreement and several other agreements with Duke Energy to effect the separation and provide a framework for our relationships with Duke Energy after the separation. These agreements will govern the relationship between us and Duke Energy subsequent to the completion of the separation and provide for the allocation between us and Duke Energy of Duke Energy’s assets, liabilities and obligations (including employee benefits and tax-related assets and liabilities) attributable to periods prior to, at and after our separation from Duke Energy. For more information on the Separation and Distribution Agreement and related agreements, see the section entitled “Certain Relationships and Related Party Transactions.”

The Duke Energy board of directors believes that the separation will increase the value of Duke Energy’s natural gas transmission and storage, distribution, and gathering and processing businesses in both the short and long terms, which the Duke Energy board of directors does not believe has been fully recognized by the investment community. Duke Energy believes that the separation of the natural gas transmission and storage, distribution, and gathering and processing businesses should not only enhance its strength, but will also improve both companies’ strategic, operational and financial flexibility. Although there can be no assurance, Duke Energy believes that, over time, the common stock of Duke Energy and Spectra Energy should have a greater aggregate market value, assuming the same market conditions, than Duke Energy has in its current configuration.

Financial Statement Basis of Presentation and the Internal Reorganization Prior to the Distribution

As a result of the internal reorganization described below, Duke Capital is treated, for accounting purposes only, as the predecessor entity to us, Spectra Energy. Accordingly, the audited consolidated financial statements included in this information statement are the financial statements of Duke Capital. Our unaudited pro forma condensed consolidated financial statements, also included in this information statement, reflect adjustments to the Duke Capital historical statements to remove the businesses that, pursuant to the reorganization discussed below, will be transferred from Duke Capital to a subsidiary of Duke Energy. We generally do not discuss these transferred businesses in this information statement.

Duke Energy operates its businesses primarily through three subsidiaries: Duke Energy Carolinas LLC, Cinergy Corp. and Duke Capital LLC. Duke Energy Carolinas LLC and Cinergy Corp. conduct, directly or indirectly, Duke Energy’s regulated electricity generation, transmission and distribution businesses, and retail gas business in the Midwest. Duke Capital holds, through its subsidiaries, the remainder of Duke Energy’s businesses, including:

• Duke Energy’s natural gas transmission and storage, distribution, and gathering and processing businesses (Natural Gas Transmission and Field Services);

• Crescent Resources (Duke Energy’s real estate business); and

• Duke Energy International (Duke Energy’s power generation and sales and marketing of power and gas outside of the United States and Canada).

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Prior to the distribution, Duke Energy will implement an internal reorganization pursuant to which all of the businesses and assets of Duke Capital other than Duke Energy’s natural gas transmission and storage, distribution, and gathering and processing businesses (i.e., Crescent Resources and Duke Energy International), will be transferred from Duke Capital to Duke Energy or its other subsidiaries.

Duke Capital will then be transferred to, and will thereafter be, a direct, wholly-owned subsidiary of Spectra Energy.

Following this internal reorganization, we will be a direct, wholly-owned subsidiary of Duke Energy. Our direct sole material asset will be Duke Capital, through which we will hold all of the assets and liabilities of Duke Energy’s natural gas transmission and storage, distribution, and gathering and processing businesses.

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Set forth below are simplified diagrams of Duke Energy prior to the separation, and of Duke Energy and Spectra Energy after the separation. Not all subsidiaries and businesses are shown and not all businesses shown are wholly-owned.

Pre-Separation

Post-Separation

In connection with the separation, Spectra Energy intends to rename certain of its subsidiaries and will discontinue use of the “Duke Energy” name. In particular, Duke Capital will be renamed Spectra Energy Capital and DEFS will be renamed DCP Midstream.

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Reasons for the Separation

Duke Energy believes that the separation of the natural gas transmission and storage, distribution, and gathering and processing businesses is the best way to unlock the full value of Duke Energy’s businesses in both the short and long terms and provides each of Duke Energy and us, with certain opportunities and benefits. The following are some of the opportunities and benefits that the Duke Energy board of directors considered in approving the separation:

• Enables investors to invest directly in our business. Separating the natural gas transmission and storage, distribution, and gathering and processing businesses from the rest of Duke Energy is expected to reduce the complexities surrounding investor and analyst understanding and will provide investors with the opportunity to invest individually in each of the separated companies.

• Provides direct access to capital. Each company will have a capital structure adequate to meet its needs. After the separation, our capital structure is expected to better facilitate acquisitions (including, possibly, acquisitions using Spectra Energy common stock as currency), joint ventures, partnerships and internal expansion, which are important for us to remain competitive in our industry.

• Creates more effective management incentives. The separation will permit the creation of equity securities, including options and restricted stock units, for each of the companies with a value that is expected to reflect more closely the efforts and performance of each company’s management.

• Allows us and Duke Energy to focus on our respective industry developments. Through the alignment of management incentives and access to the capital markets, the separation will allow Duke Energy and Spectra Energy to maintain a sharper focus on their respective core business and growth opportunities, and enable each company to respond to changes in the industry in which it operates.

Neither we nor Duke Energy can assure you that, following the separation, any of these opportunities or benefits will be realized to the extent anticipated or at all. For more detail on the reasons for the separation, see the section entitled “The Separation—Reasons for the Separation.”

The Company

We will hold all of the assets and liabilities of Duke Energy’s natural gas transmission and storage, distribution, and gathering and processing businesses as a result of an internal reorganization to be implemented by Duke Energy prior to the separation. Our headquarters are located at 5400 Westheimer Court, Houston, Texas 77056, and our general telephone number is 713-627-5400. We maintain an Internet site at http://www.spectraenergy.com. Our website and the information contained on that site, or connected to that site, are not incorporated by reference into this information statement.

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Questions and Answers about Spectra Energy and the Separation

Why am I receiving this document? Duke Energy is delivering this document to you because you were a holder of Duke Energy common stock on the record date for the distribution of our shares of common stock. Accordingly, you are entitled to receive 0.5 shares of our common stock for each share of Duke Energy common stock that you held on the record date at 5:00 p.m. Eastern Time. No action is required for you to participate in the distribution. The distribution will take place prior to the opening of the market on January 2, 2007.

How will the separation of Spectra Energy work? The separation will be accomplished through a series of transactions in which the equity interests of the entities that hold all of the assets and liabilities of Duke Energy’s transmission and storage, distribution, and gathering and processing businesses will be transferred to Spectra Energy and the common stock of Spectra Energy will be distributed by Duke Energy to its shareholders on a pro rata basis as a dividend.

Why is the separation of Spectra Energy structured as a distribution? Duke Energy believes that a tax-free distribution of shares of Spectra Energy to the Duke Energy shareholders is a tax-efficient way to separate its natural gas transmission and storage, distribution, and gathering and processing businesses from the rest of Duke Energy in a manner that will create long-term value for Duke Energy shareholders.

When will the distribution occur? Duke Energy will distribute the shares of Spectra Energy common stock prior to the opening of the market on January 2, 2007 to holders of record of Duke Energy common stock on December 18, 2006, the record date.

What do shareholders need to do to participate in the distribution? Nothing, but we urge you to read this entire information statement carefully. Shareholders who hold Duke Energy common stock as of the record date will not be required to take any action to receive Spectra Energy common stock in the distribution. No shareholder approval of the distribution is required or sought. We are not asking you for a proxy and you are requested not to send us a proxy. You will not be required to make any payment, surrender or exchange your shares of Duke Energy common stock or take any other action to receive your shares of our common stock.

If you own Duke Energy common stock as of the close of business on the record date, Duke Energy, with the assistance of The Bank of New York, the distribution agent, will electronically issue shares of our common stock to you or to your brokerage firm on your behalf by way of direct registration in book-entry form. The Bank of New York will mail you a book-entry account statement that reflects your shares of Spectra Energy common stock, or your bank or brokerage firm will credit your account for the shares.

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Following the distribution, shareholders whose shares are held in book-entry form may request that their shares of Spectra Energy common stock held in book-entry form be transferred to a brokerage or other account at any time, without charge.

What if I hold shares of Duke Energy common stock in Duke Energy’s InvestorDirect Choice Plan? If you hold shares of Duke Energy common stock in the InvestorDirect Choice Plan, Duke Energy’s share purchase and dividend reinvestment plan, the shares of Spectra Energy common stock you will receive in the distribution will be distributed to you in a direct registration position with The Bank of New York, Spectra Energy’s transfer agent. Instructions will be provided to you on how to transfer such shares to a different account. No fractional shares of Spectra Energy common stock will be distributed. Spectra Energy intends to set up a share purchase and dividend reinvestment plan immediately after the separation and information will be provided to you on how to enroll in Spectra Energy’s plan.

What if I hold shares of Duke Energy common stock in the Duke Energy Retirement Savings Plan or one of the Cinergy 401(k) plans? Duke Energy and its affiliates sponsor several 401(k) plans, including the Duke Energy Retirement Savings Plan, the Cinergy Corp. Non-Union Employees’ 401(k) Plan, the Cinergy Corp. Union Employees’ 401(k) Plan and the Cinergy Corp. Union Employees’ Savings Incentive Plan (each a “401(k) plan”). In connection with the distribution, the 401(k) plan accounts of Spectra Energy employees and former employees of the Spectra Energy business will be transferred to a 401(k) plan established by Spectra Energy, which plan generally will be comparable to the Duke Energy Retirement Savings Plan.

If shares of Duke Energy common stock are allocated to your account in a 401(k) plan, shares of Spectra Energy common stock will be distributed and allocated to your 401(k) plan account in respect of the previously allocated shares of Duke Energy common stock. Accordingly, following the separation, our 401(k) plan and the 401(k) plans of Duke Energy initially will continue to hold shares of both Duke Energy and Spectra Energy.

Can Duke Energy decide to cancel the distribution of the common stock even if all the conditions have been met? Yes. The distribution is subject to the satisfaction or waiver of certain conditions. See the section entitled “The Separation—Conditions to the Distribution.” Until the distribution date, Duke Energy has the right to terminate the distribution, even if all of the conditions are satisfied, if at any time the board of directors of Duke Energy determines that the distribution is not in the best interests of Duke Energy and its shareholders or that market conditions are such that it is not advisable to separate the natural gas transmission and storage, distribution, and gathering and processing businesses from Duke Energy and its other businesses.

Does Spectra Energy plan to pay dividends? Currently, we anticipate a dividend payout ratio of approximately 60% of our anticipated annual net income per share of common stock. Based on this dividend payout ratio, we anticipate paying an annual dividend of $0.88 per share, on a quarterly basis, beginning with the

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first quarter of 2007. The declaration and payment of dividends by us will be subject to the sole discretion of our board of directors and will depend upon many factors, including our financial condition, earnings, capital requirements of our operating subsidiaries, covenants associated with certain of our debt obligations, legal requirements, regulatory constraints and other factors deemed relevant by our board of directors.

Will Spectra Energy incur any debt in the separation? No, but subsidiaries of Spectra Energy, including Duke Capital, will continue to be subject to certain debt obligations, credit agreements and other financing arrangements to which they are a party to prior to the separation. On a pro forma basis, Spectra Energy and its subsidiaries have long-term debt in the aggregate principal amount of approximately $8.9 billion as of September 30, 2006. Approximately $5.9 billion of this debt relates to both secured and unsecured debt, capital leases and other debt incurred by our operating subsidiaries prior to the separation. Approximately $3.0 billion of this debt is comprised of amounts outstanding under the senior indenture of Duke Capital. In addition, approximately $1.1 billion of debt historically reflected on the consolidated balance sheet of Duke Capital is the debt of businesses to be transferred to Duke Energy in the internal reorganization prior to the distribution, and thus will not be reflected in our going-forward financial statements. Furthermore, we will have access to four revolving credit facilities available in two currencies upon our separation from Duke Energy, with total combined capacities of $950 million and CAN $600 million. These facilities will be used principally as a back-stop for commercial paper programs at Spectra Energy subsidiaries. Approximately $350 million is expected to be utilized at the time of separation as a result of the maturity of senior unsecured notes in November 2006.

For additional information relating to our planned financing arrangements, see the sections entitled “Unaudited Pro Forma Financial Information,” “Management’s Discussion and Analysis of Pro Forma Results of Operations and Financial Condition,” “Management’s Discussion and Analysis of Results of Operations and Financial Condition—Liquidity and Capital Resources—Description of Indebtedness,” and “Description of Material Indebtedness.”

What will the separation cost? Duke Energy expects to incur pre-tax separation costs of approximately $200 million of which approximately $130 will be allocated to Spectra Energy. Over the 12 months following our separation, the portion of these pre-tax costs incurred by Spectra Energy in total is approximately $60 to $70 million. A majority of the separation costs are expected to be cash.

What are the U.S. federal income tax consequences of the distribution to Duke Energy shareholders? The distribution is conditioned upon Duke Energy’s receipt of a private letter ruling from the Internal Revenue Service and the opinion of Skadden, Arps, Slate, Meagher & Flom LLP, in each case to the effect that the distribution, together with certain related

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transactions, will qualify as a tax-free distribution for U.S. federal income tax purposes under Sections 355 and 368(a)(1)(D) of the Internal Revenue Code of 1986, as amended (the “Code”). Duke Energy has received a private letter ruling from the Internal Revenue Service that the distribution will so qualify. Assuming the distribution so qualifies, for U.S. federal income tax purposes, no gain or loss will be recognized by you, and no amount will be included in your income, upon the receipt of shares of our common stock pursuant to the distribution. You will generally recognize gain or loss with respect to cash received in lieu of a fractional share of our common stock. For more information regarding the private letter ruling, the tax opinion and the potential consequences to you of the distribution, see the section entitled “The Separation—Certain U.S. Federal Income Tax Consequences of the Distribution.”

What will Spectra Energy’s relationship be with Duke Energy following the separation? Before the separation of Spectra Energy from Duke Energy, we will enter into a Separation and Distribution Agreement and several other agreements with Duke Energy to effect the separation and provide a framework for our relationship with Duke Energy after the separation. These agreements will govern the relationship between us and Duke Energy subsequent to the completion of the separation, and provide for the allocation between us and Duke Energy of Duke Energy’s

assets, liabilities and obligations (including employee benefits and tax-related assets and liabilities) attributable to periods prior to, at and after our separation from Duke Energy. The Separation and Distribution Agreement, in particular, requires us to assume certain contingent and other corporate liabilities related to the natural gas business and establishes the amount of debt that each company will initially have. We cannot assure you that these agreements will be on terms as favorable to us as agreements with unaffiliated third parties might be. For additional information regarding the separation agreements, see the sections entitled “Risk Factors” and “Certain Relationships and Related Party Transactions.”

Will I receive physical certificates representing shares of Spectra Energy common stock following the separation? No. Following the separation, neither Duke Energy nor Spectra Energy will be issuing physical certificates representing shares of Spectra Energy common stock. Instead, Duke Energy, with the assistance of The Bank of New York, the distribution agent, will electronically issue shares of our common stock to you or to your bank or brokerage firm on your behalf by way of direct registration in book-entry form. The Bank of New York will mail you a book-entry account statement that reflects your shares of Spectra Energy common stock, or your bank or brokerage firm will credit your account for the shares. A benefit of issuing stock electronically in book-entry form is that there will be none of the physical handling and safekeeping responsibilities that are inherent in owning physical stock certificates. After you receive your book-entry account statement, you may request that we issue you a physical stock certificate by following the directions on your account statement.

What if I want to sell my Duke Energy common stock or my Spectra Energy common stock? You should consult with your financial advisors, such as your stockbroker, bank or tax advisor.

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What is “regular-way” and “ex-distribution” trading? Beginning on or shortly before the record date and continuing up to and through the last trading day prior to the distribution date, we expect that there will be two markets in Duke Energy common stock: a “regular-way” market and an “ex-distribution” market. Shares of Duke Energy common stock that trade in the “regular-way” market will trade with an entitlement to shares of our common stock distributed pursuant to the distribution. Shares that trade in the “ex-distribution” market will trade without an entitlement to shares of our common stock distributed pursuant to the distribution. On the distribution date, all shares of Duke Energy will trade “ex-distribution.”

If you decide to sell any shares of Duke Energy before the distribution, you should make sure your stockbroker, bank or other nominee understands whether you want to sell your Duke Energy common stock or your entitlement to Spectra Energy common stock pursuant to the distribution or both.

Where will I be able to trade shares of Spectra Energy common stock? There is not currently a public market for our common stock. We have applied to list our common stock on the New York Stock Exchange, or NYSE, under the symbol “SE”. We anticipate that trading in shares of our common stock will begin on a “when-issued” basis on or shortly before the record date and will continue up to and through the distribution date and that “regular-way” trading in shares of our common stock will begin on the first trading day following the distribution date. If trading begins on a “when-issued” basis, you may purchase or sell our common stock up to and through the distribution date, but your transaction will not settle until after the distribution date. We cannot predict the trading prices for our common stock before, on or after the distribution date.

What will happen to the listing of Duke Energy common stock? Nothing. Duke Energy common stock will continue to be traded on the NYSE under the symbol “DUK” following the distribution of Spectra Energy.

Will the number of Duke Energy shares I own change as a result of the distribution? No. The number of shares of Duke Energy common stock you own will not change as a result of the distribution.                                                          

Will the distribution affect the market price of my Duke Energy shares? Yes. As a result of the distribution, we expect the trading price of shares of Duke Energy common stock immediately following the distribution to be lower than the trading price immediately prior to the distribution because the trading price will no longer reflect the value of the natural gas transmission and storage, distribution, and gathering and processing businesses. Furthermore, until the market has fully analyzed the value of Duke Energy without the natural gas transmission and storage, distribution, and gathering and processing businesses, the market price of a share of Duke Energy common stock may fluctuate significantly. In addition, although Duke Energy believes that over time following the separation, the common stock of

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Duke Energy and Spectra Energy should have a higher aggregate market value, assuming the same market conditions than if Duke Energy were to remain under its current configuration, there can be no assurance, and thus the combined trading prices of two shares of Duke Energy common stock and a share of Spectra Energy common stock after the distribution may be equal to, greater than, or less than the trading price of a share of Duke Energy common stock before the distribution.

How will I determine my tax basis in the Spectra Energy shares I receive in the distribution? Shortly after the distribution is completed, Duke Energy will provide U.S. taxpayers with information to enable them to compute their tax basis in both Duke Energy and Spectra Energy shares and other information they will need to report their receipt of Spectra Energy common stock on their 2007 federal income tax returns as a tax-free transaction. Generally, your aggregate basis in the stock you hold in Duke Energy and Spectra Energy shares received in the distribution will equal the aggregate basis of Duke Energy common stock held by you immediately before the distribution, allocated between your Duke Energy common stock and the Spectra Energy common stock you receive in the distribution in proportion to the relative fair market value of each on the date of the distribution.

You should consult your tax advisor about the particular consequences of the distribution to you, including the application of state, local and foreign tax laws.

Are there risks to owning Spectra Energy common stock? Yes. Our business is subject to both general and specific risks relating to our business, our capital structure, the industry in which we operate, our relationship with Duke Energy and our status as a separate, publicly-traded company. Our business is also subject to risks relating to the separation. These risks are described in the “Risk Factors” section of this information statement beginning on page 21. We encourage you to read that section carefully.

Where can Duke Energy shareholders obtain more information? Before the distribution, if you have any questions relating to the separation, you should contact:

Duke Energy Corporation

Investor Relations

526 S. Church St.

Charlotte, NC 28202-1803

Phone

(704) 382-DUKE

(704) 382-3853

Toll-Free

(800) 488-DUKE

(800) 488-3853

Fax

(704) 382-3814

www.duke-energy.com

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After the distribution, if you have any questions relating to our common stock, you should contact:

Spectra Energy Corp

Investor Relations

5400 Westheimer Court

Houston, Texas 77056

Phone (713) 627-5400

Fax (713) 627-4607

www.spectraenergy.com

or:

The Bank of New York

Stock Transfer Department

101 Barclay St. - 11 East

New York, NY 10286

Phone (866) 406-6840

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Terms of the Separation

The following is a summary of the material terms of the distribution and other related transactions.

Distributing company Duke Energy Corporation. After the distribution, Duke Energy will not own any shares of our common stock.

Distributed company Spectra Energy Corp, a Delaware corporation and a wholly-owned subsidiary of Duke Energy (referred to in this information statement as “Spectra Energy”) that holds, or will hold all of the assets and liabilities of Duke Energy’s natural gas transmission and storage, distribution, and gathering and processing businesses. Spectra Energy will not include Duke Energy’s regulated retail gas business operating in Ohio and Kentucky. After the distribution, Spectra Energy will be a separate, publicly-traded company.

As a result of the internal reorganization, we are treated, for accounting purposes only, as the successor entity to Duke Capital. Accordingly, our pro forma financial statements reflect the removal of the businesses that, pursuant to the reorganization, will be transferred from Duke Capital to Duke Energy or its other subsidiaries. We generally do not discuss these transferred businesses in this information statement.

Distribution ratio Each holder of Duke Energy common stock will receive 0.5 shares of our common stock for each share of Duke Energy common stock held on the record date, December 18, 2006. Cash will be distributed in lieu of fractional shares, as described below.

Distributed securities All of the shares of Spectra Energy common stock owned by Duke Energy, which will be 100% of our common stock outstanding immediately prior to the distribution, will be distributed to Duke Energy’s shareholders (on an as if converted basis). Based on approximately 1.26 billion shares of Duke Energy common stock outstanding on November 30, 2006, and the distribution ratio of 0.5 shares of Spectra Energy common stock for each share of Duke Energy common stock, approximately 630 million shares of our common stock will be distributed to Duke Energy shareholders. The number of shares that Duke Energy will distribute to its shareholders will be reduced to the extent that cash payments are to be made in lieu of the issuance of fractional shares of our common stock. In connection with the distribution, pursuant to the terms of the indenture governing Duke Energy’s 1 ³/4% Convertible Senior Notes due 2023, holders of record of such notes will participate in the distribution. As of December 1, 2006, there was approximately $110 million principal amount outstanding of such notes. Accordingly, pursuant to the terms of the indenture, approximately 2.4 million shares of Spectra Energy common stock are expected to be distributed in respect of such outstanding principal amount of such notes.

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Fractional shares Duke Energy will not distribute any fractional shares of our common stock to its shareholders. Instead, the distribution agent will aggregate fractional shares into whole shares, sell the whole shares in the open market at prevailing market prices and distribute the aggregate net cash proceeds of the sales pro rata to each holder who otherwise would have been entitled to receive a fractional share in the distribution. Recipients of cash in lieu of fractional shares will not be entitled to any interest on the amounts of payment made in lieu of fractional shares. The receipt of cash in lieu of fractional shares generally will be taxable to the recipient shareholders as described in the section entitled “The Distribution—Certain U.S. Federal Income Tax Consequences of the Distribution.”

Record date The record date for the distribution is the close of business on December 18, 2006.

Distribution date The distribution date will take place prior to the opening of the market on January 2, 2007.

Distribution On the distribution date, Duke Energy, with the assistance of The Bank of New York, the distribution agent, will electronically issue shares of our common stock to you or to your bank or brokerage firm on your behalf by way of direct registration in book-entry form. You will not be required to make any payment, surrender or exchange your shares of Duke Energy common stock or take any other action to receive your shares of our common stock.

If you sell shares of Duke Energy common stock in the “regular-way” market through the distribution date, you will be selling your right to receive shares of Spectra Energy common stock in the distribution. Registered shareholders will receive additional information from the distribution agent shortly after the distribution date. Following the distribution, shareholders may request that their shares of Spectra Energy common stock held in book-entry form be transferred to a brokerage or other account at any time, without charge. Beneficial shareholders that hold shares through a brokerage firm will receive additional information from their brokerage firms shortly after the distribution date.

Conditions to the distribution The distribution of our common stock is subject to the satisfaction or, if permissible under the Separation and Distribution Agreement, waiver by Duke Energy of the following conditions, among other conditions described in this information statement:

• the Securities and Exchange Commission, or SEC, shall have declared effective our registration statement on Form 10, of which this information statement is a part, under the Securities Exchange Act of 1934, as amended, or the Exchange Act, and no stop order relating to the registration statement is in effect;

• all permits, registrations and consents required under the securities or blue sky laws of states or other political subdivisions

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of the United States or of other foreign jurisdictions in connection with the distribution shall have been received;

• Duke Energy shall have received a private letter ruling from the Internal Revenue Service substantially to the effect that the distribution, together with certain related transactions, will qualify as a reorganization for U.S. federal income tax purposes under Sections 355 and 368(a)(1)(D) of the Code;

• Duke Energy shall have received an opinion of Skadden, Arps, Slate, Meagher & Flom LLP substantially to the effect that the distribution, together with certain related transactions, will qualify as a reorganization for U.S. federal income tax purposes under Sections 355 and 368(a)(1)(D) of the Code;

• the listing of our common stock on the NYSE shall have been approved, subject to official notice of issuance;

• any material government approvals and other consents necessary to consummate the distribution shall have been received; and

• no order, injunction or decree issued by any court of competent jurisdiction or other legal restraint or prohibition preventing consummation of the distribution or any of the transactions related thereto, including the transfers of assets and liabilities contemplated by the Separation and Distribution Agreement, shall be in effect.

The fulfillment of these conditions does not create any obligation on Duke Energy’s part to effect the distribution, and the Duke Energy board of directors has reserved the right, in its sole discretion, to waive any or all of the above conditions, and to amend, modify or abandon the distribution and related transactions at any time prior to the distribution date. Duke Energy has the right not to complete the distribution if, at any time, the Duke Energy board of directors determines, in its sole discretion, that the distribution is not in the best interests of Duke Energy or its shareholders or that market conditions are such that it is not advisable to separate the natural gas transmission and storage, distribution, and gathering and processing businesses from Duke Energy.

Stock exchange listing We have filed an application to list our shares of common stock on the NYSE under the symbol “SE”. We anticipate that on or prior to the record date for the distribution, trading of shares of our common stock will begin on a “when-issued” basis and will continue up to and through the distribution date. For additional information, see the section entitled “The Separation—Trading Between the Record Date and Distribution Date.”

Distribution and transfer agent The Bank of New York

Stock Transfer Department

101 Barclay St. - 11 East

New York, NY 10286

Phone (866) 406-6840

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Spectra Energy debt Subsidiaries of Spectra Energy, including Duke Capital, will continue to be subject to certain debt obligations, credit agreements and other financing arrangement to which they are a party to prior to the separation. On a pro forma basis, Spectra Energy and its subsidiaries have long-term debt in the aggregate principal amount of approximately $8.9 billion as of September 30, 2006. Approximately $5.9 billion of this debt relates to both secured and unsecured debt, capital leases and other debt incurred by our operating subsidiaries prior to the separation. Approximately $3.0 billion of this debt is comprised of amounts outstanding under the senior indenture of Duke Capital, our subsidiary, subsequent to the reorganization. In addition, approximately $1.1 billion of debt historically reflected on the consolidated balance sheet of Duke Capital is the debt of businesses to be transferred to Duke Energy in the internal reorganization prior to the distribution, and thus will not be reflected in our going-forward financial statements. Furthermore, we will have access to four revolving credit facilities available in two currencies upon our separation from Duke Energy, with total combined capacities of $950 million and CAN $600 million. These facilities will be used principally as a back-stop for commercial paper programs at Spectra Energy subsidiaries. Approximately $350 million is expected to be utilized at the time of separation as a result of the maturity of senior unsecured notes in November 2006.

Risks relating to ownership of our common stock and the distribution Our business is subject to both general and specific risks relating to our business, our capital structure, the industry in which we operate our relationship with Duke Energy and our being a separate, publicly-traded company. Our business is also subject to risks relating to the separation. You should read carefully the sections entitled “Risk Factors,” beginning on page 21 in this information statement.

Tax considerations Assuming the distribution, together with certain related transactions, qualifies as a reorganization for U.S. federal income tax purposes under Sections 355 and 368(a)(1)(D) of the Code, no gain or loss will be recognized by a shareholder, and no amount will be included in the income of a shareholder, upon the receipt of shares of our common stock pursuant to the distribution. However, a shareholder will generally recognize gain or loss with respect to any cash received in lieu of a fractional share of our common stock as described in the section entitled “The Separation—Certain U.S. Federal Income Tax Consequences of the Distribution.”

Certain agreements with Duke Energy We have entered into a Separation and Distribution Agreement and several other agreements with Duke Energy to effect the separation and distribution and provide a framework for our relationship with Duke Energy after the separation. These agreements will govern the relationship between us and Duke Energy subsequent to the completion of the separation and provide for the allocation between us and Duke Energy of assets, liabilities and obligations (including employee benefits and

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tax-related assets and liabilities) attributable to periods prior to, at, and after our separation from Duke Energy. The Separation and Distribution Agreement, in particular, requires us to assume certain of the contingent and other corporate liabilities of the natural gas transmission and storage, distribution, and gathering and processing businesses of Duke Energy. For a discussion of these arrangements, see the sections entitled “Risk Factors” and “Certain Relationships and Related Party Transactions.”

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RISK FACTORS

You should carefully consider each of the following risk factors and all of the other information set forth in this information statement. The risk factors generally have been separated into three groups: (i) risks relating to our business, (ii) risks relating to the separation and (iii) risks relating to ownership of our common stock. Based on the information currently known to us, we believe that the following information identifies the most significant risk factors affecting our company in each of these categories of risks. However, the risks and uncertainties our company faces are not limited to those set forth in the risk factors described below. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also adversely affect our business, financial condition or results of operations. In addition, past financial performance may not be a reliable indicator of future performance and historical trends should not be used to anticipate results or trends in future periods.

If any of the following risks and uncertainties develops into actual events, these events could have a material adverse effect on our business, financial condition or results of operations. In such case, the trading price of our common stock could decline.

Risks Relating to Our Business

Reductions in demand for natural gas, or low levels in the market prices of commodities affects our operations and cash flows.

Declines in demand for natural gas as a result of economic downturns in our franchised gas service territory may reduce overall gas deliveries and reduce our cash flows, especially if our industrial customers reduce production and, therefore, consumption of gas. Our gas gathering and processing businesses may experience a decline in the volume of natural gas gathered and processed at their plants, resulting in lower revenues and cash flows, as lower economic output reduces energy demand.

Lower demand for natural gas and lower prices for natural gas and natural gas liquids result from multiple factors that affect the markets where we transport, store, distribute, gather, and process natural gas including:

• weather conditions, including abnormally mild winter or summer weather that cause lower energy usage for heating or cooling purposes, respectively;

• supply of and demand for energy commodities, including any decreases in the production of natural gas which could negatively affect our processing business due to lower throughput;

• capacity and transmission service into, or out of, our markets; and

• petrochemical demand for natural gas liquids.

The lack of availability of natural gas resources may cause our customers to contract with alternative suppliers, which could materially adversely affect our sales, earnings, and cash flows.

Our natural gas businesses are dependent on the continued availability of natural gas production and reserves. Low prices for natural gas, regulatory limitations, or a shift in supply sources due to importing of foreign liquefied natural gas could adversely affect development of additional reserves and production that is accessible by our pipeline, gathering, processing and distribution assets. Lack of commercial quantities of natural gas available to our assets will cause our customers to contract with alternative suppliers, thereby reducing their reliance on our services, which in turn would materially adversely affect our sales, earnings and cash flows.

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Our investments and projects located in Canada expose us to fluctuations in currency rates that may adversely affect our cash flows and results of operations.

We are exposed to foreign currency risk from investments and operations in Canada. As of December 31, 2005, a 10% devaluation in the currency exchange rate of the Canadian Dollar would result in an estimated net income loss on the translation of Canadian currency earnings of approximately $24 million to our pro forma consolidated statement of operations. The pro forma consolidated balance sheet would be negatively affected by approximately $491 million currency translation through the cumulative translation adjustment in accumulated other comprehensive income.

Our natural gas gathering and processing operations are subject to commodity price risk which could result in economic losses in our earnings and cash flows.

We have gathering and processing operations that consist of contracts to buy and sell commodities, including contracts for natural gas, natural gas liquids and other commodities that are settled by the delivery of the commodity or cash. Spectra Energy’s major commodity market risk is natural gas liquids prices, due primarily to its investment in DEFS. Natural gas liquids prices historically track oil prices. At historical natural gas liquid-to-oil prices, a $1 per barrel move in oil prices would affect our pre-tax earnings from DEFS by approximately $15 million.

With respect to our Empress system, a $1 change in the difference between the weighted-average natural gas liquids price and the british thermal unit-equivalent price of natural gas (which represents theoretical gross margin for processing liquids from the gas and is commonly called the Frac-spread) would affect our pre-tax earnings by approximately $25 million.

If prices of commodities significantly deviate from historical prices, if the price volatility or distribution of those changes deviates from historical norms, or if the correlation between natural gas liquids and oil prices deviates from historical norms, our approach to price risk management may not protect us from significant losses. In addition, adverse changes in energy prices may result in economic losses in our earnings and cash flows and our balance sheet.

Our business is subject to extensive regulation that affects our operations and costs.

Our U.S. assets and operations are subject to regulation by federal, state and local authorities, including regulation by the Federal Energy Regulatory Commission and by various authorities under federal, state and local environmental laws. The majority of our Canadian natural gas assets are subject to federal and provincial regulation including the National Energy Board and the Ontario Energy Board and likewise by federal and provincial environmental laws. Regulation affects almost every aspect of our business, including, among other things, our ability to determine terms and rates for services provided by some of our businesses; make acquisitions, issue equity or debt securities; and pay dividends.

In addition, regulators have taken actions to strengthen market forces in the gas pipeline industry, which have led to increased competition. In a number of key markets, interstate pipelines are facing competitive pressure from a number of new industry participants, such as alternative suppliers as well as traditional pipeline competitors. Increased competition driven by regulatory changes could have a material impact on our business, financial condition and operating results.

Our transmission and storage, distribution, and gathering and processing activities involve numerous risks that may result in accidents or otherwise affect our operations.

There are a variety of hazards and operating risks inherent in our natural gas transmission and storage, distribution, and gathering and processing activities, such as leaks, explosions and mechanical problems that could cause substantial financial losses. In addition, these risks could result in loss of human life, significant

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damage to property, environmental pollution, and impairment of our operations, any of which could result in substantial losses to us. For pipeline and storage assets located near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas, the level of damage resulting from these risks could be greater. We do not maintain insurance coverage against all of these risks and losses, and any insurance coverage we might maintain may not fully cover the damages caused by those risks and losses for which we do maintain insurance. Therefore, should any of these risks materialize, it could have a material adverse effect on our business, financial condition and results of operations.

We are subject to numerous environmental laws and regulations, compliance with which requires significant capital expenditures, can increase our cost of operations, and may affect or limit our business plans, or expose us to environmental liabilities.

We are subject to numerous environmental laws and regulations affecting many aspects of our present and future operations, including air 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 us 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. We may not be able to obtain or maintain from time to time all required environmental regulatory approvals for our operating assets or development projects. If there is a delay in obtaining any required environmental regulatory approvals, if we fail to obtain and comply with them or if environmental laws or regulations change and become more stringent, the operation of our facilities or the development of new facilities could be prevented, delayed or become subject to additional costs. No assurance can be made that the costs we will incur to comply with environmental regulations in the future will not have a material effect.

Our Canadian businesses may be subject to the Kyoto Protocol. If Canada does implement a program to reduce greenhouse gas emissions, we may be obligated to reduce emissions and/or purchase emission credits. Due to the substantial uncertainty regarding what plan, if any, Canada will implement and whether this plan will apply to our facilities, we cannot estimate the potential effect of greenhouse gas regulation in Canada on our business, financial condition, or results of operations.

We are involved in numerous legal proceedings, the outcome of which are uncertain, and resolution adverse to us could negatively affect our cash flows, financial condition or results of operations.

We are subject to numerous legal proceedings. Litigation is subject to many uncertainties, and we cannot predict the outcome of individual matters with assurance. It is reasonably possible that the final resolution of some of the matters in which we are involved could require us 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 our cash flows and results of operations.

We rely on our access to short-term money markets and longer-term capital markets to finance our capital requirements and support our liquidity needs, and our access to those markets can be adversely affected, which could adversely affect our cash flow or restrict our businesses.

Our business is financed to a large degree through debt. The maturity and repayment profile of debt used to finance investments often does not correlate to cash flows from our assets. Accordingly, we rely 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 our operations and to fund investments originally financed through debt instruments with disparate maturities. If we are not able to access capital at competitive rates, our ability to finance our operations and implement our strategy may be adversely affected. Restrictions on our ability to

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access financial markets may also affect our ability to execute our business plan as scheduled. An inability to access capital may limit our ability to pursue improvements or acquisitions that we may otherwise rely on for future growth.

We maintain revolving credit facilities to provide back-up for commercial paper programs and/or letters of credit at various entities. These facilities typically include financial covenants which limit the amount of debt that can be outstanding as a percentage of the total capital for the specific entity. Failure to maintain these covenants at a particular entity could preclude that entity from issuing commercial paper or letters of credit or borrowing under the revolving credit facility and could require other of our affiliates to immediately pay down any outstanding drawn amounts under other revolving credit agreements which could adversely affect our cash flow or restrict our businesses.

We may be unable to secure long-term transportation agreements, which could expose our transportation volumes and revenues to increased volatility.

In the future, we may be unable to secure long-term transportation agreements for our gas transmission business as a result of economic factors, lack of commercial gas supply to our systems, increased competition, or changes in regulation. Without long-term transportation agreements, our revenues and contract volumes will be exposed to increased volatility and we cannot assure you that our pipelines will be utilized at similar levels or operate profitably. The inability to secure these agreements would materially adversely affect our business, financial condition or results of operations.

Native land claims have been asserted in British Columbia and Alberta which could affect our future access to public lands, the success of which claims could have a significant adverse affect on our natural gas production and processing.

Certain aboriginal groups have claimed aboriginal and treaty rights over a substantial portion of the lands on which our facilities in British Columbia and Alberta, and the gas supply areas served by those facilities, are located. The existence of these claims, which range from the assertion of rights of limited use to aboriginal title, has given rise to some uncertainty regarding access to public lands for future development purposes. Such claims, if successful, could have a significant adverse effect on natural gas production in British Columbia and Alberta which could have a material adverse effect on the volume of natural gas processed at our facilities and of natural gas liquids and other products transported in the associated pipelines. We cannot predict the outcome of these claims or the impact they may ultimately have on our business and operations.

We must meet credit quality standards. If we or our rated subsidiaries are unable to obtain or maintain an investment grade credit rating, our liquidity may be adversely affected and our cost of borrowing may increase. We cannot be sure that we or our rated subsidiaries will obtain or maintain investment grade credit ratings.

Certain of our subsidiaries’ senior unsecured long-term debt is currently rated investment grade by various rating agencies. We do not currently have a credit rating but expect to receive investment grade credit ratings from various rating agencies prior to or concurrent with the separation from Duke Energy. We cannot be sure that our credit rating or our rated subsidiaries’ senior unsecured long-term debt will be rated investment grade following the separation from Duke Energy. If the rating agencies were to rate us or our rated subsidiaries below investment grade, such entity’s borrowing costs would increase, perhaps significantly. In addition, the entity would likely be required to pay a higher interest rate in future financings, and its potential pool of investors and funding sources would likely decrease. Furthermore, if our short-term debt rating were to be below tier 2 (e.g. A-2/P-2, S&P and Moody’s respectively), access to the commercial paper market could be significantly limited. There are requirements for Duke Capital to post collateral or a letter of credit if Duke Capital’s S&P credit rating falls below BBB—. Any downgrade or other event negatively affecting the credit ratings of our subsidiaries could make their costs of borrowing higher or access to funding sources more limited, which in turn could increase our need to provide liquidity in the form of capital contributions or loans to such subsidiaries, thus reducing the liquidity and borrowing availability of the consolidated group.

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Poor investment performance of pension plan holdings and other factors affecting pension plan costs could unfavorably affect our liquidity and results of operations.

Our U.S. pension plan will assume certain assets and liabilities from the Duke Energy U.S. pension plan. As of September 30, 2005, the Duke Energy U.S. pension plan had assets that exceeded the value of its projected benefit obligations by approximately $95 million. As of September 30, 2005, Duke Energy’s Canadian pension plan, which we will assume, had projected benefit obligations which exceeded the value of its assets by approximately $141 million. Both plans comply with the minimum funding requirements currently applicable to them but without sustained growth in the pension investments over time to increase the value of our plan assets and depending upon the other factors affecting our costs, we could be required to fund our plans with significant amounts of cash. Such cash funding obligations could have a material affect on our liquidity by reducing our cash flows and could negatively affect our business, financial condition and results of operations.

Protecting against potential terrorist activities requires significant capital expenditures and a successful terrorist attack could adversely affect our business.

Future acts of terrorism and any possible reprisals as a consequence of any action by the United States and its allies could be directed against companies operating in the United States. This risk is particularly great for companies, like us, operating in any energy infrastructure industry that handles volatile gaseous and liquid hydrocarbons. The potential for terrorism has subjected our operations to increased risks and could have a material adverse effect on our business. In particular, we may experience increased capital and operating costs to implement increased security for our facilities and pipelines, such as additional physical facility and pipeline security and additional security personnel. Moreover, any physical damage to our high profile facilities resulting from acts of terrorism may not be covered, or covered fully, by insurance. We may be required to expend material amounts of capital to repair any facilities, the expenditure of which could adversely affect our cash flow and business.

Due to proposed or potential changes in Canadian tax laws, we may not be able to realize our goal of utilizing tax-efficient structures to improve our cost of capital, optimize returns on assets, and finance portfolio growth.

Our business strategy includes utilizing tax-efficient structures, such as MLPs and Canadian Income Trusts. On October 31, 2006, the Minister of Finance of Canada announced proposed changes to the income tax treatment of “flow-through entities,” including income trusts. If the proposal is implemented in its current form, income trusts will be subject to tax at corporate rates on the taxable portion of their distributions. Further, unitholders will be treated as if they have received a dividend equal to the taxable portion of their distributions, and will be taxed accordingly. These proposed changes will generally apply beginning in the 2007 taxation year for trusts that begin to be publicly-traded after October 2006, but would only apply beginning with the 2011 taxation year to those income trusts, such as our Duke Energy Income Fund, that were already publicly traded at the time of the announcement. While the proposed Canadian changes have not yet been implemented, such changes could have an adverse effect on our ability to implement our business strategy which may result in an increase in our cost of capital, non-optimal returns on the assets we might hold, and an inability to finance portfolio growth through the use of this vehicle.

Risks Relating to the Separation

We may be unable to achieve some or all of the benefits that we expect to achieve from our separation from Duke Energy.

We may not be able to achieve the full strategic and financial benefits that we expect will result from our separation from Duke Energy or such benefits may be delayed or may not occur at all. For example, there can be no assurance that analysts and investors will regard our corporate structure as clearer and simpler than the current Duke Energy corporate structure or place a greater value on our company as a stand-alone company than on our

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businesses being a part of Duke Energy. As a result, in the future the aggregate market price of Duke Energy’s common stock and our common stock as separate companies may be less than the market price per share of Duke Energy’s common stock had the separation and distribution not occurred.

We have no operating history as a separate publicly-traded company.

The historical and pro forma financial information included in this information statement does not necessarily reflect the financial condition, results of operations or cash flows that we would have achieved as a separate publicly-traded company during the periods presented or those that we will achieve in the future primarily as a result of the following factors:

• Prior to our separation, our business was operated by Duke Energy as part of its broader corporate organization, rather than as a separate, publicly-traded company. Duke Energy or one of its affiliates performed various corporate functions for us, including, but not limited to, accounts payable, cash management, treasury, tax administration, certain governance functions (including compliance with the Sarbanes-Oxley Act of 2002 and internal audit) and external reporting. Our historical and pro forma financial results reflect allocations of corporate expenses from Duke Energy for these and similar functions. These allocations may be more or less than the comparable expenses we believe we would have incurred had we operated as a separate publicly-traded company.

• Currently, our business is integrated with the other businesses of Duke Energy. Historically, we have shared economies of scope and scale in costs, employees, vendor relationships and certain customer relationships with Duke Energy. The Transition Services Agreement we will enter into with Duke Energy, may not capture the benefits our businesses have enjoyed as a result of being integrated with the other businesses of Duke Energy. The loss of these benefits may have an adverse effect on our business, results of operations and financial condition following the completion of the separation.

• Subsequent to the completion of our separation, the borrowing costs for our business may be higher than Duke Energy’s borrowing costs prior to our separation.

• Other significant changes may occur in our cost structure, management, financing and business operations as a result of our operating as a company separate from Duke Energy.

We may be unable to make, on a timely or cost-effective basis, the changes necessary to operate as a separate, publicly-traded company, and we may experience increased costs after the separation or as a result of the separation.

Following the completion of our separation, Duke Energy will be contractually obligated to provide to us only those services specified in the Transition Services Agreement and the other agreements we enter into with Duke Energy in preparation for the separation. We may be unable to replace in a timely manner or on comparable terms, the services that Duke Energy previously provided to us that are not specified in the Transition Services Agreement or the other agreements. Also, upon the expiration of the Transition Services Agreement or other agreements, many of the services that are covered in such agreements will be provided internally or by unaffiliated third parties, and we expect that in some instances we may incur higher costs to obtain such services than we incurred under the terms of such agreements. In addition, if Duke Energy does not continue to perform effectively the transition services and the other services that are called for under the Transition Services Agreement and the other agreements, we may not be able to operate our business effectively and our profitability may decline. For more information, see the section entitled “Certain Relationships and Related Party Transactions.”

Our agreements with Duke Energy may not reflect terms that would have resulted from arm’s-length negotiations among unaffiliated third parties.

The agreements related to our separation from Duke Energy, including the Separation and Distribution Agreement, Employee Matters Agreement, Tax Matters Agreement, Transition Services Agreement, were prepared in the context of our separation from Duke Energy while we were still part of Duke Energy and,

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accordingly, may not reflect terms that would have resulted from arm’s-length negotiations among unaffiliated third parties. The terms of the agreements were prepared in the context of our separation related to, among other things, allocation of assets, liabilities, rights, indemnifications and other obligations between Duke Energy and us. See the section entitled “Certain Relationships and Related Party Transactions.”

We will be responsible for certain contingent and other corporate liabilities related to the natural gas transmission and storage, distribution, and gathering and processing businesses of Duke Energy.

Under the Separation and Distribution Agreement, we will assume and be responsible for certain contingent and other corporate liabilities related to the natural gas transmission and storage, distribution, and gathering and processing businesses of Duke Energy (including associated costs and expenses, whether arising prior to, at, or after the distribution) and we may be required to indemnify Duke Energy for these liabilities which may have a material effect on our financial condition and results of operations. In addition, we may also be responsible for sharing unknown liabilities that do not relate to either our business following the separation or the business of Duke Energy following the separation (for example, liabilities associated with certain corporate activities not specifically attributable to either business). For a more detailed description of the Separation and Distribution Agreement and treatment of certain historical Duke Energy contingent and other corporate liabilities, see “Certain Relationships and Related Party Transactions—Agreements with Duke Energy Corporation—The Separation and Distribution Agreement.”

We will continue to be responsible for debt to third parties, which could subject us to various restrictions and decrease our profitability.

Our subsidiaries, including Duke Capital, will continue to be subject to certain debt obligations, credit agreements and other financing arrangements, to which they are a party to prior to the separation. On a pro forma basis, Spectra Energy and its subsidiaries have long-term debt in the aggregate principal amount of approximately $8.9 billion as of September 30, 2006. Approximately $5.9 billion of this debt relates to both secured and unsecured debt, capital leases and other debt incurred by our operating subsidiaries prior to the separation. Approximately $3.0 billion of this debt is comprised of amounts outstanding under the senior indenture of Duke Capital, our subsidiary, subsequent to the internal reorganization. In addition, approximately $1.1 billion of debt historically reflected on the consolidated balance sheet of Duke Capital is the debt of businesses to be transferred to Duke Energy in the internal reorganization prior to the distribution, and thus will not be reflected in our going-forward financial statements. Furthermore, we will have access to four revolving credit facilities available in two currencies upon our separation from Duke Energy, with total combined capacities of $950 million and CAN $600 million. These facilities will be used principally as a back-stop for commercial paper programs at Spectra Energy subsidiaries. Approximately $350 million is expected to be utilized at the time of separation as a result of the maturity of senior unsecured notes in November 2006. The agreements and documents governing such indebtedness contain customary restrictions, covenants and events of default. The terms of these financing arrangements and any future indebtedness impose or may impose various restrictions and covenants on us (such as tangible net worth requirements) that could limit our ability to respond to market conditions, provide for capital investment needs or take advantage of business opportunities. In addition, our financing costs may be higher than they were as part of Duke Energy. For a more detailed discussion of these borrowings and our liquidity following the separation, see the section entitled “Management’s Discussion and Analysis of Results of Operations and Financial Condition—Liquidity and Capital Resources—Description of Indebtedness.”

Our executive officers and some of our directors may have or may hold equity awards which may create, or may create the appearance of, conflicts of interest.

Because of their current or former positions with Duke Energy, substantially all of our directors and executive officers, including both our Chairman and Chief Executive Officer, own shares of Duke Energy common stock, options to purchase shares of Duke Energy common stock or other equity awards based on Duke Energy common stock. Upon Duke Energy’s distribution of all of Spectra Energy’s shares of common stock to

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Duke Energy shareholders, these options and other equity awards will be converted into options and other equity awards based in part on Duke Energy common stock and in part on Spectra Energy common stock. Accordingly, following Duke Energy’s distribution of Spectra Energy to shareholders, these officers and non-employee directors will own shares of both Duke Energy and Spectra Energy common stock and/or hold options to purchase and other equity awards based on shares of common stock of both Duke Energy and Spectra Energy. The individual holdings of common stock, options to purchase common stock and other equity awards based on common stock of Duke Energy may be significant for some of these persons compared to these persons’ total assets. Even though our board of directors will include directors who are independent from Duke Energy and our executive officers who are currently employees of Duke Energy will cease to be employees of Duke Energy upon consummation of the separation, ownership by our directors and officers, after the separation, of common stock, options to purchase common stock and other equity awards based on common stock of Duke Energy may create, or may create the appearance of, conflicts of interest when these directors and officers are faced with decisions that could have different implications for Duke Energy than the decisions do for us.

The distribution could result in significant tax liability.

Duke Energy has received a private letter ruling from the Internal Revenue Service, or IRS, that the distribution will qualify for tax-free treatment under Code Sections 355 and 368(a)(1)(D). In addition, Duke Energy intends to obtain an opinion from Skadden, Arps, Slate, Meagher & Flom LLP that the distribution will so qualify. Although Duke Energy’s board of directors may waive the condition of receiving this opinion, Duke Energy does not intend to complete the distribution if it has not obtained an opinion from Skadden, Arps, Slate, Meagher & Flom LLP that the distribution will qualify for tax-free treatment under Code Sections 355 and 368(a)(1)(D). The IRS ruling and the opinion will rely on certain representations, assumptions and undertakings, including those relating to the past and future conduct of our business, and neither the IRS ruling nor the opinion would be valid if such representations, assumptions and undertakings were incorrect. Moreover, the IRS private letter ruling does not address all the issues that are relevant to determining whether the distribution will qualify for tax-free treatment. Notwithstanding the IRS private letter ruling and opinion, the IRS could determine that the distribution should be treated as a taxable transaction if it determines that any of the representations, assumptions or undertakings that were included in the request for the private letter ruling is false or has been violated or if it disagrees with the conclusions in the opinion that are not covered by the IRS ruling. For more information regarding the tax opinion and the private letter ruling, see the section entitled “The Separation—Certain U.S. Federal Income Tax Consequences of the Distribution.”

If the distribution fails to qualify for tax-free treatment, Duke Energy would be subject to tax as if it had sold the common stock of our company in a taxable sale for its fair market value and our initial public shareholders would be subject to tax as if they had received a taxable distribution equal to the fair market value of our common stock that was distributed to them. Under the tax matters agreement between Duke Energy and us, we would generally be required to indemnify Duke Energy against any tax resulting from the distribution to the extent that such tax resulted from (1) an issuance of our equity securities, a redemption of our equity securities or our involvement in other acquisitions of our equity securities, (2) other actions or failures to act by us or (3) any of our representations or undertakings being incorrect or violated. For a more detailed discussion, see the section entitled “Tax Matters Agreement.” Our indemnification obligations to Duke Energy and its subsidiaries, officers and directors are not limited by any maximum amount. If we are required to indemnify Duke Energy or such other persons under the circumstances set forth in the Tax Matters Agreement, we may be subject to substantial liabilities.

Spectra Energy and Duke Energy might not be able to engage in desirable strategic transactions and equity issuances following the distribution.

To preserve the tax-free treatment to Duke Energy of the distribution, under a tax matters agreement that we will enter into with Duke Energy, for the two year period following the distribution, we may be prohibited, except in specified circumstances, from:

• issuing equity securities to satisfy financing needs,

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• acquiring businesses or assets with equity securities, or

• engaging in other actions or transactions that could jeopardize the tax-free status of the distribution.

These restrictions may limit our ability to pursue strategic transactions or engage in new business or other transactions that may maximize the value of our business. For more information, see the sections entitled “The Separation—Certain U.S. Federal Income Tax Consequences of the Distribution” and “Certain Relationships and Related Party Transactions—Agreement with Duke Energy—Tax Matters Agreement.”

Until the distribution occurs Duke Energy has the sole discretion to change the terms of the separation in ways which may be unfavorable to us.

Until the distribution occurs Duke Energy will have the sole and absolute discretion to determine and change the terms of the distribution, including the establishment of the record date and distribution date. These changes could be unfavorable to us. In addition, Duke Energy may decide at any time not to proceed with the separation.

Risks Relating to Our Common Stock

There is no existing market for our common stock and a trading market that will provide you with adequate liquidity may not develop for our common stock. In addition, once our common stock begins trading, the market price of our shares may fluctuate widely.

There is currently no public market for our common stock. It is anticipated that on or prior to the record date for the distribution, trading of shares of our common stock will begin on a “when-issued” basis and will continue up and through the distribution date. However, there can be no assurance that an active trading market for our common stock will develop as a result of the distribution or be sustained in the future.

We cannot predict the prices at which our common stock may trade after the distribution. The market price of our common stock may fluctuate widely, depending upon many factors, some of which may be beyond our control, including:

• a shift in our investor base;

• our quarterly or annual earnings, or those of other companies in our industry;

• actual or anticipated fluctuations in our operating results due to the seasonality of our business and other factors related to our business;

• changes in accounting standards, policies, guidance, interpretations or principles;

• announcements by us or our competitors of significant acquisitions or dispositions;

• the failure of securities analysts to cover our common stock after the distribution;

• changes in earnings estimates by securities analysts or our ability to meet those estimates;

• the operating and stock price performance of other comparable companies;

• overall market fluctuations; and

• general economic conditions.

Stock markets in general have experienced volatility that has often been unrelated to the operating or financial performance of a particular company. These broad market fluctuations may adversely affect the trading price of our common stock.

Substantial sales of our common stock may occur in connection with this distribution, which could cause our stock price to decline.

The shares of our common stock that Duke Energy distributes to its shareholders generally may be sold immediately in the public market. Although we have no actual knowledge of any plan or intention on the part of

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any shareholder to sell our common stock following the separation, it is possible that some Duke Energy shareholders, including possibly some of our largest shareholders, may sell our common stock received in the distribution for reasons such as that our business profile or market capitalization as a separate, publicly-traded company does not fit their investment objectives. Moreover, index funds tied to the Standard & Poor’s 500 Index, the Russell 1000 Index and other indices hold shares of Duke Energy common stock. To the extent our common stock is not included in these indices after the distribution, certain of these index funds may likely be required to sell the shares of our common stock that they receive in the distribution. The sales of significant amounts of our common stock or the perception in the market that this will occur may result in the lowering of the market price of our common stock.

Provisions in our certificate of incorporation, by-laws and of Delaware law may prevent or delay an acquisition of our company, which could decrease the trading price of our common stock.

Our certificate of incorporation, by-laws and Delaware law contain provisions that are intended to deter coercive takeover practices and inadequate takeover bids by making such practices or bids unacceptably expensive to the raider and to encourage prospective acquirors to negotiate with our board of directors rather than to attempt a hostile takeover. These provisions include, among others:

• a board of directors that is divided into three classes with staggered terms;

• inability of our shareholders to act by written consent;

• rules regarding how shareholders may present proposals or nominate directors for election at shareholder meetings;

• the right of our board of directors to issue preferred stock without shareholder approval; and

• limitations on the right of shareholders to remove directors.

Delaware law also imposes some restrictions on mergers and other business combinations between us and any holder of 15% or more of our outstanding common stock. For more information, see the section entitled “Description of Capital Stock—Anti-takeover Effects of Our Certificate of Incorporation and By-laws and Delaware Law.”

We believe these provisions are important for a new public company and protect our shareholders from coercive or otherwise potentially unfair takeover tactics by requiring potential acquirors to negotiate with our board of directors and by providing our board of directors with more time to assess any acquisition proposal. These provisions are not intended to make our company immune from takeovers. However, these provisions apply even if the offer may be considered beneficial by some shareholders and could delay or prevent an acquisition that our board of directors determines is not in the best interests of our company and our shareholders.

Although Spectra Energy currently anticipates paying dividends, there cannot be any assurance that dividends will be paid.

Currently, we anticipate a dividend payout ratio of approximately 60% of our anticipated annual net income per share of common stock. Based on this dividend payout ratio, we anticipate paying an annual dividend of $0.88 per share, on a quarterly basis, beginning with the first quarter of 2007. However, there can be no assurance that we will have sufficient surplus under Delaware law to be able to pay any dividends. This may result from extraordinary cash expenses, actual expenses exceeding contemplated costs, funding of capital expenditures, or increases in reserves. The declaration and payment of dividends by us will be subject to the sole discretion of our board of directors and will depend upon many factors, including our financial condition, earnings, capital requirements of our operating subsidiaries, covenants associated with certain of our debt obligations, legal requirements, regulatory constraints and other factors deemed relevant by our board of directors. If we do not pay dividends, the price of our common stock that you receive in the distribution must appreciate for you to receive a gain on your investment in Spectra Energy. This appreciation may not occur.

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FORWARD-LOOKING STATEMENTS

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

• state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an effect on rate structure, and affect the speed at and degree to which competition enters the natural gas industries;

• the outcomes of litigation and regulatory investigations, proceedings or inquiries;

• the weather and other natural phenomena, including the economic, operational and other effects of hurricanes and storms;

• the timing and extent of changes in commodity prices, interest rates and foreign currency exchange rates;

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

• changes in environmental, safety and other laws and regulations to which we and our subsidiaries are subject;

• the results of financing efforts, including our ability to obtain financing on favorable terms, which can be affected by various factors, including our credit ratings and general economic conditions;

• declines is the market prices of equity securities and resulting funding requirements for defined benefit pension plans;

• growth in opportunities for our business units, including the timing and success of efforts to develop domestic and international pipeline, storage, gathering, processing and other infrastructure projects and the effects of competition;

• the entering into definitive agreement to contribute additional midstream assets to the Duke Energy Income Fund;

• the performance of natural gas transmission and storage, distribution, and gathering and processing facilities;

• the extent of success in connecting natural gas supplies to gathering, processing and transmission systems and in connecting to expanding gas markets;

• the effect of accounting pronouncements issued periodically by accounting standard-setting bodies;

• conditions of the capital markets and equity markets during the periods covered by the forward-looking statements;

• the ability to successfully complete merger, acquisition or divestiture plans, regulatory or other limitations imposed as a result of a merger, acquisition or divestiture; and the success of the business following a merger, acquisition or divestiture;

• the final resolutions or outcomes with respect to our contingent and other corporate liabilities related to the natural gas transmission and storage, distribution, and gathering and processing businesses and any related actions for indemnification made pursuant to the Separation and Distribution Agreement;

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• our ability to operate effectively as a stand-alone, publicly-traded company; and

• the costs associated with becoming compliant with the Sarbanes-Oxley Act of 2002 as a stand-alone company and the consequences of failing to implement effective internal controls over financial reporting as required by Section 404 of the Sarbanes-Oxley Act of 2002 by the date that we must comply with that section of the Sarbanes-Oxley Act.

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 we have described. We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

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THE SEPARATION

General

On June 27, 2006, the board of directors of Duke Energy initially approved a plan to separate its natural gas transmission and storage, distribution, and gathering and processing businesses into a separate, publicly-traded company.

In furtherance of this plan, on December 8, 2006, the Duke Energy board of directors approved the distribution of all of the shares of our common stock held by Duke Energy to holders of Duke Energy common stock. The distribution of the shares of our common stock will take place prior to the opening of the market on January 2, 2007. On the distribution date, each holder of Duke Energy common stock will receive 0.5 shares of our common stock for each share of Duke Energy common stock held at the close of business on the record date, as described below.

In connection with the distribution, pursuant to the terms of the indenture governing Duke Energy’s 1¾% Convertible Senior Notes due 2023, holders of record of such notes will participate in the distribution. As of December 1, 2006, there was approximately $110 million principal amount outstanding of such notes. Accordingly, pursuant with the terms of the indenture, approximately 2.4 million shares of Spectra Energy common stock are expected to be distributed in respect of such outstanding principal amount of such notes. Following the distribution, Duke Energy shareholders (on an as if converted basis) will own 100% of the common stock of Spectra Energy.

You will not be required to make any payment, surrender or exchange your shares of Duke Energy common stock or take any other action to receive your shares of our common stock.

The distribution of our common stock as described in this information statement is subject to the satisfaction or waiver of certain conditions, including final approval of the Duke Energy board of directors. We cannot provide any assurances that the distribution will be completed or approved by the Duke Energy board of directors. For a more detailed description of these conditions, see the section entitled “—Conditions to the Distribution.”

Internal Reorganization Prior to the Distribution

Duke Energy operates its businesses primarily through three subsidiaries: Duke Energy Carolinas LLC, Cinergy Corp., and Duke Capital LLC. Duke Energy Carolinas LLC and Cinergy Corp. conduct, directly or indirectly, Duke Energy’s regulated electricity generation, transmission and distribution businesses and regulated retail gas business in the Midwest. Duke Capital holds, through its subsidiaries, the remainder of Duke Energy’s businesses, including:

• Duke Energy’s natural gas transmission and storage, distribution, and gathering and processing businesses (Natural Gas Transmission and Field Services);

• Crescent Resources (Duke Energy’s real estate business); and

• Duke Energy International (Duke Energy’s power generation and sales and marketing of power and gas outside the United States and Canada).

Prior to the distribution, Duke Energy will implement an internal reorganization pursuant to which all of the businesses and assets of Duke Capital other than Duke Energy’s transmission and storage, distribution, and gathering and processing businesses, (i.e., Crescent Resources, and Duke Energy International), will be transferred from Duke Capital to Duke Energy or its other subsidiaries.

Duke Capital will then be transferred to, and will thereafter be, a direct, wholly-owned subsidiary of Spectra Energy.

Following this internal reorganization, we will be a direct, wholly-owned subsidiary of Duke Energy. Our sole direct material asset will be Duke Capital, through which we will hold all of the assets and liabilities of Duke Energy’s natural gas transmission and storage, distribution, and gathering and processing businesses.

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Set forth below are simplified diagrams of Duke Energy prior to the separation, and of Duke Energy and Spectra Energy after the separation. Not all subsidiaries and businesses are shown and not all businesses shown are wholly-owned.

Pre-Separation

Post-Separation

In connection with the separation, Spectra Energy intends to rename certain of its subsidiaries and will discontinue use of the “Duke Energy” name. In particular, Duke Capital will be renamed Spectra Energy Capital and DEFS will be renamed DCP Midstream.

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Basis of Financial Presentation

As a result of the internal reorganization described above, Duke Capital is treated, for accounting purposes only, as the predecessor entity to us, Spectra Energy. Accordingly, the audited consolidated financial statements included in this information statement are the financial statements of Duke Capital. Our unaudited pro-forma condensed consolidated financial statements, also included in this information statement, reflect adjustments to the Duke Capital historical statements to remove the businesses that, pursuant to the reorganization discussed below, will be transferred from Duke Capital to a subsidiary of Duke Energy. We generally do not discuss these transferred businesses in this information statement.

The Number of Shares You Will Receive

For each share of Duke Energy common stock that you owned at the close of business on December 18, 2006, the record date, you will receive 0.5 shares of our common stock on the distribution date. Duke Energy will not distribute any fractional shares of our common stock to its shareholders. Instead, the transfer agent will aggregate fractional shares into whole shares, sell the whole shares in the open market at prevailing market prices and distribute the aggregate net cash proceeds of the sales pro rata (based on the fractional share such holder would otherwise be entitled to receive) to each holder who otherwise would have been entitled to receive a fractional share in the distribution. Recipients of cash in lieu of fractional shares will not be entitled to any interest on the amounts of payment made in lieu of fractional shares.

When and How You Will Receive the Distributed Shares

Duke Energy will distribute the shares of our common stock prior to the opening of the market on January 2, 2007, the distribution date. The Bank of New York, will serve as transfer agent and registrar for our common stock and as distribution agent in connection with the distribution.

If you own Duke Energy common stock as of the close of business on the record date, the shares of Spectra Energy common stock that you are entitled to receive in the distribution will be issued electronically, as of the distribution date, to you or to your bank or brokerage firm on your behalf by way of direct registration in book-entry form. Registration in book-entry form refers to a method of recording stock ownership when no physical share certificates are issued to shareholders, as is the case in this distribution. Unless specifically requested by a shareholder, no physical stock certificates of Spectra Energy will be issued.

If you sell shares of Duke Energy common stock in the “regular-way” market prior to the distribution date, you will be selling your right to receive shares of our common stock in the distribution. For more information see the section entitled “—Trading Between the Record Date and Distribution Date.”

Commencing on or shortly after the distribution date, if you hold physical stock certificates that represent your shares of Duke Energy common stock, or if you hold your shares in book-entry form, and you are the registered holder of such shares, the distribution agent will mail to you an account statement that indicates the number of shares of our common stock that have been registered in book-entry form in your name. If you have any questions concerning the mechanics of having shares of our common stock registered in book-entry form, we encourage you to contact The Bank of New York at the address and telephone number set forth on page 18 of this information statement. After you receive your book-entry account statement, you may request that we issue you physical stock certificates by following the directions on your account statement.

Most Duke Energy shareholders hold their shares of Duke Energy common stock through a bank or brokerage firm. In such cases, the bank or brokerage firm would be said to hold the stock in “street name” and ownership would be recorded on the bank’s or brokerage firm’s books. If you hold your Duke Energy common stock through a bank or brokerage firm, your bank or brokerage firm will credit your account for the shares of

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our common stock that you are entitled to receive in the distribution. If you have any questions concerning the mechanics of having shares of our common stock held in “street name,” we encourage you to contact your bank or brokerage firm.

The Bank of New York, as distribution agent, will not issue any fractional shares of our common stock in connection with the distribution except with respect to shares held in the InvestorDirect Choice Plan, Duke Energy’s share purchase and dividend reinvestment plan. Instead, The Bank of New York will aggregate all fractional shares and sell them on behalf of the holders who otherwise would be entitled to receive fractional shares. The aggregate net cash proceeds of these sales, which generally will be taxable for U.S. federal income tax purposes, will be distributed pro rata (based on the fractional shares such holder would otherwise be entitled to receive) to each holder who otherwise would have been entitled to receive a fractional share in the distribution. For more information on the tax consequences, see the section entitled “—Certain U.S. Federal Income Tax Consequences of the Distribution.” If you physically hold Duke Energy common stock certificates and are the registered holder, you will receive a check from the distribution agent in an amount equal to your pro rata share of the aggregate net cash proceeds of the sales. We estimate that it will take approximately two weeks from the distribution date for the distribution agent to complete the distributions of the aggregate net cash proceeds. If you hold your Duke Energy stock through a bank or brokerage firm, your bank or brokerage firm will receive, on your behalf, your pro rata share of the aggregate net cash proceeds of the sales and will electronically credit your account for your share of such proceeds.

Results of the Separation

After our separation from Duke Energy, we will be a separate, publicly-traded company. Immediately following the distribution, we expect to have approximately 176,466 shareholders of record, based on the number of registered shareholders of Duke Energy common stock on November 30, 2006, and approximately 630 million shares of our common stock outstanding. The actual number of shares to be distributed will be determined on the record date and will reflect any changes in the number of shares of Duke Energy common stock between August 25, 2006 and the record date for the distribution.

Before the separation, we will enter into a Separation and Distribution Agreement and several other agreements with Duke Energy to effect the separation and provide a framework for our relationships with Duke Energy after the separation. These agreements will govern the relationship between us and Duke Energy subsequent to the completion of the separation plan and provide for the allocation of the assets, liabilities and obligations (including employee benefits and tax-related assets and liabilities) of the natural gas transmission and storage, distribution, and gathering and processing businesses attributable to periods prior to, at and after our separation from Duke Energy.

For a more detailed description of these agreements, see the section entitled “Certain Relationships and Related Party Transactions.”

The distribution will not affect the number of outstanding shares of Duke Energy common stock or any rights of Duke Energy shareholders.

Duke Energy Canada Exchangeco Inc.

Duke Energy’s indirect, wholly-owned subsidiary, Duke Energy Canada Exchangeco Inc., a Canadian corporation (“Exchangeco”), has outstanding a class of exchangeable shares. The exchangeable shares were originally issued to the former shareholders of Westcoast Energy Inc. who were resident in Canada and who elected to receive the exchangeable shares in connection with Duke Energy’s acquisition of Westcoast in March 2002. Exchangeable shares are traded on the Toronto Stock Exchange. Each exchangeable share may be exchanged at any time, at the option of the holder, for one share of Duke Energy common stock, plus all declared and unpaid dividends, if any, on the exchangeable share. The provisions governing the terms of the exchangeable shares generally provide that the holders thereof are entitled to receive dividends and other distributions on a

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basis equivalent to the dividends and distributions paid on shares of Duke Energy common stock. In addition, the holders of exchangeable shares generally are entitled to vote on matters submitted to the holders of Duke Energy common stock through certain trust arrangements. Exchangeco originally issued 19,877,268 exchangeable shares in connection with Duke Energy’s acquisition of Westcoast. As of July 31, 2006, approximately 10,958,000 exchangeable shares remained outstanding.

In connection with the separation from Duke Energy, it is expected that Exchangeco will become our indirect, wholly-owned subsidiary. In connection with the separation and distribution, in order for the holders of exchangeable shares to participate in the distribution on an equivalent basis and to continue to own exchangeable shares and thus be entitled to defer recognition of a taxable disposition and to receive the Canadian dividend tax credit, it is expected that, prior to the record date for the distribution, the board of directors of Exchangeco will consider, and if approved submit to the holders of exchangeable shares for approval, a plan of arrangement (the “Plan of Arrangement”) pursuant to which the terms governing the exchangeable shares (the “Share Rights”) and certain related arrangements and agreements would be amended. In particular, the Share Rights would be amended to reorganize the existing class of exchangeable shares into two classes of exchangeable shares—one class exchangeable, on a one-for-one basis, for a share of Duke Energy common stock (“Duke Energy Exchangeable Shares”) and one class exchangeable, on a one-for-one basis, for a share of our common stock (“Spectra Energy Exchangeable Shares”). The Plan of Arrangement will be subject to the approval of (i) the holders of exchangeable shares represented in person or by proxy at a duly convened meeting of the holders of exchangeable shares called by the board of directors of Exchangeco and (ii) the Supreme Court of British Columbia. It is expected that such meeting would be convened and court approval sought in the fourth quarter of 2006 and prior to the record date for the distribution.

If the Plan of Arrangement is approved by the holders of exchangeable shares and becomes effective and the distribution occurs, each holder of one exchangeable share as of the record date established pursuant to the Plan of Arrangement will in effect receive (i) one Duke Energy Exchangeable Share and (ii) a fraction of a Spectra Energy Exchangeable Share reflecting a ratable adjustment (based on the distribution ratio). No fractional Spectra Energy Exchangeable shares will be issued, and cash will be paid to holders of the existing exchangeable shares who otherwise would receive fractional Spectra Energy Exchangeable Shares. The effectiveness of the amendments to the Share Rights described is expected to be conditioned on the occurrence of the distribution. If the Plan of Arrangement becomes effective and the distribution occurs, we anticipate that each of Duke Energy and Spectra Energy would enter into certain agreements and arrangements to facilitate the orderly distribution of shares of Duke Energy common stock and our common stock upon exchange of Duke Energy Exchangeable Shares and Spectra Energy Exchangeable Shares and the payment of any dividends declared by the board of directors of Exchangeco on the Duke Energy Exchangeable Shares and Spectra Energy Exchangeable Shares. If the Plan of Arrangement becomes effective and the distribution occurs, we anticipate that we will file with the SEC a registration statement on Form S-3 registering the shares of our common stock issuable from time to time upon exchange of the Spectra Energy Exchangeable Shares.

If the Plan of Arrangement is not approved by the holders of exchangeable shares at the meeting described above, Exchangeco would be entitled to redeem immediately (subject to an overriding right of an indirect wholly-owned subsidiary of Duke Energy to purchase) all of the outstanding exchangeable shares in exchange for the issuance of a share of Duke Energy common stock, plus all declared and unpaid dividends on the exchangeable shares for each exchangeable share outstanding. We anticipate Exchangeco would exercise such right of redemption (or such subsidiary would exercise its right to purchase) if the Plan of Arrangement is not approved by the holders of exchangeable shares and the redemption would occur prior to the separation.

Share Purchase and Dividend Reinvestment Plan (InvestorDirect Choice Plan)

Shareholders who hold shares of Duke Energy common stock in the InvestorDirect Choice Plan, Duke Energy’s share purchase and dividend reinvestment plan, are entitled to receive in the distribution shares of Spectra Energy common stock in a direct registration position with The Bank of New York, Spectra Energy’s transfer agent. Instructions will be provided to such shareholders on how to transfer such shares to a different

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account. No fractional shares of Spectra Energy common stock will be distributed. Spectra Energy intends to set up a share purchase and dividend reinvestment plan immediately after the separation and information will be provided to shareholders on how to enroll in Spectra Energy’s plan.

Incurrence of Debt

Our subsidiaries, including Duke Capital, will continue to be subject to certain debt obligations, credit agreements and other financing arrangements to which they are a party to prior to the separation. On a pro forma basis, Spectra Energy and its subsidiaries have long-term debt in the aggregate principal amount of approximately $8.9 billion as of September 30, 2006. Approximately $5.9 billion of this debt relates to both secured and unsecured debt, capital leases and other debt incurred by our operating subsidiaries prior to the separation. Approximately $3.0 billion of this debt is comprised of amounts outstanding under the senior indenture of Duke Capital. In addition, approximately $1.1 billion of debt historically reflected on the consolidated balance sheet of Duke Capital is the debt of businesses to be transferred to Duke Energy in the internal reorganization prior to the distribution, and thus will not be reflected in our going-forward financial statements. Furthermore, we will have access to three revolving credit facilities available in two currencies upon our separation from Duke Energy, with total combined capacities of $600 million and CAN $600 million. These facilities will be used principally as a back-stop for commercial paper programs at Spectra Energy subsidiaries and are expected to be largely unutilized at the time of the separation. For a more detailed discussion of these borrowings, see the section entitled “Description of Material Indebtedness.”

Certain U.S. Federal Income Tax Consequences of the Distribution

The following is a summary of certain material U.S. federal income tax consequences relating to the distribution by Duke Energy. This summary is based on the Code, the Treasury regulations promulgated thereunder, and interpretations of the Code and the Treasury regulations by the courts and the IRS, in effect as of the date hereof, and all of which are subject to change, possibly with retroactive effect. This summary does not discuss all the tax considerations that may be relevant to Duke Energy shareholders in light of their particular circumstances, nor does it address the consequences to Duke Energy shareholders subject to special treatment under the U.S. federal income tax laws (such as non-U.S. persons, insurance companies, dealers or brokers in securities or currencies, tax-exempt organizations, financial institutions, mutual funds, pass-through entities and investors in such entities, holders who hold their shares as a hedge or as part of a hedging, straddle, conversion, synthetic security, integrated investment or other risk-reduction transaction or who are subject to alternative minimum tax or holders who acquired their shares upon the exercise of employee stock options or otherwise as compensation). In addition, this summary does not address the U.S. federal income tax consequences to those Duke Energy shareholders who do not hold their Duke Energy common stock as a capital asset. Finally, this summary does not address any state, local or foreign tax consequences. DUKE ENERGY SHAREHOLDERS ARE URGED TO CONSULT THEIR OWN TAX ADVISORS CONCERNING THE U.S. FEDERAL, STATE AND LOCAL AND NON-U.S. TAX CONSEQUENCES OF THE DISTRIBUTION TO THEM.

The distribution is conditioned upon Duke Energy’s receipt of a private letter ruling from the IRS and the opinion of Skadden, Arps, Slate, Meagher & Flom LLP, in each case, to the effect that the distribution will qualify as a tax-free distribution for U.S. federal income tax purposes under Sections 355 and 368(a)(1)(D) of the Code. Duke Energy has received a private letter ruling from the Internal Revenue Service that the distribution will so qualify. Assuming the distribution so qualifies: (i) no gain or loss will be recognized by (and no amount will be included in the income of) Duke Energy common shareholders upon their receipt of shares of Spectra Energy common stock in the distribution; (ii) any cash received in lieu of fractional share interests in Spectra Energy will give rise to gain or loss equal to the difference between the amount of cash received and the tax basis allocable to the fractional share interests (determined as described below), and such gain or loss will be capital gain or loss if the Duke Energy common stock on which the distribution is made is held as a capital asset on the date of the distribution; (iii) the aggregate basis of the Duke Energy common stock and the Spectra Energy common stock in the hands of each Duke Energy common shareholder after the distribution (including any fractional interests to which the shareholder would be entitled) will equal the aggregate basis of Duke Energy common stock held by the

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shareholder immediately before the distribution, allocated between the Duke Energy common stock and the Spectra Energy common stock in proportion to the relative fair market value of each on the date of the distribution; and (iv) the holding period of the Spectra Energy common stock received by each Duke Energy common shareholder will include the holding period at the time of the distribution for the Duke Energy common stock on which the distribution is made, provided that the Duke Energy common stock is held as a capital asset on the date of the distribution.

Although the private letter ruling from the IRS generally is binding on the IRS, if the factual representations or assumptions made in the letter ruling request are untrue or incomplete in any material respect, we will not be able to rely on the ruling. Furthermore, the IRS will not rule on whether a distribution satisfies certain requirements necessary to obtain tax-free treatment under Section 355 of the Code. Rather, the ruling is based upon representations by Duke Energy that these conditions have been satisfied, and any inaccuracy in such representations could invalidate the ruling. Therefore, in addition to obtaining the ruling from the IRS, Duke Energy has made it a condition to the distribution that Duke Energy obtain an opinion of Skadden, Arps, Slate, Meagher & Flom LLP that the distribution will qualify as a tax-free distribution for U.S. federal income tax purposes under Sections 355 and 368(a)(1)(D) of the Code. The opinion will rely on the ruling as to matters covered by the ruling. In addition, the opinion will be based on, among other things, certain assumptions and representations as to factual matters made by Duke Energy and us, which if incorrect or inaccurate in any material respect would jeopardize the conclusions reached by counsel in its opinion. The opinion will not be binding on the IRS or the courts, and the IRS or the courts may not agree with the opinion.

Notwithstanding receipt by Duke Energy of the ruling and opinion of counsel, the IRS could assert that the distribution does not qualify for tax-free treatment for U.S. federal income tax purposes. If the IRS were successful in taking this position, our initial public shareholders and Duke Energy could be subject to significant U.S. federal income tax liability. In general, Duke Energy would be subject to tax as if it had sold the common stock of our company in a taxable sale for its fair market value and our initial public shareholders would be subject to tax as if they had received a taxable distribution equal to the fair market value of our common stock that was distributed to them. In addition, even if the distribution were to otherwise qualify under Section 355 of the Code, it may be taxable to Duke Energy (but not to Duke Energy’ shareholders) under Section 355(e) of the Code, if the distribution were later deemed to be part of a plan (or series of related transactions) pursuant to which one or more persons acquire directly or indirectly stock representing a 50% or greater interest in Duke Energy or us. For this purpose, any acquisitions of Duke Energy stock or of our common stock within the period beginning two years before the distribution and ending two years after the distribution are presumed to be part of such a plan, although we or Duke Energy may be able to rebut that presumption.

In connection with the distribution, we and Duke Energy will enter into a Tax Matters Agreement pursuant to which we will agree to be responsible for certain liabilities and obligations following the distribution. In general, under the terms of the Tax Matters Agreement, in the event the distribution were to fail to qualify as a reorganization for U.S. federal income tax purposes under Sections 355 and 368(a)(1)(D) of the Code (including as a result of Section 355(e) of the Code) and if such failure was not the result of actions taken after the distribution by Duke Energy or us, we and Duke Energy would be responsible for 33 ¹/3% and 66 ²/3% respectively, of any taxes imposed on Duke Energy as a result thereof. If such failure was the result of actions taken after the distribution by Duke Energy or us, the party responsible for such failure would be responsible for all taxes imposed on Duke Energy to the extent that such taxes result from such actions. For a more detailed discussion, see the section entitled “Tax Matters Agreement.” Our indemnification obligations to Duke Energy and its subsidiaries, officers and directors are not limited in amount or subject to any cap. If we are required to indemnify Duke Energy and its subsidiaries and their respective officers and directors under the circumstances set forth in the Tax Matters Agreement, we may be subject to substantial liabilities.

U.S. Treasury regulations require each shareholder that receives stock in a spin-off to attach to the shareholder’s U.S. federal income tax return for the year in which the spin-off occurs a detailed statement setting forth certain information relating to the tax-free nature of the spin-off. Shortly after the distribution, Duke Energy

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will provide shareholders who will receive Spectra Energy shares in the distribution with the information necessary to comply with that requirement.

THE FOREGOING IS A SUMMARY OF CERTAIN U.S. FEDERAL INCOME TAX CONSEQUENCES OF THE DISTRIBUTION UNDER CURRENT LAW AND IS FOR GENERAL INFORMATION ONLY. THE FOREGOING DOES NOT PURPORT TO ADDRESS ALL U.S. FEDERAL INCOME TAX CONSEQUENCES OR TAX CONSEQUENCES THAT MAY ARISE UNDER THE TAX LAWS OF OTHER JURISDICTIONS OR THAT MAY APPLY TO PARTICULAR CATEGORIES OF SHAREHOLDERS. EACH DUKE ENERGY SHAREHOLDER SHOULD CONSULT ITS TAX ADVISOR AS TO THE PARTICULAR TAX CONSEQUENCES OF THE DISTRIBUTION TO SUCH SHAREHOLDER, INCLUDING THE APPLICATION OF U.S. FEDERAL, STATE, LOCAL AND FOREIGN TAX LAWS, AND THE EFFECT OF POSSIBLE CHANGES IN TAX LAWS THAT MAY AFFECT THE TAX CONSEQUENCES DESCRIBED ABOVE.

Market for Common Stock

There is currently no public market for our common stock. A condition to the distribution is the listing on the NYSE of our common stock. We have applied to list our common stock on the NYSE under the symbol “SE”.

Trading Between the Record Date and Distribution Date

Beginning on or shortly before the record date and continuing up to and through the last trading day prior to the distribution date, we expect that there will be two markets in Duke Energy common stock: a “regular-way” market and an “ex-distribution” market. Shares of Duke Energy common stock that trade on the regular way market will trade with an entitlement to shares of our common stock distributed pursuant to the distribution. Shares that trade on the ex-distribution market will trade without an entitlement to shares of our common stock distributed pursuant to the distribution. Therefore, if you sell shares of Duke Energy common stock in the “regular-way” market prior to the distribution date, you will be selling your right to receive shares of Spectra Energy common stock in the distribution. If you own shares of Duke Energy common stock at the close of business on the record date and sell those shares on the “ex-distribution” market prior to the distribution date, you will still receive the shares of our common stock that you would be entitled to receive pursuant to your ownership of the shares of Duke Energy common stock on the record date.

Furthermore, beginning on or shortly before the record date and continuing up to and through the distribution date, we expect that there will be a “when-issued” market in our common stock. “When-issued” trading refers to a sale or purchase made conditionally because the security has been authorized but not yet issued. The “when-issued” trading market will be a market for shares of our common stock that will be distributed to Duke Energy shareholders on the distribution date. If you owned shares of Duke Energy common stock at the close of business on the record date, you would be entitled to shares of our common stock distributed pursuant to the distribution. You may trade this entitlement to shares of our common stock, without trading the shares of Duke Energy common stock you own, on the “when-issued” market. On the distribution date, “when issued” trading with respect to our common stock will end and “regular-way” trading will begin.

Conditions to the Distribution

We expect that the distribution will occur prior to the opening of the market on January 2, 2007, the distribution date, provided that, among other conditions described in this information statement, the following conditions shall have been satisfied or, if permissible under the Separation and Distribution Agreement, waived by Duke Energy:

• the SEC shall have declared effective our registration statement on Form 10, of which this information statement is a part, under the Exchange Act, as amended, and no stop order relating to the registration statement is in effect;

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• all permits, registrations and consents required under the securities or blue sky laws of states or other political subdivisions of the United States or of other foreign jurisdictions in connection with the distribution shall have been received;

• Duke Energy shall have received a private letter ruling from the Internal Revenue Service substantially to the effect that the distribution, together with certain related transactions, will qualify as a reorganization for U.S. federal income tax purposes under Sections 355 and 368(a)(1)(D) of the Code;

• Duke Energy shall have received a legal opinion of Skadden, Arps, Slate, Meagher & Flom LLP substantially to the effect that the distribution, together with certain related transactions, will qualify as a reorganization for U.S. federal income tax purposes under Sections 355 and 368(a)(1)(D) of the Code;

• the listing of our common stock on the NYSE shall have been approved, subject to official notice of issuance;

• any material government approvals and other consents necessary to consummate the distribution shall have been received; and

• no order, injunction or decree issued by any court of competent jurisdiction or other legal restraint or prohibition preventing consummation of the distribution or any of the transactions related thereto, including the transfers of assets and liabilities contemplated by the Separation and Distribution Agreement, shall be in effect.

The fulfillment of the foregoing conditions does not create any obligation on Duke Energy’s part to effect the distribution, and the Duke Energy board of directors has reserved the right, in its sole discretion, to waive any or all of the above conditions, and to amend, modify or abandon the distribution and related transactions at any time prior to the distribution date. Duke Energy has the right not to complete the distribution if, at any time, the Duke Energy board of directors determines, in its sole discretion, that the distribution is not in the best interests of Duke Energy or its shareholders or that market conditions are such that it is not advisable to separate the natural gas transmission and storage, distribution, and gathering and processing businesses from Duke Energy.

Reasons for the Separation

The Duke Energy board of directors regularly reviews the company’s various businesses to ensure that Duke Energy’s resources are being put to use in a manner that is in the best interests of Duke Energy and its shareholders. Duke Energy believes that the separation of the natural gas transmission and storage, distribution, and gathering and processing businesses is the best way to unlock the full value of Duke Energy’s businesses in both the short and long terms and provides each of Duke Energy and us, with certain opportunities and benefits. The following are some of the opportunities and benefits that the Duke Energy board of directors considered in approving the separation:

• Enables investors to invest directly in our business. Separating the natural gas transmission and storage, distribution, and gathering and processing businesses from the rest of Duke Energy is expected to reduce the complexities surrounding investor and research analyst understanding and will provide investors with the opportunity to invest individually in each of the separated companies. The Duke Energy board of directors believes that many investors prefer to invest in companies that are focused on only one industry and therefore the aggregate demand for each of the separated companies’ shares by such investors may be greater than the current demand for Duke Energy’s shares. Although there can be no assurances, Duke Energy believes that over time following the separation, the common stock of Duke Energy and Spectra Energy should have a higher aggregate market value, assuming the same market conditions, than if Duke Energy were to remain under its current configuration.

• Provides direct access to capital. Each company will have a capital structure adequate to meet its needs. After the separation, our capital structure is expected to better facilitate acquisitions (including, possibly, acquisitions using Spectra Energy common stock as currency), joint ventures, partnerships and

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internal expansion, which are important for us to remain competitive in our industry. Duke Energy believes that this should provide Spectra Energy with the ability to finance acquisitions with equity in a manner that preserves capital with significantly less dilution of its shareholders’ interests than would occur by issuing pre-distribution Duke Energy common stock. Duke Energy believes that our stock should be an attractive acquisition currency to potential sellers of businesses complementary to our business.

• Creates more effective management incentives. The separation will permit the creation of equity securities, including options and restricted stock units, for each of the companies with a value that is expected to reflect more closely the efforts and performance of each company’s management. Such equity securities should enable each company to provide incentive compensation arrangements for its key employees that are directly related to the market performance of each company’s common stock, and Duke Energy believes such equity-based compensation arrangements should provide enhanced incentives for performance and improve the ability for each company to attract, retain and motivate qualified personnel.

• Allows us and Duke Energy to focus on our respective industry developments. The Duke Energy board of directors believes that the separation will allow Duke Energy and Spectra Energy to maintain a sharper focus on their respective core business and growth opportunities, which will allow each separated company to be better able to make the changes to its business necessary for it to respond to the industry in which it operates. The separation will allow the management of each company to design and implement corporate policies and strategies that are based primarily on the business characteristics of that company and to concentrate its financial resources wholly on its own operations. For example, after the separation, the businesses within each company will no longer need to compete internally for capital with businesses operating in other industries.

Neither we nor Duke Energy can assure you that, following the separation, any of these benefits will be realized to the extent anticipated or at all.

In view of the wide variety of factors considered in connection with the evaluation of the separation and the complexity of these matters, the Duke Energy board of directors did not find it useful to, and did not attempt to, quantify, rank or otherwise assign relative weights to the factors considered. The individual members of the Duke Energy board of directors likely may have given different weights to different factors.

Separation Costs

Duke Energy expects to incur pre-tax separation costs of approximately $200 million of which approximately $130 million will be allocated to Spectra Energy in the separation or incurred by Spectra Energy post-separation. Over the 12 months following the separation, the portion of these pre-tax costs incurred by us is expected to be approximately $60 to $70 million. Certain of the separation costs, primarily costs for the development of new information systems, are expected to be capitalized.

The expected costs include:

• fees for professional services including: legal, financial advisors and other business consultants;

• costs for branding the new company, replacing signage, investor and other stakeholder communications;

• costs for building and/or reconfiguring the required information systems to run the stand-alone companies and restacking of building facilities as required;

• costs for relocating, recruiting and severing employees; and

• tax costs incurred as part of the reorganization and separation.

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Reason for Furnishing this Information Statement

This information statement is being furnished solely to provide information to Duke Energy shareholders who are entitled to receive shares of Spectra Energy common stock in the distribution. The information statement is not, and is not to be construed as, an inducement or encouragement to buy, hold or sell any of our securities or securities of Duke Energy. We believe that the information in this information statement is accurate as of the date set forth on the cover. Changes may occur after that date and neither Duke Energy nor we undertake any obligation to update such information.

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DIVIDEND POLICY

Currently, we anticipate a dividend payout ratio of approximately 60% of our anticipated annual net income per share of common stock. The declaration and payment of dividends by us will be subject to the sole discretion of our board of directors and will depend upon many factors, including our financial condition, earnings, capital requirements of our operating subsidiaries, covenants associated with certain of our debt obligations, legal requirements, regulatory constraints and other factors deemed relevant by our board of directors. Based on this dividend payout ratio, we anticipate paying an annual dividend of $0.88 per share, on a quarterly basis, beginning with the first quarter of 2007. We anticipate increasing our dividend in an amount consistent with underlying growth in earnings.

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UNAUDITED PRO FORMA FINANCIAL INFORMATION OF SPECTRA ENERGY

The following tables present Spectra Energy’s unaudited pro forma condensed consolidated financial information and should be read in conjunction with the consolidated financial statements and related notes of Duke Capital LLC “Selected Historical Consolidated Financial Data” and “Management’s Discussion and Analysis of Results of Operations and Financial Condition,” included elsewhere in this information statement.

These unaudited pro forma condensed consolidated financial statements and supplementary data present Duke Energy’s natural gas transmission and storage, distribution, and gathering and processing businesses. These businesses are primarily comprised of Duke Energy’s Natural Gas Transmission and Field Services business segments.

These Spectra Energy unaudited pro forma condensed consolidated financial statements are based on the historical consolidated financial statements of Duke Capital, LLC, an SEC registrant that is a wholly-owned subsidiary of Duke Energy. As of September 30, 2006 and for the 2005, 2004 and 2003 historical periods presented in the pro forma statements, Duke Capital owned the operations and assets that will be included in Spectra Energy, as well as the assets and operations of other components of Duke Energy’s portfolio of businesses. These other operations include Crescent Resources (real estate business), Duke Energy International (power generation and sales and marketing of power and gas outside of the United States and Canada), Duke Energy Business Services (corporate services for Duke Energy affiliates), Duke Energy North America (United States merchant power plant operations and marketing of natural gas and electricity) and other operations not associated with the Spectra Energy operations. On December 30, 2006, in order to effectuate the separation of the Spectra Energy businesses from Duke Energy, Duke Capital will first distribute these other assets and operations to Duke Energy, hereinafter referred to as the Transferred Businesses. Duke Energy will then contribute Duke Capital—which will then be comprised of the natural gas businesses of Duke Energy described above—to Spectra Energy. The unaudited pro forma condensed consolidated financial statements reflect management’s current estimate of the results of the reorganization and transfers but is subject to change as the reorganization and transfer plans are finalized prior to the date of the separation of Spectra Energy.

The transfer of Duke Capital to Spectra Energy in connection with the separation will result in the consolidation by Spectra Energy of the consolidated financial statements of Duke Capital. Because this transfer to Spectra Energy will represent a transfer of businesses between entities under common control, as contemplated in Statement of Financial Accounting Standards (SFAS), No. 141 “Business Combinations,” financial statements issued by Spectra Energy after that date will include the historical consolidated results of operations, financial condition and cash flows of Duke Capital. The Duke Capital historical consolidated financial statements represent the predecessor statements of Spectra Energy. Spectra Energy was formed July 28, 2006. Duke Energy, the sole shareholder of Spectra Energy, subscribed for 1,000 shares of Spectra Energy common stock at par, $0.001 per share. Spectra Energy had no separate operations for the periods presented.

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Pro Forma Capitalization

The following table presents Duke Capital’s historical capitalization at September 30, 2006 and Spectra Energy’s unaudited pro forma capitalization at that date reflecting the separation as if the separation had occurred on September 30, 2006. The pro forma adjustments reflect the expected effects of events that are directly attributable to the separation transaction and related agreements, are expected to have a continuing impact on Spectra Energy and are factually supportable.

Pro Forma Capitalization (unaudited)

	September 30, 2006
			Pro Forma Adjustments
	Duke Capital Historical		Transferred Businesses (a)			Other					Spectra Energy Pro Forma
	(in millions)
Debt
Current maturities of long-term debt	$	1,151	$	(239	)	$	—				$	912
Long-term Debt		8,778		(821	)		—					7,957
Total Debt		9,929		(1,060	)		—					8,869
Minority interest		792		(217	)		—					575
Equity
Equity		7,582		(2,408	)		34		(b	)		5,225
							28		(c	)
							(11	)	(d	)
Accumulated other comprehensive income		1,090		229			—					1,319
Total Equity		8,672		(2,179	)		51					6,544
Total Capitalization	$	19,393	$	(3,456	)	$	51				$	15,988

(a) Reflects the Duke Capital distribution of the Transferred Businesses to Duke Energy, expected to occur in connection with the separation. Any outstanding debt obligations issued by and recorded in the balance sheets of these Transferred Businesses will be included in the distribution of these businesses.

(b) Reflects the estimated prepaid asset and accrued liabilities resulting from the transfer from Duke Energy pension, post retirement and other benefit plans (previously accounted for as multi-employer benefit plans), related to current and former employees of Spectra Energy, determined in accordance with Internal Revenue Service IRC 414(l), which requires benefits after a transfer to be at least as valuable as those present prior to the transfer, as judged in the context of the asset allocation rules of ERISA 4044. The estimated total pension plan assets and associated projected benefit obligations that would have transferred to Spectra Energy if the separation had occurred on September 30, 2006 are approximately $580 million and $550 million, respectively.

(c) Spectra Energy expects to provide insurance coverage primarily through a captive insurance subsidiary it will establish prior to the separation transaction. These pro forma adjustments reflect the estimated reserves associated with the transfer by Duke Energy of the insurance and reinsurance positions related to Spectra Energy operations, such as workers’ compensation, property, business interruption and general business risks and assets sufficient to cover such liabilities and meet regulatory capital requirements.

(d) Reflects guarantees issued between entities under common control prior to the separation that, as a result of the separation, will require recognition under Financial Interpretation No. 45 “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.” These guarantees include payment, performance obligations and obligations under sale agreements where Duke Energy sold former businesses to third parties, and have been valued at fair value, estimated using a probability-weighted approach.

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Pro Forma Condensed Consolidated Financial Information

The unaudited pro forma condensed consolidated financial statements are for illustrative and informational purposes only and are not intended to represent, or be indicative of, what Spectra Energy’s results of operations or financial position would have been had the separation and related transactions occurred on the dates indicated. The unaudited pro forma financial information also should not be considered representative of Spectra Energy’s future financial position or results of operations.

The unaudited pro forma condensed consolidated statements of operations for the three years ended December 31, 2005, and the nine months ended September 30, 2006 have been prepared as if the separation had occurred as of January 1, 2003. The unaudited pro forma condensed consolidated balance sheet at September 30, 2006 has been prepared as if the separation had occurred on September 30, 2006. The pro forma adjustments reflect the expected impacts of events that are directly attributable to the separation and related agreements, are expected to have a continuing impact on Spectra Energy and are factually supportable, and also include material transactions in the 2005 period.

Unaudited pro forma condensed consolidated statements of operations are presented for the years ended December 31, 2004 and 2003 as a result of Duke Capital’s distribution of the Transferred Businesses. Certain of the businesses distributed by Duke Capital are expected to qualify for discontinued operations treatment when effected. Only the pro forma adjustments related to the Transferred Businesses which are expected to qualify for discontinued operations accounting treatment on the contribution date are reflected for the years ended December 31, 2004 and 2003. Therefore, other pro forma adjustments that are presented in the 2005 and 2006 pro forma statements, related to benefits, corporate costs and other Transferred Businesses not expected to qualify for discontinued operations treatment, are not reflected for the years ended December 31, 2004 and 2003.

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Pro Forma Condensed Consolidated Statement of Operations (unaudited)

				Nine Months Ended September 30, 2006
				Pro Forma Adjustments
	Duke Capital Historical			Transferred Businesses - Discontinued Operations (a)			Transferred Businesses - Other					Sub- total			Other					Spectra Energy Pro Forma
				(in millions, except per share amounts)
Operating revenues	$	4,511		$	(1,318	)	$	(22	)	(b	)	$	3,350		$	—				$	3,350
								179		(c	)
Operating expenses
Natural gas and petroleum products purchased		1,258			(259	)		18		(c	)		1,017			—					1,017
Depreciation and amortization		436			(67	)		(8	)	(b	)		361			—					361
Operation, maintenance and other		1,676			(646	)		(42	)	(b	)		1,003			12		(d	)		997
								15		(c	)					(18	)	(e	)
Gains on sales of investments in commercial and multi-family real estate		201			(201	)		—					—			—					—
Gains (losses) on sales of other assets, net		276			(244	)		—					32			—					32
Operating income		1,618			(791	)		174					1,001			6					1,007
Equity in earnings of unconsolidated affiliates		551			(71	)		—					480			—					480
Gains (losses) on sales and impairments of equity method investments		(20	)		20			—					—			—					—
Other income and expenses, net		138			71			(83	)	(b	)		(7	)		—					(7	)
								(133	)	(c	)
Interest expense		542			(85	)		3		(b	)		460			—					460
Minority interest expense		50			(17	)		—					33			—					33
Earnings from continuing operations before income taxes		1,695			(669	)		(45	)				981			6					987
Income tax expense (benefit) from continuing operations		616			(247	)		(21	)	(b	)		348			2					350
Income from continuing operations	$	1,079		$	(422	)	$	(24	)			$	633		$	4				$	637
Pro forma income from continuing operations per share
Basic (f)																				$	1.11
Diluted (g)																					1.11

(a) Reflects the Duke Capital distribution of certain of the Transferred Businesses to Duke Energy, expected to occur in connection with the separation. The adjustments represent the removal of the revenues, expenses and other income (loss) impacts of these operations. The business transfers reflected in this column are currently expected to meet the requirements for discontinued operations of Duke Capital at the distribution date.

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(b) Reflects the Duke Capital distribution of certain of the Transferred Businesses to Duke Energy, expected to occur in connection with the separation. The transfers reflected in this column primarily relate to Duke Energy Business Services (DEBS), which provides corporate services to Duke Energy affiliates, and certain of the captive insurance companies of Duke Energy. These operations are currently not expected to qualify for discontinued operations treatment because Spectra Energy is expected to create similar corporate functions after the separation. These adjustments represent the removal of the revenues, expenses and other income (loss) impacts of these operations, but do not include the removal of the corporate costs of DEBS that have been historically associated with the Spectra Energy operations. Therefore, the resulting pro forma operating costs for Spectra Energy above include these historical corporate costs in the 2006 period. See further discussion below regarding Spectra Energy’s expected operating costs.

(c) Reflects the reclassification of sales, purchases and other intercompany transactions between Spectra Energy subsidiaries and Transferred Businesses, from related party transactions that previously eliminated in Duke Capital’s historical financial statements to third-party transactions that would not have been eliminated in Spectra Energy’s pro forma financial statements.

(d) Reflects an increase of pension, other post retirement and other benefit expenses resulting from the IRS requirements governing the allocation of plan assets and liabilities associated with the current and former employees associated with Spectra Energy’s operations.

(e) Reflects the removal of non-recurring transaction costs related to the separation of Spectra Energy. Additional estimated transaction costs totaling approximately $30 million in the three months remaining in 2006 and $50 million in the year ending December 31, 2007 are expected to be incurred and recorded in Duke Capital’s consolidated results of operations.

(f) The number of shares used to compute pro forma basic income from continuing operations per share is 573 million, which is the weighted average number of shares of Spectra Energy’s common stock that would have been outstanding during this period, based on a distribution ratio of 0.5 Spectra Energy shares of common stock for each Duke Energy share of common stock outstanding, plus approximately 2 million shares expected to be issued on the distribution date to holders of certain convertible senior notes of Duke Energy.

(g) The number of shares used to compute pro forma diluted income from continuing operations per share is 575 million based on the weighted average number of shares of Spectra Energy’s common stock that would have been outstanding during this period, which is the 573 million shares utilized in the basic per share calculation plus 2 million shares estimated dilution that would have occurred if securities or other agreements to issue common stock, such as stock options, stock-based performance unit awards and phantom stock awards, were exercised or converted into Spectra Energy common stock at the distribution ratio.

Amounts reported in this pro forma condensed consolidated statement of operations for the nine months ended September 30, 2006, are not necessarily indicative of amounts expected for annual periods due to the effects of seasonal temperature variations on energy consumption, especially for the distribution operations of Union Gas which earns a significant portion of its earnings in the first half of any annual period, changes in mark-to-market valuations, changing commodity prices and other factors.

As a result of the separation from Duke Energy, Spectra Energy will staff various corporate and other support functions, such as treasury, cash management, payroll, accounts payable, information technology, human resources, and legal and compliance that will be required to operate as a stand-alone, public company. Primarily during the first year following the separation date, it is expected that Duke Energy will provide certain transition services to Spectra Energy until such time as Spectra Energy can create all of the necessary stand-alone functions. The Duke Energy corporate costs included in Spectra Energy’s pro forma operating costs will be replaced by Spectra Energy’s independent operating costs, including the new corporate functions, and will also include transition service fees paid to Duke Energy pursuant to the transition service arrangements that are expected to occur primarily in 2007. Future corporate costs of Spectra Energy are not expected to exceed the historical level of such costs included in the pro forma financial statements.

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Pro Forma Condensed Consolidated Statement of Operations (unaudited)

	Year Ended December 31, 2005
			Pro Forma Adjustments
	Duke Capital Historical		Transferred Businesses - Discontinued Operations (a)			Transferred Businesses - Other				Sub- total			DEFS/TEPPCO Dispositions (d)			Other			Spectra Energy Pro Forma
	(in millions, except per share amounts)
Operating revenues	$	11,349	$	(2,079	)	$	(117)	(b	)	$	9,418		$	(5,286	)	$	—		$	4,132
							265	(c	)
Operating expenses
Natural gas and petroleum products purchased		6,290		(505	)		36	(c	)		5,821			(4,518	)		—			1,303
Depreciation and amortization		691		(79	)		(11)	(b	)		601			(143	)		—			458
Operation, maintenance and other		2,738		(1,028	)		(205)	(b	)		1,543			(427	)		1	6 (e)		1,132
							38	(c	)
Gains on sales of investments in commercial and multi-family real estate		191		(191	)		—				—			—			—			—
Gains (losses) on sales of other assets, net		527		67			(4)	(b	)		590			(579	)		—			11
Operating income		2,348		(591	)		286				2,043			(777	)		(16	)		1,250
Equity in earnings of unconsolidated affiliates		479		(124	)		—				355			200			—			555
Gains (losses) on sales and impairments of equity method investments		1,225		20			—				1,245			(1,243	)		—			2
Other income and expenses, net		149		68			(79)	(b	)		(15	)		(291	)		—			(306	)
							(153)	(c	)
Interest expense		771		(86	)		3	(b	)		688			(81	)		—			607
Minority interest expense		538		(27	)		—				511			(479	)		—			32
Earnings (loss) from continuing operations before income taxes		2,892		(514	)		51				2,429			(1,551	)		(16	)		862
Income tax expense (benefit) from continuing operations		1,212		(307	)		27	(b	)		936			(570	)		(6	) (f)		360
							4	(c	)
Income from continuing operations	$	1,680	$	(207	)	$	20			$	1,493		$	(981	)	$	(10	)	$	502
Pro forma income from continuing operations per share
Basic (g)																			$	1.07
Diluted (h)																				1.07

(a) Reflects the Duke Capital distribution of certain of the Transferred Businesses to Duke Energy, expected to occur in connection with the separation. The above adjustments represent the removal of the revenues, expenses and other income

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(loss) impacts of these operations. The business transfers reflected in this column are expected to meet the requirements for discontinued operations of Duke Capital at the distribution date.

(b) Reflects the Duke Capital distribution of certain of the Transferred Businesses to Duke Energy, expected to occur in connection with the separation. The transfers reflected in this column primarily relate to Duke Energy Business Services (DEBS), which provides corporate services to Duke Energy affiliates, and certain of the captive insurance companies of Duke Energy. These operations are currently not expected to qualify for discontinued operations treatment because Spectra Energy is expected to create similar corporate functions after the separation. These adjustments represent the removal of the revenues, expenses and other income (loss) impacts of these operations, but do not include the removal of the corporate costs of DEBS that have been historically associated with the Spectra Energy operations. Therefore, the resulting pro forma operating costs for Spectra Energy above include these historical corporate costs in the 2005 period. See further discussion below regarding Spectra Energy’s expected operating costs.

(c) Reflects the reclassification of sales, purchases and other intercompany transactions between Spectra Energy subsidiaries and Transferred Businesses, from related party transactions that previously eliminated in Duke Capital’s historical financial statements to third-party transactions that would not have been eliminated in Spectra Energy’s pro forma financial statements.

(d) This column adjusts for the impacts of material transactions in the 2005 period. Adjustments include the removal of $290 million of equity in earnings of unconsolidated affiliates and $1,243 million of gain on sales and impairments of equity method investments resulting from the February 2005 disposition of the equity investment in TEPPCO. The remaining pro forma adjustments in this column reflect the deconsolidation of DEFS, associated removal of the gain on sale, and reclassification of certain discontinued hedge losses from Operating revenues and reclassification of hedge impairment from Impairment and other charges, to Other income and expenses, net, all resulting from the July 2005 disposition of the 19.7% interest in DEFS to ConocoPhillips, the co-equity owner in DEFS, to reduce the ownership interest in DEFS from 69.7% to 50%. (See Notes 2 and 7, of the Duke Capital Notes to Consolidated Financial Statements, “Acquisitions and Dispositions” and “Risk Management and Hedging Activities, Credit Risk, and Financial Instruments”).

(e) Reflects an increase of pension, other post retirement and other benefit expenses resulting from the IRS requirements governing the allocation of plan assets and liabilities associated with the current and former employees associated with Spectra Energy’s operations.

(f) Reflects the tax effect of the benefit expense pro forma adjustment on Spectra Energy’s earnings before income taxes based on the estimated weighted average statutory rates for all jurisdictions that would have applied during this period.

(g) The number of shares used to compute pro forma basic income from continuing operations per share is 469 million, which is the weighted average number of shares of Spectra Energy’s common stock that would have been outstanding during this period, based on a distribution ratio of 0.5 Spectra Energy shares of common stock for each Duke Energy share of common stock outstanding, plus approximately 2 million shares expected to be issued on the distribution date to holders of certain convertible senior notes of Duke Energy.

(h) The number of shares used to compute pro forma diluted income from continuing operations per share is 471 million, based on the weighted average number of shares of Spectra Energy’s common stock that would have been outstanding during this period, which is the 469 million shares utilized in the basic per share calculation plus 2 million shares estimated dilution that would have occurred if securities or other agreements to issue common stock, such as stock options, stock-based performance unit awards and phantom stock awards, were exercised or converted into Spectra Energy common stock at the distribution ratio.

As a result of the separation from Duke Energy, Spectra Energy will staff various corporate and other support functions, such as treasury, cash management, payroll, accounts payable, information technology, human resources, that will be required to operate as a stand-alone, public company. Primarily during the first year following the separation date, it is expected that Duke Energy will provide certain transition services to Spectra Energy until such time as Spectra Energy can create all of the necessary stand-alone functions. The Duke Energy corporate costs included in Spectra Energy’s pro forma operating costs will be replaced by Spectra Energy’s independent operating costs, including the new corporate functions, and will also include transition service fees paid to Duke Energy pursuant to the transition service arrangements that are expected to occur primarily in 2007. Future corporate costs of Spectra Energy are not expected to exceed the historical level of such costs included in the pro forma financial statements.

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Pro Forma Condensed Consolidated Statement of Operations (unaudited)

	Year Ended December 31, 2004
				Pro Forma Adjustments
	Duke Capital Historical			Transferred Businesses - Discontinued Operations (a)			Spectra Energy Pro Forma
	(in millions, except per share amounts)
Operating revenues	$	15,463		$	(2,208	)	$	13,255
Operating expenses
Natural gas and petroleum products purchased		10,156			(983	)		9,173
Depreciation and amortization		811			(86	)		725
Operation, maintenance and other		2,698			(1,042	)		1,656
Gains on sales of investments in commercial and multi-family real estate		192			(192	)		—
Gains (losses) on sales of other assets, net		(408	)		419			11
Operating income		1,582			130			1,712
Equity in earnings of unconsolidated affiliates		154			(66	)		88
Gains (losses) on sales and impairments of equity method investments		(3	)		(3	)		(6	)
Other income and expenses, net		292			(180	)		112
Interest expense		980			(236	)		744
Minority interest expense		200			14			214
Earnings from continuing operations before income taxes		845			103			948
Income tax expense (benefit) from continuing operations		1,341	(b)		88			1,429	(b)
(Loss) Income from continuing operations	$	(496	)	$	15		$	(481	)
Pro forma loss from continuing operations per share
Basic (c)							$	(1.03	)
Diluted (d)								(1.03	)

(a) Reflects the Duke Capital distribution of certain of the Transferred Businesses to Duke Energy, expected to occur in connection with the separation. The adjustments represent the removal of the revenues, expenses and other income (loss) impacts of these operations. The business transfers reflected in this column are expected to meet the requirements for discontinued operations of Duke Capital at the distribution date.

(b) Amount includes approximately $1,030 million related to the change in tax status of certain subsidiaries of Duke Capital (see Note 5 of the Duke Capital Notes to Consolidated Financial Statements, “Income Taxes”).

(c) The number of shares used to compute pro forma basic income from continuing operations per share is 466 million, which is the weighted average number of shares of Spectra Energy’s common stock that would have been outstanding during this period, based on a distribution ratio of 0.5 Spectra Energy shares of common stock for each Duke Energy share of common stock outstanding.

(d) The number of shares used to compute pro forma diluted income from continuing operations per share is 467 million, based on the weighted average number of shares of Spectra Energy’s common stock that would have been outstanding during this period, which is the 466 million shares utilized in the basic per share calculation plus 1 million shares estimated dilution that would have occurred if securities or other agreements to issue common stock, such as stock options, stock-based performance unit awards and phantom stock awards, were exercised or converted into Spectra Energy common stock at the distribution ratio.

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Pro Forma Condensed Consolidated Statement of Operations (unaudited)

	Year Ended December 31, 2003
				Pro Forma Adjustments
	Duke Capital Historical			Transferred Businesses - Discontinued Operations (a)			Spectra Energy Pro Forma
	(in millions, except per share amounts)
Operating revenues	$	13,217		$	(2,433	)	$	10,784
Operating expenses
Natural gas and petroleum products purchased		8,476			(1,298	)		7,178
Depreciation and amortization		864			(174	)		690
Operation, maintenance and other		4,090			(2,486	)		1,604
Gains on sales of investments in commercial and multi-family real estate		84			(85	)		(1	)
Gains (losses) on sales of other assets, net		(185	)		188			3
Operating income		(314	)		1,628			1,314
Equity in earnings (loss) of unconsolidated affiliates		123			(35	)		88
Gains (losses) on sales and impairments of equity method investments		279			(178	)		101
Other income and expenses, net		216			(185	)		31
Interest expense		1,020			(214	)		806
Minority interest expense		41			64			105
Earnings (loss) from continuing operations before income taxes		(757	)		1,380			623
Income tax expense (benefit) from continuing operations		(314	)		523			209
(Loss) Income from continuing operations	$	(443	)	$	857		$	414
Pro forma income from continuing operations per share
Basic (b)							$	0.92
Diluted (c)								0.91

(a) Reflects the Duke Capital distribution of certain of the Transferred Businesses to Duke Energy, expected to occur in connection with the separation. The above adjustments represent the removal of the revenues, expenses and other income (loss) impacts of these operations. The business transfers reflected in this column are expected to meet the requirements for discontinued operations of Duke Capital at the distribution date.

(b) The number of shares used to compute pro forma basic income from continuing operations per share is 452 million, which is the weighted average number of shares of Spectra Energy’s common stock that would have been outstanding during this period, based on a distribution ratio of 0.5 Spectra Energy shares of common stock for each Duke Energy share of common stock outstanding.

(c) The number of shares used to compute pro forma diluted income from continuing operations per share is 453 million based on the weighted average number of shares of Spectra Energy’s common stock that would have been outstanding during this period which is the 452 million shares utilized in the basic per share calculation plus 1 million shares estimated dilution that would have occurred if securities or other agreements to issue common stock, such as stock options, stock-based performance unit awards and phantom stock awards, were exercised or converted into Spectra Energy common stock at the distribution ratio.

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Pro Forma Condensed Consolidated Balance Sheet (unaudited)

	September 30, 2006
			Pro Forma Adjustments
	Duke Capital Historical		Transferred Businesses (a)		Sub- total		Other				Spectra Energy Pro Forma
			(in millions)
Current assets	$	2,618	$	(770)	$	1,848	$	3		(b)	$	1,840
								(11	)	(c)
Investments and other assets		2,926		(940)		1,986		186		(b)		2,328
								156		(c)
Goodwill		3,900		(267)		3,633		—				3,633
Assets held for sale		157		(157)		—		—				—
Property, plant and equipment
Cost		18,688		(2,978)		15,710		—				15,710
Less accumulated depreciation and amortization		3,936		(728)		3,208		—				3,208
Net property, plant and equipment		14,752		(2,250)		12,502		—				12,502
Other		1,138		1		1,139		—				1,139
Total Assets	$	25,491	$	(4,383)	$	21,108	$	334			$	21,442
Current liabilities	$	2,787	$	(757)	$	2,030	$	22		(c)	$	2,052
Long-term debt		8,778		(821)		7,957		—				7,957
Deferred income taxes		3,102		(178)		2,924		19		(b)		2,918
								(19	)	(c)
								(6	)	(d)
Other liabilities		1,360		(231)		1,129		136		(b)		1,396
								114		(c)
								17		(d)
Minority interests		792		(217)		575		—				575
Business equity		7,582		(2,408)		5,174		34		(b)		5,225
								28		(c)
								(11)		(d)
Accumulated other comprehensive income		1,090		229		1,319		—				1,319
Total Liabilities and Business Equity	$	25,491	$	(4,383)	$	21,108	$	334			$	21,442

(a) Reflects the Duke Capital distribution of all Transferred Businesses to Duke Energy expected to occur in connection with the separation. The adjustments represent the removal of the assets, liabilities and business equity related to these operations.

(b) Reflects the estimated prepaid asset and accrued liabilities resulting from the transfer from Duke Energy pension post retirement and other benefit plans (previously accounted for as multi-employer benefit plans), related to current and former employees of Spectra Energy, determined in accordance with Internal Revenue Service IRC 414(l), which requires benefits after a transfer to be at least as valuable as those present prior to the transfer, as judged in the context of the asset allocation rules of ERISA 4044. The estimated total pension plan assets and associated projected benefit obligations that would have transferred to Spectra Energy if the separation had occurred on September 30, 2006 are approximately $580 million and $550 million, respectively.

(c) Spectra Energy expects to provide insurance coverage primarily through a captive insurance subsidiary it will establish prior to the separation transaction. These pro forma adjustments reflect the estimated reserves associated with the transfer by Duke Energy of the insurance and reinsurance positions related to Spectra Energy operations, such as workers’ compensation, property, business interruption and general business risks and assets sufficient to cover such liabilities and meet regulatory capital requirements.

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(d) Reflects guarantees issued between entities under common control prior to the separation that, as a result of the separation, will require recognition under Financial Interpretation No. 45 “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.” These guarantees include payment, performance obligations and obligations under sale agreements where Duke Energy sold former businesses to third parties, and have been valued at fair value, estimated using a probability-weighted approach.

Supplemental Pro Forma Consolidated Financial Information

Spectra Energy management believes that the following additional disclosures related to the pro forma condensed consolidated financial information are helpful in understanding the financial statement impacts of the separation from Duke Energy. Therefore, the following supplemental notes and management discussion and analysis are being provided. The Supplemental Pro Forma Condensed Consolidated Financial Information should be read in conjunction with the Pro Forma Condensed Consolidated Financial Information for the year ended December 31, 2005 and as of and for the nine months ended September 30, 2006 as presented above.

Supplemental Note Disclosures

Pro Forma Business Segments

Spectra Energy is being formed to hold the natural gas transportation and storage, distribution, and gathering and processing businesses of Duke Energy. Duke Energy and Duke Capital have each historically reported these businesses primarily within the Natural Gas Transmission and Field Services business segments.

Based on the current expectations of Spectra Energy’s Chief Operating Decision Maker (CODM), and in accordance with SFAS No. 131 “Disclosures About Segments of an Enterprise and Related Information,” Spectra Energy expects to report financial and operating information about the following business segments on a prospective basis: Gas Transmission—U.S., Gas Distribution, Gas Transmission and Processing—Western Canada, and Field Services. This increased level of segment reporting as compared to Duke Energy and Duke Capital historically, will correspond to the expected operating and management structure of Spectra Energy prospectively. As a stand-alone business, the CODM of Spectra Energy is expected to regularly review more detailed financial information for the natural gas transportation and storage, distribution and field services businesses than has historically been the case for the CODM of Duke Energy and Duke Capital. There is expected to be no aggregation within Spectra Energy’s prospective business segments. A brief description of these prospective business segments follows:

Gas Transmission—U.S. provides transportation and storage of natural gas for customers along the East Coast of North America, and in the southeastern U.S. These operations are performed primarily by the operating units Texas Eastern Transmission, Algonquin Gas Transmission, East Tennessee Natural Gas, Maritimes & Northeast Pipeline, Gulfstream Natural Gas System (an entity owned 50% by Spectra Energy and accounted for using the equity method of accounting) and Market Hub Partners. These operations are primarily subject to the FERC’s and the U.S. Department of Transportation’s (DOT’s) rules and regulations.

Gas Distribution provides natural gas sales and distribution service to retail customers in Ontario, Canada, as well as transportation and storage services to energy market participants in that area. These services are provided by Union Gas Limited, and are subject to the rules and regulations of the Ontario Energy Board (OEB).

Gas Transmission & Processing—Western Canada, provides transportation of natural gas, natural gas gathering and processing services, and natural gas liquid, or “NGL,” marketing to customers in Western Canada. These operations conduct business primarily through the BC Pipeline and Field Services divisions of Westcoast Energy, Inc. (Westcoast), the Duke Energy Income Fund in which Spectra Energy owns approximately 46%, and the Empress System. Westcoast’s BC Pipeline and Field Services are subject to the rules and regulations of Canada’s National Energy Board (NEB).

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The Field Services segment of Spectra Energy is the same as Duke Energy’s and Duke Capital’s historical Field Services segment. Field Services gathers, compresses, treats, processes, transports, trades and markets, and stores natural gas; and fractionates, transports, trades and markets, and stores NGLs. It conducts operations primarily through DEFS, which is owned 50 percent by ConocoPhillips and 50 percent by Spectra Energy. Field Services gathers raw natural gas through gathering systems located in seven major natural gas producing regions in the U.S.: Permian Basin, Mid-Continent, ArklaTex, Gulf Coast, South, Central and the Rocky Mountains.

The remainder of Spectra Energy’s operations are expected to be presented as Other. While it is not considered a business segment, Other primarily includes, for the pro forma periods presented, certain corporate costs from Duke Energy that are not allocated to the Spectra Energy business segments, certain discontinued hedges described in the audited consolidated financial statements of Duke Capital and other businesses.

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

Pro forma segment data provided below has been prepared on the same basis as the pro forma condensed consolidated statements of operations and balance sheet presented above.

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Pro Forma Business Segment Data (unaudited) ^(a)

	Unaffiliated Revenues		Intersegment Revenues			Total Revenues			Segment EBIT/ Consolidated Earnings from Continuing Operations before Income Taxes			Depreciation and Amortization		Capital and Investment Expenditures
	(in millions)
Nine Months Ended September 30, 2006
Gas Transmission—U.S.	$	1,158	$	(23	)	$	1,135		$	642		$	152	$	203
Gas Distribution		1,306		—			1,306			181			108		209
Gas Transmission & Processing—Western Canada		885		(2	)		883			275			101		91
Field Services (b)		—		—			—			450			—		—
Total pro forma reportable segments		3,349		(25	)		3,324			1,548			361		503
Other		1		34			35			(116	)		—		—
Eliminations		0		(9	)		(9	)		—			—		—
Interest expense		—		—			—			(460	)		—		—
Interest income and other		—		—			—			15			—		—
Pro Forma Total	$	3,350	$	—		$	3,350		$	987		$	361	$	503
Year Ended December 31, 2005
Gas Transmission—U.S.	$	1,461	$	(8	)	$	1,453		$	822		$	207	$	387
Gas Distribution		1,725		—			1,725			277			129		172
Gas Transmission & Processing—Western Canada		874		—			874			252			120		371
Field Services (b)		—		—			—			480			—		—
Total pro forma reportable segments		4,060		(8	)		4,052			1,831			456		930
Other		72		9			81			(397	)		2		—
Eliminations		—		(1	)		(1	)		—			—		—
Interest expense		—		—			—			(607	)		—		—
Interest income and other		—		—			—			35			—		—
Pro Forma Total	$	4,132	$	—		$	4,132		$	862		$	458	$	930

(a) Pro forma segment results exclude results of entities classified as discontinued operations.

(b) In July 2005, Duke Energy reduced its ownership interest in DEFS from 69.7% to 50%. Pro forma Field Services segment data reflects DEFS as an equity method investment for these pro forma periods presented.

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Pro Forma Segment Assets (unaudited)

	September 30, 2006
	(in millions)
Gas Transmission—U.S.	$	7,720
Gas Distribution		4,303
Gas Transmission & Processing—Western Canada		4,096
Field Services		1,445
Total reportable segments		17,564
Other		4,216
Eliminations		(338	)
Total pro forma consolidated	$	21,442

Pro Forma Geographic Data (unaudited)

	U.S.		Canada		Pro Forma Consolidated
	(in millions)
2005
Consolidated revenues	$	1,527	$	2,605	$	4,132

There have been no changes in operations in 2006 that would significantly affect the geographic allocation of Spectra Energy’s revenues.

Pro Forma Revenue Presentation

In financial statement filings after the distribution date, Spectra Energy expects to report operating revenues in categories that differ from the historical presentation in the audited financial statements of Duke Capital. These categories align with management’s expected view of the Spectra Energy business and the new segments.

Pro forma consolidated revenues for historical periods, presented based on the expected reporting classification in future filings, are as follows:

Pro Forma Operating Revenues (unaudited)

	Nine Months Ended September 30, 2006		Year Ended December 31, 2005
	(in millions)
Sales of natural gas and petroleum products	$	376	$	254
Transportation and storage of natural gas		1,522		1,980
Distribution of natural gas		1,166		1,553
Other		286		345
Total pro forma operating revenues	$	3,350	$	4,132

Pro Forma Guarantees

As disclosed in Note 17, “Guarantees and Indemnifications,” of Duke Capital’s Notes to Consolidated Financial Statements, Duke Capital has historically provided support in the form of financial and/or performance guarantees to various Duke Energy operating entities, primarily for business units other than the natural gas segments of Duke Energy. Duke Capital and Duke Energy are pursuing assignment of these guarantees to Duke Energy. To the extent these guarantees and indemnifications are not assigned by Duke Capital to Duke Energy

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prior to the separation date, Spectra Energy will assume primary liability on any remaining such support. It is likely that certain of these guarantees and indemnifications will result in liabilities recorded by Spectra Energy representing the estimated fair values of those obligations, and a pro forma adjustment of $11 million for the estimated fair values has been made in the pro forma condensed consolidated balance sheet.

Related Party Transactions

As a result of the separation of Spectra Energy, Spectra Energy will become a public company, independent of Duke Energy. Therefore, any continuing services or contractual arrangements between Spectra Energy and its subsidiaries, and Duke Energy companies, will not be considered related party transactions subsequent to the separation. It is expected that Duke Energy will continue to provide certain “transition” services to Spectra Energy until such time as Spectra Energy can create the necessary stand-alone functions and systems. For purposes of governing certain of the ongoing relationships between Spectra Energy and Duke Energy at and after the proposed separation and to provide for an orderly transition, Spectra Energy and Duke Energy have entered into various agreements related to such services and relationships. As part of certain tax agreements, if the separation transaction fails to qualify as a tax-free distribution for U.S. federal income tax purposes, Spectra Energy may be required to indemnify Duke Energy for portions of any tax liability created.

Contingent Liabilities

In conjunction with the separation, Spectra Energy will retain responsibilities for the outstanding litigation associated with Sonatrach/Sonatrading and Citrus Trading Corporation both of which are disclosed in the section entitled “Legal Proceedings.”

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Management’s Discussion And Analysis Of Pro Forma Results Of

Operations And Financial Condition

Spectra Energy’s Strategy

Spectra Energy operates today within the business unit structure of Duke Energy, as the Natural Gas Transmission and Field Services segments of Duke Energy. The business units of Duke Energy, including the Natural Gas Transmission, Field Services, Franchised Electric and International operations, are generally managed autonomous from one another. Therefore, the primary business operations of Spectra Energy are not expected to change significantly from the current operating environment. There are certain shared functions among Duke Energy units, including shared corporate and business services, as well as shared strategic initiatives and capital resource allocations. The scope of Spectra Energy’s corporate management will increase as a result of the separation from Duke Energy because Spectra Energy will be creating new governance and business support functions—previously provided by Duke Energy—that are required in order to operate as a stand-alone, public company.

After the separation from Duke Energy, Spectra Energy expects to benefit from a sharper focus on core business and growth opportunities, with greater flexibility in accessing capital markets and responding to changes in the industry.

Spectra Energy’s primary business objective is to provide value added, reliable and safe services to customers, which Spectra Energy believes will create opportunities to deliver increased dividends per share and value to shareholders. Spectra Energy intends to accomplish this objective by executing the following overall business strategies:

• capitalize on the size and attributes of existing assets;

• pursue organic growth, expansion projects, strategic acquisitions and other business opportunities arising in Spectra Energy’s market and supply areas;

• continue to develop operational efficiencies among existing assets;

• utilize tax-efficient financial structures, such as MLPs and Canadian Income Trusts, to improve Spectra Energy’s cost of capital, optimize returns on assets and finance portfolio growth;

• continue to focus on operational excellence including safety, reliability, compliance and stringent cost management; and

• retain and enhance customer and other stakeholder relationships.

Through the continued execution of these strategies, Spectra Energy expects to grow and strengthen the overall business, capture new growth opportunities and deliver value to stakeholders.

Economic Factors for Spectra Energy’s Business

Spectra Energy’s regulated businesses are generally economically stable and are not significantly impacted in the long-term by seasonal temperature variations and changing commodity prices. However, all of Spectra Energy’s businesses can be negatively affected by sustained downturns or sluggishness in the economy, including reductions in demand and low market prices for natural gas and NGLs, all of which are beyond Spectra Energy’s control, and could impair Spectra Energy’s ability to meet its long-term goals.

Subsequent to the deconsolidation of DEFS, substantially all of Spectra Energy’s revenues are based on regulated tariff rates, which include the recovery of certain fuel costs. However, lower overall economic output would cause Spectra Energy to experience a decline in the volume of natural gas transported and distributed or gathered and processed at its plants, resulting in lower earnings and cash flows. This decline would primarily affect distribution revenues in the short-term. Processing revenues are also impacted by volumes of natural gas

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made available to the system, which is primarily driven by levels of natural gas drilling activity. Transmission revenues could be impacted by long-term economic declines that could result in the non-renewal of long-term contracts at time of expiration. Spectra Energy’s pipeline transportation and storage customers continue to renew most contracts as they expire.

Spectra Energy’s key markets—the Northeast United States, Florida, Ontario and the Pacific Northwest—are projected to continue exhibiting natural gas demand growth averaging from 2% to 3% annually over the 2003 to 2020 time period. This demand growth is primarily driven by the natural gas-fired electric generation sector. The natural gas industry is currently experiencing a significant shift in the sources of supply, and this dramatic change is affecting Spectra Energy’s growth strategies. Traditionally, supply to Spectra Energy’s markets has come from the Gulf Coast region, onshore and offshore, as well as from fields in Western Canada and Eastern Canada. The national supply profile is shifting to new, and, in some cases, non-conventional sources of gas from basins in the Rockies, Mid-Continent and East Texas. In addition, the natural gas supply outlook will be shaped by new liquefied natural gas or “LNG” re-gasification facilities being built. LNG will clearly be an important new source of supply, but the timing and extent of incremental supply from LNG is yet to be determined and, at present, LNG remains a small percentage of the overall supply to the markets Spectra Energy serves. These supply shifts are shaping the growth strategies that Spectra Energy will pursue, and therefore, will affect the nature of the projects anticipated in the capital and investment expenditure increases discussed below in “—Liquidity and Capital Resources.”

Spectra Energy’s businesses in the U.S. are subject to regulations on the federal and state level. Regulations, applicable to the gas transmission and storage industry, have a significant impact on the nature of the businesses and the manner in which they operate. Changes to regulations are ongoing and Spectra Energy cannot predict the future course of changes in the regulatory environment or the ultimate effect that any future changes will have on its business. Additionally, Spectra Energy’s investments and projects located in Canada expose Spectra Energy to risks related to Canadian laws, taxes, economic conditions, fluctuations in currency rates, political conditions and policies of the Canadian government. From 2002 through September 2006, the Canadian dollar has strengthened significantly compared to the U.S. dollar, which has favorably impacted the earnings of Spectra Energy during these periods as further described in the Results of Operations discussion in Duke Capital’s Management’s Discussion and Analysis of Results of Operations and Financial Condition. Changes in this exchange rate or other of these factors are difficult to predict and may impact Spectra Energy’s future results.

Certain of Spectra Energy’s earnings are impacted by fluctuations in commodity prices, especially the earnings of Spectra Energy’s DEFS investment and the processing businesses in Canada. Although natural gas and NGL commodity prices have increased in 2005 and 2006, this trend in commodity prices may not be indicative of future prices. Currently, Duke Capital does not enter into derivative instruments to hedge the expected exposures associated with its processing business in Canada. To mitigate the risks associated with its investments with DEFS, Duke Capital has historically entered into derivative instruments to hedge a portion of these expected exposures. Management evaluates, on an ongoing basis, the level of such hedging and currently does not expect to enter into new hedge positions upon expiration in 2006 of the positions associated with the DEFS investment earnings.

For periods after the separation from Duke Energy, Spectra Energy expects the effective income tax rates applicable to Spectra Energy’s earnings to approximate 30-35% on an annual basis, taking into consideration the United States and Canadian tax jurisdictions applicable to Spectra Energy’s operations.

Subsequent to the proposed distribution by Duke Energy, Spectra Energy expects to rely on access to both short-term money markets and longer-term capital markets as a source of liquidity for capital requirements not met by cash flow from operations. An inability to access capital at competitive rates could adversely affect Spectra Energy’s ability to implement its strategy. Market disruptions, or a downgrade of the expected credit rating of Spectra Energy immediately following the separation or to Spectra Energy’s subsidiaries’ credit ratings, immediately following the separation may increase its cost of borrowing or adversely affect its ability to access one or more sources of liquidity.

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Overview of Results

The following significant factors affected the pro forma consolidated results of operations for the nine and twelve months ended September 30, 2006 and December 31, 2005:

• Earnings in the nine months ended September 30 of each year benefit from the seasonal earnings by the Gas Distribution segment that results from the inclusion of the January through March winter months.

• Operations in the United States and Western Canada benefited during the first nine months of 2006 from higher processing revenues and NGL marketing activities, including results from the Empress operations acquired in August 2005.

• During the twelve months ended December 31, 2005, the Field Services segment, on a pro forma basis, included the negative effects from the hedge impairment and hedge-related losses recognized as a result of the sale of a portion of Duke Energy’s interest in DEFS and includes the favorable effect of commodity price increases. See Note 12, “Risk Management Instruments” in the Duke Capital, LLC interim Notes to Consolidated Financial Statements and Note 7, “Risk Management and Hedging Activities, Credit Risk and Financial Instruments” in the Duke Capital, LLC annual Notes to Consolidated Financial Statements that are both included in this information statement.

Management evaluates segment performance primarily based on earnings before interest and taxes from continuing operations, after deducting minority interest expense related to those profits (EBIT). On a segment basis, EBIT 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. Management considers segment EBIT to be a good indicator of each segment’s operating performance from its continuing operations, as it represents the results of Spectra Energy’s ownership interest in operations without regard to financing methods or capital structures.

Spectra Energy’s segment EBIT may not be comparable to a similarly titled measure of another company because other entities may not calculate EBIT in the same manner. Segment EBIT is summarized in the following table.

Pro Forma Segment Results (unaudited)

	Nine Months Ended September 30, 2006			Year Ended December 31, 2005
	(in millions)
Gas Transmission—U.S.	$	642		$	822
Gas Distribution		181			277
Gas Transmission & Processing—
Western Canada		275			252
Field Services (a)		450			480
Total reportable segment EBIT		1,548			1,831
Other		(116	)		(397	)
Pro forma total reportable segment EBIT and other		1,432			1,434
Interest expense		460			607
Interest income and other (b)		15			35
Pro forma consolidated earnings from continuing operations before income taxes	$	987		$	862

(a) In July 2005, Duke Capital reduced its ownership interest in DEFS from 69.7% to 50%. Pro forma Field Services segment data includes DEFS as an equity method investment for the pro forma periods presented above.

(b) Other includes foreign currency transaction gains and losses and additional minority interest expense not allocated to the segment results.

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Nine Months Ended September 30, 2006. Pro forma consolidated earnings from continuing operations for the nine months ended September 30, 2006 was $987 million. Significant impacts or transactions during the nine months ended September 30, 2006 are as follows:

• Gas Transmission. U.S. EBIT reflects the effects of pipeline expansion projects, processing revenues associated with pipeline transportation and a gain from a customer contract settlement, and also includes increased operation and maintenance costs from pipeline integrity work and higher insurance, benefit and other operating costs.

• Gas Distribution. EBIT was impacted negatively by warm weather, but benefited from the strengthening Canadian currency and customer growth.

• Gas Transmission & Processing—Western Canada. EBIT includes the NGL marketing activity of the Empress System acquired in August 2005, impacts of the strengthening Canadian currency and a gain resulting from Duke Energy Income Fund’s (“Income Fund”) issuance of additional units of the Canadian income trust fund.

• Field Services. EBIT during this period is primarily composed of equity in earnings of DEFS and includes the favorable effects of commodity price increases.

Year Ended December 31, 2005. Pro forma consolidated earnings from continuing operations for 2005 was $862 million. Significant impacts or transactions during the year ended December 31, 2005 are as follows:

• Gas Transmission—U.S. EBIT reflects the pipeline expansion projects and processing revenues associated with pipeline transportation.

• Gas Distribution and Gas Transmission & Processing—Western Canada. EBIT benefited from favorable foreign exchange rate impacts from the strengthening Canadian currency.

• Field Services. EBIT during this period is primarily composed of pro forma equity in earnings of DEFS, and includes the favorable effects of commodity price increases.

Though not an expected prospective reportable segment, Other’s EBIT is primarily impacted in these historical periods by the negative effects from the hedge impairments and hedge-related losses on the Field Services hedges assuming deconsolidation as of January 1, 2005 and corporate governance costs.

Matters Impacting Future Segment Results

Gas Transmission—U.S. plans to continue earnings growth through capital efficient projects, such as transportation and storage expansion to support a two-pronged “supply push” / “market pull” strategy, as well as continued focus on optimizing the performance of the existing operations through organizational efficiencies and cost control. Future earnings growth will be dependent on the success of expansion plans in both the market and supply areas of the pipeline network, the ability to continue renewing service contracts and continued regulatory stability. Commodity prices will continue to impact processing revenues that are associated with transportation services.

Gas Distribution plans to continue earnings growth through capital efficient “market pull” expansion projects of transportation and storage capacity to support the projected demand growth in the Ontario market. The projected natural gas demand in Ontario benefits the continued retail distribution growth as well. Gas Distribution’s annual earnings are impacted significantly by weather during the winter heating season. In addition, earnings over the last several years have benefited from the strengthening Canadian dollar and would be impacted by future changes in the US/Canadian dollar exchange rates. As with all of Spectra Energy’s regulated entities, regulatory changes may impact future earnings.

Gas Transmission & Processing—Western Canada plans to continue earnings growth through capital efficient “supply push” projects, primarily associated with gathering and processing expansion to support the continued increase in drilling activity in northern British Columbia. This segment’s earnings will also continue to improve through optimizing the performance of our existing system and through organizational efficiencies and

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cost control, and as with Gas Distribution, is impacted by the strength of the Canadian dollar. In addition, future earnings of the transportation services will be impacted by the ability to renew service contracts and regulatory stability. Earnings from processing services will be impacted by the effects of commodity prices and the ability to access additional natural gas reserves. On October 31, 2006, the Minister of Finance in Canada announced proposed changes to the income tax treatment of “flow-through entities”, including income trusts, such as the Income Fund. If the proposal is implemented in its current form, income trusts will be subject to tax at corporate rates on the taxable portion of their distributions which would apply beginning with the 2011 taxation year of the Income Fund. Duke Capital will monitor the impact of these proposed changes on the Income Fund and on the future use of such entities, but does not currently expect significant impacts to Spectra Energy as a result of these changes.

Field Services, through its 50 percent investment in DEFS, has developed significant size and scope in natural gas gathering, processing and NGL marketing and plans to focus on operational excellence and organic growth. DEFS’ revenues and expenses are significantly dependent on prevailing commodity prices for NGLs and natural gas, and past and current trends in price changes of these commodities may not be indicative of future trends. DEFS anticipates that current price levels will continue to stimulate drilling and help to offset declining raw natural gas supplies. Although the prevailing price of natural gas has less short term significance to its operating results than the price of NGLs, in the long term, the growth and sustainability of DEFS’ business depends on natural gas prices being at levels sufficient to provide incentives and capital for producers to increase natural gas exploration and production.

Future equity in earnings of DEFS will continue to be sensitive to commodity prices that have historically been cyclical and volatile. DEFS’ operating and general and administrative costs increased in 2005, primarily due to asset integrity work and financial process improvement costs incurred during the year. There are many important factors that could cause actual results to differ materially from the expectations expressed. Management can provide no assurances regarding the impact of future commodity prices or drilling activity.

Pro Forma Liquidity and Capital Resources

Spectra Energy will rely primarily upon cash flows from operations to fund its liquidity and capital requirements for 2006. Spectra Energy will have access to four revolving credit facilities available in two currencies upon separation from Duke Energy, with total combined capacities of $950 million and CAN $600 million. These facilities will be used principally as a back-stop for commercial paper programs at Spectra Energy subsidiaries. Approximately $350 million is expected to be utilized at the time of separation as a result of the maturity of senior unsecured notes in November 2006.

Cash flows from operations are subject to a number of factors, including, but not limited to, earnings sensitivities to weather, commodity prices, and the timing of associated regulatory cost recovery approval (see “Risk Factors” for further details).

Spectra Energy projects 2006 capital and investment expenditures of approximately $950 million. Total projected capital and investment expenditures include approximately $440 million for maintenance and upgrades of existing pipelines and infrastructure to serve growth and $510 million for expansion. Projects at Gas Transmission-U.S. constitute the majority of the expansion capital expenditures planned in 2006 by Spectra Energy. As Spectra Energy executes on the strategic objectives around organic growth and expansion projects, capital and investment expenditures could increase to an average of approximately $1.5 billion per year during the period from 2007 through 2009. The timing and extent of these projects are likely to vary significantly from year-to-year, however.

Spectra Energy’s pro forma debt to capitalization ratio as of September 30, 2006 is approximately 55%, which reflects the pro forma reduction of debt by $1,060 million as a result of the distribution by Duke Capital of the Transferred Businesses. There is no incremental debt expected to be incurred as a result of the separation. In connection with the separation and distribution, Spectra Energy, believes that it will likely receive an initial

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investment-grade credit rating from external credit rating analysts. Given the expected increases in capital and investment expenditures over the next several years, capital resources will likely include additional long-term borrowings as well as the utilization of financial structures such as MLPs and Canadian Income Trusts. However, Spectra Energy expects to maintain a capital structure and liquidity profile that support an investment-grade credit rating.

Pro Forma Operating Cash Flows

Although a pro forma statement of cash flows has not been presented, management has prepared certain pro forma condensed consolidated cash flow data on a basis consistent with the supplemental pro forma financial information presented above. Unaudited pro forma net cash provided by the operating activities of Spectra Energy’s continuing operations was approximately $1.3 billion in the nine months ended September 30, 2006. Significant factors impacting the pro forma net cash provided by operating activities during the nine months ended September 30, 2006 were the favorable impacts of seasonal collections in the Gas Distribution segment that occur during the first half of the year and operating cash flows from the Empress operations acquired in the third quarter of 2005.

Duke Capital is generally responsible for the centralized cash management of its subsidiaries. On the separation date, cash held at Duke Capital will be distributed between Duke Energy and Spectra Energy based on working capital requirements determined for both Duke Energy and Spectra Energy.

Pro Forma Capital and Investment Expenditures by Business Segment (unaudited)

	Nine Months Ended September 30, 2006		Year Ended December 31, 2005
Gas Transmission—U.S.	$	203	$	324
Gas Distribution		209		172
Gas Transmission & Processing—Western Canada		91		140
Field Services		—		—
Pro forma total	$	503	$	636

Unaudited pro forma capital and investment expenditures were $503 million for the nine months ended September 30, 2006. Capital expenditures attributable to expansion were $221 million, including the expansion of the Dawn-Trafalgar transmission system by Union Gas and maintenance-related capital expenditures were $282 million.

Unaudited pro forma capital and investment expenditures were $636 million in 2005. Capital expenditures attributable to expansion were $172 million and maintenance-related capital expenditures were $464 million.

In addition to the capital and investment expenditures discussed above, unaudited pro forma investing cash flows in 2005 also included the acquisition by Gas Transmission – U.S. and Gas Transmission and Processing—Western Canada of $62 million for the purchase of an additional 50% interest in Saltville Gas Storage, LLC and related assets in Virginia, and $232 million for the Empress acquisition, respectively.

Pro Forma Quantitative and Qualitative Disclosures About Market Risk

Spectra Energy is exposed to market risks associated with commodity prices, credit exposure, interest rates and foreign currency exchange rates. As a result of Duke Capital’s transfer to Duke Energy of its ownership interests in Crescent, International Energy and other businesses not related to Duke Energy’s natural gas business, these risks are anticipated to differ from the risks at Duke Capital as described further below.

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Commodity Price Risk

Spectra Energy will continue to be exposed to the impact of market fluctuations in the prices of natural gas and NGL’s. Subsequent to Duke Capital’s transfer to Duke Energy of the Transferred Businesses, Spectra Energy will no longer be exposed to the impact of market fluctuations in electricity prices and will not have interests in proprietary trading or structured contracts.

Spectra Energy’s only material mark-to-market (MTM) derivative contracts will be the remaining undesignated contracts which expire in 2006, associated with the DEFS earnings (see Note 7, “Risk Management and Hedging Activities, Credit Risk, and Financial Instruments,” of Duke Capital’s Notes to Consolidated Financial Statements). The earnings impacts of these contracts are monitored as part of the net commodity sensitivities.

Foreign Currency Risk

Spectra Energy is exposed to foreign currency risk from investments and operations in Canada. To mitigate risks associated with foreign currency fluctuations, investments are hedged through debt denominated or issued in the foreign currency. Spectra Energy may also use foreign currency derivatives from time to time to manage its risk related to foreign currency fluctuations. To monitor its currency exchange rate risks, Spectra Energy uses sensitivity analysis, which measures the impact of devaluation of foreign currencies.

As of December 31, 2005, a 10% devaluation in the currency exchange rate of the Canadian Dollar would result in an estimated net loss on the translation of local currency earnings of approximately $24 million to Spectra Energy’s pro forma consolidated statement of operations. The pro forma consolidated balance sheet would be negatively impacted by approximately $491 million currency translation through the cumulative translation adjustment in Accumulated Other Comprehensive Income.

Credit Risk

Approximately 90% of Spectra Energy’s credit exposures for transportation and storage services are considered investment grade, with 70% of those investment-grade determinations based on external ratings. “Externally Rated” represents enterprise relationships that have published ratings from at least one major credit rating agency. Credit risk associated with gas distribution services are primarily impacted by general economic conditions in the service territory.

As a result of the distribution of the Transferred Businesses, Spectra Energy will no longer be involved in the use of master collateral agreements associated with certain credit exposures but will continue to utilize cash and letters of credit as appropriate to provide credit support for ongoing operations.

Equity Price Risk

As noted in the pro forma condensed consolidated financial statements above, Spectra Energy anticipates having a captive insurance subsidiary that will carry forward certain assets and liabilities associated with the natural gas business previously insured through Duke Energy’s captive insurance subsidiaries. This Spectra Energy subsidiary will maintain investments to fund various business risks and losses, such as workers’ compensation, property, business interruption and general liability. These investments are exposed to price fluctuations in equity markets and changes in interest rates.

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SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA OF DUKE CAPITAL LLC

The following table presents Duke Capital’s selected historical consolidated financial information. This should be read in conjunction with the financial statements and related notes, and the sections entitled “Management’s Discussion and Analysis of Results of Operations and Financial Condition” and “Pro Forma Financial Information (unaudited).” The selected financial data set forth below for the years ended December 31, 2005, 2004 and 2003 has been derived from Duke Capital’s audited financial statements. The selected financial data set forth below for the nine months ended September 30, 2006 and 2005, and the years ended December 31, 2002 and 2001, have been derived from unaudited financial statements.

	Selected Financial Data (a)
	Nine Months Ended September 30,						Year ended December 31,
	2006			2005			2005			2004			2003 (b)			2002			2001
Statement of Operations
Operating revenues	$	4,511		$	9,535		$	11,349		$	15,463		$	13,217		$	10,036		$	16,956
Operating expenses		3,370			8,269			9,719			13,665			13,430			9,010			15,850
Gains on sales of investments in commercial and multi-family real estate		201			117			191			192			84			106			106
Gains (losses) on sales of other assets, net		276			588			527			(408	)		(185	)		—			238
Operating income (loss)		1,618			1,971			2,348			1,582			(314	)		1,132			1,450
Other income and expenses, net		669			1,557			1,853			443			618			372			224
Interest expense		542			596			771			980			1,020			880			548
Minority interest expense		50			508			538			200			41			48			224
Earnings (loss) from continuing operations before income taxes		1,695			2,424			2,892			845			(757	)		576			902
Income tax expense (benefit) from continuing operations		616			950			1,212			1,341			(314	)		153			344
Income (loss) from continuing operations		1,079			1,474			1,680			(496	)		(443	)		423			558
(Loss) income from discontinued operations, net of tax		(90	)		(1,227	)		(1,002	)		382			(1,255	)		(128	)		814
Income (loss) before cumulative effect of change in accounting principle		989			247			678			(114	)		(1,698	)		295			1,372
Cumulative effect of change in accounting principle, net of tax and minority interest		—			—			(4	)		—			(160	)		—			(72	)
Net income (loss)	$	989		$	247		$	674		$	(114	)	$	(1,858	)	$	295		$	1,300
Balance Sheet
Total assets	$	25,491		$	34,855		$	35,056		$	37,183		$	39,892		$	45,109		$	35,650
Long-term debt including capital leases, less current maturities	$	8,778		$	9,272		$	8,790		$	11,288		$	13,655		$	15,703		$	9,124

(a) Significant transactions reflected in the results include: 2005 DENA disposition (see Note 12 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale”), 2005 deconsolidation of DEFS effective July 1, 2005 (see Note 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions”), 2005 DEFS sale of TEPPCO (see Note 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions”), 2004 DENA sale of the Southeast plants (see Note 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions”); 2004 tax expense recognized in connection with legal entity reorganization (see Note 5) and 2003 DENA charges (see Note 12 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale”).

(b) As of January 1, 2003, Duke Capital adopted the remaining provisions of Emerging Issues Task Force (EITF) 02-03, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and for Contracts Involved in Energy Trading and Risk Management Activities” (EITF 02-03) and SFAS No. 143, “Accounting for Asset Retirement Obligations” (SFAS No. 143). In accordance with the transition guidance for these standards, Duke Capital recorded a net-of-tax and minority interest cumulative effect adjustment for change in accounting principles. (See Note 1 to the Consolidated Financial Statements, “Summary of Significant Accounting Policies,” for further discussion.)

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION OF DUKE CAPITAL LLC

Management’s Discussion and Analysis should be read in conjunction with Duke Capital’s Consolidated Financial Statements and Notes for the years ended December 31, 2005, 2004 and 2003 and the nine months ended September 30, 2006 and 2005.

Nine Months Ended September 30, 2006

INTRODUCTION

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

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 (New Duke Energy) and Old Duke Energy converted into a limited liability company named Duke Power Company LLC (subsequently renamed Duke Energy Carolinas, LLC (Duke Energy Carolinas) effective October 1, 2006). The term Duke Energy, as used in this report, refers to Old Duke Energy and New Duke Energy, as the context requires.

On April 1, 2006, in connection with the above transactions, Old Duke Energy transferred the operations of Duke Energy Merchants, LLC and Duke Energy Merchant Finance, LLC (collectively DEM) to its wholly-owned subsidiary, Duke Capital LLC (collectively with its subsidiaries, Duke Capital). As a result of these transfers, prior period amounts have been retrospectively adjusted to include the results of operations, financial position and cash flows related to DEM as these transactions represent a transfer of assets under common control. Additionally, on April 1, 2006, Duke Capital transferred the operations of its wholly-owned captive insurance subsidiary, Bison Insurance Company Limited (Bison), to Duke Energy. Accordingly, Bison’s operations are not included in Duke Capital’s results of operations, financial position or cash flows subsequent to its transfer to Duke Energy. On April 3, 2006, Duke Energy Carolinas transferred to its parent, Duke Energy, all of its membership interests in Duke Capital.

Additionally, in April 2006, Duke Capital indirectly transferred to Duke Energy Ohio, Inc. (Duke Energy Ohio) (formerly The Cincinnati Gas & Electric Company (CG&E)), a subsidiary of Cinergy, its ownership interest in Duke Energy North America’s (DENA’s) Midwestern assets, representing a mix of combined cycle and peaking plants, with a combined capacity of approximately 3,600 megawatts (MWs). In connection with this transfer, Duke Capital transferred to Duke Energy Ohio approximately $1.6 billion of assets at their carrying value and approximately $0.1 billion of liabilities at their carrying value, for a net transfer of approximately $1.5 billion. This transfer has been accounted for as a capital contribution at historical cost. In connection with the transfer, Duke Capital and Duke Energy Ohio entered into an arrangement through April 2016, unless otherwise extended by the parties, whereby Duke Capital will reimburse Duke Energy Ohio in the event of certain cash shortfalls that may result from Duke Energy Ohio’s ownership of the Midwestern assets. The results of operations for DENA’s Midwestern assets have been reflected as discontinued operations in the accompanying Consolidated Statements of Operations.

Executive Overview

In June 2006, the Board of Directors of Duke Energy authorized management to pursue a plan to create two separate publicly traded companies by spinning off Duke Energy’s natural gas businesses to Duke Energy shareholders. The new natural gas company, which would be named Spectra Energy, would principally consist of

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Duke Capital’s Natural Gas Transmission business segment, which would include Union Gas, and would also include Duke Capital’s 50-percent ownership interest in Duke Energy Field Services, LLC (DEFS). If completed, the spin off of the natural gas business is expected to deliver long-term value to Duke Energy shareholders as the two stand-alone companies would be able to more easily participate in growth opportunities in their own industries as well as the gas and power industry consolidations. It is anticipated that approximately $9 billion of debt currently at Duke Capital and its consolidated subsidiaries would transfer to the new natural gas company at the time of the spin-off. While the actual timing of the spin-off, if it occurs, is dependent upon the resolution of certain regulatory and other matters, Duke Energy is currently targeting a January 1, 2007 effective date for the transaction. Duke Energy expects the transaction to qualify for tax-free treatment for U.S. federal income tax purposes to both Duke Energy and its shareholders and is still evaluating other income tax impacts of the transaction. The transaction required Virginia State Corporation Commission approval, which was received during the third quarter of 2006. In addition, approval from the Federal Communications Commission would be required for the indirect change in control over various licenses from Duke Energy to the new gas company. Duke Energy made the requisite applications in the third quarter 2006. This spin-off will likely have a material impact on Duke Capital’s consolidated results of operations, cash flows and financial condition, as well as liquidity and capital resources.

Additionally, the Board of Directors of Duke Energy authorized management to explore the potential value of bringing in a joint venture partner at Crescent to expand the business and create a platform for increased growth. On September 7, 2006, an indirect wholly owned subsidiary of Duke Capital closed an agreement to create a joint venture of Crescent (the Crescent JV) with Morgan Stanley Real Estate Fund V U.S., L.P. (MSREF) and other affiliated funds controlled by Morgan Stanley (collectively the MS Members). Under the agreement, the Duke Capital subsidiary contributed all of the membership interests in Crescent to a newly-formed joint venture, which was ascribed an enterprise value of approximately $2.1 billion as of December 31, 2005. In conjunction with the formation of the Crescent JV, the joint venture, Crescent and Crescent’s subsidiaries entered into a credit agreement with third party lenders under which Crescent borrowed approximately $1.23 billion, of which approximately $1.19 billion was immediately distributed to Duke Capital and has been classified as a financing activity in the accompanying Consolidated Statement of Cash Flows for the nine months ended September 30, 2006. Immediately following the debt transaction, the MS Members collectively acquired a 49% membership interest in the Crescent JV from Duke Capital for a purchase price of approximately $415 million. The MS Members 49% interest reflects a 2% interest in the Crescent JV issued by the joint venture to the President and Chief Executive Officer of Crescent which is subject to forfeiture if the executive voluntarily leaves employment of the Crescent JV within a three year period. Additionally, this interest can be put back to the Crescent JV after three years or possibly earlier upon the occurrence of certain events at 2% of the fair value of the Crescent JV’s equity as of the put date. Therefore, the Crescent JV will accrue the obligation related to the put as a liability over the three year forfeiture period. Accordingly, Duke Capital has an effective 50% ownership in the equity of the Crescent JV for financial reporting purposes. In conjunction with this transaction, Duke Capital recognized a pre-tax gain of approximately $250 million on the sale. As a result of the Crescent transaction, Duke Capital no longer controls the Crescent JV and on September 7, 2006 deconsolidated its investment in Crescent and subsequently will account for its investment in the Crescent JV utilizing the equity method of accounting.

For the nine months ended September 30, 2006, Duke Capital reported net income of $989 million as compared to net income of $247 million for the nine months ended September 30, 2005. The increase in net income was due primarily to an approximate $1.1 billion after-tax impairment charge (approximately $1.3 billion pre-tax) in 2005 related to DENA, an approximate $250 million pre-tax gain recorded in 2006 on Duke Capital’s sale of 50% of its interest in Crescent and the absence of prior year hedge losses associated with de-designated Field Services’ hedges, partially offset by the pre-tax gains of approximately $900 million (net of minority interest of approximately $343 million) recorded in 2005 related to DEFS’ sale of Texas Eastern Products Pipeline Company, LLC (TEPPCO GP), which is the general partner of TEPPCO Partners, LP (TEPPCO LP) and Duke Capital’s sale of its limited partner interests in TEPPCO LP, and an approximate $575 million gain recorded in 2005 as a result of the DEFS disposition transaction.

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The highlights for the nine months ended September 30, 2006 include:

• For the nine months ended September 30, 2006, Natural Gas Transmission’s earnings increased over the same period in the previous year due to higher natural gas processing—primarily Empress assets, business expansion, favorable resolution of property tax issues and the impact of a strengthening Canadian currency, partially offset by higher operating costs and lower equity earnings related to interest expense;

• Field Services earnings decreased in 2006 as compared to the same period in the prior year, primarily as a result of the gain from the sale of TEPPCO in 2005, the gain in 2005 resulting from the DEFS disposition transaction, as well as the impact of the reduction in ownership percentage by Duke Capital as a result of the DEFS disposition transaction, and decreased volumes, partially offset by strong commodity prices during 2006, natural gas liquids (NGL) and gas marketing results and lower hedge losses recognized with the discontinuance of certain cash flow hedges in 2005;

• For the nine months ended September 30, 2006, International Energy experienced lower earnings compared to the same period in the prior year primarily driven by a second quarter 2006 impairment of the Campeche equity investment in Mexico and related note receivable, increased power purchases as a result of an unplanned outage in Peru, unfavorable hydrology in Peru and Brazil, and unplanned outages at NMC. These results were partially offset by favorable hydrology in Argentina and favorable currency impacts—mainly in Brazil;

• Crescent had improved results compared to same period in the prior year, driven primarily by the gain recorded in the third quarter 2006 on Duke Capital’s sale of 50% of its interest in Crescent and an approximate $133 million gain on the sales of properties at Potomac Yard in Washington, DC and a land sale at Lake Keowee in South Carolina in the second quarter 2006, partially offset by third quarter 2005 gains of $86 million on the sales of a commercial office building portfolio and legacy land;

• For the nine months ended September 30, 2006, Other losses decreased compared to the same period in the prior year primarily as a result of lower losses on Field Services hedges and decreased net captive insurance expenses due to the transfer of Bison to Duke Energy on April 1, 2006; and

• Income (loss) from discontinued operations, primarily related to the exit of the DENA business, improved in 2006 compared to the same period in the prior year due primarily to a charge in 2005 for the impairment of assets and the discontinuance of hedge accounting for certain positions at DENA, as a result of the decision to exit substantially all DENA operations except for the Midwestern operations, remaining Southeastern operations, and Duke Energy Trading and Marketing (DETM). The 2006 results reflect the impacts of termination or sale of the final remaining contracts at DENA, as well as the loss on operation of DENA’s Midwestern assets, which were transferred to Duke Energy Ohio in April 2006.

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RESULTS OF OPERATIONS

Results of Operations and Variances

	Nine Months Ended September 30,
	2006			2005			Increase (Decrease)
	(in millions)
Operating revenues	$	4,511		$	9,535		$	(5,024	)
Operating expenses		3,370			8,269			(4,899	)
Gains on sales of investments in commercial and multi-family real estate		201			117			84
Gains on sales of other assets and other, net		276			588			(312	)
Operating income		1,618			1,971			(353	)
Other income and expenses, net		669			1,557			(888	)
Interest expense		542			596			(54	)
Minority interest expense		50			508			(458	)
Earnings from continuing operations before income taxes		1,695			2,424			(729	)
Income tax expense from continuing operations		616			950			(334	)
Income from continuing operations		1,079			1,474			(395	)
Income (loss) from discontinued operations, net of tax		(90	)		(1,227	)		1,137
Net income (loss)	$	989		$	247		$	742

Consolidated Operating Revenues

Nine Months Ended September 30, 2006 as Compared to September 30, 2005. Consolidated operating revenues for the nine months ended September 30, 2006 decreased $5,024 million, compared to the same period in 2005. This change was driven primarily by:

• A $5,530 million decrease due to the deconsolidation of DEFS, effective July 1, 2005, and

• An approximate $203 million decrease in Other due to the continued wind-downs of DETM, DEM and Duke Capital’s 50% interest in D/FD.

Partially offsetting this decrease in revenues were:

• A $500 million increase at Natural Gas Transmission due primarily to new Canadian assets, primarily higher processing revenues on the Empress System (approximately $298 million), recovery of higher natural gas commodity costs (approximately $152 million), resulting from higher natural gas prices passed through to customers without a mark-up at Union Gas, and favorable Canadian dollar foreign exchange impacts (approximately $134 million), partially offset by lower gas usage due to unseasonably warmer weather (approximately $150 million)

• A $183 million increase at International Energy due primarily to increased ownership and resulting consolidation of Aguaytia (approximately $81 million), higher energy prices in El Salvador (approximately $41 million), favorable exchange rates in Brazil (approximately $28 million) and higher electricity volumes and prices in Argentina (approximately $25 million), and

• An approximate $130 million increase in Other related to the prior year impact of the realized and unrealized mark-to-market losses of Field Services’ hedges that had been recorded in operating revenues prior to the deconsolidation of DEFS.

For a more detailed discussion of operating revenues, see the segment discussions that follow.

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Consolidated Operating Expenses

Nine Months Ended September 30, 2006 as Compared to September 30, 2005. Consolidated operating expenses for the nine months ended September 30, 2006 decreased $4,899 million, compared to the same period in 2005. This change was driven primarily by:

• An approximate $5,087 million decrease due to the deconsolidation of DEFS, effective July 1, 2005

• An approximate $242 million decrease in Other due to the continued wind-downs of DETM, DEM and Duke Capital’s 50% interest in D/FD

• An approximate $120 million decrease associated with the prior year recognition of unrealized losses in accumulated other comprehensive income (AOCI) as a result of the discontinuance of certain cash flow hedges entered into to hedge Field Services’ commodity price risk, which were previously accounted for as cash flow hedges (see Note 12 to the Consolidated Financial Statements, “Risk Management Instruments”), and

• An approximate $96 million decrease in captive insurance expenses due primarily to the transfer of ownership in Bison to Duke Energy effective April 1, 2006, prior year charges for liabilities associated with mutual insurance companies and recognition of reserves for estimated property damage related to hurricanes and business interruption losses.

Partially offsetting this decrease in expenses were:

• A $467 million increase at Natural Gas Transmission due primarily to new Canadian assets, primarily the Empress System (approximately $225 million), increased natural gas prices at Union Gas (approximately $152 million), resulting from high natural gas prices passed through to customers without a mark-up at Union Gas, Canadian dollar foreign exchange impacts (approximately $106 million), partially offset by lower gas purchase costs due to unseasonably warmer weather (approximately $127 million), and

• A $192 million increase at International Energy due primarily to increased ownership and resulting consolidation of Aguaytia (approximately $64 million), an allowance on a note receivable from the Campeche equity investment (approximately $38 million), and higher fuel prices and volumes, and purchased power costs in Latin America (approximately $90 million).

For a more detailed discussion of operating expenses, see the segment discussions that follow.

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

Nine Months Ended September 30, 2006 as Compared to September 30, 2005. Consolidated gains on sales of investments in commercial and multi-family real estate increased $84 million compared to the same period in 2005. This increase was primarily due to an approximate $81 million gain on the sale of two office buildings at Potomac Yard in Washington, D.C. and an approximate $52 million gain on a land sale at Lake Keowee in northwestern South Carolina in 2006, partially offset by a $41 million land sale gain at Catawba Ridge in South Carolina in 2005.

Consolidated Gains on Sales of Other Assets and Other, Net

Nine Months Ended September 30, 2006 as Compared to September 30, 2005. Consolidated gains on sales of other assets and other, net for the nine months ended September 30, 2006 decreased $312 million, compared to the same period in 2005. The decrease was due primarily to an approximate $575 million gain recorded in 2005 as a result of the DEFS disposition transaction, partially offset by an approximate $250 million gain in 2006 on the sale of an effective 50% interest in Crescent, creating a joint venture between Duke Capital and MSREF and an approximate $23 million gain on the settlement of a customer’s transportation contract at Natural Gas Transmission in 2006.

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Consolidated Operating Income

Nine Months Ended September 30, 2006 as Compared to September 30, 2005. Consolidated operating income for the nine months ended September 30, 2006 decreased $353 million, compared to the same period in 2005. Decreased operating income was primarily related to an approximate $575 million gain in 2005 resulting from the DEFS disposition transaction and the impacts of the deconsolidation of DEFS, effective July 1, 2005, which amounted to approximately $443 million for the nine months ended September 30, 2005. Partially offsetting these decreases were an approximate $250 million gain in 2006 on the sale of a 50% interest in Crescent, an approximate $250 million negative impact to operating income in 2005 related to the discontinuance of certain cash flow hedges entered into to hedge Field Services’ commodity price risk and an $84 million increase in gains on sales of investments in commercial and multi-family real estate. Other drivers to operating income are discussed above.

For more detailed discussions, see the segment discussions that follow.

Consolidated Other Income and Expenses, net

Nine Months Ended September 30, 2006 as Compared to September 30, 2005. Consolidated other income and expenses, net for the nine months ended September 30, 2006 decreased $888 million, compared to the same period in 2005. The decrease was due primarily to the $1,245 million pre-tax gains on sales of equity investments recorded in 2005, primarily associated with the sale of TEPPCO GP and Duke Capital’s limited partner interest in TEPPCO LP, as discussed above, partially offset by an increase of approximately $308 million in equity in earnings of unconsolidated affiliates primarily due to the deconsolidation of DEFS starting July 1, 2005 and an approximate $80 million increase related to mark-to-market impacts associated with DEFS hedges resulting from prior year losses of approximately $105 million offset by 2006 losses of approximately $25 million.

Consolidated Interest Expense

Nine Months Ended September 30, 2006 as Compared to September 30, 2005. Consolidated interest expense for the nine months ended September 30, 2006 decreased $54 million, compared to the same period in 2005. This decrease is primarily attributable to the reduced interest expense associated with DEFS, which was deconsolidated on July 1, 2005, partially offset by higher interest in Brazil and Argentina, and unfavorable exchange rate impacts.

Consolidated Minority Interest Expense

Nine Months Ended September 30, 2006 as Compared to September 30, 2005. Consolidated minority interest expense for the nine months ended September 30, 2006 decreased $458 million, compared to the same period in 2005. The decrease primarily resulted from the 2005 gain associated with the sale of TEPPCO GP and the impact of deconsolidation of DEFS.

Consolidated Income Tax Expense from Continuing Operations

Nine Months Ended September 30, 2006 as Compared to September 30, 2005. Consolidated income tax expense from continuing operations for the nine months ended September 30, 2006 decreased $334 million, compared to the same period in 2005. This decrease primarily resulted from lower pre-tax earnings, due primarily to the 2005 gains associated with the sale of TEPPCO GP and Duke Capital’s limited partner interest in TEPPCO LP as discussed above, offset by the 2006 gain on Crescent. The effective tax rate decreased in the nine months ended September 30, 2006 (36.3%) compared to the same period in 2005 (39.2%), due primarily to the reduction in the unitary state tax rate in 2006 as a result of Duke Energy’s merger with Cinergy, partially offset by non-deductible costs associated with the proposed spin-off of the natural gas businesses. Additionally, the effective tax rate for income from continuing operations was impacted by tax expenses of approximately $36 million associated with the 2005 repatriation of foreign earnings under the American Jobs Creation Act of 2004 and the flow through of certain tax losses to Duke Energy up through April 1, 2006.

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Consolidated Income (Loss) from Discontinued Operations, net of tax

Nine Months Ended September 30, 2006 as Compared to September 30, 2005. Consolidated income (loss) from discontinued operations, net of tax for the nine months ended September 30, 2006 improved $1,137 million compared to the same period in 2005. This improvement primarily resulted from approximately $70 million of after-tax losses at DENA in 2006 associated with certain contract terminations or sales, as compared to an approximate $1.1 billion, after-tax impairment charge (approximately $1.3 billion pre-tax) in 2005 related to DENA, discussed above. Also contributing to the improvement was an approximate $36 million decrease in loss related to the transfer of DENA’s Midwestern assets to Duke Energy Ohio in April 2006.

Segment Results

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 Capital, so the gains and losses on foreign currency remeasurement, and interest and dividend income on those balances, are excluded from the segments’ EBIT. Management considers segment EBIT to be a good indicator of each segment’s operating performance from its continuing operations, as it represents the results of Duke Capital’s ownership interest in operations without regard to financing methods or capital structures.

Duke Capital’s segment EBIT may not be comparable to a similarly titled measure of another company because other entities may not calculate EBIT in the same manner. Segment EBIT is summarized in the following table, and detailed discussions follow.

See Note 11 to the Consolidated Financial Statements, “Business Segments,” for a discussion of Duke Capital’s new segment structure.

EBIT by Business Segment

	Nine Months Ended September 30,
	2006			2005
	(in millions)
Natural Gas Transmission	$	1,102		$	1,044
Field Services (a)		450			1,784
International Energy		182			217
Crescent (c)		515			210
Total reportable segment EBIT		2,249			3,255
Other		(55	)		(270	)
Total reportable segment and other EBIT		2,194			2,985
Interest expense		(542	)		(596	)
Interest income and other (b)		43			35
Consolidated earnings from continuing operations before income taxes	$	1,695		$	2,424

(a) In July 2005, Duke Energy caused a Duke Capital subsidiary to complete the agreement with ConocoPhillips to reduce Duke Capital’s ownership interest in DEFS from 69.7% to 50%. Field Services segment data includes DEFS as a consolidated entity for periods prior to July 1, 2005 and an equity method investment for periods after June 30, 2005.

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(b) Other includes foreign currency transaction gains and losses, and additional minority interest expense not allocated to the segment results.

(c) In September 2006, Duke Energy caused a Duke Capital subsidiary to complete a joint venture transaction of Crescent (see Note 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions”). As a result, Crescent EBIT for the nine months ended September 30, 2006 includes Crescent as a consolidated entity for periods prior to September 7, 2006 and as an equity method investment for periods subsequent to September 7, 2006.

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

Natural Gas Transmission

	Nine Months Ended September 30,
	2006		2005		Increase (Decrease)
	(in millions, except where noted)
Operating revenues	$	3,324	$	2,824	$	500
Operating expenses		2,276		1,809		467
Gains on sales of other assets and other, net		31		4		27
Operating income		1,079		1,019		60
Other income and expenses, net		52		48		4
Minority interest expense		29		23		6
EBIT	$	1,102	$	1,044	$	58
Proportional throughput, TBtu (a)		2,398		2,534		(136	)

(a) Trillion British thermal units. Revenues are not significantly impacted by pipeline throughput fluctuations, since revenues are primarily composed of demand charges.

Nine Months Ended September 30, 2006 as Compared to September 30, 2005

Operating Revenues. The increase was driven primarily by:

• A $298 million increase due to new Canadian assets, primarily higher processing revenues on the Empress System as a result of commodity prices

• A $152 million increase from recovery of higher natural gas commodity costs, resulting from higher natural gas prices passed through to customers without a mark-up at Union Gas. This revenue increase is offset in expenses.

• A $134 million increase due to foreign exchange rates favorably impacting revenues from the Canadian operations as a result of the strengthening Canadian dollar (partially offset by currency impacts to expenses),

• A $29 million increase in U.S. business operations driven by increased processing revenues associated with transportation, partially offset by a 2005 insurance recovery, and

• A $21 million increase from completed and operational pipeline expansion projects in the U.S., partially offset by

• A $150 million decrease in gas distribution revenues at Union Gas primarily resulting from lower gas usage due to warmer weather compared to 2005.

Operating Expenses. The increase was driven primarily by:

• A $225 million increase due to new Canadian assets, primarily gas purchase cost associated with the Empress System

• A $152 million increase related to increased natural gas prices at Union Gas. This amount is offset in revenues

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• A $106 million increase caused by foreign exchange impacts (offset by currency impacts to revenues, as discussed above) and

• A $66 million increase in U.S. primarily related to higher insurance premiums, benefits costs, IT costs, pipeline integrity costs, and other increased transmission and storage operation expenses, partially offset by

• A $127 million decrease in gas purchase costs at Union Gas, primarily resulting from lower gas usage due to unseasonably warmer weather and

• A $15 million decrease related to the resolution in 2006 of prior tax years’ ad valorem tax issues.

Gain on Sales of Other Assets and Other, net. The increase was driven primarily by a $23 million gain in 2006 on the settlement of a customer’s transportation contract, and a $5 million gain on the sale of Stone Mountain assets in 2006.

Other Income and Expenses, net. The increase was driven primarily a pre-tax SAB No. 51 gain of $15 million related to the Income Fund’s issuance of additional units of the Canadian income trust fund, partially offset by a $5 million construction fee received in 2005 from an affiliate as a result of the successful completion of the Gulfstream Natural Gas System, LLC (Gulfstream), 50% owned by Duke Capital, Phase II project, and Natural Gas Transmission’s 50% share of operating and maintenance expenses in 2006 on the Southeast Supply Header project.

EBIT. The increase in EBIT is due primarily to the increase in processing earnings (Empress System), the gain on settlement of a customer’s transportation contract, U.S. business expansion and operations, the gain on the Income Fund’s issuance of additional units of the Canadian income trust fund and the strengthening Canadian currency, partially offset by increased U.S. operating and maintenance expenses, the 2005 Gulfstream success fee and unfavorable Union weather and operations.

Matters Impacting Future Results. In June 2006, the Board of Directors of Duke Energy authorized management to pursue a plan to create two separate publicly traded companies by spinning off Duke Energy’s natural gas businesses to Duke Energy shareholders. The new natural gas company, which would be named Spectra Energy, would principally consist of Duke Capital’s Natural Gas Transmission business segment, which would include Union Gas, and would also include Duke Capital’s 50-percent ownership interest in DEFS. Approximately $9 billion of debt currently at Duke Capital and its consolidated subsidiaries is anticipated to transfer to the new natural gas company at the time of the spin-off. If completed, the decision to spin off the natural gas business is expected to deliver long-term value to shareholders. While the actual timing of the spin-off, if it occurs, is dependent upon the resolution of certain regulatory and other matters, Duke Energy is currently targeting a January 1, 2007 effective date for the transaction.

During the nine months ended September 30, 2006, Natural Gas Transmission recognized a $15 million pre-tax gain on the sale of additional units of the Canadian income trust fund, the Duke Energy Income Fund (Income Fund). If the Income Fund issues additional units in the future to finance its cash needs, Natural Gas Transmission could recognize future SAB No. 51 gain or loss transactions.

On October 31, 2006, the Minister of Finance in Canada announced proposed changes to the income tax treatment of “flow-through entities”, including income trusts, such as the Income Fund. If the proposal is implemented in its current form, income trusts will be subject to tax at corporate rates on the taxable portion of their distributions which would apply beginning with the 2011 taxation year of the Income Fund. Duke Capital will monitor the impact of these proposed changes on the Income Fund and on the future use of such entities, but does not currently expect significant impacts to Natural Gas Transmission as a result of these changes.

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Field Services

	Nine Months Ended September 30,
	2006			2005		Increase (Decrease)
	(in millions, except where noted)
Operating revenues	$	—		$	5,530	$	(5,530	)
Operating expenses		4			5,211		(5,207	)
Gains on sales of other assets and other, net		—			577		(577	)
Operating income		(4	)		896		(900	)
Equity in earnings of unconsolidated affiliates (a)		454			126		328
Other income and expenses, net		—			1,259		(1,259	)
Minority interest expense		—			497		(497	)
EBIT (a)	$	450		$	1,784	$	(1,334	)
Natural gas gathered and processed/transported, TBtu/d (b)		6.8			6.8		—
NGL production, MBbl/d (c)		361			355		6
Average natural gas price per MMBtu (d)(e)	$	7.45		$	7.12	$	0.33
Average NGL price per gallon (e)	$	0.96		$	0.80	$	0.16

(a) Includes Duke Capital’s 50% equity in earnings of DEFS net income subsequent to the deconsolidation of DEFS effective July 1, 2005. Results of DEFS prior to July 1, 2005 are presented on a consolidated basis.

(b) Trillion British thermal units per day

(c) Thousand barrels per day

(d) Million British thermal units. Average price based on NYMEX Henry Hub

(e) Does not reflect results of commodity hedges.

In July 2005, Duke Energy caused a Duke Capital subsidiary to complete the transfer of a 19.7% interest in DEFS to ConocoPhillips, Duke Capital’s co-equity owner in DEFS, which reduced Duke Capital’s ownership interest in DEFS from 69.7% to 50% (the DEFS disposition transaction) and resulted in Duke Capital and ConocoPhillips becoming equal 50% owners in DEFS. As a result of the DEFS disposition transaction, Duke Capital deconsolidated its investment in DEFS and subsequently has accounted for DEFS as an investment utilizing the equity method of accounting.

Nine months ended September 30, 2006 as Compared to September 30, 2005

Operating Revenues. The decrease was due to the DEFS disposition transaction and subsequent deconsolidation of DEFS.

Operating Expenses. The decrease was due to the DEFS disposition transaction and subsequent deconsolidation of DEFS. Operating expenses for the nine months ended September 30, 2005 were also impacted by approximately $120 million of losses recognized due to the reclassification of pre-tax unrealized losses in AOCI as a result of the discontinuance of certain cash flow hedges entered into to hedge Field Services’ commodity price risk, which were previously accounted for as cash flow hedges.

Gains on Sales of Other Assets and Other, net. The decrease was due primarily to an approximate pre-tax gain of $575 million on the DEFS disposition transaction during the prior year.

Equity in Earnings of Unconsolidated Affiliates. The increase is due to Duke Capital’s 50% of equity in earnings of DEFS’ net income for the nine months ended September 30, 2006 as compared to equity in earnings of DEFS’ net income for the three months ended September 30, 2005. DEFS’ earnings during the nine months ended September 30, 2006 have continued to be favorably impacted by increased NGL and crude oil prices as compared to the prior period, as well as increased trading and marketing gains due primarily to changes in

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natural gas prices and the timing of derivative and inventory transactions. These increases have been partially offset by higher operating costs and expenses for repair and maintenance for the nine months ended September 30, 2006.

Other Income and Expenses, net. The decrease is due to the DEFS disposition transaction and subsequent deconsolidation of DEFS. During the nine months ended September 30, 2005, DEFS had a pre-tax gain on the sale of its wholly-owned subsidiary, TEPPCO GP, the general partner of TEPPCO LP of $1.1 billion, and Duke Capital had a pre-tax gain on the sale of its limited partner interest in TEPPCO LP of approximately $97 million. TEPPCO GP and Duke Capital’s limited partner interest in TEPPCO LP were each sold to Enterprise GP Holdings LP, an unrelated third party.

Minority Interest Expense. The decrease was due to the DEFS disposition transaction and subsequent deconsolidation of DEFS. Minority interest expense for the nine months ended September 30, 2005 was due primarily to the gain on the sale of TEPPCO GP to Enterprise GP Holdings LP for approximately $1.1 billion, as discussed above.

EBIT. The decrease in EBIT resulted primarily from the gain on sale of TEPPCO GP and Duke Capital’s limited partner interest in TEPPCO LP during the nine months ended September 30, 2005 and gain on the the DEFS disposition transaction, which reduced Duke Capital’s ownership interest in DEFS from 69.7% to 50%. These decreases were partially offset by increased commodity prices for the nine months ended September 30, 2006 as compared to the prior period.

Supplemental Data. Below is supplemental information for DEFS operating results for the nine months ended September 30, 2006:

	Nine Months Ended September 30, 2006
	(in millions)
Operating revenues	$	9,501
Operating expenses		8,492
Operating income		1,009
Other income and expenses, net		10
Interest expense, net		89
Income tax expense (benefit)		22
Net income	$	908

Matters Impacting Future Results. As previously mentioned, in June 2006, the Board of Directors of Duke Energy authorized management to pursue a plan to create two separate publicly traded companies by spinning off Duke Energy’s natural gas businesses to Duke Energy shareholders. The new natural gas company, which would be named Spectra Energy, would principally consist of Duke Capital’s Natural Gas Transmission business segment, which would include Union Gas, and would also include Duke Capital’s 50-percent ownership interest in DEFS. If completed, the decision to spin off the natural gas business is expected to deliver long-term value to shareholders. While the actual timing of the spin-off, if it occurs, is dependent upon the resolution of certain regulatory and other matters, Duke Energy is currently targeting a January 1, 2007 effective date for the transaction.

In July 2006, the State of New Mexico Environment Department issued Compliance Order to DEFS that list air quality violations during the past five year at three DEFS owned or operated facilities in New Mexico. DEFS intends to contest these allegations. Management of DEFS does not believe this matter will result in a material impact on DEFS’ future consolidated results of operations, cash flows or financial position.

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International Energy

	Nine Months Ended September 30,
	2006			2005		Increase (Decrease)
	(in millions, except where noted)
Operating revenues	$	719		$	536	$	183
Operating expenses		577			385		192
Gains on sales of other assets and other, net		(1	)		1		(2	)
Operating income		141			152		(11	)
Other income and expenses, net		57			74		(17	)
Minority interest expense		16			9		7
EBIT	$	182		$	217	$	(35	)
Sales, GWh		15,715			13,555		2,160
Proportional megawatt capacity in operation		3,995			4,064		(69	)

Nine Months Ended September 30, 2006 as Compared to September 30, 2005

Operating Revenues. The increase was driven primarily by:

• A $89 million increase in Peru due to increased ownership and resulting consolidation of Aguaytia (See Note 2 in the Consolidated Financial Statements, “Acquisitions and Dispositions”) and an increase in energy sales in Egenor.

• A $41 million increase in El Salvador primarily due to higher energy prices as a result of a favorable regulatory price bid methodology.

• A $28 million increase in Brazil due to favorable exchange rates and higher average energy prices, offset by lower volumes, and

• A $25 million increase in Argentina mainly due to higher electricity generation as a result of favorable hydrology, higher electricity prices and increased gas marketing sales.

Operating Expenses. The increase was driven primarily by:

• A $88 million increase in Peru due to increased ownership and resulting consolidation of Aguaytia (See Note 2 in the Consolidated Financial Statements, “Acquisitions and Dispositions”) and increased purchased power and fuel costs in Egenor

• A $36 million increase in El Salvador primarily due to higher fuel prices and increased fuel consumption

• A $32 million increase in Mexico mainly due to an allowance on notes receivable from the Campeche equity investment, and

• A $30 million increase in Brazil due to unfavorable exchange rates, increased regulatory fees, and purchased power costs

Other Income and Expenses, net. The decrease was primarily due to the increased ownership and resulting consolidation of Aguaytia (See Note 2 in the Consolidated Financial Statements, “Acquisitions and Dispositions”), in addition to lower MTBE margins and unplanned outages at NMC.

EBIT. The decrease in EBIT was primarily due to an impairment of the Campeche equity investment and notes receivable as discussed above and higher purchased power costs in Egenor due to lower hydrology, offset by favorable hydrology and pricing in Argentina.

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Matters Impacting Future Results. The Bolivian government has announced plans to nationalize its energy infrastructure. As a result, management is currently monitoring the potential impact on its 50 percent interest in Corani. Depending upon future actions of the Bolivian government, Duke Capital’s investment in Corani could become impaired. Additionally, Duke Capital is evaluating various options related to certain of its operations, principally in Bolivia and Ecuador, which could include the sale or other disposition of these operations. Impairments or losses could be recognized in future periods if Duke Capital decides to pursue such a sale or disposition of any of these operations.

Crescent ^(a)

	Nine Months Ended September 30,
	2006			2005		Increase (Decrease)
	(in millions)
Operating revenues	$	221		$	281	$	(60	)
Operating expenses		158			225		(67	)
Gains on sales of investments in commercial and multi-family real estate		201			117		84
Gains on sales of other assets and other, net		246			—		246
Operating income		510			173		337
Equity in earnings of unconsolidated affiliates		(4	)		—		(4	)
Other income and expenses, net		14			44		(30	)
Minority interest expense		5			7		(2	)
EBIT	$	515		$	210	$	305

(a) In September 2006, Duke Energy caused a Duke Capital subsidiary to complete a joint venture transaction at Crescent. As a result, Crescent segment data includes Crescent as a consolidated entity for periods prior to September 7, 2006 and as an equity investment for the periods subsequent to September 7, 2006.

Nine Months Ended September 30, 2006 as Compared to September 30, 2005

Operating Revenues. The decrease was driven primarily by a $51 million decrease in residential developed lot sales, primarly due to decreased sales at the LandMar division in Florida.

Operating Expenses. The decrease was driven primarily by a $41 million decrease in the cost of residential developed lot sales as noted above and a $16 million impairment charge in 2005 related to a residential community in South Carolina (Oldfield).

Gains on Sales of Investments in Commercial and Multi-Family Real Estate. The increase was driven primarily by an $81 million gain on the sale of two office buildings at Potomac Yard in Washington, DC along with a $52 million land sale at Lake Keowee in northwestern South Carolina in 2006, partially offset by a $41 million land sale at Catawba Ridge in South Carolina in 2005.

Gains on Sales of Other Assets and Other, net. The increase was due to an approximate $250 million pre-tax gain on Duke Capital’s sale of 50% of its interest in Crescent (see Note 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions”).

Other Income and Expenses, net. The decrease is primarily due to the $45 million gain from the sale of assets owned by Crescent Brookdale Associates, an unconsolidated joint venture, in the third quarter of 2005 with no comparable gains during the nine months ended September 30, 2006.

EBIT. The increase was primarily due to the sale of the Potomac Yard office buildings and the sale of an ownership interest in Crescent as noted above.

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Matters Impacting Future Results. In September 2006, Duke Capital closed an agreement to create a joint venture of Crescent and sold an effective 50% interest in Crescent to the MS Members. In conjunction with the formation of the Crescent JV, the joint venture, Crescent and Crescent’s subsidiaries entered into a credit agreement with third party lenders under which Crescent borrowed approximately $1.23 billion, of which $1.19 billion was immediately distributed to Duke Capital. Subsequent to the sale, Duke Capital deconsolidated its investment in the Crescent JV and has accounted for the investment under the equity method of accounting. The combination of Duke Capital’s reduction in ownership and the increased interest expense at Crescent JV as a result of the debt transaction, the impacts of which will be reflected in Duke Capital’s future equity earnings, will likely significantly impact the amount of equity earnings of the Crescent JV that Duke Capital will recognize in future periods. Since the Crescent JV will capitalize interest as a component of project costs, the impacts of the interest expense on Duke Capital’s equity earnings will be recognized as projects are sold by the Crescent JV.

Other

	Nine Months Ended September 30,
	2006			2005			Increase (Decrease)
	(in millions)
Operating revenues	$	282		$	431		$	(149	)
Operating expenses		393			689			(296	)
Gains on sales of other assets and other, net		—			6			(6	)
Operating income		(111	)		(252	)		141
Other income and expenses, net		51			(25	)		76
Minority interest expense		(5	)		(7	)		2
EBIT	$	(55	)	$	(270	)	$	215

Nine Months Ended September 30, 2006 as Compared to September 30, 2005

Operating Revenues. The decrease was driven primarily by:

• A $203 million decrease due to the continued wind-downs of DETM, DEM and Duke Capital’s 50% interest in D/FD

• A $44 million decrease in captive insurance revenues due to the transfer of ownership in Bison to Duke Energy effective April 1, 2006

• A $30 million decrease due to a prior year mark-to-market gain related to DENA’s hedge discontinuance in the Southeast, partially offset by

• An approximate $130 million increase as a result of the prior year impact of realized and unrealized mark-to-market losses on certain discontinued cash flow hedges originally entered into to hedge Field Services’ commodity price risk which were accounted for as Operating Revenues prior to the deconsolidation of DEFS, effective July 1, 2005.

Operating Expenses. The decrease was driven primarily by:

• A $242 million decrease due to the continued wind-downs of DETM, DEM and Duke Capital’s 50% interest in D/FD

• A $96 million decrease in captive insurance expenses due primarily to the transfer of ownership in Bison to Duke Energy effective April 1, 2006, prior year charges for liabilities associated with mutual insurance companies and recognition of reserves for estimated property damage related to hurricanes and business interruption losses, partially offset by

• A $19 million increase associated with Duke Capital’s proportionate share of Duke Energy’s costs-to-achieve in 2006 related to the Cinergy merger.

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Other Income and Expenses, net. The increase was driven primarily by an approximate $80 million favorable variance resulting from the realized and unrealized mark-to-market impacts associated with certain discontinued cash flow hedges originally entered into to hedge Field Services’ commodity price risk which are recorded in Other income and expenses, net on the Consolidated Statements of Operations subsequent to the deconsolidation of DEFS, effective July 1, 2005.

EBIT. The increase was due primarily to the favorable variance related to realized and unrealized mark-to-market impacts of certain discontinued cash flow hedges originally entered into to hedge Field Services’ commodity price risk.

LIQUIDITY AND CAPITAL RESOURCES

Operating Cash Flows

Net cash provided by operating activities decreased $306 million for the nine months ended September 30, 2006 compared to the same period in 2005. This change was driven primarily by:

• An approximate $400 million decrease in 2006 due to the net settlement of remaining DENA contracts

• The settlement of the payable to Barclays (approximately $600 million) in 2006, partially offset by

• Collateral received by Duke Capital (approximately $540 million) in 2006 from Barclays.

Investing Cash Flows

Net cash provided by investing activities increased $953 million for the nine months ended September 30, 2006 compared to the same period in 2005. This change was driven primarily by:

• Approximately $570 million in net purchases (net of sales and maturities) of marketable securities at DEFS in 2005, which was deconsolidated effective July 1, 2005

• An approximate $176 million decrease in 2006 capital and investment expenditures.

Financing Cash Flows and Liquidity

Net cash used in financing activities increased $393 million for the nine months ended September 30, 2006, compared to the same period in 2005. This change was driven primarily by:

• An approximate $2.3 billion distribution to Duke Energy in 2006 due primarily to the Crescent JV transaction offset by a $1,150 million distribution to Duke Energy in 2005, partially offset by

• An approximate $1.2 billion increase in the proceeds from the issuance of long-term debt in 2006, net of redemptions, due to the Crescent JV transaction.

Significant Financing Activities. During the nine months ended September 30, 2006, Duke Capital’s consolidated credit capacity decreased by approximately $1,263 million, primarily due to the terminations of an $800 million syndicated credit facility and $460 million of other bi-lateral credit facilities. The terminations of these credit facilities primarily reflect Duke Capital’s reduced liquidity needs as a result of exiting the DENA business.

In September 2006, prior to the completion of the partial sale of Crescent to the MS members as discussed in Note 2, Crescent issued approximately $1.23 billion principal amount of debt. The net proceeds from the debt issuance of approximately $1.21 billion were recorded as a Financing Activity on the Consolidated Statements of Cash Flows. As a result of Duke Capital’s deconsolidation of Crescent effective September 7, 2006, Crescent’s outstanding debt balance of $1,298 million was removed from Duke Capital’s Consolidated Balance Sheets.

In September 2006, Union Gas entered into a fixed-rate financing agreement denominated in 165 million Canadian dollars (approximately $148 million in U.S. dollar equivalents as of the issuance date) due in 2036 with an interest rate of 5.46%.

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During October 2006, the $130 million bi-lateral credit facility at Duke Capital was cancelled. In addition, the remaining $120 million bi-lateral credit facility was cancelled in November 2006 and reissued at Duke Energy for the same amount with the same terms and conditions.

In December 2004, Duke Capital reached an agreement to sell its partially completed Grays Harbor power generation facility to an affiliate of Invenergy LLC. In 2004, Duke Capital terminated its capital lease with the dedicated pipeline which would have transported natural gas to Grays Harbor. As a result of this termination, approximately $94 million was paid by Duke Capital in January 2005.

On March 1, 2005, redemption notices were sent to the bondholders of the $100 million PanEnergy 8.625% bonds due in 2025. These bonds were redeemed on April 15, 2005 at a redemption price of 104.03 or approximately $104 million.

In August 2005, Duke Capital’s International business unit issued project-level debt in Peru, of which $75 million is denominated in U.S. dollars and approximately $34 million (in U.S. dollar equivalents) is denominated in Peru Nuevos Soles. This debt has terms ranging from four to six years as well as variable and fixed interest rate terms, as applicable.

On September 21, 2005, Union Gas entered into a fixed-rate financing denominated in 200 million Canadian dollars (approximately $171 million in U.S. dollar equivalents) due in 2016 with an interest rate of 4.64%.

Available Credit Facilities and Restrictive Debt Covenants. Duke Capital’s 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 September 30, 2006, Duke Capital was in compliance with those covenants. In addition, some credit agreements may allow for acceleration of payments or termination of the agreements due to nonpayment, or to the acceleration of other significant indebtedness of the borrower or some of its subsidiaries. None of the debt or credit agreements contain material adverse change clauses.

Credit Ratings. Duke Capital and certain subsidiaries each hold credit ratings by Standard & Poor’s (S&P), Moody’s Investors Service (Moody’s) and Dominion Bond Rating Service (DBRS).

The most recent rating action by S&P occurred in September 2006 when S&P changed the outlook of Duke Capital, Texas Eastern Transmission, LP, Union Gas and Westcoast Energy Inc. (collectively the gas entities) from developing to positive following the completion of their assessment of Duke Energy’s announcement of the separation of the electric and gas businesses. S&P had earlier in June 2006 changed the outlook of the gas entities from positive to developing due to S&P’s uncertainty as to how the new gas company would be capitalized and funded. In May 2006, S&P changed the outlook of Duke Capital and all of its subsidiaries (with the exception of Maritimes & Northeast Pipeline, LLC and Maritimes & Northeast Pipeline, LP (collectively M&N Pipeline) and Duke Energy Trading and Marketing, LLC from stable to positive. In April 2006, following the completion of Duke Energy’s merger with Cinergy, S&P raised the credit rating of Duke Capital one ratings level as disclosed in the table below. S&P last affirmed its rating for M&N Pipeline in July 2006 where it has remained unchanged with a stable outlook for the last several years.

The most recent rating action by Moody’s occurred in October 2006 when the credit ratings of Duke Capital and Texas Eastern Transmission, LP were placed under review for possible upgrade following Moody’s preliminary assessment of Duke Capital’s pending restructuring as a subsidiary of the new natural gas company, which would be named Spectra Energy. In April 2006 upon Duke Energy’s completion of the merger with Cinergy, Moody’s upgraded the credit ratings of Duke Capital and Texas Eastern Transmission, LP one ratings level each as disclosed in the table below. Moody’s concluded their April action placing Duke Capital and Texas Eastern Transmission, LP on stable outlook. Moody’s noted in their April action the substantial reduction in

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business and operating risk of Duke Capital through the restructuring of its ownership in DEFS and the divestiture of the Duke Energy North America merchant generation assets and trading book. Moody’s also noted the upgrade at Texas Eastern Transmission, LP in connection to its parent Duke Capital. In August 2005, Moody’s concluded a review of M&N Pipeline and downgraded the credit ratings one ratings level to the respective ratings disclosed in the table below concluding this action with a stable outlook. Moody’s action was primarily as a result of their concerns over the downward revisions in the reserve estimates for the Sable Offshore Energy Project (SOEI) and reduced production by SOEI producers. In August 2006, Moody’s revised the outlook for Maritimes & Northeast Pipeline, LLC to negative, noting the potential for a somewhat weaker shipper profile resulting from a recently announced expansion project on the U.S. portion of the pipeline.

The most recent rating action by DBRS occurred in June 2006 when DBRS confirmed the stable trend of the entities disclosed in the table below following Duke Energy’s announcement of the separation of the electric and gas businesses. Each of the credit ratings assigned by DBRS to the entities below has remained unchanged for the last several years with a stable trend.

The following table summarizes the November 1, 2006 credit ratings from the agencies retained by Duke Capital to rate its securities, its principal funding subsidiaries and its trading and marketing subsidiary DETM.

Credit Ratings Summary as of November 1, 2006

	Standard and Poor’s	Moody’s Investor Service	Dominion Bond Rating Service
Duke Capital LLC (a)	BBB	Baa2	Not applicable
Texas Eastern Transmission, LP (a)	BBB	Baa1	Not applicable
Westcoast Energy Inc. (a)	BBB	Not applicable	A(low)
Union Gas (a)	BBB	Not applicable	A
Maritimes & Northeast Pipeline, LLC (b)	A	A2	A
Maritimes & Northeast Pipeline, LP (b)	A	A2	A
Duke Energy Trading and Marketing, LLC (c)	BBB-	Not applicable	Not applicable

(a) Represents senior unsecured credit rating

(b) Represents senior secured credit rating

(c) Represents corporate credit rating

These entities credit ratings are dependent upon, among other factors, the ability to generate sufficient cash to fund capital and investment expenditures, while maintaining the strength of their current balance sheets. In addition, the M&N Pipeline ratings are dependent upon, among other factors, the future gas supply availability and potential changes in customer credit profiles. These credit ratings could be negatively impacted if as a result of market conditions or other factors, these entities are unable to maintain their current balance sheet strength, or if earnings and cash flow outlook materially deteriorates, or if the gas supply availability contracted on the M&N pipeline materially deteriorates, or the M&N customer credit profiles materially deteriorates.

During the third quarter of 2005, the Board of Directors of Duke Energy authorized and directed management to execute the sale or disposition of substantially all of DENA’s remaining assets and contracts outside the Midwestern United States. On November 18, 2005, Duke Capital announced it signed an agreement to transfer substantially all of the DENA portfolio of derivatives contracts to Barclays. Under the agreement, Barclays acquired substantially all of DENA’s outstanding gas and power derivatives contracts which essentially

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eliminated Duke Capital’s credit, collateral, market and legal risk associated with DENA’s derivative trading positions effective on the date of signing. Substantially all of the underlying contracts have been transferred to Barclays.

A reduction in the credit rating of Duke Capital to below investment grade as of September 30, 2006 would have resulted in Duke Capital posting additional collateral of up to approximately $358 million. The majority of this collateral is related to outstanding surety bonds.

Duke Capital would fund any additional collateral requirements through a combination of cash on hand and the use of credit facilities. Additionally, if credit ratings for Duke Capital or its affiliates fall below investment grade there is likely to be a negative impact on its working capital and terms of trade that is not possible to fully quantify, in addition to the posting of additional collateral and segregation of cash described above.

Other Financing Matters. As of September 30, 2006, Duke Capital and its subsidiaries had effective SEC shelf registrations for up to $592 million in gross proceeds from debt and other securities. Additionally, as of September 30, 2006, Duke Capital had 935 million Canadian dollars (approximately U.S. $838 million) available under Canadian shelf registrations for issuances in the Canadian market. Of the 935 million Canadian dollars available under Canadian shelf registrations, 500 million expires in May 2008 and 435 million expires in August 2008.

Off-Balance Sheet Arrangements

During the nine months ended September 30, 2006, there were no material changes to Duke Capital’s off-balance sheet arrangements. For information on Duke Capital’s off-balance sheet arrangements, see “Off-Balance Sheet Arrangements” in Duke Capital’s Annual Report on Form 10-K/A for the year-ended December 31, 2005.

Contractual Obligations

Duke Capital enters into contracts that require cash payment at specified periods, based on specified minimum quantities and prices. During the nine months ended September 30, 2006, there were no material changes in Duke Capital’s contractual obligations. For an in-depth discussion of Duke Capital’s contractual obligations, see “Contractual Obligations” and “Quantitative and Qualitative Disclosures about Market Risk” in “Management’s Discussion and Analysis of Results of Operations and Financial Condition” in Duke Capital’s Annual Report on Form 10-K/A for the year ended December 31, 2005.

OTHER ISSUES

Plan to Separate Duke Energy’s Natural Gas and Electric Power Businesses. In June 2006, the Board of Directors of Duke Energy authorized management to pursue a plan to create two separate publicly traded companies by spinning off Duke Energy’s natural gas businesses to Duke Energy shareholders. The new natural gas company, which would be named Spectra Energy, would principally consist of Duke Capital’s Natural Gas Transmission business segment, which includes Union Gas, and Duke Capital’s 50-percent ownership interest in DEFS. The primary businesses remaining in Duke Energy post-spin are anticipated to principally be the U.S. Franchised Electric and Gas business segment, the Commercial Power business segment, the International Energy business segment and Duke Energy’s 50% interest in the Crescent JV. It is anticipated that approximately $9 billion of debt currently at Duke Capital and its consolidated subsidiaries would transfer to the new natural gas company at the time of the spin-off. While the actual timing of the spin-off, if it occurs, is dependent upon the resolution of certain regulatory and other matters, Duke Energy is currently targeting a January 1, 2007 effective date for the transaction. Duke Energy expects the transaction to qualify for tax-free treatment for U.S. federal income tax purposes to both Duke Energy and its shareholders and is still evaluating other income tax impacts of the transaction. The transaction required Virginia State Corporation Commission approval, which was

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received during the third quarter of 2006. In addition, approval from the Federal Communications Commission is required for the indirect change in control over various licenses from Duke Energy to the new gas company. Duke Energy made the requisite applications in the third quarter 2006. This spin-off will likely have a material impact on Duke Capital’s consolidated results of operations, cash flows and financial position, as well as liquidity and capital resources.

(For additional information on other issues related to Duke Capital, see Note 13 to the Consolidated Financial Statements, “Regulatory Matters” And Note 14 to the Consolidated Financial Statements, “Commitments and Contingencies.”)

New Accounting Standards

The following new accounting standards have been issued, but have not yet been adopted by Duke Capital as of September 30, 2006:

Statement of Financial Accounting Standards (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 Financial Accounting Standards Board (FASB) issued SFAS No. 155, which amends SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” and 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 is effective for Duke Capital for all financial instruments acquired, issued, or subject to remeasurement after January 1, 2007, and for certain hybrid financial instruments that have been bifurcated prior to the effective date, for which the effect is to be reported as a cumulative-effect adjustment to beginning retained earnings. Duke Capital does not anticipate the adoption of SFAS No. 155 will have any material impact on its consolidated results of operations, cash flows or financial position.

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

SFAS No. 158, “Employer’s Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment to FASB Statements No. 87, 88, 106, and 132(R)” (SFAS No. 158). In October 2006, the FASB issued SFAS No. 158, which changes the recognition and disclosure provisions and measurement date requirements for an employer’s accounting for defined benefit pension and other postretirement plans. The recognition and disclosure provisions require an employer to (1) recognize the funded status of a benefit plan—measured as the difference between plan assets at fair value and the benefit obligation—in its statement of financial position, (2) recognize as a component of OCI, net of tax, the gains or losses and prior service costs or credits that arise during the period but are not recognized as components of net periodic benefit cost, and (3) disclose in the notes to financial statements certain additional information. SFAS No. 158 does not change the amounts recognized in the income statement as net periodic benefit cost. Duke Capital is required to initially recognize the funded status of its defined benefit pension and other postretirement plans and to provide the required additional disclosures as of December 31, 2006. Retrospective application is not permitted. Duke Capital anticipates that adoption of SFAS No. 158 recognition and disclosure provisions will result in an increase in total assets of approximately $34 million, an increase in total liabilities of approximately $111 million and a

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decrease in accumulated other comprehensive income, net of tax, of approximately $77 million as of December 31, 2006 related to the Westcoast plans. Duke Capital does not anticipate the adoption of SFAS No. 158 will have any material impact on its consolidated results of operations or cash flows.

Under the measurement date requirements of SFAS No. 158, an employer is required to measure defined benefit plan assets and obligations as of the date of the employer’s fiscal year-end statement of financial position (with limited exceptions). Historically, Duke Capital has measured its plan assets and obligations up to three months prior to the fiscal year-end, as allowed under the authoritative accounting literature. The measurement date requirement is effective for the year ending December 31, 2008, and early application is encouraged. Duke Capital intends to adopt the change in measurement date effective January 1, 2007 by remeasuring plan assets and benefit obligations as of that date, pursuant to the transition requirements of SFAS No. 158. Net periodic benefit cost for the three-month period between September 30, 2006 and December 31, 2006 will be recognized, net of tax, as a separate adjustment of retained earnings as of January 1, 2007, except for any gain or loss arising from curtailments or settlement, if any, during that three-month period, which would be recognized in earnings in 2006. Additionally, changes in plan assets and plan obligations between September 30, 2006 and December 31, 2006 not related to net periodic benefit cost will be recognized, net of tax, as an adjustment to OCI.

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 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 is effective for Duke Capital’s 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 Capital currently uses a dual approach for quantifying identified financial statement misstatements. Therefore, Duke Capital does not anticipate the adoption of SAB No. 108 will have any material impact on its consolidated results of operations, cash flows or financial position.

FASB Interpretation (FIN) No. 48, “Accounting for Uncertainty in Income Taxes—an interpretation of FASB Statement No. 109” (FIN No. 48). On July 13, 2006, the FASB issued FIN No. 48, which interprets SFAS No. 109, “Accounting for Income Taxes.” FIN No. 48 provides guidance for the recognition, measurement, classification and disclosure of the financial statement effects of a position taken or expected to be taken in a tax return (“tax position”). The financial statement effects of a tax position must be recognized when there is a likelihood of more than 50 percent that based on the technical merits, the position will be sustained upon examination and resolution of the related appeals or litigation processes, if any. A tax position that meets the recognition threshold must be measured initially and subsequently as the largest amount of tax benefit that is greater than 50 percent likely of being realized upon ultimate settlement with a taxing authority. The Interpretation is effective for Duke Capital as of January 1, 2007. Duke Capital is currently evaluating the impact of adopting FIN No. 48, and cannot currently estimate the impact of FIN No. 48 on its consolidated results of operations, cash flows or financial position.

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FASB Staff Position (FSP) No. FAS 123(R)-5, “Amendment of FASB Staff Position FAS 123(R)-1” (FSP No. FAS 123(R)-5). In October 2006, the FASB staff issued FSP No. FAS 123(R)-5 to address whether a modification of an instrument in connection with an equity restructuring should be considered a modification for purposes of applying FSP No. FAS 123(R)-1, “Classification and Measurement of Freestanding Financial Instruments Originally Issued in Exchange for Employee Services under FASB Statement No. 123(R) (FSP No. FAS 123(R)-1).” In August 2005, the FASB staff issued FSP FAS 123(R)-1 to defer indefinitely the effective date of paragraphs A230–A232 of SFAS No. 123(R), and thereby require entities to apply the recognition and measurement provisions of SFAS No. 123(R) throughout the life of an instrument, unless the instrument is modified when the holder is no longer an employee. The recognition and measurement of an instrument that is modified when the holder is no longer an employee should be determined by other applicable generally accepted accounting principles. FSP No. FAS 123(R)-5 addresses modifications of stock-based awards made in connection with an equity restructuring and clarifies that for instruments that were originally issued as employee compensation and then modified, and that modification is made to the terms of the instrument solely to reflect an equity restructuring that occurs when the holders are no longer employees, no change in the recognition or the measurement (due to a change in classification) of those instruments will result if certain conditions are met. This FSP is effective for Duke Capital as of January 1, 2007. Duke Capital is currently evaluating the impact of adopting FSP No. FAS 123(R)-5 and cannot currently estimate the impact of adopting FAS 123(R)-5 on its consolidated results of operations, cash flows or financial position.

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

Emerging Issues Task Force (EITF) Issue No. 06-3, “How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (That Is, Gross versus Net Presentation)” (EITF No. 06-3). In June 2006, the EITF reached a consensus on EITF No. 06-3 to address any tax assessed by a governmental authority that is directly imposed on a revenue-producing transaction between a seller and a customer and may include, but are not limited to, sales, use, value added, and some excise taxes. For taxes within the issue’s scope, the consensus requires that entities present such taxes on either a gross (i.e. included in revenues and costs) or net (i.e. exclude from revenues) basis according to their accounting policies, which should be disclosed. If such taxes are reported gross and are significant, entities should disclose the amounts of those taxes. Disclosures may be made on an aggregate basis. The consensus is effective for Duke Capital beginning January 1, 2007. Duke Capital does not anticipate the adoption of EITF No. 06-3 will have any material impact on its consolidated results of operations.

EITF Issue No. 06-5, “Accounting for Purchases of Life Insurance—Determining the Amount That Could Be Realized in Accordance with FASB Technical Bulletin No. 85-4” (EITF No. 06-5). In June 2006, the EITF reached a consensus on the accounting for corporate-owned and bank-owned life insurance policies. EITF No. 06-5 requires that a policyholder consider the cash surrender value and any additional amounts to be received under the contractual terms of the policy in determining the amount that could be realized under the insurance contract. Amounts that are recoverable by the policyholder at the discretion of the insurance company must be excluded from the amount that could be realized. Fixed amounts that are recoverable by the policyholder in future periods in excess of one year from the surrender of the policy must be recognized at their present value. EITF No. 06-5 is effective for Duke Capital as of January 1, 2007 and must be applied as a change in accounting principle through a cumulative-effect adjustment to retained earnings or other components of equity as of

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January 1, 2007. Duke Capital is currently evaluating the impact of adopting EITF No. 06-5, and cannot currently estimate the impact of EITF No. 06-5 on its consolidated results of operations, cash flows or financial position.

Subsequent Events

For information on subsequent events related to debt and credit facilities, discontinued operations and assets held for sale, commitments and contingencies and member’s equity and related party transactions, see the section entitled “Legal Proceedings,” Note 5, “Debt and Credit Facilities,” Note 10, “Discontinued Operations and Assets Held For Sale,” Note 14, “Commitments and Contingencies,” and Note 16, “Member’s Equity and Related Party Transactions,” to the Consolidated Financial Statements.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

For an in-depth discussion of Duke Capital’s market risks, see “Management’s Discussion and Analysis of Quantitative and Qualitative Disclosures about Market Risk” in Duke Capital’s Annual Report on Form 10-K/A for the year ended December 31, 2005.

Commodity Price Risk

Duke Capital is exposed to the impact of market fluctuations in the prices of natural gas, NGLs and other energy-related products marketed and purchased as a result of its ownership of energy related assets, remaining proprietary trading contracts, and interests in structured contracts classified as undesignated. Price risk represents the potential risk of loss from adverse changes in the market price of energy commodities. Duke Capital employs established policies and procedures to manage its risks associated with these market fluctuations using various commodity derivatives.

Duke Capital’s largest commodity exposure is due to market price fluctuations of NGLs primarily in the Field Services segment and, to a lesser extent, in the Natural Gas Transmission segment. Based on a sensitivity analysis as of September 30, 2006, it was estimated that a price change of fifteen cents per gallon in the price of NGLs (net of related hedges and an equivalent price change in crude oil) would have a corresponding effect on pre-tax income from continuing operations of approximately $157 million over the next 12 months. Comparatively, a fifteen cent price change sensitivity analysis as of December 31, 2005 would have impacted pre-tax income from continuing operations by approximately $105 million over the next 12 months. The increase is due primarily to the NGL production after December 31, 2006 being included in the September 30, 2006 sensitivity which is currently not hedged.

Normal Purchases and Normal Sales. During 2005, the Board of Directors of Duke Energy authorized and directed management to execute the sale or disposition of substantially all of DENA’s remaining physical and commercial assets outside the Midwestern United States and certain contractual positions related to the Midwestern assets. As a result, Duke Capital recognized a pre-tax loss of approximately $1.9 billion in 2005 for the disqualification of its power and gas forward sales contracts previously designated under the normal purchases normal sales exception. This loss is partially offset by the recognition of a pre-tax gain of approximately $1.2 billion for the discontinuance of hedge accounting for natural gas and power cash flow hedges. In April 2006, Duke Capital transferred to Duke Energy Ohio the Midwestern generation assets of DENA, representing approximately 3,600 megawatts of power generation (see Note 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions,” for further details on the Cinergy merger).

Trading and Undesignated Portfolio Risk. Subsequent to Duke Energy’s merger with Cinergy, Duke Capital adopted a Value at Risk (VaR) methodology to measure and disclose market risk inherent in its trading portfolio, in line with how Duke Energy currently manages the portfolio. VaR is a statistical measure used to quantify the potential change in the economic value of the trading portfolio over a particular period of time, with a specified likelihood of occurrence, due to market movement.

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VaR is reported based on a 95 percent confidence interval, utilizing a one-day holding period. This means that on a given day (one-day holding period) there is a 95 percent chance (confidence level) that the trading portfolio will not lose more than the stated amount. VaR is measured using a Monte Carlo simulation methodology that considers implied forward-looking volatilities and historical 21 day correlations. Duke Capital’s VaR amounts for commodity derivatives recorded using the mark-to-market model of accounting were immaterial during the third quarter of 2006.

Duke Capital historically used daily earnings at risk (DER) to measure and monitor the mark-to-market portfolio’s impact on earnings. DER computations are based on historical simulation, which uses price movements over an eleven day period. The historical simulation emphasizes the most recent market activity, which is considered the most relevant predictor of immediate future market movements for natural gas, electricity and other energy-related products. DER computations use several key assumptions, including a 95% confidence level for the resultant price movement and the holding period specified for the calculation.

Duke disclosed a DER of $12 million as of December 31, 2005, which was primarily comprised of DENA derivative positions. DENA’s DER at September 30, 2006 was zero due to the DENA wind-down. The DER figures do not include the hedges which were de-designated as a result of the transfer of 19.7% of Duke Capital’s interest in DEFS to ConocoPhillips. The calculated consolidated DER at December 31, 2005 consists of approximately $11 million related to discontinued operations and less than $1 million related to continuing operations.

DETM, the 60%/40% unregulated joint venture with Exxon Mobil continues to prudently manage down its legacy natural gas positions. While the venture was originally created to actively trade and market natural gas following de-regulation, the venture is a very different business today. No active trading is occurring now other than transacting to meet contractual obligations and to optimize remaining legacy gas positions. These legacy positions do not generate any material earnings volatility for Duke Capital.

Credit Risk

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

Duke Capital’s principal customers for power and natural gas marketing and transportation services are industrial end-users, marketers, local distribution companies and utilities located throughout the U.S., Canada and Latin America. Duke Capital has concentrations of receivables from natural gas and electric utilities and their affiliates, as well as industrial customers and marketers throughout these regions. These concentrations of customers may affect Duke Capital’s overall credit risk in that risk factors can negatively impact the credit quality of the entire sector. Where exposed to credit risk, Duke Capital 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.

In 1999, the Industrial Development Corp of the City of Edinburg, Texas (IDC) issued approximately $100 million in bonds to purchase equipment for lease to Duke Hidalgo (Hidalgo), a subsidiary of Duke Capital. Duke Capital unconditionally and irrevocably guaranteed the lease payments of Hidalgo to IDC through 2028. In 2000, Hidalgo was sold to Calpine Corporation and Duke Capital remained obligated under the lease guaranty. In January 2006, Hidalgo and its subsidiaries filed for bankruptcy protection in connection with the previous

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bankruptcy filing by its parent, Calpine Corporation in December 2005. Gross exposure under the guarantee obligation as of September 30, 2006 is approximately $200 million, which includes principal and interest. Duke Capital does not believe a loss under the guarantee obligation is probable as of September 30, 2006, but continues to evaluate the situation. Therefore, no reserves have been recorded for any contingent loss as of September 30, 2006. No demands for payment of principal or interest have been made under the guarantee. If future losses are incurred under the guarantee, Duke Capital has certain rights which should allow it to mitigate such loss.

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Fiscal Year Ended December 31, 2005

INTRODUCTION

Management’s Discussion and Analysis should be read in conjunction with the Duke Capital’s Consolidated Financial Statements and Notes for the years ended December 31, 2005, 2004 and 2003.

Recasting of Previously Issued Financial Statements. Duke Energy Holding Corporation (Duke Energy HC) was incorporated in Delaware on May 3, 2005 as Deer Holding Corporation, a wholly-owned subsidiary of Duke Energy Corporation (Old Duke Energy). On April 3, 2006, in accordance with the previously announced merger agreement, Old Duke Energy and Cinergy Corp. (Cinergy) merged into two wholly-owned subsidiaries of Duke Energy HC, resulting in Duke Energy HC becoming the parent of Old Duke Energy and Cinergy. In connection with the closing of the merger transactions, Duke Energy HC changed its name to Duke Energy Corporation (New Duke Energy or Duke Energy) and, on April 3, 2006, Old Duke Energy converted its form of organization from a North Carolina corporation to a North Carolina limited liability company and was renamed Duke Power Company LLC (Duke Power). On April 3, 2006, Duke Power transferred to its parent, Duke Energy, all of its membership interests in its wholly-owned subsidiary Duke Capital. The term Duke Energy, as used in this report, refers to Old Duke Energy and New Duke Energy, as the context requires.

On April 1, 2006, in connection with the above transactions, Old Duke Energy transferred the operations of Duke Energy Merchants, LLC and Duke Energy Merchant Finance, LLC (collectively DEM) to Duke Capital. As a result of these transfers, prior periods have been retrospectively adjusted to include the results of operations, financial position and cash flows related to DEM as these transactions represent a transfer of assets between entities under common control.

Also on April 1, 2006, Duke Capital transferred the operations of its wholly-owned captive insurance subsidiary, Bison Insurance Company Limited (Bison), to New Duke Energy. Due to continuing involvement between Bison and Duke Capital entities, the results of operations of Bison do not qualify for discontinued operations treatment. Accordingly, Bison’s operations continue to be included in Duke Capital’s results of operations, financial position and cash flows for all periods presented.

Additionally in April 2006, Duke Capital indirectly transferred to The Cincinnati Gas & Electric Company (CG&E), a subsidiary of Cinergy, its ownership interest in Duke Energy North America’s (DENA’s) Midwestern assets, representing a mix of combined cycle and peaking plants, with a combined capacity of approximately 3,600 megawatts (MWs). The results of operations of DENA’s Midwestern assets have been reflected as discontinued operations in the accompanying Consolidated Statements of Operations (see Note 12).

In conjunction with Duke Energy’s merger with Cinergy, Duke Capital adopted new business segments (see Note 3). Also, Duke Capital has reclassified management fees charged to an unconsolidated affiliate of Duke Capital from revenues to other income/expense (see Note 10).

Restatement of Previously Issued Financial Statements. Duke Capital’s consolidated results of operations for the year ended December 31, 2004 have been restated as the result of a correction of an error related to the classification of income taxes between income from continuing operations and discontinued operations in the Consolidated Statements of Operations. Duke Capital has determined that approximately $584 million of income tax expense for the year ended December 31, 2004 that was included in discontinued operations should have been included in continuing operations. The amount relates to tax attributes that were associated with operations that were appropriately classified as discontinued operations, but the associated income tax expense should have been included in income from continuing operations since the income tax expense resulted from a change in tax status of certain subsidiaries of Duke Capital. As a result, this error had no impact on Duke Capital’s net loss, financial position or cash flows as of and for the year ended December 31, 2004;

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EXECUTIVE OVERVIEW

During 2005, Duke Capital reported net income of $674 million.

• Natural Gas Transmission’s earnings grew during 2005 as a result of U.S. pipeline expansion projects and favorable foreign exchange rate impacts from the strengthening Canadian currency;

• Field Services benefited from strong commodity prices and operational improvements in 2005, offset by the reduction in ownership percentage by Duke Capital as a result of the DEFS disposition transaction discussed below;

• International Energy had solid results in 2005 due to favorable hydrological conditions and foreign exchange rate impacts in Latin America as well as increased equity earnings from its investment in NMC;

• Crescent had another outstanding year in 2005 with strong commercial, residential and multifamily real estate transactions and continues to reinvest in the real estate market, as opportunities arise; and

• As a result of the announced exit plan of DENA, discontinued operations recorded pre-tax losses of approximately $1.1 billion related to the wind-down of the business.

Consistent with its portfolio management strategy, during 2005 Duke Energy caused a Duke Capital subsidiary to finalize a transaction with ConocoPhillips, Duke Capital’s co-equity owner in DEFS, to reduce Duke Capital’s ownership interest in DEFS from 69.7% to 50%, which resulted in Duke Capital and ConocoPhillips becoming equal 50% owners in DEFS. As a result, Duke Capital recognized a pre-tax gain of approximately $575 million while receiving direct and indirect cash and assets from ConocoPhillips as consideration. Additionally, in February 2005, DEFS sold its wholly owned subsidiary TEPPCO GP, which was the general partner of TEPPCO LP, and Duke Capital sold its limited partner interest in TEPPCO LP, which resulted in Duke Capital recognizing pre-tax gains of approximately $0.9 billion (net of minority interest of approximately $0.3 billion). These transactions provided liquidity to Duke Capital to facilitate the accelerated share repurchase program discussed below and allowed Natural Gas Transmission to increase the scope, scale and diversity of its Canadian operations.

A key goal for 2005 was to position DENA to be a successful merchant operator with a sustainable business model. However, management determined that its objective of break-even earnings for DENA by 2006 was no longer realistic without taking on additional risk. As a result, 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 DENA’s remaining assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets, resulting in pre-tax charges of approximately $1.3 billion in the third quarter of 2005. In April 2006, DENA’s Midwestern generation assets, consisting of approximately 3,600 megawatts of power generation, and certain contracts related to the Midwestern generating facilities were transferred to Cinergy, as the merger with Cinergy provides a sustainable business model for those assets. Duke Capital has completed the exit plan, transferring substantially all of DENA’s portfolio of derivative contracts to Barclays and selling DENA’s remaining fleet of power generation assets outside the Midwest to LS Power for approximately $1.6 billion. The LS Power transaction resulted in a pre-tax gain of approximately $380 million in the fourth quarter of 2005, reducing the charge recognized in the third quarter of 2005.

The following Duke Energy objectives for 2006 relate to Duke Capital:

• Deliver on the 2006 financial objectives and position Duke Capital for growth in 2007 and beyond

• Complete the DENA exit and pursue strategic portfolio opportunities

• Build a high-performance culture focused on safety, diversity and inclusion, employee development, leadership and results, and

• Build credibility through leadership on key policy issues, transparent communications and excellent customer service.

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In June 2006, the Board of Directors of Duke Energy authorized management to pursue a plan to create two separate publicly traded companies by spinning off Duke Energy’s natural gas business to Duke Energy shareholders. The new gas company, which would be named Spectra Energy, would consist primarily of Duke Capital’s Natural Gas Transmission and Field Services businesses segments. Prior to the distribution, Duke Energy expects to implement an internal reorganization pursuant to which all of the businesses and assets of Duke Capital other than Duke Energy’s natural gas transmission and storage, distribution, and gathering and processing businesses (i.e., such as Crescent, Commercial Power, and Duke Energy International), will be transferred to a new, wholly-owned, direct subsidiary of Duke Energy. Duke Capital will then be transferred to and will thereafter be a direct, wholly-owned subsidiary of Spectra Energy. While the actual timing of the spinoff, if it occurs, is dependent upon the resolution of certain regulatory and other matters, Duke Energy is currently targeting a January 1, 2007 effective date for the transaction. It is anticipated that approximately $9 billion of debt currently at Duke Capital and its consolidated subsidiaries would transfer to the new natural gas company at the time of the spin-off. Additionally, as a result of the spin-off, Duke Capital is expected to indemnify Duke Energy for certain amounts paid under existing guarantees of wholly-owned subsidiaries that will become guarantees of third party performance upon the separation of the gas and power businesses. Duke Energy expects the transaction to qualify for tax-free treatment for U.S. federal income tax purposes to both Duke Energy and its shareholders and is still evaluating other income tax impacts of the transaction. The transaction required Virginia State Corporation Commission approval, which was received during the third quarter of 2006. In addition, approval from the Federal Communications Commission would be required for the indirect change in control over various licenses from Duke Energy to the new gas company. Duke Energy made the requisite applications in the third quarter 2006. This spin-off will likely have a material impact on Duke Capital’s consolidated results of operations, cash flows and financial condition, as well as liquidity and capital resources.

Economic Factors for Duke Capital’s Business. Duke Capital’s business model provides diversification between stable, less cyclical businesses like Natural Gas Transmission, and the traditionally higher-growth and more cyclical energy businesses like International Energy and Field Services. Additionally, Crescent’s portfolio strategy is diversified between residential, commercial and multi-family development. All of Duke Capital’s businesses can be negatively affected by sustained downturns or sluggishness in the economy, including low market prices of commodities, all of which are beyond Duke Capital’s control, and could impair Duke Capital’s ability to meet its goals for 2006 and beyond.

A significant portion of Natural Gas Transmission’s revenues are based on regulated tariff rates, which include the recovery of certain fuel costs. However, lower economic output would cause the Natural Gas Transmission and Field Services businesses to experience a decline in the volume of natural gas shipped through their pipelines, gathered and processed at their plants, or distributed by Natural Gas Transmission’s distribution company, resulting in lower earnings and cash flows. For Natural Gas Transmission, this decline would primarily affect the distribution revenues in the short-term. Transmission revenues could be impacted by long-term economic declines that could result in the turnback of long-term contracts. Natural Gas Transmission’s customers continue to renew most contracts as they expire.

If negative market conditions should persist over time and estimated cash flows over the lives of Duke Capital’s individual assets do not exceed the carrying value of those individual assets, asset impairments may occur in the future under existing accounting rules and diminish results of operations. A change in management’s intent about the use of individual assets (held for use versus held for sale) or a change in fair value of assets held for sale could also result in impairments or losses.

Duke Capital’s 2006 goals can also be substantially at risk due to the regulation of its businesses. Duke Capital’s businesses in North America are subject to regulations on the federal and state level. Regulations, applicable to the gas transmission and storage industry, have a significant impact on the nature of the businesses and the manner in which they operate. Changes to regulations are ongoing and Duke Capital cannot predict the future course of changes in the regulatory environment or the ultimate effect that any future changes will have on its business.

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Duke Capital’s net income is impacted by fluctuations in commodity prices. Exposure to commodity prices generates higher earnings volatility in the unregulated businesses as no mechanism exists to recover those costs in rates. To mitigate these risks, Duke Capital has typically entered into derivative instruments to effectively hedge known exposures. The sale of DENA’s assets outside the Midwestern United States, including substantially all the derivative portfolio, has resulted in a less volatile earnings pattern for Duke Capital going forward.

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

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

For further information related to management’s assessment of Duke Capital’s risk factors, see Item 1A. “Risk Factors.”

RESULTS OF OPERATIONS

Consolidated Operating Revenues

Year Ended December 31, 2005 as Compared to December 31, 2004. Consolidated operating revenues for 2005 decreased $4.1 billion, compared to 2004. This change was driven by:

• A $5.4 billion decrease due to the deconsolidation of DEFS, effective July 1, 2005, and

• A $465 million decrease as a result of the continued wind-down of DEM

• An approximate $130 million decrease resulting from mark-to-market losses, primarily unrealized, due to increased commodity prices as a result of the discontinuance of certain cash flow hedges entered into to hedge Field Services’ commodity price risk (see Note 7 to the Consolidated Financial Statements, “Risk Management and Hedging Activities, Credit Risk, and Financial Instruments”) from February 22, 2005 to June 30, 2005. Effective with the deconsolidation of DEFS on July 1, 2005, mark-to-market changes related to these discontinued hedges are classified in Other income and expenses, net on the Consolidated Statements of Operations

Partially offsetting these decreases in revenues were:

• An approximate $850 million increase at Field Services, excluding the impact of those hedges which were discontinued as cash flow hedges and the impact of the deconsolidation of DEFS, due primarily to higher average commodity prices, primarily NGL and natural gas in the first six months of 2005

• A $704 million increase at Natural Gas Transmission due primarily to new Canadian assets, primarily the Empress System, favorable foreign exchange rates as a result of the strengthening Canadian dollar (partially offset by currency impacts to expenses), higher natural gas prices that are passed through to customers, an increase related to U.S. business operations driven by higher rates and contracted volumes and increased gas distribution revenues, resulting from higher gas usage in the power market

• An $126 million increase at International Energy due primarily to favorable foreign exchange rate changes in Brazil, and higher energy prices and volumes, and

• A $58 million increase at Crescent due primarily to higher residential developed lot sales.

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Year Ended December 31, 2004 as Compared to December 31, 2003. Consolidated operating revenues for 2004 increased $2.2 billion, compared to 2003. This change was driven by:

• A $2.4 billion increase in Non-regulated Electric, Natural Gas, Natural Gas Liquids, and Other revenues due to higher average NGL and natural gas prices at Field Services, partially offset by the continued wind-down of DETM, and

• A $194 million increase in Regulated Natural Gas revenues, due primarily to the strengthening Canadian dollar at Natural Gas Transmission, partially offset by

• A $303 million decrease in revenues as a result of the continued wind-down of DEM

For a more detailed discussion of operating revenues, see the segment discussions that follow.

Consolidated Operating Expenses

Year Ended December 31, 2005 as Compared to December 31, 2004. Consolidated operating expenses for 2005 decreased $3.9 billion, compared to 2004. The change was primarily driven by:

• A $5.1 billion decrease due to the deconsolidation of DEFS, effective July 1, 2005, and

• A $454 million decrease as a result of the continued wind-down of DEM

• An approximate $100 million decrease in operating expenses at DENA, mainly resulting from the sale of the Southeast Plants

Partially offsetting these decreases in expenses were:

• An approximate $675 million increase in operating expenses at Field Services driven primarily by higher average NGL and natural gas prices in the first six months of 2005

• A $640 million increase at Natural Gas Transmission due primarily to new Canadian assets, primarily gas purchase costs associated with the Empress System, increased natural gas prices at Union Gas (offset in revenues), foreign exchange impacts as discussed above (offset by currency impacts to revenues), and increased gas purchases for distribution primarily due to higher gas usage in the power market

• An approximate $120 million increase related to the recognition of unrealized losses in accumulated other comprehensive income (AOCI) as a result of the discontinuance of certain cash flow hedges entered into to hedge Field Services’ commodity price risk, which were previously accounted for as cash flow hedges (see Note 7 to the Consolidated Financial Statements, “Risk Management and Hedging Activities, Credit Risk, and Financial Instruments”)

• A $74 million increase at International Energy due primarily to higher fuel prices, increased fuel volumes purchased, higher maintenance costs and the impact of foreign exchange rate changes in Brazil, offset by decreased power purchase obligations in Brazil, and

• An approximate $50 million charge to increase liabilities associated with mutual insurance companies

Year Ended December 31, 2004 as Compared to December 31, 2003. Consolidated operating expenses for 2004 increased $235 million, compared to 2003. The change was primarily driven by:

• A $2,041 million increase in Natural Gas and Petroleum Products Purchased due primarily to higher average NGL and natural gas prices at Field Services

Partially offsetting this increase in expenses was:

• A $1,152 million decrease in Impairments and Other Charges due primarily to charges of $1,106 million in 2003 resulting from strategic actions taken at Commercial Power which led to the recording of

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impairments primarily related to the Southeast Plants, offset by $65 million of impairments in 2004 at Field Services and Crescent

• A $364 million decrease in expenses as a result of the continued wind-down of DEM

• A $91 million decrease in Operation, Maintenance and Other due primarily to severance costs accrued in 2003 related to workforce reductions and decreased operating and maintenance cost at DENA resulting from cost reduction efforts and the sale of plants in 2004, partially offset by increased costs at Crescent related to increased residential developed lot sales, and

• A $254 million decrease due to the 2003 write off of goodwill, most of which related to DENA’s trading and marketing business.

For a more detailed discussion of operating expenses, see the segment discussions that follow.

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

Consolidated gains on sales of investments in commercial and multi-family real estate were $191 million in 2005, $192 million in 2004, and $84 million in 2003. The gain in 2005 was driven primarily by pre-tax gains from the sales of surplus legacy land, particularly a large sale in Lancaster, South Carolina, commercial land sales, including a large sale near Washington, D.C. and multi-family project sales in North Carolina and Florida. The gain in 2004 was driven primarily by pre-tax gains from commercial land and project sales in the Washington D.C. area and pre-tax gains from the sales of surplus legacy land. The gain in 2003 was driven primarily by pre-tax gains from the sales of surplus legacy land and pre-tax gains from commercial land and project sales, including the initial sales of land at the Potomac Yards project in the Washington D.C. area.

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

Consolidated gains (losses) on sales of other assets, net was a gain of $527 million for 2005, a loss of $408 million for 2004, and a loss of $185 million for 2003. The gain in 2005 was due primarily to the pre-tax gain resulting from the DEFS disposition transaction (approximately $575 million), partially offset by net pre-tax losses at Commercial Power (approximately $65 million), principally the termination of DENA structured power contracts in the Southeast region. The loss in 2004 was due primarily to pre-tax losses on the sale of the Southeast Plants (approximately $360 million) at Commercial Power, and the termination and sale of DETM contracts ($65 million) which is included in Other. The loss for 2003 was primarily comprised of a $208 million loss at in Other primarily related to charges on DETM contracts ($127 million) resulting from the wind-down of DETM’s operations and stored turbines and related equipment ($66 million).

Consolidated Operating Income (Loss)

Year Ended December 31, 2005 as Compared to December 31, 2004. For 2005, consolidated operating income increased $766 million, compared to 2004. Increased operating income was due primarily to the gain resulting from the DEFS disposition transaction, the charge in 2004 associated with the sale of Commercial Power’s Southeast Plants, increased income from DEFS resulting from higher commodity prices, lower operating expenses, mainly resulting from the sale of the Southeast Plants, favorable results at Natural Gas Transmission driven by higher earnings from business operations and expansion projects in the U.S. and favorable foreign exchange rate from the strengthening Canadian currency, favorable results at International Energy driven primarily by higher volumes and prices and favorable foreign exchange rate changes, and increased income at Crescent resulting from an increase in residential developed lot sales, partially offset by a net decrease to operating income due to the deconsolidation of DEFS, charges in 2005 related to the discontinuance of certain cash flow hedges entered into to hedge Field Services’ commodity price risk, charges in 2005 related to the termination of structured power contracts in the Southeast region and increased liabilities associated with mutual insurance companies.

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Year Ended December 31, 2004 as Compared to December 31, 2003. For 2004, consolidated operating income (loss) increased $1,896 million, compared to 2003. Increased operating income was driven primarily by increased operating income at Commercial Power, as a result of impairments and other related charges in 2003.

Other drivers to operating income are discussed above. For more detailed discussions, see the segment discussions that follow.

Consolidated Other Income and Expenses

Year Ended December 31, 2005 as Compared to December 31, 2004. For 2005, consolidated other income and expenses increased approximately $1.4 billion, compared to 2004. The increase was due primarily to the gains associated with the sale of TEPPCO GP and Duke Capital’s limited partner interest in TEPPCO LP, equity income for the investment in DEFS subsequent to the deconsolidation of DEFS, effective July 1, 2005, income related to a distribution from an interest in a portfolio of office buildings, and increased earnings from International Energy’s NMC investment driven by higher product margins, slightly offset by the realized and unrealized pre-tax losses recognized in 2005 on certain 2005 and 2006 derivative contracts hedging Field Services commodity price risk which were discontinued as cash flow hedges as a result of the deconsolidation of DEFS by Duke Capital and an impairment charge related to Campeche. Effective with the deconsolidation of DEFS on July 1, 2005, mark-to-market changes related to the Field Services discontinued hedges are classified in Other income and expenses, net on the Consolidated Statements of Operations, while from February 22, 2005 to June 30, 2005 these mark-to-market changes were classified in Non-regulated electric, natural gas, natural gas liquids and other revenues on the Consolidated Statements of Operations.

Year Ended December 31, 2004 as Compared to December 31, 2003. Consolidated other income and expenses decreased $175 million for the year ended December 31, 2004 as compared to December 31, 2003. The decrease primarily resulted from the $178 million pre-tax gain on the sale of DENA’s 50% interest in American Ref-Fuel (an owner and operator of advanced waste-to-energy facilities that convert municipal solid waste into energy in the form of steam and electricity) in 2003 (within the Other segment) and Natural Gas Transmission’s $90 million gain on sales of various investments in 2003, offset by foregone earnings from those investments and an approximate $20 million increase in management fees charged to Duke Power (see Note 10 to the Consolidated Financial Statements).

Consolidated Interest Expense

Year Ended December 31, 2005 as Compared to December 31, 2004. For 2005, consolidated interest expense decreased $209 million, compared to 2004. This decrease was due primarily to Duke Capital’s debt reduction efforts in 2004 (an approximate $110 million impact) and the deconsolidation of DEFS (an approximate $80 million impact).

Year Ended December 31, 2004 as Compared to December 31, 2003. For 2004, consolidated interest expense decreased $40 million, compared to 2003. The decrease was due primarily to:

• A $116 million decrease from net debt reduction and refinancing activities, partially offset by

• $33 million of lower capitalized interest due to decreased construction activity

• $11 million of expenses related to financial instruments with characteristics of both liabilities and equity whose related distributions are now classified as interest expense instead of minority interest expense. Those instruments were classified as debt as of July 1, 2003, in accordance with SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity” (SFAS No. 150)

• A $20 million increase associated with Canadian exchange rates, and

• $17 million higher interest costs in Brazil, due to Duke Capital’s Brazilian debt being indexed annually to inflation and unfavorable impact of exchange rates.

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Consolidated Minority Interest Expense

Year Ended December 31, 2005 as Compared to December 31, 2004. For 2005, consolidated minority interest expense increased $338 million, compared to 2004. This increase was driven primarily by increased earnings at DEFS in the first six months of 2005 as a result of the sale of TEPPCO GP and higher commodity prices, offset by the impact of the deconsolidation of DEFS effective July 1, 2005.

Year Ended December 31, 2004 as Compared to December 31, 2003. For 2004, consolidated minority interest expense increased $159 million, compared to 2003. This increase was driven by increased earnings at Field Services and improved results at DENA as a result of the continued wind-down of DETM. Through June 30, 2003, minority interest expense included expense related to regular distributions on trust preferred securities of Duke Capital and its subsidiaries. As of July 1, 2003, those distributions were accounted for as interest expense on a prospective basis in accordance with the adoption of SFAS No. 150. As a result of this accounting change, minority interest expense decreased $33 million for 2004 and $54 million for 2003.

Minority interest expense as shown and discussed in the following business segment EBIT sections includes only minority interest expense related to EBIT of Duke Capital’s joint ventures. It does not include minority interest expense related to interest and taxes of the joint ventures.

Consolidated Income Tax Expense (Benefit) from Continuing Operations

Year Ended December 31, 2005 as Compared to December 31, 2004. For 2005, consolidated income tax expense (benefit) from continuing operations decreased $129 million, compared to 2004. The decrease in income tax expense from continuing operations is primarily a result of the reorganization of Duke Energy Americas LLC (DEA) in 2004 which caused the recognition of tax expense of approximately $1,030 million offset by approximately $2,047 million in higher pre-tax earnings in 2005, due primarily to the gains associated with the sale of TEPPCO GP, Duke Capital’s limited partner interest in TEPPCO LP, and the DEFS disposition transaction (see Note 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions”). The effective tax rate for 2005 was approximately 42%, compared to approximately 159% in 2004. The decrease in the effective tax rate was due primarily to the decrease in deferred taxes of approximately $1,030 million related to the restructuring of certain subsidiaries in 2004, partially offset by the release of $52 million of income tax reserves in 2004, an increase in the pass-through of income tax benefit to Duke Energy of approximately $90 million and an increase of $34 million in the tax expense related to the repatriation in 2005. (See Note 5 to the Consolidated Financial Statements, “Income Taxes.”)

Year Ended December 31, 2004 as Compared to December 31, 2003. For 2004 consolidated income tax expense (benefit) from continuing operations changed $1,655 million, compared to 2003. The increase was primarily a result of the reorganization of Duke Energy Americas LLC (DEA) in 2004 which caused the recognition of tax expense of approximately $1,030 million and the $1,602 million increase in pre-tax earnings from continuing operations. The effective tax rate for 2004 was 159%, compared to approximately 42% in 2003. The increase in the effective tax rate was due primarily to the increase in deferred tax expense of approximately $1,030 million related to the restructuring of certain subsidiaries in 2004 and an increase in the passthrough of income tax benefit to Duke Energy of approximately $50 million, partially offset by the release of $52 million of income tax reserves in 2004. (See Note 5 to the Consolidated Financial Statements, “Income Taxes.”)

Consolidated Income (Loss) from Discontinued Operations, net of tax

Income (Loss) from discontinued operations was a loss of $1,002 million for 2005, a gain of $382 million for 2004, and a loss of $1,255 million for 2003. These amounts represent results of operations and gains (losses) on dispositions related primarily to DENA’s assets and contracts outside the Southeastern United States, International Energy’s Asia-Pacific Business and European Business, DCP, Field Services and Crescent (see Note 12 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale”). The 2005 amount is primarily comprised of an approximate $740 million non-cash, after-tax charge (approximately

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$900 million pre-tax) for the impairment of assets, and the discontinuance of hedge accounting and the discontinuance of the normal purchase/normal sale exception for certain positions at DENA, as a result of exiting substantially all of DENA’s remaining assets and contracts. Additionally, during 2005, DENA recognized after-tax losses of approximately $330 million (approximately $400 million pre-tax) as the result of selling certain gas transportation and structured contracts. These charges were offset by the recognition of after-tax gains of approximately $160 million (approximately $200 million pre-tax) related to the recognition of deferred gains in AOCI related to discontinued cash flow hedges. These amounts are included in Other.

The 2004 amount is primarily comprised of an approximate $273 million after-tax gain resulting from the sale of International Energy’s Asia-Pacific Business, and an approximate $180 million after-tax gain on the sale of two partially constructed DENA plants offset by operating losses at DENA. DENA’s 2004 gain related to the settlement of the Enron bankruptcy proceedings was entirely offset by a charge related to the California and Western U.S. energy markets settlement. These amounts are included in Other.

The 2003 amount is primarily comprised of $1.7 billion in pre-tax impairment charges related to DENA’s partially completed Western plants, related forward power and gas contracts that were de-designated as normal purchases and sales and cash flow hedges, a generation plant in Maine and the Morro Bay plant in California. Also contributing to the 2003 amount was a $223 million after tax charge for International Energy’s impairment charges incurred as a result of classifying its Asia-Pacific assets as held for sale and exiting the European market. These amounts are included in Other.

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

During 2005, Duke Capital recorded a net-of-tax and minority interest cumulative effect adjustment for a change in accounting principle of $4 million as a reduction in earnings. The change in accounting principle related to the implementation of FIN 47, “Accounting for Conditional Asset Retirement Obligations,” in which the timing or method of settlement are conditional on a future event that may or may not be within the control of Duke Capital.

During 2003, Duke Capital recorded a net-of-tax and minority interest cumulative effect adjustment for a change in accounting principles of $160 million as a reduction in earnings. The change in accounting principles included an after-tax and minority interest charge of $150 million related to the implementation of EITF 02-03 and an after-tax charge of $10 million related to the implementation of SFAS No. 143.

Segment Results

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 Capital, so the gains and losses on foreign currency remeasurement, and interest and dividend income on those balances, are excluded from the segments’ EBIT. Management considers segment EBIT to be a good indicator of each segment’s operating performance from its continuing operations, as it represents the results of Duke Capital’s ownership interest in operations without regard to financing methods or capital structures.

As discussed in Note 3 to the Consolidated Financial Statements, in conjunction with the merger between Duke Energy and Cinergy, Duke Capital has adopted new business segments that management believes properly align the various operations of the new corporate structure with how the chief operating decision maker views the business and monitors performance. Commercial Power consists of a portion of Duke Capital’s operations formerly known as Duke Energy North America (DENA). Commercial Power operates and manages power plants and related contractual positions in the Midwestern and Southeastern United States. As indicated in Note 1, Commercial Power’s Midwestern generation assets, consisting of approximately 3,600 megawatts of

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power generation, and certain contracts related to the Midwestern generating facilities were transferred to CG&E in April 2006. As such the results of operations of the Midwestern assets have been reflected as discontinued operations in the accompanying Consolidated Statements of Operations (see Note 12). Commercial Power’s continuing operations prior to 2005 consist primarily of DENA’s eight natural gas-fired merchant power plants in the Southeastern United States and certain other power and gas contracts (collectively, the Southeast Plants). Duke Capital sold the Southeast Plants in August 2004 (see also Note 2). Additionally during 2005, DENA transferred its 50% investment in the McMahon facility in British Columbia, Canada to Natural Gas Transmission. The remaining portion of Duke Capital’s business formerly known as DENA, including its 100% owned affiliates Duke Energy Marketing America, LLC and Duke Energy Marketing Canada Corp., and DETM are included in Other. Also, during the third quarter of 2005, the Board of Directors of Duke Energy authorized and directed management to execute the sale or disposition of substantially all of DENA’s remaining assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets, which was completed during 2006.

In July 2005, Duke Energy caused a Duke Capital subsidiary to complete the agreement with ConocoPhillips to reduce Duke Capital’s ownership interest in DEFS from 69.7% to 50% (see Note 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions”). In connection with the DEFS disposition transaction, DEFS transferred its Canadian natural gas gathering and processing facilities to Natural Gas Transmission. Prior period segment results for Field Services have been retrospectively adjusted to exclude the results of operations of these Canadian gathering and processing facilities, while prior period segment results for Natural Gas Transmission have been retrospectively adjusted to include the results of operations of these Canadian gathering and processing facilities.

Duke Capital’s segment EBIT may not be comparable to a similarly titled measure of another company because other entities may not calculate EBIT in the same manner. Segment EBIT is summarized in the following table, and detailed discussions follow.

EBIT by Business Segment

	Years Ended December 31,
	2005			2004			Variance 2005 vs 2004			2003			Variance 2004 vs 2003
	(in millions)
Natural Gas Transmission	$	1,388		$	1,329		$	59		$	1,333		$	(4	)
Field Services (a)		1,946			367			1,579			176			191
Commercial Power		(66	)		(408	)		342			(1,233	)		825
International Energy		314			222			92			215			7
Crescent		314			240			74			134			106
Total reportable segment EBIT		3,896			1,750			2,146			625			1,125
Other (b)		(295	)		77			(372	)		(365	)		442
Total reportable segment and other EBIT		3,601			1,827			1,774			260			1,567
Interest expense		(771	)		(980	)		209			(1,020	)		40
Interest income and other (b)		62			(2	)		64			3			(5	)
Consolidated earnings (loss) from continuing operations before income taxes	$	2,892		$	845		$	2,047		$	(757	)	$	1,602

(a) In July 2005, Duke Energy caused a Duke Capital subsidiary to transfer 19.7% of its ownership interest in DEFS to ConocoPhillips. Field Services segment data includes DEFS as a consolidated entity for periods prior to July 1, 2005 and an equity method investment for periods after June 30, 2005.

(b) Other includes foreign currency transaction gains and losses, and additional minority interest expense not allocated to the segment results.

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

Natural Gas Transmission

	Years Ended December 31,
	2005		2004		Variance 2005 vs 2004			2003		Variance 2004 vs 2003
	(in millions)
Operating revenues	$	4,055	$	3,351	$	704		$	3,253	$	98
Operating expenses		2,715		2,075		640			2,009		66
Gains on sales of other assets, net		13		17		(4	)		7		10
Operating income		1,353		1,293		60			1,251		42
Other income, net of expenses		65		63		2			130		(67	)
Minority interest expense		30		27		3			48		(21	)
EBIT	$	1,388	$	1,329	$	59		$	1,333	$	(4	)
Proportional throughput, TBtu (a)		3,410		3,332		78			3,362		(30	)

(a) Trillion British thermal units. Revenues are not significantly impacted by pipeline throughput fluctuations since revenues are primarily composed of demand charges.

Year Ended December 31, 2005 as Compared to December 31, 2004

Operating Revenues. The increase was driven primarily by:

• A $269 million increase due to new Canadian assets, primarily the Empress System

• A $153 million increase due to foreign exchange rates favorably impacting revenues from the Canadian operations as a result of the strengthening Canadian dollar (partially offset by currency impacts to expenses)

• A $152 million increase from recovery of higher natural gas commodity costs, resulting from higher natural gas prices that are passed through to customers without a mark-up at Union Gas. This revenues increase is offset in expenses

• A $60 million increase for U.S. business operations driven by higher rates at Maritimes & Northeast Pipeline, LLC and Maritimes & Northeast Pipeline, LP (collectively, M&N Pipeline) and favorable commodity prices on natural gas processing activities

• A $36 million increase in gas distribution revenues, primarily due to higher gas usage in the power market, and

• A $20 million increase from completed and operational pipeline expansion projects in the U.S.

Operating Expenses. The increase was driven primarily by:

• A $272 million increase due to new Canadian assets, primarily gas purchase costs associated with the Empress System

• A $152 million increase related to increased natural gas prices at Union Gas. This amount is offset in revenues

• A $118 million increase caused by foreign exchange impacts (offset by currency impacts to revenues, as discussed above)

• A $43 million increase in gas purchases for distribution, primarily due to higher gas usage in the power market, and

• A $23 million increase related to the 2004 resolution of ad valorem tax issues in various states.

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Other Income, net of expenses. The increase was driven primarily by the successful completion of the Gulfstream Phase II project which went into service in February 2005 and increased volumes at Gulfstream, resulting in a $11 million increase in Gas Transmission’s 50% equity earnings and a $5 million construction fee received from an affiliate. These increases were partially offset by a $16 million gain in 2004 on the sale of equity investments, primarily due to the resolution of contingencies related to prior year sales.

EBIT. The increase in EBIT was due primarily to earnings from U.S. business expansion projects, improved U.S. operations and favorable foreign exchange rate impacts from the strengthening Canadian currency, partially offset by the 2004 resolution of ad valorem tax issues.

Matters Impacting Future Natural Gas Transmission Results

Natural Gas Transmission plans to continue earnings growth through capital efficient expansions in existing markets, optimization of existing systems, and organizational efficiencies and cost control. Over time, Natural Gas Transmission expects continued modest annual EBIT growth from its 2005 EBIT. Demand for natural gas is expected to grow two to three percent in DEGT’s key markets. Changes in the Canadian dollar, weather, throughput and regulatory stability, commodity prices and the ability to renew service contracts would impact future financial results at Natural Gas Transmission. As discussed further in the Executive Overview within this Management’s Discussion and Analysis and Results of Operations and Financial Condition of Duke Capital for fiscal year ended December 31, 2005, Duke Energy is pursuing a plan to separate Natural Gas Transmission, which would include Duke Capital’s 50 percent investment in DEFS.

Year Ended December 31, 2004 as Compared to December 31, 2003

Operating Revenues. The increase was driven primarily by:

• A $175 million increase due to foreign exchange rates favorably impacting revenues from the Canadian operations as a result of the strengthening Canadian dollar (partially offset by currency impacts to expenses)

• A $62 million increase from recovery of higher natural gas commodity costs, resulting from higher natural gas prices that are passed through to customers without a mark-up at Union Gas. This revenues increase is offset in expenses

• A $40 million increase from completed and operational pipeline expansion projects in the United States, partially offset by

• A $95 million decrease as a result of the sale of Empire State Pipeline in February 2003 and Pacific Natural Gas (PNG) in December 2003, and

• An $80 million decrease in gas distribution revenues at Union Gas resulting from lower gas usage in the power market due to unfavorable weather.

Operating Expenses. The increase was driven primarily by:

• A $127 million increase caused by foreign exchange impacts (offset by currency impacts to revenues)

• A $62 million increase related to increased natural gas prices at Union Gas. This amount is offset in revenues

• A $52 million increase resulting from the favorable resolution in 2003 of various contingencies primarily related to a capital project and outstanding ad valorem and franchise tax issues from prior state audits

• A $17 million increase associated with the pipeline expansion projects placed in service

• A $14 million increase in depreciation primarily due to an increase in the depreciation rate and the addition of two major projects in the Western Canadian operations, partially offset by

• An $80 million decrease as a result of operations sold in 2003 as discussed above

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• A $63 million decrease in the cost of gas sold for distribution at Union Gas, due primarily to reduced volumes

• A $29 million decrease due to severance costs in 2003, and

• A $23 million decrease primarily related to the 2004 resolution of ad valorem tax issues in various states.

Other Income, net of expenses. The decrease was driven primarily by:

• A $90 million decrease as a result of prior year gains on sales, primarily the gain on the sale of Natural Gas Transmission’s interests in Northern Border Partners L.P. in January 2003, Alliance Pipeline and the Aux Sable liquids plants in April 2003, and Foothills Pipe Lines Ltd in August 2003

• A $22 million decrease in AFUDC (equity component) due to lower capital spending in 2004

• An $18 million decrease in equity earnings as a result of investments sold in 2003, partially offset by

• A $36 million increase resulting from the 2003 negative settlement of hedges related to foreign currency exposure

• An increase of $16 million in equity earnings of Gulfstream, resulting from higher revenues and volumes due to fuel switching during the unusually active hurricane season in Florida in 2004, and

• A $16 million increase from 2004 gains on the sale of equity investments, primarily due to resolution of contingencies related to prior year sales.

Minority Interest Expenses. The decrease was driven primarily by the sale of PNG in December 2003, as well as lower earnings on Maritimes & Northeast Pipeline.

EBIT. EBIT decreased primarily as a result of gains from sales of equity investments recorded in the prior year and foregone earnings from the investments sold. Those decreases were mostly offset by earnings from expansion projects and foreign exchange EBIT impacts from the strengthening Canadian currency.

Field Services

	Years Ended December 31,
	2005		2004		Variance 2005 vs 2004			2003			Variance 2004 vs 2003
	(in millions)
Operating revenues	$	5,530	$	10,044	$	(4,514	)	$	8,538		$	1,506
Operating expenses		5,215		9,489		(4,274	)		8,320			1,169
Gains (Losses) on sales of other assets, net		577		2		575			(4	)		6
Operating income		892		557		335			214			343
Equity in earnings of unconsolidated affiliates (a)		292		—		292			—			—
Other income, net of expenses		1,259		37		1,222			68			(31	)
Minority interest expense		497		227		270			106			121
EBIT	$	1,946	$	367	$	1,579		$	176		$	191
Natural gas gathered and processed/transported, TBtu/d (b)		6.8		6.8		—			7.0			(0.2	)
NGL production, MBbl/d (c)		353		356		(3	)		346			10
Average natural gas price per MMBtu (d)	$	8.59	$	6.14	$	2.45		$	5.39		$	0.75
Average NGL price per gallon (e)	$	0.85	$	0.68	$	0.17		$	0.53		$	0.15

(a) Includes Duke Capital’s 50% equity in earnings of DEFS net income subsequent to the deconsolidation of DEFS effective July 1, 2005. Duke Capital’s equity in earnings was $292 million for the year ended December 31, 2005. Results of DEFS prior to July 1, 2005 are presented on a consolidated basis.

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(b) Trillion British thermal units per day

(c) Thousand barrels per day

(d) Million British thermal units

(e) Does not reflect results of commodity hedges

In July 2005, Duke Energy caused a Duke Capital subsidiary to complete the transfer of a 19.7% interest in DEFS to ConocoPhillips, Duke Capital’s co-equity owner in DEFS, which reduced Duke Capital’s ownership interest in DEFS from 69.7% to 50% (the DEFS disposition transaction) and resulted in Duke Capital and ConocoPhillips becoming equal 50% owners in DEFS. As a result of the DEFS disposition transaction, Duke Capital deconsolidated its investment in DEFS and subsequently has accounted for DEFS as an investment utilizing the equity method of accounting (see Note 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions”).

Year Ended December 31, 2005 as Compared to December 31, 2004

Operating Revenues. $5.4 billion of the decrease was due to the DEFS disposition transaction and subsequent deconsolidation of DEFS. This decrease was partially offset by increased revenues of approximately $850 million during the six months ended June 30, 2005 versus the comparable period in the prior year which was primarily attributable to a $0.14 per gallon increase in average NGL prices and a $0.66 per MMBtu increase in average natural gas prices. Subsequent to June 2005, Duke Capital’s 50% of equity in earnings related to its investment in DEFS are included in Equity in Earnings of Unconsolidated Affiliates.

Operating Expenses. $5.1 billion of the decrease was due to the DEFS disposition transaction and subsequent deconsolidation of DEFS. Subsequent to June 2005, the results of DEFS are included in Equity in Earnings of Unconsolidated Affiliates in the accompanying Consolidated Statements of Operations. This decrease was partially offset by:

• Increased operating expense of approximately $675 million during the six months ended June 30, 2005 versus the comparable period in the prior year which was primarily attributable to higher average costs of raw natural gas supply, due primarily to an increase in average NGL and natural gas prices, and

• An approximate $120 million increase due to the reclassification of pre-tax unrealized losses in AOCI during the first quarter as a result of the discontinuance of certain cash flow hedges entered into to hedge Field Services’ commodity price risk, which were previously accounted for as cash flow hedges (see Note 7 to the Consolidated Financial Statements, “Risk Management and Hedging Activities, Credit Risk, and Financial Instruments”). After the discontinuance of these hedges, changes in their fair value are being recognized in Other results, as management considers the discontinuance to be an event which disassociates the contracts from the Field Services’ results.

Gain on sales of other assets, net. The increase was primarily due to an approximate pre-tax gain of $575 million on the DEFS disposition transaction.

Equity in earnings of unconsolidated affiliates. The increase was driven by the equity in earnings of $292 million for Duke Capital’s investment in DEFS subsequent to the completion of the DEFS disposition transaction and related deconsolidation. DEFS earnings during the six months ended December 31, 2005 have continued to be favorably impacted by increased commodity prices. These increases were partially offset by higher operating costs and pipeline integrity work as well as lower volumes due in part to hurricane interruptions.

Other Income, net of expenses. The increase was driven primarily by an approximate $1.1 billion pre-tax gain in 2005 on the sale of DEFS’ wholly-owned subsidiary, TEPPCO GP, the general partner of TEPPCO LP, and the pre-tax gain on the sale of Duke Capital’s limited partner interest in TEPPCO LP of approximately $100 million. TEPPCO GP and Duke Capital’s limited partner interest in TEPPCO LP were each sold to Enterprise GP Holdings LP, an unrelated third party. The gain was partially offset by a $33 million decrease in earnings from

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equity method investments, primarily as a result of the sale of TEPPCO GP and Duke Capital’s limited partner interest in TEPPCO LP in the first quarter of 2005.

Minority Interest Expense. The increase was due primarily to the minority interest impact of the gain on the sale of TEPPCO GP to Enterprise GP Holdings LP for approximately $1.1 billion as well as increased earnings at DEFS during the six months ended June 30, 2005 due to commodity price increases. This increase was partially offset by the DEFS disposition transaction and the related deconsolidation of Duke Capital’s investment in DEFS effective July 1, 2005.

EBIT. The increase was primarily driven by the gain on sale of TEPPCO GP and Duke Capital’s limited partner interest in TEPPCO LP, the gain as a result of the DEFS disposition transaction and favorable effects of commodity price increases, partially offset by the impact of Duke Capital’s decreased ownership percentage resulting from the completion of the DEFS disposition transaction. Also, during the first three months of 2005, Duke Capital discontinued certain cash flow hedges entered into to hedge Field Services’ commodity price risk (see Note 7 to the Consolidated Financial Statements, “Risk Management and Hedging Activities, Credit Risk, and Financial Instruments”). As a result of the discontinuance of these cash flow hedges and hedge accounting treatment, approximately $120 million of pre-tax unrealized losses in AOCI related to these contracts have been recognized by Field Services during the year ended December 31, 2005. Field Services’ future results are subject to volatility for factors such as commodity price changes.

Matters Impacting Future Field Services Results

Field Services, through its 50 percent investment in DEFS, has developed significant size and scope in natural gas gathering and processing and NGL marketing and plans to focus on operational excellence and organic growth. DEFS’ revenues and expenses are significantly dependent on prevailing commodity prices for NGLs and natural gas, and past and current trends in price changes of these commodities may not be indicative of future trends. DEFS anticipates that current price levels will continue to stimulate drilling and help to offset declining raw natural gas supplies. Although the prevailing price of natural gas has less short term significance to its operating results than the price of NGLs, in the long term, the growth and sustainability of DEFS’ business depends on natural gas prices being at levels sufficient to provide incentives and capital for producers to increase natural gas exploration and production.

Future equity in earnings of unconsolidated affiliates will continue to be sensitive to commodity prices that have historically been cyclical and volatile. DEFS’ operating and general and administrative costs increased in 2005, primarily due to asset integrity work and financial process improvement costs incurred during the year.

There are many important factors that could cause actual results to differ materially from the expectations expressed. Management can provide no assurances regarding the impact of future commodity prices or drilling activity.

In July 2006, the State of New Mexico Environment Department issued Compliance Orders to DEFS that list air quality violations during the past five years at three DEFS owned or operated facilities in New Mexico. DEFS intends to contest these allegations. Management of DEFS does not believe this matter will result in a material impact on DEFS’ future consolidated results of operations, cash flows or financial position.

As previously mentioned, in June 2006, the Board of Directors of Duke Energy authorized management to pursue a plan to create two separate publicly traded companies by spinning off Duke Energy’s natural gas businesses to Duke Energy shareholders. The new natural gas company, which would be named Spectra Energy, would principally consist of Duke Capital’s Natural Gas Transmission business segment and would also include Duke Capital’s 50-percent ownership interest in DEFS. If completed, the decision to spin off the natural gas business is expected to deliver long-term value to shareholders. While the actual timing of the spin-off, if it occurs, is dependent upon the resolution of certain regulatory and other matters, Duke Energy is currently targeting a January 1, 2007 effective date for the transaction.

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Year Ended December 31, 2004 as Compared to December 31, 2003

Operating Revenues. The increase was primarily driven by:

• An $870 million increase due primarily to a $0.15 per gallon increase in average NGL prices

• A $590 million increase due primarily to a $0.75 per MMBtu increase in average natural gas prices

• A $51 million increase from trading and marketing net margin, due primarily to natural gas asset based trading and marketing price volatility

• A $45 million increase attributable to a $10.29 per barrel increase in average condensate prices to $41.37 during 2004 from $31.08 during 2003

• A $30 million increase related to higher transportation, storage and processing fees which was primarily due to higher fees from processing contracts, partially offset by

• A $44 million decrease related to the impact of cash flow hedging, which reduced revenues by approximately $242 million for the year ended December 31, 2004 and by $198 million for the year ended December 31, 2003, as compared to what revenue would have been without any hedging, and

• A $30 million decrease related to lower NGL and raw natural gas sales volume, partially offset by an increase in wholesale propane marketing activity primarily due to higher propane prices, and the acquisition of gathering, processing and transmission assets in Southeast New Mexico from ConocoPhillips (“COP Acquisition”). Although production volumes increased as a result of processing economics and the COP Acquisition, sales volumes decreased as a result of producers marketing their NGLs on their own behalf.

Operating Expenses. The increase was driven primarily by:

• A $1,175 million increase due to higher average costs of raw natural gas supply which was due primarily to an increase in average NGL and natural gas prices

• A $20 million increase related primarily to an increase in wholesale propane marketing activity and the COP Acquisition partially offset by lower purchased raw natural gas supply volume

• An $18 million increase related to impairment charges associated with a planned shut down of a specific plant and a disposal of certain assets, partially offset by

• A $25 million decrease in operating, and general and administrative expenses, primarily due to severance charges and other employee related expenditures in 2003 not experienced in 2004, lower repairs and maintenance, and environmental expenses in 2004, partially offset by an increase related to Field Services’ Sarbanes-Oxley compliance costs.

Other Income, net of expenses. The decrease was driven primarily by:

• A $23 million decrease due to impairment charges in 2004 related to management’s assessment of the recoverability of certain equity method investments

• A $13 million decrease due to the gains on sales of equity method investments in 2003, partially offset by

• A $7 million increase in equity earnings primarily due to increased earnings from equity method investments.

Minority Interest Expense. Minority interest expense increased in 2004 compared to 2003 due to increased earnings from DEFS. The increase was not proportionate to the increase in Field Services’ earnings, as the Field Services segment includes the results of incremental hedging activities contracted at the Duke Capital corporate level that are not included in DEFS’ results.

EBIT. The increase in EBIT in 2004 compared to 2003 resulted primarily from the favorable effects of commodity prices and improved results from trading and marketing activities, partially offset by NGL and raw natural gas sales volume declines and impairments. The full impact from the effects of commodity prices were not realized as some sales volumes were previously hedged at prices different than actual market prices at settlement.

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Supplemental Data

Below is supplemental information for DEFS operating results subsequent to deconsolidation on July 1, 2005:

	Six Months Ended December 31, 2005
	(in millions)
Operating revenues	$	7,463
Operating expenses		6,814
Operating income		649
Other income, net of expenses		1
Interest expense, net		62
Income tax expense		4
Net income	$	584

Commercial Power

	Years Ended December 31,
	2005			2004			Variance 2005 vs 2004			2003			Variance 2004 vs 2003
	(in millions)
Operating revenues	$	—		$	104		$	(104	)	$	87		$	17
Operating expenses		—			151			(151	)		1,320			(1,169	)
Losses on sales of other assets, net		(69	)		(364	)		295			—			(364	)
Operating loss		(69	)		(411	)		342			(1,233	)		822
Other income, net of expenses		3			3			—			—			3
Minority interest benefit		—			—			—			—			—
EBIT	$	(66	)	$	(408	)	$	342		$	(1,233	)	$	825
Actual plant production, GWh (a)(b)		—			2,100			(2,100	)		3,363			(1,263	)
Net proportional megawatt capacity in operation		—			5,325			(5,325	)		5,325			—

(a) Includes plant production from plants accounted for under the equity method

(b) Excludes discontinued operations

As indicated in Note 1, Commercial Power’s Midwestern generation assets, consisting of approximately 3,600 megawatts of power generation, and certain contracts related to the Midwestern generating facilities were transferred to Cinergy in April 2006. As such the results of operations of the Midwestern assets have been reflected as discontinued operations in the accompanying Consolidated Statements of Operations (see Note 12). Commercial Power’s continuing operations prior to 2005 consist primarily of DENA’s eight natural gas-fired merchant power plants in the Southeastern United States and certain other power and gas contracts (collectively, the Southeast Plants). Duke Capital sold the Southeast Plants in August 2004.

Year Ended December 31, 2005 as compared to December 31, 2004

Operating Revenues. The decrease was driven by the sale of the Southeast plants in 2004. The 2004 results of DENA’s continuing operations included $104 million of power generation revenues.

Operating Expenses. The decrease was driven by the sale of the Southeast plants in 2004. The 2004 results of DENA’s continuing operations include:

• $52 million of operations, maintenance and depreciation expenses

• $99 million of fuel costs

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Losses on Sales of Other Assets, net. The 2005 loss was driven primarily by an approximate $75 million charge related to the termination of structured power contracts in the Southeastern Region. The change is due to the sale of the Southeast plants in 2004. The 2004 results include pre-tax losses of approximately $360 million associated with the sale of the Southeast Plants.

Year Ended December 31, 2004 as Compared to December 31, 2003

Operating Revenues. The increase was driven primarily by an increase in power generation revenues, due primarily to increased average power prices, partially offset by lower volumes due to the sale of the Southeast Plants in the second quarter of 2004.

Operating Expenses. The decrease was driven primarily by:

• A $1,139 million decrease in asset impairments and other related charges primarily in connection with DENA’s exit from the Southeast region and the related discontinuance of the Southeast region hedges

• A $72 million decrease in depreciation expense, primarily due to the sale of the Southeast Plants

• A $20 million decrease in operations and maintenance expense, due primarily to the sale of the Southeast Plants and reduced costs from renegotiated outsourcing agreements, partially offset by

• A $56 million increase in plant fuel costs due primarily to higher average gas prices, offset by lower volumes as a result of the sale of the Southeast Plants.

Losses on Sales of Other Assets, net. Losses on sales of other assets for the year ended December 31, 2004 were due primarily to an approximate $360 million pre-tax loss associated with the sale of DENA’s Southeast Plants.

EBIT. EBIT increased primarily as a result of the decreased losses from impairments and other related charges, lower plant depreciation and operating expenses from the 2004 sale of the Southeast Plants.

International Energy

	Years Ended December 31,
	2005		2004			Variance 2005 vs 2004			2003		Variance 2004 vs 2003
	(in millions)
Operating revenues	$	745	$	619		$	126		$	597	$	22
Operating expenses		536		462			74			426		36
Losses on sales of other assets, net		—		(3	)		3			—		(3	)
Operating income		209		154			55			171		(17	)
Other income, net of expenses		117		78			39			57		21
Minority interest expense		12		10			2			13		(3	)
EBIT	$	314	$	222		$	92		$	215	$	7
Sales, GWh		18,213		17,776			437			16,374		1,402
Net proportional megawatt capacity in operation (a)		3,937		4,139			(202	)		4,121		18

(a) Excludes discontinued operations

Year Ended December 31, 2005 as Compared to December 31, 2004

Operating Revenues. The increase was driven primarily by:

• A $32 million increase in Brazil due to favorable exchange rates, higher average energy prices, partially offset by lower sales volumes

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• A $31 million increase in El Salvador due to higher power prices and a favorable change in regulatory price bid methodology

• A $28 million increase in Argentina due primarily to higher power prices and hydroelectric generation

• A $14 million increase in Ecuador mainly due to higher volumes resulting from a lack of water for hydro competitors

• A $12 million increase in Guatemala due to higher power prices, and

• An $8 million increase in Peru due to favorable hydrological conditions and higher power prices.

Operating Expenses. The increase was driven primarily by:

• A $29 million increase in El Salvador due primarily to higher fuel oil prices, increased fuel oil volumes purchased and increased transmission costs

• A $26 million increase in Ecuador due to higher maintenance, higher diesel fuel prices, increased diesel fuel volumes purchased and a prior year credit related to long term service contract termination

• A $15 million increase in Guatemala due to higher fuel prices and increased fuel volumes purchased, in addition to higher operations and maintenance costs

• A $14 million increase in Brazil due to unfavorable exchange rates and an increase in regulatory and transmission fees, partially offset by lower power purchase obligations

• A $14 million increase in Argentina due to higher power purchase volumes and prices, partially offset by

• A $13 million decrease related to a 2004 charge for the disposition of the ownership share in Compania de Nitrogeno de Cantarell, S.A. de C.V. (Cantarell), a nitrogen production and delivery facility in the Bay of Campeche, Gulf of Mexico in 2004, and

• A $10 million decrease in general and administrative expenses primarily due to lower corporate overhead allocations and compliance costs.

Other Income, net of expenses. The increase was driven primarily by a $55 million increase in equity earnings from the NMC investment driven by higher product margins, offset by a $20 million equity investment impairment related to Campeche in 2005.

EBIT. The increase was due primarily to favorable pricing and hydrological conditions in Peru and Argentina, favorable exchange rates in Brazil and higher equity earnings from NMC, absence of a charge associated with the disposition of the ownership share in Cantarell recorded in 2004, partially offset by an equity investment impairment related to Campeche in 2005.

Matters Impacting Future International Energy Results

International Energy’s current strategy is focused on selectively growing its Latin American power generation business while continuing to maximize the returns and cash flow from its current portfolio. EBIT results for International Energy are sensitive to changes in hydrology, power supply, power demand and fuel prices. Regulatory matters can also impact EBIT results, as well as impacts from fluctuations in exchange rates, most notably the Brazilian Real.

Certain of International Energy’s long-term sales contracts and long-term debt in Brazil contain inflation adjustment clauses. While this is favorable to revenue in periods of inflation in the long run, as International Energy’s contract prices are adjusted, there is an unfavorable impact on interest expense resulting from revaluation of International Energy’s outstanding local currency debt. In periods of deflation, revenue is negatively impacted and interest expense is positively impacted.

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International Energy owns a 50% joint venture interest in Campeche. Campeche operates a natural gas compression facility in the Cantarell oil field in the Gulf of Mexico. Campeche project revenues are generated from the gas compression services agreement (GCSA) with the Mexican national oil company (PEMEX). The current five year GCSA expires on November 7, 2006 and PEMEX has the option to renew the GCSA for an additional four years. As a result of ongoing discussions between Campeche and PEMEX to either sell the Campeche investment or renew the GCSA, an other than temporary impairment in value of the Campeche occurred during 2005 and a $20 million impairment charge was recorded to write down the investment to its estimated fair value. An additional other-than temporary impairment charge of $55 million was recorded during the second quarter of 2006. In the second quarter of 2006, based on ongoing discussions with PEMEX, it was determined that there was a limited future need for Campeche’s gas compression services. Management of International Energy determined that it is probable that the Campeche investment will ultimately be sold or the GCSA will be renewed for a significantly lower rate. An other-than-temporary impairment loss was recorded to reduce the carrying value to $14 million, which is management’s best estimate of realizable value.

The Bolivian government has announced plans to nationalize its energy infrastructure. As a result, management is currently monitoring the potential impact on its 50 percent interest in Corani. Depending upon future actions of the Bolivian government, Duke Capital’s investment in Corani could become impaired. Additionally, Duke Capital is evaluating various options related to certain of its operations, principally in Bolivia and Ecuador, which could include the sale or other disposition of these operations. Impairments or losses could be recognized in future periods if Duke Capital decides to pursue such a sale or disposition of any of these operations.

Year Ended December 31, 2004 as Compared to December 31, 2003

Operating Revenues. The increase was driven primarily by:

• A $32 million increase due to the fourth quarter 2003 completion of the 160 MW Planta Arizona expansion in Guatemala

• A $22 million increase in volumes due to higher electricity dispatch in Ecuador as a result of unplanned outages at competing generators

• A $20 million increase in Brazil resulting from higher contracted sales prices of $26 million which were positively impacted by inflation adjustments primarily offset by the impact of a 2003 regulatory audit revenue adjustment

• A $12 million increase due to higher electricity prices caused by low water availability in Peru

• A $12 million increase due to favorable exchange rates primarily in Brazil, partially offset by

• A $48 million decrease in Guatemala and El Salvador due to decreased cross border power marketing activity resulting from unfavorable market conditions, and

• A $33 million decrease in natural gas sales due to the termination of a natural gas sales contract from the liquefied natural gas business in 2003.

Operating Expenses. The increase was driven primarily by:

• A $23 million increase due to the fourth quarter 2003 completion of the 160 MW Planta Arizona expansion in Guatemala as discussed above

• A $21 million increase in electricity generation costs resulting from higher levels of dispatch in Ecuador as described above

• An $18 million increase due to a reserve reduction in 2003 related to the early termination of a natural gas sales contract from the liquefied natural gas business

• A $17 million increase in Peru power purchases to satisfy sale contract requirements caused by decreased generation as a result of low water availability

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• A $14 million increase due to general and administrative expenses primarily due to higher corporate allocations and Sarbanes-Oxley compliance costs

• A $12 million increase in Brazil due primarily to increased transmission fees and other costs offset by an environmental charge recorded in 2003 and a reduction in the environmental reserves in 2004, partially offset by

• A $42 million decrease in spot market purchases in Guatemala and El Salvador due to decreased cross border power marketing activity

• A $37 million decrease in natural gas sales purchases due to the termination of a natural gas sales contract from the LNG business in 2003, and

• A $13 million charge associated with the disposition of the ownership share in the Cantarell nitrogen facility in Mexico.

Other Income, net of expenses. The increase was primarily the result of:

• An $11 million increase due to a 2003 adjustment related to revenue recognition for the Cantarell equity investment, and

• A $6 million increase due to favorable netback pricing at NMC.

EBIT. EBIT increased modestly in 2004 compared to 2003. The slight increase was due to the factors described above.

Crescent

	Years Ended December 31,
	2005		2004			Variance 2005 vs 2004			2003		Variance 2004 vs 2003
	(in millions)
Operating revenues	$	495	$	437		$	58		$	284	$	153
Operating expenses		399		393			6			231		162
Gains on sales of investments in commercial and multi-family real estate		191		192			(1	)		84		108
Operating income		287		236			51			137		99
Other income, net of expenses		44		3			41			—		3
Minority interest (benefit) expense		17		(1	)		18			3		(4	)
EBIT	$	314	$	240		$	74		$	134	$	106

Year Ended December 31, 2005 as Compared to December 31, 2004

Operating Revenues. The increase was driven primarily by a $64 million increase in residential developed lot sales, due to increased sales at the Palmetto Bluff project in Bluffton, South Carolina and the LandMar affiliate in Northeastern and Central Florida.

Operating Expenses. The increase was driven primarily by a $30 million increase in the cost of residential developed lot sales, due to increased developed lot sales at the projects noted above along with an $11 million increase in corporate administrative expense as a result of increased incentive compensation tied to increased operating results. The increases were offset by a $16 million impairment charge in 2005 related to the Oldfield residential project near Beaufort, South Carolina as compared to $50 million in impairment and bad debt charges in 2004 related to the Twin Creeks residential project in Austin, Texas and The Rim project in Payson, Arizona.

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Gains on Sales of Investments in Commercial and Multi-Family Real Estate. The decrease was driven primarily by:

• A $37 million increase in multi-family sales primarily due to the $15 million gain on a land sale in Charlotte, North Carolina and a $19 million gain on a project sale in Jacksonville, Florida

• A $32 million increase in surplus land sales primarily due to a $42 million gain from a large land sale in Lancaster County, South Carolina, partially offset by

• A $37 million decrease in real estate land sales primarily due to the $45 million gain on the sale of the Alexandria tract in the Washington, D.C. area in 2004, and

• A $33 million decrease in commercial project sales primarily due to the $20 million gain on the sale of a commercial project in the Washington, D.C. area in 2004.

Other Income, net of expenses. The increase was primarily due to $45 million in income related to a distribution from an interest in a portfolio of commercial office buildings in the third quarter of 2005.

Minority Interest (Benefit) Expense. The increase in minority interest (benefit) expense is primarily due to increased earnings from the LandMar affiliate.

EBIT. The increase was primarily due to income related to a distribution from an interest in a portfolio of commercial office buildings, a large land sale in Lancaster County, South Carolina, increased multi-family and residential developed lot sales offset by a decrease in commercial land and project sales due primarily to the sale of a commercial project and the Alexandria tract in the Washington, D.C. area in 2004.

Matters Impacting Future Crescent Results

While Crescent regularly refreshes its property holdings, 2005 results reflected opportunistic real estate sales which resulted in strong earnings during 2005. While future results are difficult to predict, Crescent expects segment EBIT in 2006 to return to a level approximating 2004 segment EBIT. Segment results at Crescent are ultimately subject to volatility as a result of management’s portfolio allocation decisions, the strength of the real estate markets, the cost of construction materials, and changes in interest rates. When property management or other significant continuing involvement is not retained by Crescent after the sale of an operating property, the transaction is recorded in discontinued operations.

On September 7, 2006, an indirect wholly owned subsidiary of Duke Capital closed an agreement to create a joint venture of Crescent (the Crescent JV) with Morgan Stanley Real Estate Fund V U.S., L.P. (MSREF) and other affiliated funds controlled by Morgan Stanley (collectively the MS Members). Under the agreement, the Duke Capital subsidiary contributed all of the membership interests in Crescent to a newly-formed joint venture, which was ascribed an enterprise value of approximately $2.1 billion as of December 31, 2005. In conjunction with the formation of the Crescent JV, the joint venture, Crescent and Crescent’s subsidiaries entered into a credit agreement with third party lenders under which Crescent borrowed approximately $1.23 billion, of which approximately $1.19 billion was immediately distributed to Duke Capital. Immediately following the debt transaction, the MS Members collectively acquired a 49% membership interest in the Crescent JV from Duke Capital for a purchase price of approximately $415 million. The MS Members 49% interest reflects a 2% interest in the Crescent JV issued by the joint venture to the President and Chief Executive Officer of Crescent which is subject to forfeiture if the executive voluntarily leaves the employment of the Crescent JV within a three year period. Additionally, this interest can be put back to the Crescent JV after three years or possibly earlier upon the occurrence of certain events at an amount equal to 2% of the fair value of the Crescent JV’s equity as of the put date. Therefore, the Crescent JV will accrue the obligation related to the put as a liability over the three year forfeiture period. Accordingly, Duke Capital has an effective 50% ownership in the equity of the Crescent JV for financial reporting purposes.

In conjunction with this transaction, Duke Capital has recognized a pre-tax gain on the sale of approximately $250 million during the nine months ended September 30, 2006. As a result of the Crescent

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transaction, Duke Capital no longer controls the Crescent JV and on September 7, 2006 deconsolidated its investment in Crescent and subsequently will account for its investment in the Crescent JV utilizing the equity method of accounting. Duke Capital’s equity investment in the Crescent JV is approximately $163 million as of September 30, 2006. The combination of Duke Capital’s reduction in ownership and the increased interest expense at the Crescent JV as a result of the debt transaction, the impacts of which will be reflected in Duke Capital’s future equity earnings, will likely significantly impact the amount of equity earnings of the Crescent JV that Duke Capital will recognize in future periods. Since the Crescent JV will capitalize interest as a component of project costs, the impacts of the interest expense on Duke Capital’s equity earnings will be recognized as projects are sold by the Crescent JV.

Year Ended December 31, 2004 as Compared to December 31, 2003

Operating Revenues. The increase was driven primarily by a $160 million increase in residential developed lot sales, due to increased sales at the LandMar division in Northeastern and Central Florida, the Palmetto Bluff project in Bluffton, South Carolina, The Sanctuary project near Charlotte, North Carolina, the Lake James projects in Northwestern North Carolina and the Lake Keowee projects in Northwestern South Carolina.

Operating Expenses. The increase was driven primarily by a $101 million increase in the cost of residential developed lot sales, due to increased developed lot sales at the projects noted above, $50 million in impairments and other related charges (net of $12 million minority interest as discussed below) related to Twin Creeks, Texas and Payson, Arizona residential development projects and a $26 million increase in corporate administrative expense as a result of increased incentive compensation tied to increased operating results. (See Note 11 to the Consolidated Financial Statements, “Impairments, Severance, and Other Charges” for further discussion of Crescent’s impairments.)

Gains on Sales of Investments in Commercial and Multi-Family Real Estate. The increase was driven primarily by:

• A $63 million increase in real estate land sales due primarily to the sale of the Alexandria and Arlington land tracts in the Washington, D.C. area in 2004,

• A $31 million increase in commercial project sales, resulting primarily from the sale of a commercial project in the Washington, D.C. area in March 2004, and

• A $16 million increase in land management or “legacy” land sales, due to several large sales closed in the first quarter of 2004.

Minority Interest (Benefit) Expense. The increase in minority interest (benefit) expense is primarily due to $12 million of benefit related to impairment and bad debt charges at the Payson, Arizona project as noted above offset by an additional $8 million in minority interest expense related to increased earnings from the LandMar division.

EBIT. As discussed above, the increase in EBIT was driven primarily by an increase in residential developed lot sales and commercial project sales, the sale of the Washington, D.C. area land tracts and an increase in “legacy” land sales.

Other

	Years Ended December 31,
	2005			2004			Variance 2005 vs 2004			2003			Variance 2004 vs 2003
	(in millions)
Operating revenues	$	602		$	1,368		$	(766	)	$	2,051		$	(683	)
Operating expenses		926			1,447			(521	)		2,686			(1,239	)
(Losses) gains on sales of other assets, net		8			(60	)		68			(188	)		128
Operating (loss) income		(316	)		(139	)		(177	)		(823	)		684
Other (loss) income, net of expenses		25			192			(167	)		352			(160	)
Minority interest expense		4			(24	)		(28	)		(106	)		82
EBIT	$	(295	)	$	77		$	(372	)	$	(365	)	$	442

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Year Ended December 31, 2005 as Compared to December 31, 2004

Operating Revenues. The decrease was driven primarily by:

• A $465 million decrease in revenues as a result of the continued wind-down of DEM

• A $155 million decrease in revenues as a result of the continued wind-down of DETM

• An approximate $130 million decrease as a result of the realized and unrealized mark-to-market impact of certain discontinued cash flow hedges originally entered into to hedge Field Services’ commodity price risk (see Note 7 to the Consolidated Financial Statements, “Risk Management and Hedging Activities, Credit Risk, and Financial Instruments”)

Operating Expenses. The decrease was driven primarily by:

• A $454 million decrease in expenses as a result of the continued wind-down of DEM

• A $150 million decrease in expenses as a result of the continued wind-down of DETM, partially offset by

• An approximate $50 million charge to increase liabilities associated with mutual insurance companies in 2005

• A $59 million increase as a result of the 2004 correction of an immaterial accounting error in prior periods related to reserves at Bison attributable to property losses at several Duke Capital subsidiaries, and

• A $10 million increase in corporate governance costs in 2005.

(Losses) Gains on Sales of Other Assets, net. Losses on sales of other assets for the year ended December 31, 2004 were due primarily to approximately $65 million of pre-tax losses associated with the sales and terminations of DETM contracts.

Other (Loss) Income, net of expenses. The decrease was driven primarily by an approximate $90 million decrease in management fees charged to Duke Power Company, an unconsolidated affiliate of Duke Capital (Duke Power) (see Note 10 to the Consolidated Financial Statements, “Investments in Unconsolidated Affiliates and Related Party Transactions”) and an approximate $64 million decrease as a result of the realized and unrealized mark-to-market impact on discontinued hedges related to the DEFS disposition transaction. (See Note 7 to the Consolidated Financial Statements, “Risk Management and Hedging Activities, Credit Risk, and Financial Instruments.”)

EBIT. The decrease was due primarily to the realized and unrealized mark-to-market impact of certain discontinued cash flow hedges originally entered into to hedge Field Services’ commodity price risk, the continued wind-down of DEM and DETM, the reversal of insurance reserves at Bison in 2004 and the increase in liabilities associated with mutual insurance companies.

Matters Impacting Future Other Results

Future Other results will be subject to volatility as a result of the change in mark-to-market of certain Field Services commodity price risk contracts subsequent to the discontinuance of hedge accounting in the first quarter of 2005. The fair value of these contracts as of December 31, 2005 was a liability of approximately $130 million. As these contracts settle, principally in 2006, Duke Capital will realize an offset to equity in earnings of unconsolidated affiliates at Field Services. Additionally, future impacts due to losses insured by Bison, changes in liabilities associated with mutual insurance companies, and the impact of DENA’s continuing operations could impact future earnings for Other.

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Year Ended December 31, 2004 as Compared to December 31, 2003

Operating Revenues. Operating revenues for 2004 decreased $683 million, compared to 2003. The decrease was driven primarily by:

• A $303 million decrease in revenues as a result of the continued wind-down of DEM

• A $246 million decrease in revenues as a result of the continued wind-down of DETM

• A $162 million decrease due to the sale of Energy Delivery Services (EDS) in December 2003.

Operating Expenses. The decrease was driven primarily by:

• A $364 million decrease in expenses as a result of the continued wind-down of DEM

• A $379 million decrease in expenses as a result of the continued wind-down of DETM, including

• A goodwill impairment charge recognized in 2003 related to the trading and marketing business of $221 million

• A $150 million decrease as a result of the sale of EDS in December 2003

• A $60 million impairment associated with a plan to sell Bayside, an unconsolidated affiliate

• A $59 million decrease in 2004 as a result of the correction of an immaterial accounting error in prior periods related to reserves at Bison attributable to property losses at several Duke Capital subsidiaries

• A $51 million write-off in 2003 related to a corporate risk management information system that was abandoned, lower governance costs in 2004 due to cost reductions and allocation of certain costs previously designated as corporate to business units, and severance costs in 2003

• A 2003 $28 million Commodity Futures Trading Commission (CFTC) settlement ($17 million net of minority interest expense) and 2003 severance costs of $10 million also contributed to a favorable variance in general and administrative expense, partially offset by

• An approximate $100 million increase due to higher captive insurance expenses.

Losses on Sales of Other Assets, net. Losses on sales of other assets for the year ended December 31, 2004 were due primarily to approximately $65 million of pre-tax losses associated with the sales and terminations of DETM contracts. Losses on sales of other assets for 2003 were due primarily a $66 million pre-tax loss on the sale of turbines and $127 million of DETM pre-tax charges related to the sale of contracts.

Other Income (Loss), net of expenses. An approximate $20 million increase in management fees charged to Duke Power (see Note 10 to the Consolidated Financial Statements, “Investments in Unconsolidated Affiliates and Related Party Transactions”).

Minority Interest Expense. The change was due primarily to continued wind-down of DETM

EBIT. EBIT increased in 2004 compared to 2003. The increase in EBIT was primarily driven by the reversal of insurance reserves at Bison and other reductions in operating expense.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The application of accounting policies and estimates is an important process that continues to evolve as Duke Capital’s operations change and accounting guidance evolves. Duke Capital has identified a number of critical accounting policies and estimates that require the use of significant estimates and judgments.

Management bases its estimates and judgments on historical experience and on other various assumptions that they believe are reasonable at the time of application. The estimates and judgments may change as time

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passes and more information about Duke Capital’s environment becomes available. If estimates and judgments are different than the actual amounts recorded, adjustments are made in subsequent periods to take into consideration the new information. Duke Capital discusses its critical accounting policies and estimates and other significant accounting policies with senior members of management. Duke Capital’s critical accounting policies and estimates are listed below.

Risk Management Accounting

Duke Capital uses two comprehensive accounting models for its risk management activities in reporting its consolidated financial position and results of operations: the MTM Model and the Accrual Model. As further discussed in Note 1 to the Consolidated Financial Statements, “Summary of Significant Accounting Policies,” the MTM Model is applied to trading and undesignated non-trading derivative contracts, and the Accrual Model is applied to derivative contracts that are accounted for as cash flow hedges, fair value hedges, and normal purchases or sales, as well as to non-derivative contracts used for commodity risk management purposes. For the three years ended December 31, 2005, the determination as to which model was appropriate was primarily based on accounting guidance issued by the Financial Accounting Standards Board (FASB) and the EITF. Effective January 1, 2003, Duke Capital adopted EITF 02-03. While the implementation of such guidance changed the accounting model used for certain of Duke Capital’s transactions, especially non-derivative energy trading contracts, the overall application of the models remained the same.

As a result of the September, 2005 decision to pursue the sale or other disposition of substantially all of DENA’s remaining assets and contracts outside the Midwestern United States, DENA discontinued hedge accounting for forward natural gas and power contracts accounted for as cash flow hedges and disqualified other forward power contracts previously designated under the normal purchases normal sales exception effective September, 2005.

Under the MTM Model, an asset or liability is recognized at fair value on the Consolidated Balance Sheets and the change in the fair value of that asset or liability is recognized in the Consolidated Statements of Operations during the current period. While DENA is the primary business segment that uses this accounting model, the Field Services segment, as well as Other, also have certain transactions subject to this model. For the years ended December 31, 2005, 2004 and 2003, Duke Capital applied the MTM Model to its derivative contracts, unless subject to hedge accounting or the normal purchase and normal sale exemption (as described below).

The MTM Model is applied within the context of an overall valuation framework. All new and existing transactions are valued using approved valuation techniques and market data, and discounted using a London Interbank Offered Rate (LIBOR) based interest rate. When available, quoted market prices are used to measure a contract’s fair value. However, market quotations for certain energy contracts may not be available for illiquid periods or locations. If no active trading market exists for a commodity or for a contract’s duration, holders of these contracts must calculate fair value using internally developed valuation techniques or models. Key components used in these valuation techniques include price curves, volatility, correlation, interest rates and tenor. While volatility and correlation are the most subjective components, the price curve is generally the most significant component affecting the ultimate fair value for a contract subject to the MTM Model, especially after implementation of EITF 02-03 due to the discontinuation of the MTM Model for certain energy trading contracts, such as transportation agreements. Prices for illiquid periods or locations are established by extrapolating prices for correlated products, locations or periods. These relationships are routinely re-evaluated based on available market data, and changes in price relationships are reflected in price curves prospectively. Consideration may also be given to the analysis of market fundamentals when developing illiquid prices. A deviation in any of the components affecting fair value may significantly affect overall fair value.

Valuation adjustments for performance and market risk, and administration costs are used to arrive at the fair value of the contract and the gain or loss ultimately recognized in the Consolidated Statements of Operations.

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While Duke Capital uses common industry practices to develop its valuation techniques, changes in Duke Capital’s pricing methodologies or the underlying assumptions could result in significantly different fair values and income recognition. However, due to the nature and number of variables involved in estimating fair values, and the interrelationships among these variables, sensitivity analysis of the changes in any individual variable is not considered to be relevant or meaningful.

Validation of a contract’s calculated fair value is performed by an internal group independent of Duke Capital’s trading areas. This group performs pricing model validation, back testing and stress testing of valuation techniques, prices and other variables. Validation of a contract’s fair value may be done by comparison to actual market activity and negotiation of collateral requirements with third parties.

For certain derivative instruments Duke Capital applies either hedge accounting or the normal purchase and normal sales exemption in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” The use of hedge accounting and the normal purchase and normal sales exemption provide effectively for the use of the Accrual Model. Under this model, there is generally no recognition in the Consolidated Statements of Operations for changes in the fair value of a contract until the service is provided or the associated delivery period occurs (settlement).

Hedge accounting treatment is used when Duke Capital contracts to buy or sell a commodity such as natural gas at a fixed price for future delivery corresponding with anticipated physical sales or purchase of natural gas (cash flow hedge). In addition, hedge accounting treatment is used when Duke Capital holds firm commitments or asset positions and enters into transactions that “hedge” the risk that the price of a commodity, such as natural gas or electricity, may change between the contract’s inception and the physical delivery date of the commodity (fair value hedge). To the extent that the fair value of the hedge instrument offsets the transaction being hedged, there is no impact to the Consolidated Statements of Operations prior to settlement of the hedge. However, as not all of Duke Capital’s hedges relate to the exact location being hedged, a certain degree of hedge ineffectiveness may be recognized in the Consolidated Statements of Operations.

The normal purchases and normal sales exception, as provided in SFAS No. 133 as amended and interpreted by Derivative Implementation Group (DIG) Issue C15, “Scope Exceptions: Normal Purchases and Normal Sales Exception for Option-Type Contracts and Forward Contracts in Electricity,” and amended by SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities,” indicates that no recognition of the contract’s fair value in the Consolidated Financial Statements is required until settlement of the contract (in Duke Capital’s case, the delivery of power). Previously, Duke Capital applied this exception for certain contracts involving the sale of power in future periods. SFAS No. 149 includes certain modifications and changes to the applicability of the normal purchase and normal sales scope exception for contracts to deliver electricity. As a result, Duke Capital reevaluated its policy for accounting for forward power sale contracts and determined that the majority of all forward contracts to sell power entered into after July 1, 2003 will be designated as cash flow hedges. To the extent that the hedge is perfectly effective, income statement recognition for the contract will be the same under either model.

In addition to derivative contracts that are accounted for as cash flow hedges, fair value hedges, and normal purchases or sales, the Accrual Model also encompasses non-derivative contracts used for commodity risk management purposes. For these non-derivative contracts, there is no recognition in the Consolidated Statements of Operations until the service is provided or delivery occurs.

For additional information regarding risk management activities, see Quantitative and Qualitative Disclosures about Market Risk. The Quantitative and Qualitative Disclosures about Market Risk include daily earnings at risk information related to commodity derivatives recorded using the MTM Model and an operating income sensitivity analysis related to hypothetical changes in certain commodity prices recorded using the Accrual Model.

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Regulatory Accounting

Duke Capital accounts for certain of its regulated operations (primarily Natural Gas Transmission) under the provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” As a result, Duke Capital records assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for non-regulated entities. Regulatory assets generally represent incurred costs that have been deferred because such costs are probable of future recovery in customer rates. Regulatory liabilities generally represent obligations to make refunds to customers for previous collections for costs that either are not likely to or have yet to be incurred. Management continually assesses whether the regulatory assets are probable of future recovery by considering factors such as applicable regulatory environment changes, recent rate orders to other regulated entities, and the status of any pending or potential deregulation legislation. Based on this continual assessment, management believes the existing regulatory assets are probable of recovery. This assessment reflects the current political and regulatory climate at the state, provincial and federal levels, and is subject to change in the future. If future recovery of costs ceases to be probable, the asset write-offs would be required to be recognized in operating income. Total regulatory assets were $1,063 million as of December 31, 2005 and $953 million as of December 31, 2004. Total regulatory liabilities were $420 million as of December 31, 2005 and $425 million as of December 31, 2004. (See Note 4 to the Consolidated Financial Statements, “Regulatory Matters.”)

Long-Lived Asset Impairments and Assets Held For Sale

Duke Capital evaluates the carrying value of long-lived assets, excluding goodwill, when circumstances indicate the carrying value of those assets may not be recoverable. For long-lived assets, impairment would exist when the carrying value exceeds the sum of estimates of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the asset is impaired, the asset’s carrying value is adjusted to its estimated fair value. When alternative courses of action to recover the carrying amount of a long-lived asset are under consideration, a probability-weighted approach is used for developing estimates of future cash flows.

Duke Capital uses the best information available to estimate fair value of its long-lived assets and may use more than one source. Judgment is exercised to estimate the future cash flows, the useful lives of long-lived assets and to determine management’s intent to use the assets. The sum of undiscounted cash flows is primarily dependent on forecasted commodity prices for sales of power, natural gas or NGL, costs of fuel over periods of time consistent with the useful lives of the assets or changes in the real estate market. Management’s intent to use or dispose of assets is subject to re-evaluation and can change over time.

A change in Duke Capital’s plans regarding, or probability assessments of, holding or selling an asset could have a significant impact on the estimated future cash flows. Duke Capital considers various factors when determining if impairment tests are warranted, including but not limited to:

• Significant adverse changes in legal factors or in the business climate;

• A current-period operating or cash flow loss combined with a history of operating or cash flow losses, or a projection or forecast that demonstrates continuing losses associated with the use of a long-lived asset;

• An accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of a long-lived asset;

• Significant adverse changes in the extent or manner in which an asset is used or in its physical condition or a change in business strategy;

• A significant change in the market value of an asset; and

• A current expectation that, more likely than not, an asset will be sold or otherwise disposed of before the end of its estimated useful life.

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Judgment is also involved in determining the timing of meeting the criteria for classification as an asset held for sale under SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” (SFAS No. 144)

During 2005, Duke Capital recorded impairments on several of its long-lived assets. (For additional discussion of these impairments, see Note 12 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale.”)

Duke Capital may dispose of certain other assets in addition to the assets classified as held for sale at December 31, 2005. Accordingly, based in part on current market conditions in the merchant energy industry, it is reasonably possible that Duke Capital’s current estimate of fair value of its long-lived assets being considered for sale at December 31, 2005 and its other long-lived assets, could change and that change may impact the consolidated results of operations. In addition, Duke Capital could decide to dispose of additional assets in future periods, at prices that could be less than the book value of the assets.

Duke Capital uses the criteria in SFAS No. 144 and EITF 03-13, “Applying the Conditions in Paragraph 42 of FAS 144 in Determining Whether to Report Discontinued Operations,” to determine whether components of Duke Capital that are being disposed of or are classified as held for sale are required to be reported as discontinued operations in the Consolidated Statements of Operations. To qualify as a discontinued operation under SFAS No. 144, the component being disposed of must have clearly distinguishable operations and cash flows. Additionally, pursuant to EITF 03-13, Duke Capital must not have significant continuing involvement in the operations after the disposal (i.e. Duke Capital must not have the ability to influence the operating or financial policies of the disposed component) and cash flows of the assets sold must have been eliminated from Duke Capital’s ongoing operations (i.e. Duke Capital 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 Loss From Discontinued Operations, net of tax, in the Consolidated Statements of Operations. If an asset held for sale does not meet the requirements for discontinued operations classification, any impairments and gains or losses on sales are recorded in continuing operations as Gains (Losses) on Sales of Other Assets, net, in the Consolidated Statements of Operations. Impairments for all other long-lived assets, other than goodwill, are recorded as Impairment and Other Charges in the Consolidated Statements of Operations.

Impairment of Goodwill

At December 31, 2005 and 2004, Duke Capital had goodwill balances of $3,775 million and $4,148 million, respectively. Duke Capital evaluates the impairment of goodwill under SFAS No. 142, “Goodwill and Other Intangible Assets.” The majority of Duke Capital’s goodwill at December 31, 2005 relates to the acquisition of Westcoast in March 2002, whose assets were primarily included within the Natural Gas Transmission segment. The remainder relates to International Energy’s Latin American operations and Crescent. As of the acquisition date, Duke Capital allocates goodwill to a reporting unit, which Duke Capital defines as an operating segment or one level below an operating segment. As required by SFAS No. 142, Duke Capital performs an annual goodwill impairment test and updates the test if events or circumstances occur that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Key assumptions used in the analysis include, but are not limited to, the use of an appropriate discount rate, estimated future cash flows and estimated run rates of operation, maintenance, and general and administrative costs. In estimating cash flows, Duke Capital incorporates expected growth rates, regulatory stability and ability to renew contracts as well as other factors into its revenue and expense forecasts. As a result of the 2005 impairment test required by SFAS No. 142, Duke Capital did not record any impairment on its goodwill. Had the discount rate used to determine fair value of the reporting units been 1% lower, there would still not have been any impairment recorded in 2005. In the third quarter of 2003, Duke Capital recorded a $254 million goodwill impairment charge to write off all of DENA’s

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goodwill, most of which related to certain aspects of DENA’s trading and marketing business, and was recorded as a component of continuing operations. This impairment charge reflected the reduction in scope and scale of DETM’s business and the continued deterioration of market conditions affecting DENA during 2003. Duke Capital used a discounted cash flow analysis utilizing the key assumptions described above to perform the analysis.

Management continues to remain alert for any indicators that the fair value of a reporting unit could be below book value and will assess goodwill for impairment as appropriate.

Revenue Recognition

Unbilled and Estimated Revenues. Revenues on sales of natural gas, natural gas transportation, storage and distribution as well as sales of petroleum products, primarily at Natural Gas Transmission and Field Services (prior to deconsolidation on July 1, 2005), are recognized when either the service is provided or the product is delivered. Revenues related to these services provided or products delivered but not yet billed are estimated each month. These estimates are generally based on contract data, regulatory information, estimated distribution usage based on historical data adjusted for heating degree days (a quantitative index used by the energy industry to reflect demand for energy to heat houses and businesses which is calculated over a period of time by adding up the differences between each day’s mean daily temperature and the “balance point” temperature of 65°F), commodity prices and preliminary throughput and allocation measurements. Final bills for the current month are billed and collected in the following month. Differences between actuals and estimates are immaterial.

Trading and Marketing Revenues. The recognition of income in the Consolidated Statements of Operations for derivative activity is primarily dependent on whether the Accrual Model or MTM Model is applied. Prior to January 1, 2003, Duke Capital applied the MTM Model to certain derivative contracts and certain contracts classified as energy trading pursuant to EITF 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities.” With the implementation of EITF 02-03, use of the MTM Model has been restricted to contracts classified as derivatives pursuant to SFAS No. 133. Contracts classified previously as energy trading that do not meet the definition of a derivative are subject to the Accrual Model. While the MTM Model is the default method of accounting for all SFAS No. 133 derivatives, SFAS No. 133 allows for the use of the Accrual Model for derivatives designated as hedges and certain scope exceptions, including the normal purchase and normal sale exception. Duke Capital designates a derivative as a hedge or a normal purchase or normal sale contract in accordance with internal hedge guidelines and the requirements provided by SFAS No. 133. (For further information regarding the Accrual Model or MTM Model, see Risk Management Accounting above. For further information regarding the presentation of gains and losses or revenue and expense in the Consolidated Statements of Operations, see Note 1 to the Consolidated Financial Statements, “Summary of Significant Accounting Policies.”)

LIQUIDITY AND CAPITAL RESOURCES

Known Trends and Uncertainties

Duke Capital will rely primarily upon cash flows from operations to fund its liquidity and capital requirements for 2006. Also, Duke Capital expects net positive cash flows from asset sales and other transaction settlements related to exiting the DENA business. The cash flows from these transactions, along with current cash, cash equivalents and short-term investments, and future cash generated from operations may be distributed to Duke Energy to support its dividend obligation and facilitate additional share repurchases by Duke Energy under its stock repurchase program originally announced in February 2005 and reactivated to permit repurchases of its common stock. The repurchases under the stock repurchase program may commence following Duke Energy’s and Cinergy’s special meetings of their respective shareholders that occurred on March 10, 2006.

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Duke Capital currently anticipates net cash provided by operating activities in 2006 to be impacted by the following:

• The return of collateral as a result of finalizing the transaction with Barclays to transfer or novate a significant portion of DENA’s derivative portfolio to Barclays compared to significant collateral outflows in 2005;

• Payment of approximately $600 million to Barclays, which was made in January 2006, as a result of settling the transaction to transfer or novate a significant portion of DENA’s derivative portfolio to Barclays; and,

• Tax benefits realized from losses on the DENA asset sales to LS Power and the Barclays transaction as compared to significant tax payments in 2005.

Ultimate cash flows from operations are subject to a number of factors, including, but not limited to, regulatory constraints, economic trends, and market volatility (see Item 1A, Risk Factors for details).

Duke Capital projects 2006 capital and investment expenditures of approximately $1.7 billion, primarily consisting of approximately $950 million at Natural Gas Transmission and $650 million at Crescent, including $500 million of residential real estate capital expenditures.

Duke Capital continues to focus on reducing risk and restructuring its business for future success and will invest principally in its strongest business sectors with an overall focus on positive net cash generation. Total projected 2006 capital and investment expenditures include approximately $0.5 billion for maintenance and upgrades of existing plants, pipelines and infrastructure to serve load growth, and approximately $1.2 billion of expansion capital expenditures allocated primarily to Crescent and Natural Gas Transmission. Duke Capital received approximately $1.6 billion in pre-tax proceeds from the sale of DENA’s facilities outside of the Midwest to LS Power during 2006.

Duke Capital anticipates its debt to total capitalization ratio to be 50% by the end of 2006. Duke Capital does not expect its debt balance to change significantly in 2006. Duke Capital monitors compliance with all debt covenants and restrictions, and does not currently believe that it will be in violation or breach of its debt covenants. However, circumstances could arise that may alter that view. If and when management had a belief that such potential breach could exist, appropriate action would be taken to mitigate any such issue. Duke Capital also maintains an active dialogue with the credit rating agencies, and believes that the current credit ratings have stabilized.

As noted previously, in June 2006, the Board of Directors of Duke Energy authorized management to pursue a plan to create two separate publicly traded companies by spinning off Duke Energy’s natural gas business to Duke Energy shareholders. The new gas company, which would be named Spectra Energy, would consist primarily of Duke Capital’s Natural Gas Transmission and Field Services businesses segments. Prior to the distribution, Duke Energy expects to implement an internal reorganization pursuant to which all of the businesses and assets of Duke Capital other than Duke Energy’s natural gas transmission and storage, distribution, and gathering and processing businesses (i.e., such as Crescent, Commercial Power, and Duke Energy International), will be transferred to Duke Energy. Duke Capital will then be transferred to and will thereafter be a direct, wholly-owned subsidiary of, Spectra Energy. After the separation, Duke Capital’s liquidity and capital resource needs will be significantly different from past needs. See “Supplemental Pro Forma Consolidated Financial Information, Management’s Discussion and Analysis of Pro Forma Results of Operations and Financial Condition, Pro Forma Liquidity and Capital Resources” within this Spectra Energy Form 10 for further details.

Operating Cash Flows

Net cash provided by operating activities was $1,097 million in 2005 compared to $2,237 million in 2004, a decrease of $1,140 million. The decrease in cash provided by operating activities was due primarily to approximately $800 million of additional net cash collateral posted by Duke Capital during 2005 attributable to

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increased crude oil prices, as well as increases to the forward market prices of power, an approximate $900 million increase in taxes paid, net of refunds, in 2005, and the impacts of the deconsolidation of DEFS effective July 1, 2005.

Net cash provided by operating activities was $2,237 million in 2004 compared to $1,779 million in 2003, an increase of $458 million. The increase in cash provided by operating activities was due primarily to higher cash settlements from trading and hedging activities, increased earnings related to Field Services, and increased cash flows in 2004 from changes in working capital related primarily to a cash refund received related to income taxes. Duke Capital made a $29 million voluntary contribution to its Westcoast retirement plans (Westcoast plans) in 2004.

Investing Cash Flows

Net cash provided by investing activities was $1,216 million in 2005 compared to $760 million in 2004, an increase in cash provided of $456 million. Net cash provided by investing activities was $760 million in 2004 compared to $644 million in 2003, an increase in cash provided of $116 million.

The primary use of cash related to investing activities is capital and investment expenditures, detailed by business segment in the following table.

Capital and Investment Expenditures by Business Segment

	Years Ended December 31,
	2005		2004		2003
	(in millions)
Natural Gas Transmission	$	930	$	544	$	773
Field Services (c)		86		202		204
Commercial Power		2		6		336
International Energy		23		28		71
Crescent (a)		599		568		290
Other (b)		29		34		(92	)
Total consolidated	$	1,669	$	1,382	$	1,582

(a) Amounts include capital expenditures associated with residential real estate of $355 million in 2005, $322 million in 2004, and $196 million in 2003 which are included in Capital Expenditures for Residential Real Estate within Cash Flows from Operating Activities on the accompanying Consolidated Statements of Cash Flows.

(b) Amount for 2003 include deferral of the consolidation of 50% of the profit earned by D/FD for the construction of DENA’s merchant generation plants, which is associated with Duke Capital’s share of ownership.

(c) As a result of the deconsolidation of DEFS, effective July 1, 2005, Field Services amounts for 2005 only include DEFS capital and investment expenditures for periods prior to July 1, 2005.

Capital and investment expenditures, including Crescent’s residential real estate investments, increased $287 million in 2005 compared to 2004. The increase was due primarily to the approximate $230 million acquisition of the Empress System at Natural Gas Transmission.

The increase in net cash provided by investing activities in 2005 when compared to 2004 was also impacted by proceeds from the sale of TEPPCO GP and Duke Capital’s interest in TEPPCO LP for approximately $1.2 billion and DEFS disposition transaction proceeds of approximately $1.0 billion received in 2005, offset by the approximate $1.4 billion in proceeds received in 2004 primarily from the sales of the Asia-Pacific Business, Southeast Plants and Moapa and Luna partially completed facilities. Additionally, approximately $383 million of

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distributions from equity investees (approximately $310 million for Gulfstream and approximately $73 million for DEFS) were considered returns of equity. Also, during 2004, additional amounts of cash were invested in short-term investments.

Capital and investment expenditures, including Crescent’s residential real estate investments, decreased $200 million in 2004 compared to 2003. The decrease was due primarily to decreased investments in generating facilities at DENA due to the continuing downturn in the merchant energy portion of its business that began in 2002 and decreased investments at Gas Transmission due to the completion of infrastructure projects in Western Canada and New England in 2003.

The increase in net cash provided in 2004 when compared to 2003 was impacted by a $292 million increase in proceeds from the sales of commercial and multi-family real estate at Crescent, due primarily to sales of the Potomac Yard retail center and the Alexandria land tract in 2004.

The increase in cash provided by investing activities in 2004 was also impacted by a $260 million decrease in net proceeds received from the sales of equity investments and other assets, primarily related to large sales activity in 2003 partially offset by the sale of International Energy’s Asia-Pacific Business and DENA’s sale of its Southeast Plants and its Moapa and Luna partially completed facilities, and its Vermillion facilities, in 2004.

Financing Cash Flows and Liquidity

Duke Capital’s consolidated capital structure as of December 31, 2005, including short-term debt, was 46% debt, 51% member’s equity and 3% minority interests. The fixed charges coverage ratio, calculated using SEC guidelines, was 5.0 times for 2005, which includes a pre-tax gain on the sale of TEPPCO GP and LP of approximately $0.9 billion, net of minority interest, and 1.9 times for 2004. Earnings were inadequate to cover fixed charges by $724 million for the year ended December 31, 2003.

Net cash used in financing activities decreased $561 million for the year ended December 31, 2005, compared to 2004. The change was due primarily to approximately $2.5 billion of higher net paydowns of long-term debt, commercial paper, notes payable, and preferred stock of a subsidiary during 2004 in connection with an effort to reduce debt balances, approximately $120 million of lower net distributions to minority interest in 2005, and $110 million of proceeds from the Duke Energy Income Fund. This decrease was partially offset by an increase of approximately $1.8 billion of net distributions to Duke Energy and an increase of approximately $350 million of advances to Duke Energy in 2005 as compared to 2004.

Net cash used in financing activities increased $561 million for the year ended December 31, 2004, compared to 2003. This change was due primarily to a decrease of approximately $1,050 million in capital infusions from Duke Energy, which were partially offset by $475 million of lower net paydowns of long-term debt, commercial paper and notes payable in 2004 as compared to 2003. Total net debt reductions of approximately $3.7 billion in 2004 consisted of approximately $3.0 billion in cash redemptions (see Note 14 to the Consolidated Financial Statements, “Debt and Credit Facilities”) and approximately $840 million of debt retired (as a non-cash financing activity) as part of the sale of International Energy’s Asia-Pacific Business, which were partially offset by minimal issuances of long-term debt. The $840 million does not include the approximately $50 million of Asia-Pacific debt which was placed in trust and fully funded in connection with the closing of the sale transaction and repaid in September 2004. The assets held in the consolidated trust were received from Alinta, Ltd. as part of the sale of the Asia-Pacific Business.

During 2004, $267 million of cash advances were received by Duke Capital from Duke Energy. During the first quarter of 2005, Duke Energy forgave these advances of $267 million and Duke Capital classified the $267 million as an addition to Member’s Equity. Additionally, during the third quarter of 2005, Duke Energy forgave additional advances of $494 million and classified the $494 million as an addition to Member’s Equity. These forgivenesses are presented as a non-cash financing activity in the Consolidated Statements of Cash Flows for the year ended December 31, 2005.

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In April 2005, Duke Capital received a $269 million capital contribution from Duke Energy, which Duke Capital classified as an addition to Member’s Equity.

During 2005, Duke Capital distributed $2.1 billion to its parent, Duke Energy, to principally provide for funding for the execution of Duke Energy’s accelerated share repurchase transaction and to provide funding support for Duke Energy’s dividend. The distribution was primarily obtained from Duke Capital’s portion of the cash proceeds realized from the sale by DEFS of TEPPCO GP and Duke Capital’s sale of its limited partner interest in TEPPCO LP.

Significant Financing Activities. In December 2004, Duke Capital reached an agreement to sell its partially completed Gray’s Harbor power generation facility (Grays Harbor) to an affiliate of Invenergy LLC. In 2004, Duke Capital terminated its capital lease with the dedicated pipeline which would have transported natural gas to Grays Harbor. As a result of this termination, approximately $94 million was paid by Duke Capital in January 2005.

On March 1, 2005, redemption notices were sent to the bondholders of the $100 million PanEnergy 8.625% bonds due in 2025. These bonds were redeemed on April 15, 2005 at a redemption price of 104.03 or approximately $104 million.

In August 2005, DEI issued project-level debt in Peru, of which $75 million is denominated in U.S. dollars and approximately $34 million (in U.S. dollar equivalents as of the issuance date) is denominated in Peru Nuevos Soles. This debt has terms ranging from four to six years as well as variable or fixed interest rate terms, as applicable.

On September 21, 2005, Union Gas entered into a fixed-rate financing agreement denominated in 200 million Canadian dollars (approximately $171 million in U.S. dollar equivalents as of the issuance date) due in 2016 with an interest rate of 4.64%.

In November 2005, International Energy issued floating rate debt in Guatemala for $87 million (in USD) and in El Salvador for $75 million (in USD). These debt issuances have variable interest rate terms and mature in 2015.

In December 2005, the Income Fund, a Canadian income trust fund, was created which sold approximately 40% ownership in the Canadian Midstream operations for proceeds, net of underwriting discount, of approximately $110 million. 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. Duke Capital retains an ownership interest in the Income Fund of approximately 58% and will continue to operate and manage this business.

Available Credit Facilities and Restrictive Debt Covenants. Duke Capital’s 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, 2005, Duke Capital was in compliance with those covenants. In addition, some credit agreements may allow for acceleration of payments or termination of the agreements due to nonpayment, or to the acceleration of other significant indebtedness of the borrower or some of its subsidiaries. None of the debt or credit agreements contain material adverse change clauses.

(For information on Duke Capital’s credit facilities as of December 31, 2005, see Note 14 to the Consolidated Financial Statements, “Debt and Credit Facilities.”)

Duke Capital has approximately $1,600 million of credit facilities which expire in 2006. In the second quarter of 2006, Duke Capital closed on the syndication of $600 million in revolving credit facilities in the United States and 600 million in Canadian dollars. These syndications, which were amendments to and extensions of existing U.S. and Canadian credit facilities, extended the terms of the credit facilities by one year and built in covenant flexibility where appropriate to allow Duke Capital to pursue certain strategic activities, including Duke Energy’s expected separation of the gas and electric businesses.

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During the nine months ended September 30, 2006, Duke Capital’s consolidated credit capacity decreased by approximately $1,263 million, primarily due to the terminations of an $800 million syndicated credit facility and $460 million in bi-lateral credit facilities. The terminations of these credit facilities primarily reflect Duke Capital’s reduced liquidity needs as a result of exiting the DENA business.

Credit Ratings. In February 2004, Standard and Poor’s (S&P) lowered its long-term ratings of Duke Capital and its subsidiaries (with the exception of M&N Pipeline, DEFS and DETM) one ratings level. S&P’s actions were based upon Duke Capital’s weaker than anticipated financial performance in 2003 and the execution risk associated with Duke Capital’s 2004 debt reduction plans. S&P concluded this action by placing Duke Capital and its subsidiaries on Stable Outlook, with the exception of DETM, which remained on Negative Outlook until changed to Stable Outlook in July 2004. In December 2004, S&P changed the outlook of Duke Capital and its subsidiaries (with the exception of M&N Pipeline) from Stable to Positive and then from Positive to Stable in February 2005. The S&P and Dominion Bond Rating Service (DBRS) credit ratings and outlooks for M&N Pipeline have remained unchanged during 2004 and 2005. S&P last affirmed its rating for M&N Pipeline in August 2004 and DBRS last confirmed its rating for M&N Pipeline in March 2005. The DBRS credit ratings for Union Gas remained unchanged during 2004 and 2005 and were last confirmed in June 2005.

In February 2005, Moody’s Investors Service (Moody’s) changed the outlook of Duke Capital from Stable to Negative and placed the ratings of M&N Pipeline under Review for Possible Downgrade. Moody’s concluded their review of M&N Pipeline in August 2005 and downgraded the credit ratings from A1 to A2. Moody’s actions were primarily as a result of their concerns over the downward revisions in the reserve estimates for the Sable Offshore Energy Project (SOEI) and reduced production by SOEI producers. Moody’s concluded their action placing the ratings outlook for M&N Pipeline on Stable.

In May 2005, following the announcement of Duke Energy’s merger with Cinergy, S&P placed the credit ratings of Duke Capital and its subsidiaries (excluding M&N Pipeline) on “CreditWatch with negative implications.” In addition, Moody’s revised the ratings outlook of Duke Capital and Texas Eastern Transmission LP to “Developing” and DBRS placed the credit ratings of Westcoast Energy Inc. “Under Review with Developing Implications.”

In September, 2005 S&P affirmed the credit ratings of Duke Capital and its subsidiaries (excluding M&N Pipeline) with a Stable outlook removing them from “CreditWatch with negative implications.” In addition, DBRS confirmed the credit rating of Westcoast Energy Inc. with a Stable trend removing them from “Under Review with Developing Implications.”

The most recent rating action by S&P occurred in September 2006 when S&P changed the outlook of Duke Capital, Texas Eastern Transmission, LP, Union Gas and Westcoast Energy Inc. (collectively the gas entities) from developing to positive following the completion of their assessment of Duke Energy’s announcement of the separation of the electric and gas businesses. S&P had earlier in June 2006 changed the outlook of the gas entities from positive to developing due to S&P’s uncertainty as to how the new gas company would be capitalized and funded. In May 2006, S&P changed the outlook of Duke Capital and all of its subsidiaries (with the exception of Maritimes & Northeast Pipeline, LLC and Maritimes & Northeast Pipeline, LP (collectively M&N Pipeline) and Duke Energy Trading and Marketing, LLC from stable to positive. In April 2006, following the completion of Duke Energy’s merger with Cinergy, S&P raised the credit rating of Duke Capital one ratings level as disclosed in the table below. S&P last affirmed its rating for M&N Pipeline in July 2006 where it has remained unchanged with a stable outlook for the last several years.

The most recent rating action by Moody’s occurred in October 2006 when the credit ratings of Duke Capital and Texas Eastern Transmission, LP were placed under review for possible upgrade following Moody’s preliminary assessment of Duke Capital’s pending restructuring as a subsidiary of the new natural gas company, which would be named Spectra Energy. In April 2006 upon Duke Energy’s completion of the merger with Cinergy, Moody’s upgraded the credit ratings of Duke Capital and Texas Eastern Transmission, LP one ratings

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level each as disclosed in the table below. Moody’s concluded their April action placing Duke Capital and Texas Eastern Transmission, LP on stable outlook. Moody’s noted in their April action the substantial reduction in business and operating risk of Duke Capital through the restructuring of its ownership in DEFS and the divestiture of the Duke Energy North America merchant generation assets and trading book. Moody’s also noted the upgrade at Texas Eastern Transmission, LP in connection to its parent Duke Capital. In August 2005, Moody’s concluded a review of M&N Pipeline and downgraded the credit ratings one ratings level to the respective ratings disclosed in the table below concluding this action with a stable outlook. Moody’s action was primarily as a result of their concerns over the downward revisions in the reserve estimates for the Sable Offshore Energy Project (SOEI) and reduced production by SOEI producers. In August 2006, Moody’s revised the outlook for Maritimes & Northeast Pipeline, LLC to negative, noting the potential for a somewhat weaker shipper profile resulting from a recently announced expansion project on the U.S. portion of the pipeline.

The most recent rating action by DBRS occurred in June 2006 when DBRS confirmed the stable trend of the entities disclosed in the table below following Duke Energy’s announcement of the separation of the electric and gas businesses. Each of the credit ratings assigned by DBRS to the entities below has remained unchanged for the last several years with a stable trend.

The following table summarizes the November 1, 2006 credit ratings from the agencies retained by Duke Capital to rate its securities, its principal funding subsidiaries and its trading and marketing subsidiary DETM.

Credit Ratings Summary as of November 1, 2006

	Standard and Poor’s	Moody’s Investor Service	Dominion Bond Rating Service
Duke Capital LLC (a)	BBB	Baa2	Not applicable
Texas Eastern Transmission, LP (a)	BBB	Baa1	Not applicable
Westcoast Energy Inc. (a)	BBB	Not applicable	A(low)
Union Gas (a)	BBB	Not applicable	A
Maritimes & Northeast Pipeline, LLC (b)	A	A2	A
Maritimes & Northeast Pipeline, LP (b)	A	A2	A
Duke Energy Trading and Marketing, LLC (c)	BBB-	Not applicable	Not applicable

(a) Represents senior unsecured credit rating

(b) Represents senior secured credit rating

(c) Represents corporate credit rating

Duke Capital’s credit ratings are dependent on, among other factors, the ability to generate sufficient cash to fund capital and investment expenditures and balance distributions to Duke Energy, while maintaining the strength of its current balance sheet. If, as a result of market conditions or other factors, Duke Capital is unable to maintain its current balance sheet strength, or if its earnings and cash flow outlook materially deteriorates, Duke Capital’s credit ratings could be negatively impacted.

Duke Capital and its subsidiaries are required to post collateral under derivatives and other marketing contracts. Typically, the amount of the collateral is dependent upon Duke Capital’s economic position at points in time during the life of a contract and the credit rating of the subsidiary (or its guarantor, if applicable) obligated under the collateral agreement. Business activity by DENA generates the majority of Duke Capital’s collateral requirements. DENA conducts business throughout the United States and Canada through Duke Energy North America LLC and its 100% owned affiliates Duke Energy Marketing America, LLC (DEMA) and Duke Energy Marketing Canada Corp (DEMC). DENA also participates in DETM. During the third quarter of 2005, the Board of Directors of Duke Energy authorized and directed management to execute the sale or disposition of substantially all of DENA’s remaining assets and contracts outside the Midwestern United States.

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On November 18, 2005, Duke Energy announced it signed an agreement to transfer substantially all of the DENA portfolio of derivatives contracts to Barclays. Under the agreement, Barclays will acquire substantially all of DENA’s outstanding gas and power derivatives contracts which essentially eliminates Duke Capital’s credit, collateral, market and legal risk associated with DENA’s derivative trading positions effective on the date of signing. The underlying contracts will transfer to Barclays over a period of months.

A reduction in DETM’s credit rating to below investment grade as of December 31, 2005 would have resulted in Duke Capital posting additional collateral of up to approximately $170 million. Additionally, in the event of a reduction in DETM’s credit rating to below investment grade, collateral agreements may require the segregation of cash held as collateral to be placed in escrow. As of December 31, 2005, Duke Capital would have been required to escrow approximately $350 million of such cash collateral held if DETM’s credit rating had been reduced to below investment grade. Amounts above reflect Duke Capital’s 60% ownership of DETM and the allocation of collateral to DENA for contracts executed by DETM on its behalf.

A reduction in the credit rating of Duke Capital to below investment grade as of December 31, 2005 would have resulted in Duke Capital posting additional collateral of up to approximately $365 million. Additionally, in the event of a reduction in Duke Capital’s credit rating to below investment grade, certain interest rate and foreign exchange swap agreements may require settlement payments due to termination of the agreements. As of December 31, 2005, Duke Capital could have been required to pay up to $5 million in such settlement payments if Duke Capital’s credit rating had been reduced to below investment grade. Duke Capital would fund any additional collateral requirements through a combination of cash on hand and the use of credit facilities. Subsequent to December 31, 2005, in connection with the sale to Barclays of contracts related to DENA’s energy marketing and management activities, Barclays provided DENA cash equal to the net cash collateral posted by DENA under the contracts. As the underlying contracts are transferred to Barclays, the downgrade impact will continue to change until the exit from DENA is completed. A majority of the negative impact of the collateral position has reversed during 2006, upon completion of the DENA exit plan.

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

Other Financing Matters. As of December 31, 2005, Duke Capital and its subsidiaries had effective SEC shelf registrations for up to $592 million in gross proceeds from debt and other securities. The total amount available under effective shelf registrations decreased $500 million as compared to December 31, 2004, resulting from the de-registering of DEFS on January 31, 2005. Additionally, as of December 31, 2005, Duke Capital had access to 200 million Canadian dollars (approximately U.S. $172 million) available under the Canadian shelf registrations for issuances in the Canadian market. This amount represents a decrease of 700 million Canadian dollars as compared to December 31, 2004, primarily resulting from the November 2005 expiration of a 500 million shelf registration. In the first quarter of 2006, management has plans to renew the 500 million Canadian dollar shelf registration that expired in November 2005. A shelf registration is effective in Canada for a 25-month period. The 200 million Canadian dollars that is available as of December 31, 2005 will expire in July 2006.

While maintaining the financial strength of the consolidated company, Duke Energy has the ability to provide equity support to Duke Capital, as long as the source of the support excludes Duke Energy debt and trust preferred security funding. Duke Energy intends to provide such equity support as needed.

Duke Capital continues to review its policy with respect to paying future distributions and anticipates periodic distributions during 2006 to facilitate Duke Energy’s stock repurchase program and to provide funding support for Duke Energy’s dividend.

Off-Balance Sheet Arrangements

Duke Capital and certain of its subsidiaries enter into guarantee arrangements in the normal course of business to facilitate commercial transactions with third parties. These arrangements include financial and

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performance guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications. (See Note 17 to the Consolidated Financial Statements, “Guarantees and Indemnifications,” for further details of the guarantee arrangements.)

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

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

Duke Capital does not have any material off-balance sheet financing entities or structures, except for normal operating lease arrangements and guarantee arrangements. (For additional information on these commitments, see Note 16 to the Consolidated Financial Statements, “Commitments and Contingencies” and Note 17 to the Consolidated Financial Statements, “Guarantees and Indemnifications.”)

Contractual Obligations

Duke Capital enters into contracts that require payment of cash at certain specified periods, based on certain specified minimum quantities and prices. The following table summarizes Duke Capital’s contractual cash obligations for each of the periods presented. The table below excludes all amounts classified as current liabilities on the Consolidated Balance Sheets, other than current maturities of long-term debt. It is expected that the majority of current liabilities on the Consolidated Balance Sheets will be paid in cash in 2006.

Contractual Obligations as of December 31, 2005

	Payments Due By Period
	Total		Less than 1 year (2006)		2-3 Years (2007 & 2008)		4-5 Years (2009 & 2010)		More than 5 Years (Beyond 2010)
	(in millions)
Long-term debt (a)	$	16,446	$	2,043	$	2,246	$	2,990	$	9,167
Capital leases (a)		21		10		5		3		3
Operating leases (b)		241		39		59		49		94
Purchase Obligations: (g)
Firm capacity payments (c)		1,461		292		303		263		603
Energy commodity contracts (d)		14,416		4,965		5,910		3,076		465
Other purchase obligations (e)		1,631		678		184		157		612
Other long-term liabilities on the Consolidated Balance Sheets (f)		44		44		—		—		—
Total contractual cash obligations	$	34,260	$	8,071	$	8,707	$	6,538	$	10,944

(a) See Note 14 to the Consolidated Financial Statements, “Debt and Credit Facilities.” Amount includes interest payments over life of debt or capital lease.

(b) See Note 16 to the Consolidated Financial Statements, “Commitments and Contingencies.”

(c) Includes firm capacity payments that provide Duke Capital with uninterrupted firm access to natural gas transportation and storage, electricity transmission capacity, refining capacity and the option to convert natural gas to electricity at third-party owned facilities (tolling arrangements) in some natural gas and power locations throughout North America.

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(d) Includes contractual obligations to purchase physical quantities of electricity, natural gas and NGLs. Amount includes certain normal purchases, energy derivatives and hedges per SFAS No. 133. For contracts where the price paid is based on an index, the amount is based on forward market prices at December 31, 2005. For certain of these amounts, Duke Capital may settle on a net cash basis since Duke Capital has entered into payment netting agreements with counterparties that permit Duke Capital to offset receivables and payables with such counterparties. A significant portion of these amounts pertain to DENA’s physical purchase commitments of electricity. Since DENA primarily markets electricity, consideration should be given to DENA’s forward sales of electricity, which exceed their forward purchases, when assessing the potential implications of these physical purchase commitments. (See Note 12 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale,” for more information regarding DENA’s exit plan.)

(e) Includes purchase commitments for outsourcing of certain real estate services, contracts for software and consulting or advisory services. Amount also includes contractual obligations for engineering, procurement and construction costs for pipeline and real estate projects, and major maintenance of certain merchant plants. Amount excludes certain open purchase orders for services that are provided on demand, and the timing of the purchase can not be determined.

(f) Includes expected retirement plan contributions for 2006 (see Note 19 to the Consolidated Financial Statements, “Employee Benefit Plans”). The amount of cash flows to be paid to settle the asset retirement obligations is not known with certainty as Duke Capital may use internal resources or external resources to perform retirement activities. As a result, cash obligations for asset retirement activities are excluded. Asset retirement obligations recognized on the Consolidated Balance Sheets total $29 million at December 31, 2005. Amount excludes reserves for litigation, environmental remediation and self-insurance claims (see Note 16 to the Consolidated Financial Statements, “Commitments and Contingencies”) because Duke Capital is uncertain as to the timing of when cash payments will be required. Additionally, amount excludes annual insurance premiums that are necessary to operate the business, funding of other post-employment benefits (see Note 19 to the Consolidated Financial Statements, “Employee Benefit Plans”) and regulatory credits (see Note 4 to the Consolidated Financial Statements, “Regulatory Matters”) because the amount and timing of the cash payments are uncertain. Also amount excludes Deferred Income Taxes and Investment Tax Credits on the Consolidated Balance Sheets since cash payments for income taxes are determined based primarily on taxable income for each discrete fiscal year. Liabilities Associated with Assets Held for Sale (see Note 12 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale”) are also excluded as Duke Capital expects these liabilities will be assumed by the buyer upon sale of the assets.

(g) Purchase obligations reflected in the Consolidated Balance Sheets have been excluded from the above table, including approximately $600 million of amounts due to Barclays (see Note 12 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held For Sale”) which were paid in January 2006.

Quantitative and Qualitative Disclosures About Market Risk

Risk and Accounting Policies

Duke Capital is exposed to market risks associated with commodity prices, credit exposure, interest rates, equity prices and foreign currency exchange rates. Management has established comprehensive risk management policies to monitor and manage these market risks. Duke Energy’s Chief Executive Officer and Chief Financial Officer are responsible for the overall approval of market risk management policies and the delegation of approval and authorization levels. Duke Energy’s Executive Committee which is composed of senior executives, receives periodic updates from the Chief Risk Officer (CRO) and other members of management, on market risk positions, corporate exposures, credit exposures and overall risk management activities. The CRO is responsible for the overall governance of managing credit risk and commodity price risk, including monitoring exposure limits.

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

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Commodity Price Risk

Duke Capital is exposed to the impact of market fluctuations in the prices of natural gas, electricity, NGLs and other energy-related products marketed and purchased as a result of its ownership of energy related assets, remaining proprietary trading contracts, and interests in structured contracts classified as undesignated. Duke Capital employs established policies and procedures to manage its risks associated with these market fluctuations using various commodity derivatives, including forward contracts, futures, swaps and options. (See Note 1 to the Consolidated Financial Statements, “Summary of Significant Accounting Policies” and Note 7 to the Consolidated Financial Statements, “Risk Management and Hedging Activities, Credit Risk, and Financial Instruments.”)

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

Hedging Strategies. Duke Capital closely monitors the risks associated with these commodity price changes on its future operations and, where appropriate, uses various commodity instruments such as electricity, natural gas, crude oil and NGL forward contracts to mitigate the effect of such fluctuations on operations. Duke Capital’s primary use of energy commodity derivatives is to hedge the output and production of assets and other contractual positions it owns.

To the extent that instruments accounted for as hedges are effective in offsetting the transaction being hedged, there is no impact to the Consolidated Statements of Operations until delivery or settlement occurs. Accordingly, assumptions and valuation techniques for these contracts have no impact on reported earnings prior to settlement. Several factors influence the effectiveness of a hedge contract, including counterparty credit risk and using contracts with different commodities or unmatched terms. Hedge effectiveness is monitored regularly and measured each month. (See Note 1 to the Consolidated Financial Statements, “Summary of Significant Accounting Policies” and Note 7 to the Consolidated Financial Statements, “Risk Management and Hedging Activities, Credit Risk, and Financial Instruments.”)

In addition to the hedge contracts described above and recorded on the Consolidated Balance Sheets, Duke Capital enters into other contracts that qualify for the normal purchases and sales exception described in paragraph 10 of SFAS No. 133 and DIG Issue No. C15. For contracts qualifying for the scope exception, no recognition of the contract’s fair value in the Consolidated Financial Statements is required until settlement of the contract 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 Capital has applied this scope exception for certain contracts involving the purchase and sale of electricity at fixed prices in future periods. As discussed in Critical Accounting Policies and Estimates for risk management activities, Duke Capital determined that the majority of all forward contracts to sell power entered into after July 1, 2003 will be designated as cash flow hedges. Income statement recognition for the contracts 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. However, Duke Capital’s decisions to sell DENA’s Southeast Plants, reduce DENA’s interest in partially completed plants and sale or disposition of substantially all of DENA’s remaining physical and commercial assets outside of the Midwestern United States and certain contractual positions related to the Midwestern assets (see Normal Purchases and Normal Sales below) required the reassessment of all associated derivatives, including normal purchases and normal sales. This required a change from the application of the Accrual Model to the MTM Model for these contracts and resulted in recording substantial unrealized losses that had not previously been recognized in the Consolidated Financial Statements.

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Duke Capital’s largest commodity exposure is due to market price fluctuations of NGLs primarily in the Field Services segment and, to a lesser extent, in the Natural Gas Transmission segment. Based on a sensitivity analysis as of December 31, 2005, it was estimated that price changes of ten cents per gallon and fifteen cents per gallon in the price of NGLs (net of related hedges and an equivalent price change in crude oil) would have a corresponding effect on pre-tax income of approximately $75 million and $105 million, respectively. Comparatively, a ten cent price change sensitivity analysis as of December 31, 2004 would impact pre-tax income by approximately $60 million. The equivalent effect on pre-tax income for 2006 or 2005 was also not expected to be material as of December 31, 2005 or 2004 for exposures to other commodities’ price changes. These hypothetical calculations consider existing hedge positions and estimated production levels, but do not consider other potential effects that might result from such changes in commodity prices.

Normal Purchases and Normal Sales. 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 DENA’s remaining assets and contracts outside the Midwestern United States, approximately 6,100 megawatts of power generation, and certain contractual positions related to the Midwestern assets (see Note 12 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale”). As a result of this decision, Duke Capital recognized a pre-tax loss of approximately $1.9 billion in the third quarter of 2005 for the disqualification of its power and gas forward sales contracts previously designated under the normal purchases normal sales exception. This loss is partially offset by the recognition of a pre-tax gain of approximately $1.2 billion for the discontinuance of hedge accounting for natural gas and power cash flow hedges. As of December 31, 2005, there are approximately $10 million of pre-tax deferred net losses in AOCI related to certain DENA cash flow hedges, which will be recognized within the next twelve months in discontinued operations, net of tax. Duke Capital transfered the Midwestern generation assets of DENA, representing approximately 3,600 megawatts of power generation to Cinergy, and combined with Cinergy’s commercial operations in April 2006 which provides a sustainable business model for these assets in the region (see Note 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions” for further details on the Cinergy merger).

Trading and Undesignated Contracts. The risk in the MTM portfolio is measured and monitored on a daily basis utilizing a Value-at-Risk model to determine the potential one-day favorable or unfavorable Daily Earnings at Risk (DER) as described below. DER is monitored daily in comparison to established thresholds. Other measures are also used to limit and monitor risk in the trading portfolio on monthly and annual bases. These measures include limits on the nominal size of positions and periodic loss limits.

DER computations are based on historical simulation, which uses price movements over an eleven day period. The historical simulation emphasizes the most recent market activity, which is considered the most relevant predictor of immediate future market movements for natural gas, electricity and other energy-related products. DER computations use several key assumptions, including a 95% confidence level for the resultant price movement and the holding period specified for the calculation. Duke Capital’s DER amounts for commodity derivatives recorded using the MTM Model are shown in the following table.

Daily Earnings at Risk

	Period Ending One-Day Impact on Pre-tax Income from Continuing and Discontinued Operations for 2005		Estimated Average One- Day Impact on Pre-tax Income from Continuing and Discontinued Operations for 2005		Estimated Average One- Day Impact on Pre-tax Income from Continuing and Discontinued Operations for 2004		High One-Day Impact on Pre-tax Income from Continuing and Discontinued Operations for 2005		Low One-Day Impact on Pre-tax Income from Continuing and Discontinued Operations for 2005
	(in millions)
Calculated DER (a)	$	12	$	10	$	15	$	67	$	1

(a) DER measures the MTM portfolio’s impact on earnings. While this calculation includes both trading and undesignated contracts, the trading portion, as defined by EITF 02-03, is not material.

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The DER figures above do not include the hedges which were discontinued as a result of the transfer of 19.7% of Duke Capital’s interest in DEFS to ConocoPhillips (see Note 7 to the Consolidated Financial Statements, “Risk Management and Hedging Activities, Credit Risk, and Financial Instruments”). The DER figures as of and for the year ended December 31, 2005 were impacted by the DENA exit plan and the resulting decision to move the DENA hedges to the mark-to-market portfolio as well as commodity price volatility due to Hurricane Rita. The calculated consolidated DER at December 31, 2005 consists of approximately $11 million related to discontinued operations and an immaterial amount related to continuing operations. DENA’s DER at June 30, 2006 was zero due to the DENA wind-down.

DER is an estimate based on historical price volatility. Actual volatility can exceed assumed results. DER also assumes a normal distribution of price changes; thus, if the actual distribution is not normal, the DER may understate or overstate actual results. DER is used to estimate the risk of the entire portfolio, and for locations that do not have daily trading activity, it may not accurately estimate risk due to limited price information. Stress tests are employed in addition to DER to measure risk where market data information is limited. In the current DER methodology, options are modeled in a manner equivalent to forward contracts which may understate the risk.

Duke Capital’s exposure to commodity price risk is influenced by a number of factors, including contract size, length, market liquidity, location and unique or specific contract terms. The following table illustrates the movement in the fair value of Duke Capital’s trading instruments during 2005.

Fair Value of Duke Capital’s Trading Contracts as of December 31, 2005

Asset/(Liability) Sources of Fair Value	Maturity in 2006		Maturity in 2007		Maturity in 2008		Maturity in 2009 and Thereafter		Total Fair Value
	(in millions)
Prices supported by quoted market prices and other external sources	$	—	$	2	$	1	$	2	$	5
Prices based on models and other valuation methods		—		—		—		—		—
Total	$	—	$	2	$	1	$	2	$	5

The “prices supported by quoted market prices and other external sources” category includes Duke Capital’s New York Mercantile Exchange (NYMEX) futures positions in natural gas, crude oil, propane, heating oil, and unleaded gasoline. The NYMEX has quoted monthly natural gas prices for the next 72 months and quoted monthly crude oil prices for the next 72 months. The NYMEX has quoted monthly prices for varying periods of 18 months or less for propane, heating oil, and unleaded gasoline. In addition, this category includes Duke Capital’s forward positions and options in natural gas, natural gas basis swaps, and power at points for which over-the-counter (OTC) broker quotes are available. On average, OTC quotes for power and natural gas forwards and swaps extend 36 months into the future. OTC quotes for natural gas options extend 12 months into the future, on average. Duke Capital values these positions using internally developed forward market price curves that are validated and recalibrated against OTC broker quotes. This category also includes “strip” transactions whose prices are obtained from external sources and then modeled to daily or monthly prices as appropriate.

The “prices based on models and other valuation methods” category includes (i) the value of options not quoted by an exchange or OTC broker, (ii) the value of transactions for which an internally developed price curve was constructed as a result of the long dated nature of the transaction or the illiquidity of the market point, and (iii) the value of structured transactions. In certain instances structured transactions can be decomposed and modeled by Duke Capital as simple forwards and options based on actively quoted prices. Although the valuation of the individual simple structures may be based on quoted market prices, the effective model price for any given period is a combination of prices from two or more different instruments and such transactions therefore are included in this category due to its complex nature. As a result of the adoption of EITF 02-03 in January 2003, all of the contracts in the “prices based on models and other valuation methods” category as of December 31, 2005 are derivatives as defined by SFAS No. 133.

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Credit Risk

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

Duke Capital’s principal customers for power and natural gas marketing and transportation services are industrial end-users, marketers, local distribution companies and utilities located throughout the U.S., Canada and Latin America. Duke Capital has concentrations of receivables from natural gas and electric utilities and their affiliates, as well as industrial customers and marketers throughout these regions. These concentrations of customers may affect Duke Capital’s overall credit risk in that risk factors can negatively impact the credit quality of the entire sector. Where exposed to credit risk, Duke Capital analyzes the counterparties’ financial condition prior to entering into an agreement, establishes credit limits and monitors the appropriateness of those limits on an ongoing basis.

The following table represents Duke Capital’s distribution of unsecured credit exposure with the largest 30 enterprise credit exposures at December 31, 2005. These credit exposures are aggregated by ultimate parent company, include on and off balance sheet exposures, are presented net of collateral, and take into account contractual netting rights.

Distribution of Largest 30 Enterprise Credit Exposures

As of December 31, 2005

	% of Total
Investment Grade—Externally Rated	72%
Non-Investment Grade—Externally Rated	11%
Investment Grade—Internally Rated	11%
Non-Investment Grade—Internally Rated	6%
Total	100%

“Externally Rated” represents enterprise relationships that have published ratings from at least one major credit rating agency. “Internally Rated” represents those relationships which have no rating by a major credit rating agency. For those relationships, Duke Capital utilizes appropriate risk rating methodologies and credit scoring models to develop an internal risk rating which is intended to map to an external rating equivalent. The total of the unsecured credit exposure included in the table above represents approximately 89% of the gross fair value of Duke Capital’s Receivables and Unrealized Gains on Mark-to-Market and Hedging Transactions on the Consolidated Balance Sheets at December 31, 2005.

Duke Capital had no net exposure to any one customer that represented greater than 10% of the gross fair value of trade accounts receivable and unrealized gains on mark-to-market and hedging transactions at December 31, 2005. Based on Duke Capital’s policies for managing credit risk, its exposures and its credit and other reserves, Duke Capital does not anticipate a materially adverse effect on its financial position or results of operations as a result of non-performance by any counterparty.

DENA (within Other) represents the majority of Duke Capital’s unsecured credit exposure. On November 18, 2005, Duke Capital announced it signed an agreement to transfer substantially all of the DENA portfolio of derivatives contracts to Barclays. During 2006, Barclays acquired substantially all of DENA’s outstanding gas and power derivatives contracts which essentially eliminates Duke Capital’s credit, collateral, market and legal risk associated with DENA’s derivative trading positions effective on the date of signing.

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In 1999, the Industrial Development Corp of the City of Edinburg, Texas (IDC) issued approximately $100 million in bonds to purchase equipment for lease to Duke Hidalgo (Hidalgo), a subsidiary of Duke Capital. Duke Capital unconditionally and irrevocably guaranteed the lease payments of Hidalgo to IDC through 2028 due to IDC. In 2000, Hidalgo was sold to Calpine Corporation and Duke Capital remained obligated under the lease guaranty. Total maximum exposure under the guarantee obligation as of December 31, 2005 is approximately $200 million, including principal and interest payments. In January 2006, Hidalgo and its subsidiaries filed for bankruptcy protection in connection with the previous bankruptcy filing by its parent, Calpine Corporation in December 2005. Duke Capital does not believe a loss under the guarantee obligation is probable as of December 31, 2005, but continues to evaluate the situation. Therefore, no reserves have been recorded for any contingent loss as of December 31, 2005. No demands for payment have been made under the guarantee. If losses are incurred under the guarantee, Duke Capital has certain rights which should allow it to economically recover such loss. As such recovery is a contingent gain, the timing of recognition of as well as the value of any future recovery may vary.

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

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

Collateral amounts held or posted may be fixed or may vary depending on the terms of the collateral agreement and the nature of the underlying exposure and cover trading, normal purchases and normal sales, and hedging contracts outstanding. Duke Capital 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 Capital’s and its counterparties’ publicly disclosed credit ratings impact the amounts of additional collateral to be posted. If Duke Capital or its affiliates have a credit rating downgrade, it could result in reductions in Duke Capital’s unsecured thresholds granted by counterparties. Likewise, downgrades in credit ratings of counterparties could require counterparties to post additional collateral to Duke Capital and its affiliates. (See Liquidity and Capital Resources—Financing Cash Flows and Liquidity for additional discussion of downgrades.)

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

Interest Rate Risk

Duke Capital is exposed to risk resulting from changes in interest rates as a result of its issuance of variable-rate debt and commercial paper. Duke Capital manages its interest rate exposure by limiting its variable-rate exposures to percentages of total capitalization and by monitoring the effects of market changes in interest rates. Duke Capital 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, 7, 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.”, respectively.)

Based on a sensitivity analysis as of December 31, 2005, it was estimated that if market interest rates average 1% higher (lower) in 2006 than in 2005, interest expense, net of offsetting impacts in interest income,

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would increase (decrease) by approximately $2 million. Comparatively, based on a sensitivity analysis as of December 31, 2004, had interest rates averaged 1% higher (lower) in 2004 than in 2003, it was estimated that interest expense, net of offsetting impacts in interest income, would have increased (decreased) by approximately $4 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, 2005 and 2004. The decrease in interest rate sensitivity was primarily due to a decrease in outstanding variable-rate commercial paper, net of invested cash and swaps, offset by an increase in other debt. 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 Capital’s financial structure.

Equity Price Risk

Bison, Duke Capital’s wholly owned captive insurance subsidiary, maintains investments to fund various business risks and losses, such as workers compensation, property, business interruption and general liability. Those investments are exposed to price fluctuations in equity markets and changes in interest rates.

Duke Capital participates in Duke Energy Corporation’s non-contributory defined benefit retirement and postretirement benefit plans. The costs of providing non-contributory defined benefit retirement and postretirement benefit plans are dependent upon a number of factors, such as the rates of return on plan assets, discount rate, the rate of increase in health care costs and contributions made to the plans. The market value of Duke Energy’s defined benefit retirement plan assets has been affected by changes in the equity market since 2000. Westcoast has a $46 million minimum pension liability recorded as of December 31, 2005, recorded as a reduction to AOCI, net of income taxes.

Foreign Currency Risk

Duke Capital is exposed to foreign currency risk from investments in international affiliate businesses owned and operated in foreign countries and from certain commodity-related transactions within domestic operations. To mitigate risks associated with foreign currency fluctuations, contracts may be denominated in or indexed to the U.S. Dollar and/or local inflation rates, or investments may be hedged through debt denominated or issued in the foreign currency. Duke Capital may also use foreign currency derivatives, where possible, to manage its risk related to foreign currency fluctuations. To monitor its currency exchange rate risks, Duke Capital uses sensitivity analysis, which measures the impact of devaluation of the foreign currencies to which it has exposure.

As of December 31, 2005, Duke Capital’s primary foreign currency rate exposures were the Canadian Dollar and the Brazilian Real. A 10% devaluation in the currency exchange rate as of December 31, 2005 in all of Duke Capital’s exposure currencies would result in an estimated net pre-tax loss on the translation of local currency earnings of approximately $30 million to Duke Capital’s Consolidated Statements of Operations. The Consolidated Balance Sheets would be negatively impacted by approximately $550 million currency translation through the cumulative translation adjustment in AOCI.

OTHER ISSUES

Duke Energy Merger with Cinergy. On April 3, 2006, Duke Energy completed its previously announced merger with Cinergy. In conjunction with the merger, Duke Energy transferred the operations of Duke Energy Merchants, LLC and Duke Energy Merchant Finance, LLC (collectively DEM) to Duke Capital, Duke Capital transferred the operations of its wholly-owned captive insurance subsidiary, Bison Insurance Company Limited (Bison), to Duke Energy and Duke Capital indirectly transferred to CG&E, a subsidiary of Cinergy, its ownership interest in DENA’s Midwestern assets.

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In connection with the transfer of the Midwestern assets, Duke Capital transferred to CG&E approximately $1.6 billion of assets at their carrying value and approximately $0.1 billion of liabilities at their carrying value, for a net transfer of approximately $1.5 billion. In connection with the transfer of DENA’s Midwestern assets, Duke Capital and CG&E entered into an arrangement through April 2016, unless otherwise extended by the parties, whereby Duke Capital will reimburse CG&E in the event of certain cash shortfalls that may result from CG&E’s ownership of the Midwestern assets.

As a result of Duke Energy’s merger with Cinergy, Duke Capital and its subsidiaries entered into a tax sharing agreement with Duke Energy, effective April 1, 2006, where the separate return method is used to allocate income taxes to the subsidiaries based on the results of their operations. The accounting for income taxes essentially represents the income taxes that Duke Capital would incur if Duke Capital were a separate company filing its own tax return as a C-Corporation. Prior to entering into this tax sharing agreement, Duke Capital and Duke Energy Americas (DEA) were pass-through entities for U.S. income tax purposes. As a result, on April 1, 2006, all deferred taxes related to Duke Capital and DEA, which previously flowed through to Duke Capital’s parent, Duke Energy, were reinstated, resulting in an increase in Member’s Equity of approximately $37 million.

Plan to Separate Duke Energy’s Natural Gas and Electric Power Business. In June 2006, the Board of Directors of Duke Energy authorized management to pursue a plan to create two separate publicly traded companies by spinning off Duke Energy’s natural gas business to Duke Energy shareholders. The new gas company, which would be named Spectra Energy, would consist primarily of Duke Capital’s Natural Gas Transmission and Field Services businesses segments. Prior to the distribution, Duke Energy expects to implement an internal reorganization pursuant to which all of the businesses and assets of Duke Capital other than Duke Energy’s natural gas transmission and storage, distribution, and gathering and processing businesses (i.e., such as Crescent, Commercial Power, and Duke Energy International), will be transferred to Duke Energy. Duke Capital will then be transferred to and will thereafter be a direct, wholly-owned subsidiary of Spectra Energy. While the actual timing of the spin off, if it occurs, is dependent upon the resolution of certain regulatory and other matters, Duke Energy is currently targeting a January 1, 2007 effective date for the transaction. It is anticipated that approximately $9 billion of debt currently at Duke Capital and its consolidated subsidiaries would transfer to the new natural gas company at the time of the spin-off. Additionally, as a result of the spin-off, Duke Capital is expected to indemnify Duke Energy for certain amounts paid under existing guarantees of wholly-owned subsidiaries that will become guarantees of third party performance upon the separation of the gas and power businesses. Duke Energy expects the transaction to qualify for tax-free treatment for U.S. federal income tax purposes to both Duke Energy and its shareholders and is still evaluating other income tax impacts of the transaction. The transaction required Virginia State Corporation Commission approval, which was received during the third quarter of 2006. In addition, approval from the Federal Communications Commission would be required for the indirect change in control over various licenses from Duke Energy to the new gas company. Duke Energy made the requisite applications in the third quarter 2006. This spin-off will likely have a material impact on Duke Capital’s consolidated results of operations, cash flows and financial condition, as well as liquidity and capital resources.

Sale of 51% of Crescent. On September 7, 2006, an indirect wholly owned subsidiary of Duke Capital closed an agreement to create a joint venture of Crescent (the Crescent JV) with Morgan Stanley Real Estate Fund V U.S., L.P. (MSREF) and other affiliated funds controlled by Morgan Stanley (collectively the MS Members). Under the agreement, the Duke Capital subsidiary contributed all of the membership interests in Crescent to a newly-formed joint venture, which was ascribed an enterprise value of approximately $2.1 billion as of December 31, 2005. In conjunction with the formation of the Crescent JV, the joint venture, Crescent and Crescent’s subsidiaries entered into a credit agreement with third party lenders under which Crescent borrowed approximately $1.23 billion, of which approximately $1.19 billion was immediately distributed to Duke Capital. Immediately following the debt transaction, the MS Members collectively acquired a 49% membership interest in the Crescent JV from Duke Capital for a purchase price of approximately $415 million. The MS Members 49% interest reflects a 2% interest in the Crescent JV issued by the joint venture to the President and Chief Executive Officer of Crescent which is subject to forfeiture if the executive voluntarily leaves the employment of

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the Crescent JV within a three year period. Additionally, this interest can be put back to the Crescent JV after three years or possibly earlier upon the occurrence of certain events at an amount equal to 2% of the fair value of the Crescent JV’s equity as of the put date. Therefore, the Crescent JV will accrue the obligation related to the put as a liability over the three year forfeiture period. Accordingly, Duke Capital has an effective 50% ownership in the equity of the Crescent JV for financial reporting purposes.

In conjunction with this transaction, Duke Capital has recognized a pre-tax gain on the sale of approximately $250 million in the quarter ended September 30, 2006. As a result of the Crescent transaction, Duke Capital no longer controls the Crescent JV and on September 7, 2006 deconsolidated its investment in Crescent and subsequently will account for its investment in the Crescent JV utilizing the equity method of accounting. Duke Capital’s equity investment in the Crescent JV is approximately $163 million as of September 30, 2006.

Energy Policy Act of 2005. The Energy Policy Act of 2005 was signed into law in August 2005. The legislation directs specified agencies to conduct a significant number of studies on various aspects of the energy industry and to implement other provisions through rulemakings. Among the key provisions, the Energy Policy Act of 2005 repeals the PUHCA of 1935, directs FERC to establish a self-regulating electric reliability organization governed by an independent board with FERC oversight, extends the Price Anderson Act for 20 years (until 2025), provides loan guarantees, standby support and production tax credits for new nuclear reactors, gives FERC enhanced merger approval authority, provides FERC new backstop authority for the siting of certain electric transmission projects, streamlines the processes for approval and permitting of interstate pipelines, and reforms hydropower relicensing (the process of renewing the license to operate a hydropower plant). FERC’s enhanced merger authority will not apply to transactions pending with the FERC as of August 8, 2005, such as the anticipated Duke Energy and Cinergy merger, as discussed in Note 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions.” In late 2005 and early 2006, FERC initiated several rulemakings as directed by the Energy Policy Act of 2005. Duke Capital is currently evaluating these proposals and does not anticipate that these rulemakings will have a material adverse effect on its consolidated results of operations, cash flows or financial position.

Global Climate Change. The United Nations-sponsored Kyoto Protocol, which prescribes specific greenhouse gas emission-reduction targets for developed countries, became effective February 16, 2005. Of the countries where Duke Capital has assets, Canada is presently the only one that has a greenhouse gas reduction obligation under the Kyoto Protocol. That obligation is to reduce average greenhouse gas emissions to 6 percent below their 1990 level over the period 2008 to 2012. The Canadian Government’s strategy for achieving its Kyoto reduction target includes, among other things, an emissions intensity-based greenhouse gas cap-and-trade program for large final emitters (companies that produce goods in emissions intensive sectors including primary energy production, electricity production, and selected areas of mining and manufacturing production) (LFE). A final LFE rule could be issued sometime in 2006. If an LFE program is ultimately enacted, then all of Duke Capital’s Canadian operations would likely be subject to the program beginning in 2008, with compliance options ranging from the purchase of greenhouse gas credits to actual emission reductions at the source, or a combination of strategies.

The United States is not a party to the Kyoto Protocol. Instead, the U.S. greenhouse gas policy currently favors voluntary actions, continued research, and technology development over near-term mandatory greenhouse gas reduction requirements. Although several bills have been introduced in Congress that would compel carbon dioxide (CO₂) emission reductions, none have advanced through the legislature and presently there are no federal mandatory greenhouse gas reduction requirements. The likelihood of a federally mandated CO₂ emissions reduction program being enacted in the near future, or the specific requirements of any such regime, is highly uncertain. Several states have taken legislative or regulatory steps to manage greenhouse gas emissions; none of which will impact Duke Capital’s operations. A number of U.S. states in the Northeast and far West are discussing the enactment of either state-specific or regional programs that could mandate future reductions in greenhouse gas emissions, or otherwise manage those emissions, although the outcome of those state discussions is highly uncertain.

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Duke Capital supports the enactment of U.S. federal legislation that would encourage a gradual transition to a lower-carbon-intensive economy. Legislation preferably would be in the form of a federal-level carbon tax or

other market based mechanism that provides the policy advantages of a carbon tax approach and also applies to all sectors of the economy. Duke Capital, believing that it is in the best interest of its investors and customers to do so, is actively participating in the evolution of federal policy on this important issue.

Duke Capital’s proactive role in climate change policy debates in the United States does not change the uncertainty around climate change policy. Due to the speculative outlook regarding any U.S. federal and state policies and the uncertainty of the Canadian policy, Duke Capital cannot estimate the potential effect of either nation’s greenhouse gas policy on its future consolidated results of operations, cash flows or financial position. Duke Capital will assess and respond to the potential implications of greenhouse gas policies for its business operations in the United States and Canada if policies become sufficiently developed and certain to support a meaningful assessment.

Hurricane Damage. Duke Capital continues to assess and monitor damage assessments related to Hurricanes Katrina and Rita in the Gulf Coast. Duke Capital has recorded all losses known to date, and is currently not aware of any additional damages incurred which will have a material adverse impact on its consolidated results of operations, cash flows, or financial position. During 2005, Duke Capital incurred net expenses of approximately $40 million (net of reinsurance receivables) related to Hurricanes Katrina and Rita.

(For additional information on other issues related to Duke Capital, see the section entitled “Legal Proceedings,” Note 4 to the Consolidated Financial Statements, “Regulatory Matters” and Note 16 to the Consolidated Financial Statements, “Commitments and Contingencies.”)

New Accounting Standards

The following new accounting standards were issued, but have not yet been adopted by Duke Capital as of December 31, 2005:

SFAS No. 123 (Revised 2004), “Share-Based Payment” (SFAS No. 123R). In December of 2004, the FASB issued SFAS No. 123R, which replaces SFAS No. 123, “Accounting for Stock Based Compensation,” and supersedes Accounting Principles Board (APB) Opinion 25, “Accounting for Stock Issued to Employees.” SFAS No. 123R 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, timing for implementation of SFAS No. 123R is January 1, 2006. The pro forma disclosures previously permitted under SFAS No. 123 will no longer be an acceptable alternative. Instead, Duke Capital will be required to record compensation expense in the Consolidated Statements of Operations for stock options. Under SFAS No. 123R, Duke Energy must determine an appropriate expense for stock options and the transition method to be used effective January 1, 2006. The transition methods include prospective and retroactive adoption options. Both methods record compensation expense for all unvested awards beginning January 1, 2006. Under the retroactive method, prior periods presented are also restated for awards which have vested prior to January 1, 2006.

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

Duke Energy plans to implement SFAS No. 123R using the prospective transition method and currently there are no plans to change the option-pricing model used for share-based compensation awards issued to

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employees in future periods. SFAS No. 123R, which was adopted by Duke Energy effective January 1, 2006, is not anticipated to have a material impact on its 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 Capital in periods subsequent to adoption of SFAS No. 123R will be largely dependent upon the nature of any new share-based compensation awards issued to employees.

Staff Accounting Bulletin (SAB) No. 107, “Share-Based Payment” (SAB 107). On March 29, 2005, the SEC staff issued SAB 107 to express the views of the staff regarding the interaction between SFAS No. 123R and certain SEC rules and regulations and to provide the staff’s views regarding the valuation of share-based payment arrangements for public companies. Duke Energy has considered the additional guidance provided by SAB 107 in connection with the implementation of SFAS No. 123R.

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

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BUSINESS

As discussed above under the heading “The Separation”, only the natural gas businesses of Duke Energy will be included in the assets transferred to us in connection with our separation from Duke Energy. Accordingly, the following description of our businesses describes only those businesses to be included in our assets at and following the separation.

Our Company

We own and operate a large and diversified portfolio of complementary natural gas-related energy assets and are one of North America’s leading midstream natural gas companies. We operate primarily in three of the four segments of the natural gas industry: Transmission and Storage, Distribution, and Gathering and Processing. We do not operate in the Exploration & Production segment. The midstream sector within the natural gas industry is the link between the production of natural gas and the delivery of its components to end-use markets, and consists of the Transmission and Storage and the Gathering and Processing industry segments. We intend to expand and optimize our current assets, construct new assets and make strategic acquisitions with an experienced management team dedicated to a growth strategy. We provide transportation and storage of natural gas to customers in various regions of the Eastern and Southeastern United States, the Maritimes Provinces and the Pacific Northwest in the United States and Canada and in the province of Ontario in Canada. We also provide natural gas sales and distribution service to retail customers in Ontario, and natural gas gathering and processing services to customers in Western Canada. Duke Energy Field Services, in which we have a 50% investment, is one of the largest natural gas liquids producers in North America and provides natural gas gathering, processing and natural gas liquids transportation services in the United States.

Our pipeline systems consist of approximately 17,500 miles of transmission pipelines. The pipeline systems receive natural gas from major North American producing regions for delivery to markets primarily in the

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Mid-Atlantic, New England and Southeastern states, the Maritimes Provinces, Ontario, Alberta, and the Pacific Northwest. For 2005, our proportional throughput for our pipelines totaled 3,410 TBtu, compared to 3,332 TBtu in 2004. These amounts include throughput on our wholly-owned U.S. and Canadian pipelines and our proportional share of throughput on pipelines that are not wholly-owned.

Spectra Energy has an investment in Duke Energy Field Services, LLC, or DEFS, which gathers, compresses, treats, processes, transports, trades and markets, and stores natural gas. DEFS also fractionates, transports, trades, markets and stores natural gas liquids, or NGLs. DEFS is 50% owned by ConocoPhillips and 50% owned by Spectra Energy. DEFS gathers raw natural gas through its gathering systems located in major natural gas producing regions: Permian Basin, Mid-Continent, East Texas, Austin Chalk, North Louisiana, onshore and offshore Gulf of Mexico, and Rocky Mountains.

For the year ended December 31, 2005, we generated, on a pro forma basis, net revenues of approximately $4.1 billion, operating income of approximately $1.3 billion and earnings from continuing operations of approximately $502 million. For the nine months ended September 30, 2006, we generated on a pro forma basis, revenues of approximately $3.4 billion, operating income of approximately $1.0 billion and earnings from continuing operations of approximately $637 million.

Our Industry

The natural gas industry is comprised of four segments: Exploration and Production, Gathering and Processing, Transmission and Storage, and Distribution.

Industry Segments

Exploration and Production. Exploration and production consists of the identification and acquisition of prospective properties or leases, the drilling of wells thereon and, if the wells successfully reach a productive horizon, development of facilities for the production of natural gas or other hydrocarbons from such successful wells, the development and construction of production facilities and the operation of such production facilities.

Gathering and Processing. Gathering and processing represents the second stage of the natural gas industrial cycle, the transportation of natural gas from field production facilities and the transformation of natural gas into a standardized reliable product. The gathering system consists generally of small diameter pipelines that transport raw natural gas from field production facilities to the processing plant. At the processing plant, the various hydrocarbons and fluids are separated from the pure natural gas to produce pipeline quality dry natural gas. The separated hydrocarbons are known as natural gas liquids (NGLs), and include a mixture of ethane, propane, butane, iso-butane, and natural gasoline. Once removed, the mixed NGLs are then further separated into component products and transported to end use markets.

Transmission and Storage. Transmission is the transportation of processed natural gas from natural gas supply areas to areas with high natural gas demand. This is typically accomplished using high-pressure large diameter pipelines. Along the transportation path, natural gas may be delivered to or received from natural gas market points, storage facilities or other pipelines. Natural gas may be stored in underground facilities located in either supply areas or market areas.

Distribution. Distribution is the sale and delivery of natural gas by a local distribution company to end users. Local distribution companies use transmission companies to transport their natural gas from supply areas to key points on their delivery system. The distribution sector’s delivery system is a network of thousands of miles of small-diameter low pressure distribution pipe connecting to the end user (for example, an industrial customer or individual residence).

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Industry Participants

The natural gas industry is primarily composed of four types of companies: exploration and production; gathering and processing; transmission and storage; and local distribution. There are a few companies that are fully integrated across all four natural gas industry segments. More commonly, companies only concentrate on two or three segments.

Master Limited Partnerships

In recent years, gathering and processing assets in the United States have increasingly been held through publicly-traded Master Limited Partnership or “MLP.” A master limited partnership (“MLP”) is a publicly traded limited partnership. Shares of ownership are referred to as units. MLPs generally operate in the natural resource, financial services, and real estate industries. U.S. transmission and storage assets may also follow this trend. Because MLPs do not pay income taxes at the entity level, they frequently have a lower cost of capital than companies organized as traditional corporations. This can provide them with a competitive advantage when building or acquiring new assets. A similar market development has taken place in Canada for energy assets held in the Canadian Income Trust Format. A “Canadian Income Trust” is an investment trust that holds income-producing assets. Shares of ownership are referred to as units and are typically traded on the Toronto stock exchange.

Industry Characteristics

Natural gas is a critical component of energy consumption in North America. The industrial and electricity generation sectors are the largest users of natural gas. During the last three years, these sectors accounted for approximately 56% of the total natural gas consumed in the United States, according the Energy Information Administration, or the EIA. Currently, natural gas represents approximately 24% of all end-user domestic energy requirements. During the past five years, the United States has on average consumed approximately 22.4 Tcf per year, with average annual domestic production of approximately 18.9 Tcf during the same period. According to the EIA, total annual domestic consumption of natural gas is expected to increase from approximately 22.3 trillion cubic feet, or Tcf, in 2005, to approximately 23.4 Tcf in 2010, representing an average annual growth rate of approximately 1% per year. During the same time period, domestic natural gas production is projected to increase from 18.1 Tcf to 18.6 Tcf, also representing an average annual growth rate of 1% per year. The demand growth in our key markets, the Northeast United States, Florida, Ontario and the Pacific Northwest, is projected to average from 2% to 3% annually over the 2003 to 2020 time period. This demand growth is primarily driven by the natural gas-fired electric generation sector.

The natural gas industry is currently experiencing a significant shift in the sources of supply, and this dramatic change is affecting our growth strategies. Traditionally, supply to our markets, the U.S. Northeast, Florida, Ontario and the Pacific Northwest, has come from the Gulf Coast region, onshore and offshore, as well as from fields in Western and Eastern Canada. While supply in certain areas in which we operate is experiencing an increase in production and reserves, traditional supply in other areas in which we operate is beginning to decline. As supply from these areas declines, or becomes less attractive because of vulnerability to hurricanes and other disruptions, the national supply profile is shifting to new, and, in some cases, to non-conventional sources of gas from basins in the Rockies, Mid-Continent and East Texas. In addition, the natural gas supply outlook will be shaped by new liquefied natural gas re-gasification facilities being built. Liquefied natural gas (or “LNG”) will clearly be an important new source of supply, but the timing and extent of incremental supply from LNG is yet to be determined and at present LNG remains a small percentage of the overall supply to the markets we serve.

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Our Business Strategies

Our primary business objective is to provide value added, reliable and safe services to our customers, which we believe will create opportunities to deliver increased dividends per share and value to our shareholders. We intend to accomplish this objective by executing the following business strategies:

• capitalize on the size and attributes of our existing assets;

• pursue organic growth, expansion projects, strategic acquisitions and other business opportunities arising in our market and supply areas;

• continue to explore operational efficiencies between our existing assets;

• utilize tax-efficient financial structures, such as MLPs and Canadian Income Trusts, to improve our cost of capital, optimize returns on the assets we hold and finance portfolio growth;

• continue our focus on operational excellence including safety, reliability, compliance and stringent cost management; and

• retain and enhance our customer and other stakeholder relationships.

Through the continued execution of these strategies, we expect to grow and strengthen the overall business, capture new growth opportunities and deliver value to our stakeholders. Our overall strategies are supported by the strategies within each of the industry segments in which we operate. Except as described in this information statement, we do not currently anticipate any material acquisitions or changes in our business after the separation.

Our natural gas transmission and storage strategies:

We have one of the largest natural gas pipeline systems in North America, with approximately 12,800 miles of transmission pipelines with five primary transmission systems: Texas Eastern, Algonquin, East Tennessee, Maritimes & Northeast and Gulfstream. In Canada, our Union Gas subsidiary has approximately 3,000 miles of transmission pipelines and our BC Pipeline subsidiary has approximately 1,800 miles of transmission pipelines in British Columbia and Alberta. Together, our proportional throughput for our pipelines totaled 3,410 TBtu, in 2005. The key elements of our natural gas transmission and storage strategy are as follows:

Capitalize on the scale of our existing operations. We intend to use the size and regional scale of our natural gas transmission assets to take advantage of transportation growth opportunities. The attractive nature of the source and end use markets served by our pipeline asset base generally provides us with a competitive advantage in capturing new transportation volumes.

Pursue pipeline and storage expansions and other business opportunities arising in our market and supply areas. We have developed a two-pronged growth strategy for gas transmission: “market pull” and “supply push”. We continue to employ a “market pull” strategy — taking gas away from established market points and building pipeline transportation capacity to satisfy end user demand in new markets or demand growth in existing markets. These market points are locations in the national pipeline network where natural gas supply inputs converge with market outlets and have evolved as recognized pricing and transaction points for natural gas supplies. Customer demand creates the “market pull” for new projects—where sufficient market demand exists, customers are prepared to enter into long-terms capacity arrangements which serve as the financial underpinning of the project. This high return “market pull” approach remains a key strategy for us.

We also employ a “supply push” strategy to take advantage of the evolving supply profile in the continental United States and Canada and the increasing desire by producers to enhance the value of their production by gaining access to more attractive market points than those to which they currently have access. In “supply push” projects, producers agree to pay to transport specified volumes of natural gas in order to support the construction of new pipelines. The contract terms tend to be shorter than a demand pull contract and the pipelines are built to reach the most attractive established market points rather than the “last mile” or all the way to specific end use markets.

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Together, we believe our market pull and supply push strategies result in a more effective approach for providing our producer customers with access to a more diverse market base and our consumer customers to an expansive source of natural gas supplies, which increases overall service reliability and pricing alternatives. This strategy has created an opportunity for us to enhance our asset base and revenue opportunities.

We currently have numerous pipeline expansion projects under development and have confirmed significant shipper interest during 2006:

• Gulfstream Natural Gas System capacity expansion (“market pull”);

• “Southeast Supply Header” pipeline project (“market pull”);

• “Mid-Continent Crossing” pipeline project (“supply push”); and

• Salt cavern storage facility expansion projects.

Several of our pipeline systems are substantially sold out of takeaway capacity (the maximum amount of gas that can be carried through a pipeline). As a result, we are pursuing multiple expansion opportunities to alleviate existing capacity bottlenecks and to increase our overall throughput. Texas Eastern’s Time II (“market pull”) and Algonquin’s Ramapo East (“market pull”) projects are good examples of projects that will increase capacity on our existing systems. This new capacity is fully subscribed under multi-year contracts beginning in 2007 and 2008 respectively.

Our flexible and diverse gas storage assets are expandable to meet growing market demand for storage services. We are in the process of expanding the capacity of our Egan gas storage field by approximately 8 Bcf, and have sold 60% of this capacity to customers for firm storage service beginning in 2008. Combining these new storage facilities with our existing storage facilities will enable us to offer additional firm storage services to our customers to meet peak day deliveries and additional short-term interruptible storage services, as well as to meet the operational needs on our systems.

Expand our existing asset base through accretive acquisitions of complementary assets. We will seek to expand our existing natural gas transportation and storage businesses by pursuing acquisitions that are accretive to earnings and cash flow. In recent years, there has been a rationalization of the energy infrastructure in the United States and Canada resulting in a number of transactions. We expect this trend to continue and believe we are well positioned to take advantage of future opportunities. We have pursued a disciplined acquisition strategy focused on acquiring complementary assets and integrating the acquired assets into our operations with over $10 billion in acquisitions completed since 2000. These acquisitions demonstrate our ability to successfully identify, acquire and integrate attractive transmission and storage operations.

Integrate our pipeline systems with existing and proposed LNG terminals. We believe that existing and proposed LNG terminals will become critical sources of natural gas supply for the United States over the next decade. Our extensive pipeline network is well-positioned to benefit from the development and expansion of several of the existing and proposed LNG terminal sites, both in the United States and Canada. As an example the planned expansion to the Maritimes and Northeast Pipeline system will connect new supply from the Canaport LNG facility to markets in the Northeast United States.

Utilize tax-efficient financial structures to improve our cost of capital, optimize returns on the assets we hold and finance growth. Similar to our strategy in gathering and processing, we plan to pursue an MLP strategy in natural gas transmission. Specifically, we plan to form an MLP to hold a portion of our transmission assets. Through this strategy, we hope to achieve the following objectives: opportunistically acquire third party assets through access to low-cost capital and monetize existing or recently completed assets at superior valuation multiples while retaining control of the assets.

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Our natural gas distribution strategies:

We will pursue opportunities to ensure strong growth of the Union Gas distribution base and position ourselves for rate stability for our distribution customers. Union Gas is a natural gas utility that provides energy delivery and related services to approximately 1.3 million residential, commercial and industrial customers in over 400 communities in northern, southwestern and Eastern Ontario. The key elements of our gas distribution strategy are as follows:

Pursue growth through system expansions and other business opportunities arising in our market areas. There are a number of conditions in Union Gas’ markets that could contribute to its future growth, including demand for natural gas, adequate existing and potential supply, the development of additional transportation infrastructure and strong environmental support for natural gas as an appropriate alternative to other fuels. We believe that Union Gas’ large and diverse customer base, extensive distribution system and the strategic location of its storage and transmission facilities, with interconnections between major U.S. markets in Michigan and New York State, are positive factors in Union Gas’ ability to take advantage of these conditions.

We will continue to seek growth, in all of Union Gas’ market segments, through the expansion of our gas distribution system for new construction and to penetrate existing communities where no distribution system exists and the pursuit of acquisition opportunities to grow residential, commercial and industrial markets. For our storage and transportation customers, we will pursue the expansion of the Dawn to Trafalgar pipeline to further enhance the path for Western Canadian and U.S. natural gas to Central Canadian and Northeast U.S. markets.

Continue our long history of operational excellence, reliable service and stable cash flows. Union Gas has provided safe and reliable service to its residential, commercial and industrial customers since it was originally incorporated in 1911. Regulated by the Ontario Energy Board, Union Gas provides us with a stable and predictable earnings stream.

Our natural gas gathering and processing strategies:

We provide our gathering and processing services in the United States through our 50% interest in DEFS and in Canada through our BC Field Services and Midstream operations. DEFS is one of the largest gatherers of raw natural gas and one of the largest producers and marketers of NGLs in the United States. DEFS has significant midstream natural gas operations in the largest natural gas producing regions in the United States. With our Canadian BC Field Services and Midstream operations, we are one of the largest sour gas processors in Canada. To take advantage of the anticipated growth in natural gas demand in North America, we are pursuing the following key elements of our gathering & processing strategy:

Capitalize on the size and focus of our existing operations. We intend to use the size, scope and concentration of our assets in our regions of operation to take advantage of growth opportunities and to acquire additional supplies of raw natural gas. Our significant market presence and asset base generally provide us with a competitive advantage in capturing new supplies of raw natural gas because of our resulting lower costs of connection to new wells and of processing additional raw natural gas. In addition, we believe our size and geographic diversity also allow us to benefit from the growth of natural gas production in multiple regions while mitigating the adverse effects from a downturn in any one region.

Increase our presence in each aspect of the gathering and processing business. We are active in each significant aspect of the gathering and processing midstream natural gas value chain, including raw natural gas gathering, processing, and transportation, NGL fractionation (whereby NGLs are separated from raw natural gas), and NGL and residue gas transportation and marketing. Each link in the value chain provides us with an opportunity to earn incremental income from the raw natural gas that we gather and from the NGLs and residue gas that we produce. We intend to grow our significant NGL market presence by investing in additional NGL infrastructure, including pipelines, fractionators and terminals (facilities that store NGLs).

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Increase our presence in production areas with higher growth potential. Production from new areas in western Canada, Rocky Mountains, Mid-Continent and East Texas is expected to increase, as traditional sources of supply in the Gulf Coast and eastern Canada are beginning to decline. We intend to use our strategic asset base in these growth areas and our leading position in the gathering and processing industry as a platform for future growth in these areas. We plan to increase our operations in these areas by following a disciplined acquisition strategy, and by expanding existing infrastructure and constructing new gathering lines and processing facilities.

Capitalize on proven acquisition skills in a consolidating industry. In addition to pursuing internal growth by attracting new raw natural gas supplies, we intend to use our substantial acquisition and integration skills to continue to participate selectively in the consolidation of the gathering and processing industry. We have pursued a disciplined acquisition strategy focused on acquiring complementary assets during periods of relatively low

commodity prices and integrating the acquired assets into our operations. Between 2001 and 2005, we have completed a number of acquisitions, totalling over $554 million, demonstrating our ability to successfully identify, acquire, and integrate attractive gathering and processing operations.

Utilize tax-efficient financial structures to improve our cost of capital, optimize returns on the assets we hold and finance growth. We plan to continue our strategy of holding a portion of our gathering and processing assets in tax efficient structures such as master limited partnerships and Canadian income funds. In 2005, DEFS formed DCP Midstream Partners from a portion of its assets. DEFS is the general partners of, and retains a 42.7% interest in, DCP Midstream Partners. It was formed with the objective of utilizing DCP Midstream Partners lower cost capital in order to support further growth at DEFS. DEFS may also contribute additional assets to DCP Midstream Partners in order to generate proceeds for DEFS at an attractive valuation without losing its ability to control the assets contributed.

Similarly, in 2005 we formed a Canadian Income Trust, the Duke Energy Income Fund, with a portion of the gathering and processing assets in our Canadian Midstream operations, which is one of the largest gathering and processing operations in Western Canada. The long-term plan for our Western Canadian processing assets is to prudently deploy capital resources to maintain our position as a low cost operator and expand our raw gas gathering capabilities, natural gas processing facilities and transportation assets to grow the core business. Over time, Spectra Energy may transfer additional assets to Duke Energy Income Fund or Duke Energy Income Fund may make accretive third party acquisitions of Canadian assets with the ultimate intent of improving financial returns to Spectra Energy shareholders.

Further streamline our low-cost structure. We believe we have a complementary base of assets from which to extract operating efficiencies and cost reductions, while continuing to provide superior customer service. In addition, we continue to optimize our existing assets by looking at potential plant consolidation and ensuring reliability in our plant operations. Our economies of scale, operating efficiency and resulting low cost structure enhance our ability to attract new raw natural gas supplies and generate current income. The low-cost provider in any region can more readily attract new raw natural gas volumes by offering more competitive terms to producers.

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Our Strengths

We believe that we are well-positioned to execute our primary business objective and business strategies successfully because of the following competitive strengths:

Our gas transmission and gathering and processing systems are among the largest in North America.

We have one of the largest natural gas pipeline systems in North America, with approximately 12,800 miles of transmission pipelines with five primary transmission systems: Texas Eastern, Algonquin, East Tennessee, Maritimes & Northeast and Gulfstream. In Canada, our Union Gas subsidiary has approximately 3,000 miles of transmission pipelines and our BC Pipeline subsidiary has approximately 1,800 miles of transmission pipelines in British Columbia and Alberta. Through our investment in DEFS, we are also one of the largest gatherers of raw natural gas and one of the largest producers and marketers of NGLs in North America. We have significant midstream natural gas operations in the largest natural gas producing regions in North America. The size of our asset position allows us to seize new business opportunities and through economies of scale, further optimize our existing low-cost structure.

We are strategically positioned to expand our operations through capital investment.

The industry dynamics of natural gas demand growth and shifting supply sources combined with the location of our transmission and storage, distribution, and gathering and processing assets provide us with numerous expansion opportunities. On average over the next several years, we anticipate that we will invest more than $1 billion per year in expansion projects. While the cost of these expansion opportunities will vary, we are well positioned to offer a lower total cost solution than competing proposals through the use of existing rights-of-way, compression and storage facilities and drawing upon our expertise and experience in managing and constructing expansion projects.

We supply natural gas to the fastest growing markets in North America.

Our natural gas pipelines serve four of the fastest growing natural gas markets. Gas demand growth in the key Spectra Energy markets of the U.S. Northeast, Florida, Ontario and the Pacific Northwest is projected to average 2% to 3% annually over the 2003 to 2020 time period compared to a 1% average for all the lower 48 states. As the demand for natural gas grows, so will the need for reliable, safe transportation and storage infrastructure. We will aggressively pursue expansion projects to capture this growth.

We have a strategically-positioned pipeline asset base that provides supply base diversity.

In addition to delivering to growing markets, our pipeline network is connected to a diverse supply of natural gas. We access natural gas from the Gulf Coast region, both onshore and offshore, as well as from fields in Western and Eastern Canada, and indirectly from Mid-Continent and Rocky Mountain supply sources. This extensive diversity of supply sources provides options for our customers to obtain the lowest cost supplies with added security that a disruption in any one supply source will not completely interrupt service.

With two back-to-back years of significant hurricane activity, customers, as well as state regulatory agencies, have become aware of the benefits of diverse natural gas supply. In 2005, hurricanes Katrina and Rita disrupted offshore gas production and onshore gas processing capacity in unprecedented ways. As a consequence, the wholesale price for natural gas increased substantially. This followed similar significant disruptions caused by hurricane Ivan in 2004. These hurricanes have heightened attention to the critical need for supply diversity. Customers not limited to a single supply source are less exposed to potential disruptions and customers will continue to prefer to contract for transmission and storage capacity that has access to diverse sources of supply.

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Cash flows in our natural gas transmission and distribution segments are relatively stable due to the regulated nature of these businesses.

A majority of our transportation services are regulated by the FERC, NEB and OEB, and are provided under firm service agreements with LDC customers in the pipelines’ market areas. A majority of our transportation revenues are generated from our firm services contract demand charges, which generally are not impacted by fluctuations in volumes transported. This contract structure reduces the risk of revenue fluctuations due to changes in weather or supply conditions and provides us with greater stability of cash flows. Additionally, we have little direct commodity price exposure in the transmission and distribution segments, as we generally do not own the gas we transport for our customers and are entitled to reimbursement for natural gas used as fuel in our operations.

Our gas distribution segment is subject to regulation with respect to the rates that it may charge its customers. This regulation is intended to allow Union Gas the opportunity to earn an allowed rate of return. Union Gas’ distribution services are affected by weather and overall economic conditions. Most of Union Gas’ power generation, industrial and large commercial customers, and a portion of residential customers, purchase their natural gas directly from suppliers or marketers. Because Union Gas earns income from the distribution of natural gas and not the sale of the natural gas commodity, our gas distribution margins are not significantly affected by movements in the price of natural gas. As a consequence of these factors, earnings and cash flow in our distribution segment tend to be stable and predictable.

We have financial flexibility to pursue growth opportunities.

The senior unsecured debt of our subsidiaries currently has an investment grade rating from Standard & Poor’s Rating Services and Moody’s Investors Services and we expect to receive investment grade credit ratings prior to or concurrent with our separation from Duke Energy which is consistent with our financing strategy. We are appropriately capitalized with a low cost of debt and are well positioned for future growth. Furthermore, we will have access to three revolving credit facilities available in two currencies upon our separation from Duke Energy, with total combined capacities of $600 million and CAN $600 million. These facilities will be used principally as a back-stop for commercial paper programs at Spectra Energy subsidiaries and are expected to be largely unutilized at the time of the separation. These facilities will provide additional liquidity and financing flexibility to assist us in executing our business strategy. Through our interests in DCP Midstream Partners and Duke Energy Income Fund, we also have access to additional sources of capital. We remain committed to maintaining financial flexibility in order to fund expansion projects and other attractive investment opportunities.

Our focus on customer and other stakeholder relationships helps us avoid costly and time-consuming contract negotiations and rate-making activities through clear communication and knowledge of issues.

We enjoy very strong relationships with our customers and our regulators. Our U.S. pipelines have successfully re-sold capacity every year since 2000 and our U.S. market based storage sells out year after year with consistent revenue increases over the past four years. On many of our pipelines, we have entered into rate settlements with our customers that have been approved by the regulatory body which will provide rate stability through the 2007 to 2011 time period. This provides us with revenue stability and our customers with cost certainty.

We have a strong and experienced management team.

Our strong management team has a breadth of operating experience in the energy industry beyond our business segments, and including finance and mergers and acquisitions. Our management team is well equipped to respond to changing market conditions and changing demands of our customers. This capability is essential to achievement of our goals and the creation of value for our stakeholders.

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History and Development

Spectra Energy Corp, currently a wholly-owned subsidiary of Duke Energy, was incorporated as Gas SpinCo, Inc. on July 28, 2006 in the state of Delaware to effectuate the separation of Duke Energy’s natural gas transmission and storage, distribution, and gathering and processing businesses from Duke Energy. On November 8, 2006 we amended and restated our certificate of incorporation to change our name to Spectra Energy Corp. In connection with our incorporation, we issued to Duke Energy a thousand shares of our common stock, par value $.001 per share, in exchange for a $1.00 contribution. The issuance of such shares of Spectra Energy common stock to Duke Energy was exempt from registration under Section 4(2) of the Securities Act of 1934, as amended. Below is a brief timeline summarizing the history and development of Duke Energy’s natural gas businesses.

1947	Texas Eastern Transmission was founded following the purchase of the Big Inch and Little Big Inch crude oil pipelines from the U.S. government, thus initiating natural gas transmission service from the gas fields of East Texas to the Northeastern United States.
1949	Texas Eastern Transmission began servicing the Philadelphia area and formed a partnership called Algonquin to provide natural gas to New England.
1951	Panhandle Eastern expanded into gathering and processing, building its first petrochemical plant to extract natural gas liquids (NGLs) from natural gas.
1953	Algonquin made its first deliveries of Gulf Coast natural gas to New England customers.
1989	Texas Eastern’s board announced a $3.2 billion transaction with Panhandle Eastern Corp. in which Texas Eastern became a wholly-owned subsidiary of Panhandle Eastern. The new company had four major pipelines: Panhandle Eastern Pipe Line, Trunkline Gas, Texas Eastern Transmission and Algonquin Gas Transmission.
1994	Panhandle Eastern acquired Colorado-based Associated Natural Gas Corporation, a gathering and processing company operating in Colorado, Louisiana and Texas.
1996	Panhandle Eastern formally changed its name to PanEnergy Corp.
1997	In an effort to take advantage of a rising trend toward energy deregulation, Duke Power and PanEnergy merged, forming Duke Energy, a diversified energy company.
1998	Construction began on the 900-mile Maritimes & Northeast Pipeline, which was in service by December 1999. It provided a link to the first major new supply source (Sable Island, offshore Nova Scotia) to be introduced to the United States in 20 years.
1999	Duke Energy purchases Union Pacific Resources midstream gas business. Panhandle Eastern Pipe Line and Trunkline Gas are sold to CMS Energy.
2000	Duke Energy purchased East Tennessee Natural Gas from El Paso Energy. After the purchase, DEGT established interconnects between East Tennessee Natural Gas and Texas Eastern Transmission to provide Duke Energy customers with seamless service from the Gulf Coast to East Tennessee Natural Gas’ southeastern markets.
	Duke Energy purchased Market Hub Partners LP from NiSource.
	Duke Energy Field Services, as it is known today, was formed in March 2000 by combining the natural gas gathering and processing businesses of Duke Energy and ConocoPhillips.
2001	Construction began on the 691-mile Gulfstream Natural Gas System, which was in service by May 2002. It is the first offshore pipeline to come onshore in Florida and the first new natural gas pipeline serving Florida in more than 40 years.
2002	Duke Energy acquired Westcoast Energy. The acquisition significantly strengthened the company’s natural gas transmission and storage capacity positions. DEGT added approximately 5,000 miles of transmission pipeline, approximately 150 Bcf of natural gas storage capacity and approximately 35,000 miles of distribution pipeline.

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2005	DEFS created a new master limited partnership, DCP Midstream Partners, LP. DEFS owns a 42.7% retained interested, including the general partnership of DCP Midstream Partners, and manages and operates its assets in Louisiana and Texas.
	We completed the initial public offering of a Canadian income trust fund, the Duke Energy Income Fund. The Duke Energy Income Fund acquired an interest in the Canadian Midstream operations located in Western Canada. We currently retain an approximate 46% interest in the Income Fund and will continue to operate and manage this business.
2006	Duke Energy announced that its board of directors had unanimously decided to pursue a plan to separate its electric and gas businesses into two publicly-traded companies.

Business Segments

Our Business Segments

Our business is currently reported by Duke Capital in Duke Capital’s Natural Gas Transmission and Field Services segments. As a result of the reorganization of Duke Capital prior to the distribution, we expect to manage our business in four reportable segments: Gas Transmission—U.S., Gas Distribution, Gas Transmission & Processing—Western Canada, and Field Services. The first three segments are included in Duke Capital’s Natural Gas Transmission business and DEFS is reported in the Field Services segment of Duke Capital. We believe that we are an industry leader in each of our business segments. The remainder of our business operations is expected to be presented as “Other,” which consists of the realized and unrealized mark-to-market impact on discontinued hedges that expire in 2006 related to the DEFS disposition transaction, certain unallocated corporate costs and other businesses.

Gas Transmission—U.S.

U.S. gas transmission provides transportation and storage of natural gas for customers in the Eastern and Southeastern U.S. For 2005, our proportional throughput for gas transmission U.S.’s pipelines totaled 1,953 trillion TBtu, compared to 1,909 TBtus in 2004. This includes throughput on our wholly-owned U.S. pipelines and our proportional share of throughput on pipelines that are not wholly-owned. A majority of our transportation volumes are under long-term firm service agreements with LDC customers in the pipelines’ market areas. Firm transportation services are also provided to gas marketers, producers, other pipelines, electric power generators and a variety of end-users, and both firm and interruptible transportation services are provided to gas marketers, producers, other pipelines, electric power generators and a variety of end-users, as well as on a short-term or seasonal basis. In the course of providing transportation services, our natural gas transmission business also processes some natural gas on its U.S. system. Demand on our pipeline systems is seasonal, with the highest throughput occurring during colder periods in the first and fourth calendar quarters. Our pipeline systems consist of approximately 12,800 miles of transmission pipelines with five primary transmission systems: Texas Eastern, Algonquin, East Tennessee, Maritimes & Northeast and Gulfstream.

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Texas Eastern

The Texas Eastern gas transmission system extends approximately 1,700 miles from producing fields in the Gulf Coast region of Texas and Louisiana to Ohio, Pennsylvania, New Jersey and New York. It consists of two parallel systems, one with three large-diameter parallel pipelines and the other with one to three large-diameter pipelines. Texas Eastern’s onshore system consists of approximately 8,600 miles of pipeline and 73 compressor stations (facilities that increase the pressure of gas to facilitate its pipeline transmission). Texas Eastern also owns and operates two offshore Louisiana pipeline systems, which extend approximately 100 miles into the Gulf of Mexico and include approximately 500 miles of Texas Eastern’s pipeline system and has an ownership interest in a processing plant in Southern Louisiana. Texas Eastern has two joint-venture storage facilities in Pennsylvania and one wholly-owned and operated storage field in Maryland. Texas Eastern’s total working capacity in these three fields is 75 Bcf. Texas Eastern is connected with two storage facilities through our MHP business in Texas and Louisiana, with a total working capacity of approximately 30 Bcf.

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Algonquin

The Algonquin pipeline connects with Texas Eastern’s facilities in New Jersey, and extends approximately 250 miles through New Jersey, New York, Connecticut, Rhode Island and Massachusetts where it connects to the Maritimes & Northeast Pipeline. The system consists of approximately 1,100 miles of pipeline with six compressor stations.

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East Tennessee

East Tennessee crosses Texas Eastern’s system at two points in Tennessee and consists of two mainline systems totaling approximately 1,400 miles of pipeline in Tennessee, Georgia, North Carolina and Virginia, with 18 compressor stations. East Tennessee has a liquefied natural gas storage facility in Tennessee with a total working capacity of 1.2 Bcf. East Tennessee also connects to Saltville Gas Storage Company L.L.C. and other storage facilities in Virginia have a total working gas capacity of approximately 5 Bcf.

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Maritimes & Northeast Pipeline

Maritimes & Northeast Pipeline transmission system is operated primarily through our 77.53% investment in Maritimes & Northeast Pipeline, LP and Maritimes & Northeast Pipeline, LLC. Maritimes & Northeast Pipeline transmission system extends approximately 900 miles from producing fields in Nova Scotia through New Brunswick, Maine, New Hampshire and Massachusetts, connecting to Algonquin in Beverly, Massachusetts. There are two compressor stations on the system.

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Gulfstream

Our U.S. gas transmission segment also has a 50% investment in Gulfstream Natural Gas System, LLC (Gulfstream), a 691-mile interstate natural gas pipeline system owned and operated jointly by us and The Williams Companies, Inc. Gulfstream has a capacity to transport 1.1 Bcf/day from Mississippi and Alabama, crossing the Gulf of Mexico to markets in central and southern Florida. Gulfstream has one compressor station.

Storage Services

We, through Market Hub Partners (MHP), wholly own underground natural gas salt cavern storage facilities in Southeast Texas and Louisiana. These fields are connected to several interstate natural gas pipelines, as well as, to our Texas Eastern system and provide storage services to customers along these various pipeline systems. We also own underground reservoir and salt cavern storage facilities in Virginia through Saltville Gas Storage Company L.L.C. and other facilities. These fields are integrated with the East Tennessee system and provide storage services to customers in the southeast and operate under a cost-of-service regulatory model. Combined, MHP, Saltville Gas Storage and other facilities in Virginia have approximately 30 Bcf of working gas capacity.

Nature of Contracts

In general, our U.S. pipelines provide transportation services to LDC’s, electric power generators, industrial and commercial customers, as well as energy marketers. We provide transportation and storage services under firm agreements where customers reserve capacity in our pipelines and storage facilities. The vast majority of these agreements provide for fixed reservation charges that are paid regardless of actual volumes transported on our pipelines or injected or withdrawn from our storage by customers plus a small variable component that is based on volumes transported to recover variable costs. These contracts are held by such entities as KeySpan

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Energy, Public Service Electric & Gas of New Jersey and Florida Power & Light. We also provide interruptible transportation and storage service agreements where customers can use capacity if it is available at the time of the request and payments under these services are based on volumes transported or stored. We provide a variety of other value-added services including natural gas parking, loaning and balancing services to meet our customers’ needs. These services are provided in accordance with our tariffs that govern the provision of services and are approved by the appropriate regulatory agency that has jurisdiction over those systems.

Competition

Our U.S. gas transmission segment competes with similar transportation and storage facilities that serve our supply and market areas. The principal elements of competition in our markets are transportation rates, terms of service, and flexibility and reliability of service. We believe we are able to offer a very competitive service offering along all of these dimensions due to our scale, our geographic presence in important supply and market areas, our financial stability and flexibility, and the strength of stakeholder relationships. Moreover, the presence of our existing pipeline assets, right of way, customer base and operations enables us to more quickly and cost effectively add capacity and service for customers in our core markets. Our reputation for customer service, project execution, stakeholder relations, reliability and predictable rates further enhance our competitive advantage. Taken as a whole, we believe our service offerings are among the most competitive in the sector.

Our U.S. gas transmission segment competes with other forms of energy available to our natural gas transmission business’ customers and end-users, including electricity, coal, propane and fuel oils. Several factors influence the demand for natural gas including price changes, the availability of natural gas and other forms of energy, the level of business activity, conservation, legislation, governmental regulations, the ability to convert to alternative fuels, weather and other factors.

Gas Distribution

We provide retail distribution services in Canada through our subsidiary, Union Gas Limited (Union Gas). Union Gas owns primarily pipeline, storage and compression facilities used in the transportation, storage and distribution of natural gas. Union Gas’ system consists of approximately 35,000 miles of distribution pipelines. Union Gas’ underground natural gas storage facilities have a working capacity of approximately 150 Bcf in 20 underground facilities located in depleted gas fields. Its transmission system consists of approximately 3,000 miles of high-pressure transmission pipeline and six mainline compressor stations.

Union Gas distributes natural gas to approximately 1.3 million residential, commercial and industrial customers in Northern, Southwestern and Eastern Ontario and provides storage, transportation and related services to utilities and other industry participants in the gas markets of Ontario, Quebec and the Central and Eastern United States.

Union Gas provides natural gas storage and transportation services for other utilities and energy market participants in Ontario, Quebec and the United States. Its storage and transmission system forms an important link in moving natural gas from Western Canadian and U.S. supply basins to Central Canadian and northeastern U.S. markets. Transportation and storage customers are primarily Canadian natural gas transmission and distribution companies. A substantial amount of Union Gas’ annual transportation and storage revenue is generated by fixed demand charges under contracts with remaining terms of up to 11 years and an average outstanding term of 3.9 years.

Union Gas’ distribution services to power generation and industrial customers are affected by weather, economic conditions and the price of competitive energy sources. Most of Union Gas’ power generation, industrial and large commercial customers, and a portion of residential customers, purchase their natural gas directly from suppliers or marketers. Because Union Gas earns income from the distribution of natural gas and not the sale of the natural gas commodity, our gas distribution margins are not affected by the source of our customers’ gas supply.

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Customers and Contracts

Union Gas’ distribution service area extends throughout northern Ontario from the Manitoba border to the North Bay/Muskoka area, through southern Ontario from Windsor to just west of Toronto, and across eastern Ontario from Port Hope to Cornwall. Union Gas’ franchise area has a population of approximately four million people and a diversified commercial and industrial base.

Union Gas also provides natural gas storage and transportation services for other utilities and energy market participants in Ontario, Quebec and the United States. Transportation and storage customers include large Canadian natural gas transmission and distribution companies, such as Enbridge Gas Distribution, TransCanada Pipelines and Gaz Metro.

The rates that Union Gas charges for its regulated services are subject to the approval of the OEB.

Competition

Union Gas is a regulated entity and is not generally subject to third-party competition within its distribution franchise area, although a recent decision of the OEB has permitted physical bypass of Union Gas’ facilities even within its distribution franchise area. In addition, other companies could enter Union Gas’ markets or regulations could change. Union Gas is regulated by the OEB pursuant to the provisions of the Ontario Energy Board Act (1998) and is subject to regulation in a number of areas including rates.

Gas Transmission & Processing—Western Canada

Our Gas Transmission & Processing—Western Canada segment is comprised of the BC Pipeline and Field Services operations, the Midstream operations and the NGL Marketing operations.

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We own and operate natural gas processing plants and gathering pipelines in western Canada through our BC Field Services operations that provide services primarily to natural gas producers to remove impurities from the raw gas stream including water, carbon dioxide, hydrogen sulphide and other substances. Where required, these facilities remove various natural gas liquids. Including our 46% interest in Duke Energy Income Fund, we operate more than 2,500 miles of gathering pipelines in western Canada, as well as 22 field compressor stations; thirteen gas processing plants which contain three elemental sulphur recovery plants (facilities that remove sulphur impurities from natural gas). Total contractible capacity is approximately 2.7 Bcf of residue gas (gas remaining after processing and extraction of NGL from natural gas, primarily methane) per day. The BC Pipeline has approximately 1,800 miles of transmission pipelines in British Columbia and Alberta, as well as 18 mainline compressor stations. For 2005, our throughput for the BC pipeline totaled 619 trillion TBtu, compared to 652 TBtus in 2004.

We provide gathering and processing services, through our Canadian Midstream operations, in western Canada through 9 natural gas processing plants and over 870 miles of natural gas gathering pipelines. In December 2005, we reduced our ownership percentage in a portion of these operations as a result of the creation of a Canadian income trust fund, the Duke Energy Income Fund. We previously had an approximate 58% interest in the Duke Energy Income Fund and will continue to operate and manage this business. In September 2006, we entered into an agreement to contribute additional midstream assets into the Duke Energy Income Fund, which reduced our ownership to approximately 46%.

The NGL Marketing operations are comprised of the Empress system, acquired in August 2005 from ConocoPhillips, which is a collection of midstream assets involved in the extraction, storage, transportation, distribution and marketing of NGLs in Canada and the U.S. Assets include, among other things, majority ownership interest in an NGL extraction plant on the TransCanada system in Alberta, a liquids transmission pipeline, seven terminals along the pipe, two storage facilities, a fractionation facility, and an integrated NGL marketing and gas supply business. Total processing capacity of the Empress system is 2.4 Bcf of gas per day. The Empress system is located in western and central Canada.

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Competition

Gas Transmission and Processing—Western Canada’s transmission and processing businesses compete with third party midstream companies, exploration and production companies and pipelines in the transportation of natural gas. The Company competes directly with other pipeline facilities serving its market areas. The principal elements of competition are rates, terms of service, and flexibility and reliability of service. Customer demands for toll certainty and lower cost tailored services have promoted increased competition from other midstream service companies and producers. We believe we are able to offer a very competitive service offering along all of these dimensions due to our scale, our geographical presence in important supply and market areas, our financial stability and flexibility, and the strength of stakeholder relationships. Moreover, the presence of our existing pipeline assets, right of way, customer base and operations enables us to more quickly and cost effectively add capacity and service for customers in our core markets. Our reputation for customer service, project execution, stakeholder relations, reliability and predictable rates further enhance our competitive advantage. Taken as a whole, we believe our service offerings are among the most competitive in the sector.

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

Customers & Contracts

Our British Columbia transmission pipelines provide: (i) transportation services from the outlet of natural gas processing plants in Northeast BC to LDCs, end use industrial and commercial customers, and exploration and production companies requiring transportation services to the nearest liquid natural gas trading hub; and (ii) transportation services primarily to downstream markets in the Pacific Northwest (both United States and Canada.) Major customer segments include local distribution companies, electric power generators, exploration and production companies, gas marketers, industrial and commercial end users including Terasen Gas Inc., Nexen, BP Canada, Canadian Natural Resources, Puget Sound Energy, Northwest Natural Gas, Cargill, and BC Hydro. We provide both firm and interruptible service.

The largest portion of our business in Western Canada is represented by the BC Field Services and Midstream operations providing raw natural gas gathering and processing services to exploration and production companies under firm agreements which are primarily fee for service contracts. We provide both firm and interruptible service. Although both operations gather and process raw natural gas from the Western Canadian Sedimentary basin, they are significantly different in size and infrastructure within their respective regions. Each has approximately 200 customers, with a majority of the revenues generated from very large investment grade exploration and production companies such as Canadian Natural Resources, Talisman Energy, EnCana, Devon, ConocoPhillips (Burlington), BP Canada, Petro Canada and Imperial Oil.

The NGLs extraction operation at Empress, Alberta produces approximately 50 thousand barrels of NGL per day comprised of approximately 50% ethane, 32% propane, 12% butanes and 6% condensate. All ethane is sold to Alberta based petrochemical companies, the majority of propane is sold to propane wholesalers, butane is sold mainly into the motor gasoline refinery market, and condensate sales are directed to the crude blending market. Key customers representing a majority of the business include Dow Chemical, Superior Gas Liquids, SemStream and ConocoPhillips.

Field Services

Field Services includes our investment in Duke Energy Field Services, LLC, which we refer to in this information statement as DEFS. Field Services gathers, compresses, treats, processes, transports, trades and markets, and stores natural gas; and fractionates, transports, trades and markets and stores NGLs. In July 2005,

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Spectra Energy completed the transfer of a 19.7% interest in DEFS to ConocoPhillips, our co-owner in DEFS, which reduced our ownership interest in DEFS from 69.7% to 50%, which we refer to as the DEFS disposition transaction, and resulted in our and ConocoPhillips becoming equal 50% owners in DEFS.

As a result of the DEFS disposition transaction, we deconsolidated our investment in DEFS and subsequently have accounted for DEFS as an investment utilizing the equity method of accounting. The DEFS disposition transaction included the transfer to us of DEFS’ Canadian Midstream business and included the acquisition of ConocoPhillips’ interest in the Empress System, both of which are included in our Gas Transmission and Processing – Western Canada segment. Additionally, in February 2005, DEFS sold its wholly-owned subsidiary, TEPPCO, the general partner of TEPPCO Partners L.P., and Duke Energy sold its limited partner interest in TEPPCO Partners, L.P., in each case to EPCO Inc., an unrelated third party.

In 2005, DEFS formed DCP Midstream Partners, LP. DCP Midstream Partners completed an initial public offering of 58% of its partnership interests in December. As a result, DEFS has a 42.7% ownership interest in DCP Midstream Partners, consisting of a 40% limited partner ownership interest and a 2% general partner ownership interest. DEFS owns 100% of the general partner of DCP Midstream Partners.

DEFS operates in sixteen states in the United States (Alabama, Arkansas, Colorado, Kansas, Louisiana, Maine, Massachusetts, Mississippi, New Mexico, New York, Oklahoma, Pennsylvania, Texas, Rhode Island, Vermont and Wyoming). DEFS’ gathering systems include connections to several interstate and intrastate natural gas and NGL pipeline systems and one natural gas storage facility. DEFS gathers raw natural gas through gathering systems located in major natural gas producing regions: Permian Basin, Mid-Continent, East Texas Austin Chalk, North Louisiana, onshore and offshore Gulf of Mexico, and Rocky Mountains. DEFS owns or operates approximately 56,000 miles of gathering and transmission pipe, with approximately 34,000 active receipt points.

DEFS’ natural gas processing operations separate raw natural gas that has been gathered on its own systems and third-party systems into condensate, NGLs and residue gas. DEFS processes the raw natural gas at 54 natural gas processing facilities.

The NGLs separated from the raw natural gas are either sold and transported as NGL raw mix, or further separated through a fractionation process into their individual components (ethane, propane, butane, iso-butane

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and natural gasoline) and then sold as components. DEFS fractionates NGL raw mix at seven fractionation facilities that it owns and operates and at four third-party-operated facilities in which it has an ownership interest. In addition, DEFS operates a propane wholesale marketing business. DEFS sells NGLs to a variety of customers ranging from large, multi-national petrochemical and refining companies to small, regional retail propane distributors. Substantially all of its NGL sales are at market-based prices.

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

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

DEFS’ operating results are significantly affected by changes in average NGL prices, which increased approximately 25% in 2005 compared to 2004. DEFS closely monitors the risks associated with these price changes, using NGL and crude forward contracts to mitigate the effect of such fluctuations on operating results. (See “Management’s Discussion and Analysis of Results of Operations and Financial Condition, Quantitative and Qualitative Disclosures About Market Risk” for a discussion of DEFS’ exposure to changes in commodity prices.)

Customers and Contracts

DEFS sells NGLs to a variety of customers ranging from large, multi-national petrochemical and refining companies to small regional retail propane distributors. Substantially all of DEFS’ NGL sales are made at market-based prices, including approximately 40% of its NGL production that is committed to ConocoPhillips and Chevron Phillips Chemical LLC under existing contracts that have primary terms that expire on December 31, 2014. ConocoPhillips, a 50% co-owner in DEFS, is a significant customer. In 2005, ConocoPhillips, including its affiliate, Chevron Phillips Chemical, represented approximately 19% of DEFS’ consolidated revenues.

The residual natural gas (primarily methane) that results from processing raw natural gas is sold at market-based prices to marketers and end-users. End-users include large industrial companies, natural gas distribution companies and electric utilities.

DEFS purchases or takes custody of substantially all of its raw natural gas from producers, principally under the following types of contractual arrangements:

• Percentage-of-proceeds arrangements.    In general DEFS purchases natural gas from producers, transports and processes it and then sells the residue natural gas and NGLs in the market. The payment to the producer is an agreed upon percentage of the proceeds from those sales. DEFS’ revenues correlate directly with the price of natural gas and NGLs.

• Fee-based arrangements.    DEFS receives a fee or fees for the various services it provides including gathering, compressing, treating, processing or transporting natural gas. The revenue DEFS earns is directly related to the volume of natural gas that flows through its systems and is not directly dependent on commodity prices.

• Keep-whole.    DEFS gathers raw natural gas from producers for processing and then markets the NGLs. DEFS keeps the producer whole by returning an equivalent amount of natural gas after the processing is

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complete. DEFS is exposed to the “frac spread” which is the value difference between the NGLs extracted and the natural gas returned to the producer.

• Wellhead purchase arrangements.    DEFS purchases raw natural gas from the producer at the wellhead for processing and then markets the resulting NGLs and residue gas at market prices. DEFS is also exposed to frac spread in these arrangements.

As defined by the terms of the above arrangements DEFS sells condensate, which is generally similar to crude oil and is produced in association with natural gas gathering and processing.

Competition

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

Supplies and Raw Materials

We purchase a variety of manufactured equipment and materials for use in our operations and expansion projects. The primary equipment and materials utilized in our operations and project execution processes are steel pipe, compression, valves, fittings, and other consumables.

We operate a North American supply chain management network with employees dedicated to this function in the United States and Canada. The supply chain management group uses the scale of the Spectra Energy group to maximize the efficiency of supply networks where applicable.

The recovery in global economic growth, particularly in the North American energy sector, and rising international demand have led to increased demand levels and increased cost of steel used in certain of our manufactured equipment. While some of these increases in price and supplier capacity will be offset through the use of strategic supplier contracts, we expect stable to rising prices and constant to extended lead times for many of these products in 2006 through 2008 compared to the previous three year period. The increasing costs and extended lead times are expected to primarily affect our expansion project execution process.

There can be no assurance that our ability to obtain sufficient equipment and materials will not be adversely affected by unforeseen developments. In addition, the price of equipment and materials may vary, perhaps substantially, from year to year.

Some of our major suppliers by category are:

• Major pipe suppliers: Corinth Pipe Works, Berg Steel Pipe Corp, Stupp & Mannesmann Line Pipe

• Major compression supplier: Solar Turbines

• Major valve supplier: Cooper Cameron Valves

• Union Gas construction contractors: AECON, Link-Line Contractors

• United States construction contractors: Associated Pipeline Constructors, Inc, Bi-Con Services, M. G. Dyess, Inc., Sheehan Pipeline Construction Co.

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Intellectual Property

We rely on a combination of intellectual property laws, trade secrets, nondisclosure agreements and other measures to protect our proprietary rights. We own a number of U.S. trademark registrations, including: Spectra Energy Corp, PanEnergy, Algonquin Gas Transmission Company, Texas Eastern Transmission Corporation, and Maritimes & Northeast.

We also rely on licenses with third parties to use various technologies that are material to our business. Specifically, certain core computer applications that are critical to the operational functions of our business were developed and are supported by third party vendors. Our business also relies on certain core third party systems to support various business functions, such as human resources, and financial and supply chain management.

Certain other computer applications which are essential to the operational functions of our business are proprietary applications that were developed by or for us and which are supported by internal personnel. We seek to protect our proprietary information and other intellectual property by generally requiring our employees, consultants, contractors, and other advisors to execute non-disclosure and assignment of invention agreements on commencement of their employment or engagement. Our policies forbid our employees from bringing the proprietary rights of third parties to us. We also generally require confidentiality or material transfer agreements from third parties that receive our confidential data or materials. We cannot provide any assurance that employees and third parties will abide by the confidentiality or assignment terms of these agreements. Despite measures taken to protect our intellectual property, unauthorized parties might copy aspects of our products or obtain and use information that we regard as proprietary.

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ENVIRONMENTAL MATTERS

We are subject to federal, state, provincial and local laws and regulations with regard to air and water quality, hazardous and solid waste disposal and other environmental matters. These regulations often impose substantial testing and certification requirements. The cost of complying with these regulations can be significant, and we expect to incur significant compliance costs in the future. Additionally, environmental permitting requirements can negatively affect our ability to engage in, or complete on a timely or cost efficient basis, new projects.

Environmental laws and regulations affecting us include, but are not limited to:

• The Clean Air Act, or CAA, and the 1990 amendments to the CAA, as well as state laws and regulations affecting air emissions (including State Implementation Plans related to existing and new national ambient air quality standards), which may limit new sources of air emissions. Our natural gas processing, transmission, and storage assets are considered sources of air emissions, and thus are subject to the CAA. Owners and/or operators of air emission sources, such as us, are responsible for obtaining permits for existing and new sources of air emissions, and for annual compliance and reporting.

• The Federal Water Pollution Control Act, which requires permits for facilities that discharge wastewaters into the environment. The Oil Pollution Act, or OPA, was enacted in 1990 and amends parts of the Clean Water Act and other statutes as they pertain to the prevention of and response to oil spills. OPA imposes certain spill prevention, control and countermeasure requirements. Although we are primarily a natural gas business, OPA affects our business primarily because of the presence of liquid hydrocarbons (condensate) in our offshore pipelines.

• The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, which imposes liability for remediation costs associated with environmentally contaminated sites. Under CERCLA, any individual or entity that currently owns or in the past owned or operated a disposal site can be held liable and required to share in remediation costs, as well as transporters or generators of hazardous substances sent to a disposal site. Because of the geographical extent of our operations we have disposed of waste at many different sites.

• The Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act, which requires certain solid wastes, including hazardous wastes, to be managed pursuant to a comprehensive regulatory regime. As part of our business, we generate solid waste within the scope of these regulations and therefore must comply with such regulations.

• The Toxic Substances Control Act, which requires that PCB contaminated materials be managed in accordance with a comprehensive regulatory regime. Because of the historic use of lubricating oils containing PCBs the internal surfaces of some of our pipeline systems are contaminated with PCBs and liquids and other materials removed from these pipelines must be managed in compliance with such regulations.

• The National Environmental Policy Act, which requires federal agencies to consider potential environmental impacts in their decisions, including siting approvals. Many of our projects require federal agency review, and therefore the environmental affect of proposed projects is a factor in determining whether we will be permitted to complete proposed projects.

• The Fisheries Act (Canada), which regulates activities near any body of water in Canada.

• The Environmental Management Act (British Columbia); The Environmental Protection and Enhancement Act (Alberta); and The Environmental Protection Act (Ontario), are each provincial laws governing various aspects, including permitting and site remediation obligations, of our facilities and operations in those provinces.

The pro forma condensed consolidated balance sheet of Spectra Energy includes reserves of approximately $22 million, as of September 30, 2006, to address remediation issues associated with approximately nine

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projects. These projects include the cost of disposal of PCB contaminated pipeline liquids through 2016, the cost of site remediation obligations at five sites owned or leased by us, and costs associated with remedial obligations at certain third party sites previously operated by us or at which we disposed waste. We believe that costs for environmental remediation and separately ongoing compliance with applicable environmental regulations will not have a material adverse effect on our cash flows, financial position or results of operations, or materially diminish our ability to operate our businesses. However, there can be no assurances that future events, such as changes in existing laws, the promulgation of new laws, the discovery of circumstances or conditions currently unforeseen by us, or that the development of new facts or conditions will not cause us to incur significant unanticipated costs and liabilities.

Canada’s obligation for the first Kyoto compliance period (2008-2012) is to achieve a 6% reduction of greenhouse gas emissions compared to a 1990 baseline. In 2005, the Canadian government published a proposed plan to achieve compliance with the greenhouse gas emission reductions required pursuant to Kyoto, which plan included a system of regulated emission targets and emissions trading for large industrial facilities. However, a new federal government was elected in 2006 and there is substantial uncertainty as to whether the government intends to comply with the Kyoto Protocol. If Canada does implement a program to reduce greenhouse gas emissions, we may be obligated to reduce emissions and/or purchase emission credits.

The United States is not a signatory to the Kyoto Protocol and there are currently no federal statutes or regulations that require us to reduce our emissions of greenhouse gases. However, over the last several years, there have been a number of developments relating to the potential regulation of greenhouse gas emissions. Although we do not think it is likely that we will be subject to such regulation in the short term, it is possible that we will be subject to regulation of greenhouse gas emissions in the future.

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EMPLOYEES, PROPERTIES AND FACILITIES,

GOVERNMENT REGULATION AND LEGAL PROCEEDINGS

Employees

As of December 1, 2006, we had approximately 4,800 employees, including approximately 3,200 employees outside of the United States, mostly in Canada. In addition, DEFS, our joint venture with ConocoPhillips, employed approximately 2,500 employees as of such date. Approximately 1,500 of our employees, all of whom are located in Canada, are subject to collective bargaining agreements governing their employment with our company. We believe that our employee relations are good and we reached agreements with all bargaining units with agreements subject to renewal in 2006.

Properties and Facilities

At December 31, 2005, we had over 100 primary facilities located in the United States and Canada. We generally own sites associated with our major pipeline facilities such as compressor stations, however, we generally operate our transmission facilities—transmission and distribution pipelines—using rights of way pursuant to easements to install and operate pipelines but do not own the fee of underlying realty. At year-end 2005, none of our property was secured by mortgages or other material security interests.

Our corporate headquarters are located at 5400 Westheimer Court, Houston, Texas 77056. The lease expires in April, 2018. We also maintain major offices in Calgary, Alberta; Vancouver, British Columbia; Chatham, Ontario; Boston, Massachusetts; Tampa, Florida; Halifax, Nova Scotia; and Nashville, Tennessee. For a description of our material properties, see the above section entitled “Business—Business Segments.”

We believe that we have satisfactory title to the properties owned and used in our businesses, subject to liens for taxes not yet payable, liens incident to minor encumbrances, liens for credit arrangements and easements and restrictions that do not materially detract from the value of these properties, our interests in these properties, or the use of these properties in our businesses. We believe that our properties are adequate and suitable for the conduct of our business in the future.

Our property, plant and equipment includes buildings, technical equipment, and other equipment capitalized under capital lease agreements. For more details please refer to Note 13 to Duke Capital LLC’s Consolidated Financial Statements.

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Regulations Generally Applicable to Our Business

Most of our U.S. gas transmission segment’s pipeline and storage operations are regulated by the FERC. The FERC regulates natural gas transportation in U.S. interstate commerce including the establishment of rates for services. The FERC also regulates the construction of U.S. interstate pipelines and storage facilities including extension, enlargement or abandonment of such facilities. In addition, certain operations are subject to oversight by state regulatory commissions.

FERC regulations restrict U.S. interstate pipelines from sharing transmission or customer information with energy affiliates and require that U.S. interstate pipelines function independently of their energy affiliates.

The FERC may propose and implement new rules and regulations affecting interstate natural gas transmission companies, which remain subject to the FERC’s jurisdiction. These initiatives may also affect certain transportation of gas by intrastate pipelines.

Our U.S. gas transmission segment’s operations are subject to the jurisdiction of the EPA and state and local environmental agencies. For a discussion of environmental regulation, please see the section entitled “Environmental Matters”. Our U.S. gas transmission segment’s interstate natural gas pipelines are also subject to the regulations of the DOT concerning pipeline safety.

The natural gas transmission, storage and distribution operations in Canada are subject to regulation by the National Energy Board, or NEB, and provincial agencies in Canada, such as the Ontario Energy Board. These agencies have jurisdiction similar to the FERC for regulating rates, regulating the operations of facilities and construction of any additional facilities. Our federally regulated gathering and processing facilities and business in Western Canada is regulated by the NEB pursuant to a framework for light-handed regulation under which the NEB acts on a complaints basis for rates associated with that business. Similarly, the rates charged by our midstream operations for gathering and processing services in Western Canada are regulated on a complaints basis by applicable provincial regulators. The Empress NGL businesses are not under any form of rate regulation.

The intrastate natural gas and NGL pipelines owned by DEFS are subject to state regulation. To the extent that the natural gas intrastate pipelines provide services under Section 311 of the Natural Gas Policy Act of 1978, they are also subject to FERC regulation. The interstate natural gas pipeline owned and operated by DEFS is subject to FERC regulation, but its natural gas gathering and processing activities are not subject to FERC regulation.

DEFS is subject to the jurisdiction of the EPA and state and local environmental agencies. For more information, see “Environmental Matters”. DEFS’ natural gas transmission pipelines and some gathering pipelines are also subject to the regulations of the DOT, and in some cases, state agencies, concerning pipeline safety.

Proceedings

Spectra Energy and its subsidiaries are involved in various legal, tax and regulatory proceedings in various forums regarding performance, contracts, royalty disputes, mismeasurement and mispayment claims (some of which are brought as class actions), and other matters arising in the ordinary course of business, some of which involve substantial amounts. Management believes that the final disposition of these proceedings will have no material adverse effect on Spectra Energy’s consolidated results of operations, cash flows or financial position.

Legal

Sonatrach/Sonatrading Arbitration

Duke Energy LNG Sales Inc. (Duke LNG), an indirect subsidiary of Spectra Energy, claims in an arbitration commenced in January 2001 in London that Sonatrach, the Algerian state-owned energy company, together with

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its subsidiary, Sonatrading Amsterdam B.V. (Sonatrading), breached their shipping obligations under a liquefied natural gas (LNG) purchase agreement and related transportation agreements (the LNG Agreements) relating to Duke LNG’s purchase of LNG from Algeria and its transportation by LNG tanker to Lake Charles, Louisiana. Duke LNG seeks damages of approximately $27 million. Sonatrading and Sonatrach, on the other hand, claim that Duke LNG repudiated the LNG Agreements by allegedly failing to diligently perform LNG marketing obligations. Sonatrading and Sonatrach seek damages in the amount of approximately $250 million. In 2003, an arbitration tribunal issued a partial award on liability issues, finding that Sonatrach and Sonatrading breached their obligations to provide shipping. The tribunal also found that Duke LNG breached the LNG Purchase Agreement by failing to perform marketing obligations. The final hearing on damages was concluded in March 2006, and the tribunal issued its award on damages on November 30, 2006. Duke LNG was awarded approximately $23 million for Sonatrach’s breach of its shipping obligations. Sonatrach and Sonatrading were awarded a smaller but unspecified amount that will, when calculated, be substantially less than the $23 million awarded to Duke LNG, and result ultimately in a net positive, but immaterial, award to Duke LNG.

Citrus Trading Corporation Litigation

In conjunction with the Sonatrach LNG Agreements, Duke LNG, an indirect subsidiary of Spectra Energy, entered into a natural gas purchase contract (the Citrus Agreement) with Citrus Trading Corporation, or Citrus. Citrus is owned 50% by El Paso and 50% by CCE Holdings. CCE Holdings is owned 50% by Southern Union, 30% by EFS-PA, LLC (a subsidiary of General Electric), and 20% by other institutional investors. Citrus filed a lawsuit in March 2003 in the U.S. District Court for the Southern District of Texas against Duke LNG and PanEnergy Corp alleging that Duke LNG breached the Citrus Agreement by failing to provide sufficient volumes of gas to Citrus. Duke LNG contends that Sonatrach caused Duke LNG to experience a loss of LNG supply that affected Duke LNG’s obligations and termination rights under the Citrus Agreement. Citrus seeks monetary damages and a judicial determination that Duke LNG did not experience such a loss. After Citrus filed its lawsuit, Duke LNG terminated the Citrus Agreement and filed a counterclaim asserting that Citrus had breached the agreement by, among other things, failing to provide sufficient security under a letter of credit for the gas transactions. Citrus denies that Duke LNG had the right to terminate the agreement and contends that Duke LNG’s termination of the agreement was itself a breach, entitling Citrus to terminate the agreement and recover damages in the amount of approximately $187 million. The Court has made rulings regarding the issues of fact and law that remain for trial, and the parties have jointly requested a trial setting in December 2006. It is not possible to predict with certainty whether we will incur any liability or to estimate the damages, if any, that we might incur in connection with the Citrus matter.

Duke Energy Retirement Cash Balance Plan

A class action lawsuit has been filed in federal court in South Carolina against Duke Energy and the Duke Energy Retirement Cash Balance Plan. Six causes of action are alleged, including violations of the Employee Retirement Income Security Act of 1974 (“ERISA”) and the Age Discrimination in Employment Act. These allegations arise out of the conversion of the Duke Power Company Employees’ Retirement Plan into the Duke Power Company Retirement Cash Balance Plan. The plaintiffs seek to represent present and former participants in the Duke Energy Retirement Cash Balance Plan. This group is estimated to include approximately 36,000 persons. Duke Energy filed its answer in March 2006. A second class action lawsuit was filed in federal court in South Carolina, alleging similar claims and seeking to represent the same class of defendants. The second case has been voluntarily dismissed, without prejudice, effectively consolidating it with the first case. It is not possible to predict with certainty whether we will incur any liability or to estimate the damages, if any, that we might incur in connection with this matter. We have agreed to share these liabilities with Duke Energy after the separation. For more information, see “Certain Relationships and Related Party Transactions—Separation and Distribution Agreement—Transfers of Assets and Assumptions of Liabilities.”

Regulatory

From time to time, we are subject to regulatory proceedings, including proceedings brought by governmental entities regulating the use or taxation of real estate, in the jurisdictions in which we operate, none

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of which we believe are likely to have a material adverse effect on our financial position, results of operations or cash flows. There can be no assurance that such regulatory proceedings, or any future regulatory proceedings, will not have a material adverse effect on our business, financial condition or results of operations.

Rate Related Information. Some of our interstate gas transmission companies from time to time have in effect rate settlements approved by FERC which prevent those companies or third parties from modifying rates, except for allowed adjustments. These settlements do not preclude FERC from taking action on its own to modify the rates. It is not possible to determine at this time whether any such actions will be instituted or what the outcome would be, but such proceedings could result in rate adjustments.

Our Canadian gas operations are subject to various degrees of regulation by Canadian authorities. The rates charged by a significant portion of our Canadian gas business for the gathering, processing and transmission services provided to shippers and the terms and conditions under which those services are provided are subject to regulation by the National Energy Board or NEB. Our federally regulated gathering and processing facilities and businesses in Western Canada are regulated by the NEB pursuant to “light-handed regulation” under which the NEB acts on a complaints basis for rates associated with that business. Similarly, the rates charged by our midstream operations for gathering and processing services in Western Canada are regulated on a complaints basis by applicable provincial regulators.

The BC Pipeline and Field Services operations of Westcoast Energy Inc. in Western Canada recorded regulatory assets related to deferred income tax liabilities of approximately $640 million as of December 31, 2005 and $612 million as of December 31, 2004. Under the current National Energy Board, or NEB-authorized rate structure, income tax costs are recovered in tolls based on the current income tax payable and do not include accruals for deferred income tax. However, as income taxes become payable as a result of the reversal of timing differences that created the deferred income taxes, it is expected that the transportation and field services tolls will be adjusted to recover these taxes. Since most of these timing differences are related to property, plant and equipment costs, this recovery is expected to occur over a 20 to 30 year period.

When evaluating the recoverability of the BC Pipeline and Field Services’ regulatory assets, management takes into consideration the NEB regulatory environment, natural gas reserve estimates for reserves located, or expected to be located, near these assets, the ability to remain competitive in the markets served, and projected demand growth estimates for the areas served by BC pipeline and field services business. Based on current evaluation of these factors, management believes that recovery of these tax costs is probable over the periods described above.

In November 2005, the BC Pipeline System filed an application with the NEB for interim and final tolls for 2006. In December 2005, the NEB approved the 2006 interim tolls as filed and BC Pipeline started negotiations with its shippers to reach a settlement on final tolls for years 2006 and 2007. BC Pipeline reached a toll settlement agreement in principal with its customers for the 2006 and 2007 fiscal years on March 30, 2006. This agreement includes an increase to the equity thickness from 31% in 2005 to 35% in 2006 and 36% in 2007. The total settlement agreement was approved by the NEB on August 17, 2006.

Union Gas is a regulated entity and is not generally subject to third-party competition within its distribution franchise area, although a recent decision of the OEB has permitted physical bypass of Union Gas’ facilities even within its distribution franchise area. In addition, other companies could enter Union Gas’ markets or regulations could change. Union Gas is regulated by the OEB pursuant to the provisions of the Ontario Energy Board Act (1998) and is subject to regulation in a number of areas including rates.

Effective January 1, 2006, Union Gas implemented new rates approved by the Ontario Energy Board in December 2005. Earnings in 2006 above an allowable rate of return on equity, normalized for weather, will be shared equally between ratepayers and Union Gas. Based on current estimates, management expects that 2006 weather-adjusted earnings are unlikely to exceed the allowable return on equity. In May 2006, the OEB accepted

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the settlement reached by Union Gas with intervenors on all financial issues related to Union Gas’ proposed 2007 rates, except regulation of storage rates and Demand Side Management (“DSM”) parameters. Storage regulation and DSM are being addressed through separate proceedings. The result of the settlement is an average rate increase of approximately 2.7% effective January 1, 2007. The agreement includes an increase in the common equity component of Union Gas’ capital structure, from 35% to 36% and no earnings sharing.

The OEB has issued a decision on most of the DSM parameters. The decision will result in an increase in Union Gas’ rates, which is associated with an increase in the DSM expense budget, of 1.4% effective January 1, 2007. The DSM process has not yet concluded, as the OEB will be setting out a process to address the DSM input assumptions that affect DSM program acceptance and design.

Union Gas’ rates for 2007 will also be affected by a change in its return on equity which is set by formula every October based on a forecast of long Canada bond rates. The current forecast suggests that there will be a decline in the return on equity, which would be implemented effective January 1.

As of December 31, 2005, Union Gas had regulatory assets of approximately $190 million related to deferred income tax liabilities like those discussed above for BC Pipeline and Field Services. Management believes that recovery of these tax costs is probable over long-term periods associated with the useful lives of Union Gas’ property, plant and equipment.

Effective January 1, 2005, new rates for Maritimes & Northeast Pipeline L.L.C. took effect, subject to refund, as a result of a rate case filed by Maritimes & Northeast Pipeline L.L.C. in 2004. In June 2005, a settlement agreement to resolve the proceeding was reached with customers that would provide for a rate increase over rates charged prior to January 1, 2005. This settlement agreement was approved by FERC on May 15, 2006, and the settlement rates were retroactively placed into effect on January 1, 2006. The order approving the settlement is subject to a request for rehearing by a non-customer of Maritimes & Northeast Pipeline L.L.C.

On November 1, 2005, East Tennessee Natural Gas, LLC placed into effect new rates approved by FERC as a result of a rate settlement with customers. The settlement agreement includes a five year rate moratorium that continues through 2010.

Algonquin is operating under a rate settlement with its customers which includes a rate moratorium that continues through 2008. Texas Eastern continues to operate with rates based on a 1998 settlement with a rate moratorium that ended in 2003. Currently, Gulfstream has no obligation to file a rate case and Gulfstream is not subject to a rate moratorium.

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MANAGEMENT

Executive Officers Following the Separation

While our expected executive officers are currently officers and employees of Duke Energy, after the separation, none of these individuals will continue to be employees of Duke Energy. The following table sets forth information regarding individuals who are expected to serve as our executive officers following the separation.

Name	Age	Position
Fred J. Fowler	61	President and Chief Executive Officer, Director
Martha B. Wyrsch	48	President and Chief Executive Officer, Spectra Energy Transmission, Director
Gregory L. Ebel	42	Group Executive and Chief Financial Officer
William S. Garner, Jr.	57	Group Vice President, General Counsel and Secretary
Alan N. Harris	53	Group Executive and Chief Development Officer
Keith A. Crane	42	Vice President and Treasurer
Sabra L. Harrington	43	Vice President and Controller

Fred J. Fowler is currently Group Executive and President of Duke Energy Gas. Mr. Fowler assumed his current position effective in April 2006. Prior to then, Mr. Fowler served as President and Chief Operating Officer of Duke Energy Corporation from November 2002 until April 2006. Mr. Fowler served as Group Vice President of PanEnergy from 1996 until the PanEnergy merger in 1997, when he was named Group Vice President, Energy Transmission.

Martha B. Wyrsch is currently President of Duke Energy Gas Transmission. Ms. Wyrsch assumed her current position effective in March 2005. Ms. Wyrsch served as Group Vice President and General Counsel of Duke Energy Corporation from January 2004 until March 2005. Prior to then, Ms. Wyrsch served as Senior Vice President, Legal Affairs for Duke Energy Corporation from February 2003 until January 2004; Senior Vice President, Legal Affairs for Duke Energy Business Services from January 2003 until February 2003 and Senior Vice President and General Counsel of Duke Energy Field Services from February 2001 until January 2003.

Gregory L. Ebel is currently President of Union Gas. Mr. Ebel assumed his current position effective in January 2005. Prior to then, Mr. Ebel served as Vice President, Investor & Shareholder Relations of Duke Energy Corporation from November 2002 until January 2005. Mr. Ebel joined Duke Energy as Managing Director of Mergers and Acquisitions in connection with the company’s acquisition of Westcoast Energy. He served in that position from March 2002 until November 2002. At Westcoast Energy, Mr. Ebel served as Vice President of Strategic Development from March 1999 until March 2002.

William S. Garner, Jr. is currently Group Vice President, Corporate Development of Duke Energy Gas Transmission. Mr. Garner assumed his current position effective in March 2006. Prior to joining Duke Energy, Mr. Garner served as managing director at Petrie Parkman & Co., a company which provides investment banking and advisory services to the energy industry and institutional investors. He served in this position from March 2000 until March 2006.

Alan N. Harris is currently Group Vice President and Chief Financial Officer of Duke Energy Gas Transmission. Mr. Harris assumed his current position effective in February 2004. Prior to then, Mr. Harris served as Executive Vice President of Duke Energy Gas Transmission from January 2003 until February 2004, Senior Vice President, Strategic Development & Planning from March 2002 until January 2003 and Vice President, Controller & Strategic Planning from April 1999 until March 2002.

Keith A. Crane was hired in October 2006 by Duke Energy Gas Transmission to become Vice President and Treasurer of Spectra Energy in connection with the spin off. Prior to joining Duke Energy, Mr. Crane was an independent financial consultant from June 2005 to October 2006, from January 2005 to June 2005, he was engaged in charitable work for the Houston Heights Association, a historic neighborhood preservation

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organization. From March 2003 until January 2005 he was treasurer for Entergy-Koch, LP a private energy trading and gas transportation company and parent of Entergy-Koch Trading, LP and from August 2001 to March 2003 he was Treasurer of both Entergy-Koch, LP and Entergy-Koch Trading, LP.

Sabra L. Harrington is currently Vice President, Financial Strategy of Duke Energy Gas Transmission and has served in this role since February 2006. Prior to then, Ms. Harrington served as Vice President and Controller of Duke Energy Gas Transmission from August 2003 until February 2006. From March 2002 until August 2003, Ms. Harrington served as Controller of Duke Energy Gas Transmission and from April 1999 until March 2002, she served as Director, Gas Accounting, Forecasts, Budgets and Reporting.

Board of Directors Following the Separation

In addition to Mr. Fowler and Ms. Wyrsch, the following sets forth information with respect to those persons who are expected to serve on our board of directors prior to our anticipated listing on the New York Stock Exchange. The board of directors will be expanded from three to seven members and the following nominees will be approved by the board for appointment prior to our listing on the New York Stock Exchange. Following the separation, we anticipate increasing the board to ten and appointing three additional directors. There are no arrangements between any director and any other person pursuant to which such director was selected for nomination. We may name and present additional nominees for appointment prior to the separation.

Name	Age	Position(s)
Paul M. Anderson	61	Chairman of the Board of Directors
Roger Agnelli	47	Director
William T. Esrey	66	Director
Dennis R. Hendrix	66	Director
Michael E.J. Phelps	59	Director

Paul M. Anderson is currently Chairman of the Board of Duke Energy. Prior to the merger of Duke Energy and Cinergy Corp. in April 2006, Mr. Anderson served as Chairman of the Board and Chief Executive Officer of Duke Energy from November 2003 to April 2006. Prior to such time, Mr. Anderson served as Managing Director and Chief Executive Officer of BHP Billiton Ltd and BHP Billiton PLC, which operate on a combined basis as BHP Billiton, the world’s largest diversified resources company and which is involved in major commodity businesses, from 1998 until his retirement in July 2002. Mr. Anderson also served on the Board of Directors of Fluor Corporation from March 2003 until October 2003, the Board of Directors of Temple Inland Inc. from August 2002 to May 2004, the Board of Directors of Qantas Airways from September 2002 to the present and the Board of Directors of BHP Billiton Limited from June 2006 to the present. Prior to joining BHP in 1998, Mr. Anderson had a career that spanned more than 20 years at Duke Energy and its predecessor companies, including serving as Chief Executive Officer of PanEnergy Corp. Mr. Anderson is currently a director of Duke Energy, Quantas Airways Limited, BHP Billiton Limited and BHP Billiton Plc.

Roger Agnelli is currently President and CEO of Companhia Vale do Rio Doce (CVRD), a global mining company and the world’s largest producer of iron ore. Mr. Agnelli was elected to that position in 2001. He served in various positions at Bradesco, a Brazilian financial conglomerate, from 1981 to 2001 and was President and CEO of Bradespar S.A. from March 2000 to July 2001. He is a director of Asea Brown Boveri (ABB Ltd), Suzano Petroquímica S.A. and Petrobras-Petroleo Brasileiro S.A.

William T. Esrey is Chairman Emeritus of Sprint Corporation, a diversified telecommunications holding company, since 2003. Prior to that he served as its CEO from 1985 to 2003, and as its Chairman from 1990 to 2003. He also served as Chairman of Japan Telecom from 2003 to 2004. Mr. Esrey is a director of General Mills, Inc.

Dennis R. Hendrix is currently the retired Chairman of the Board of PanEnergy Corp. He was Chairman of the Board of PanEnergy Corp from 1990 to 1997, CEO from 1990 to 1995 and President from 1990 to 1993.

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From 1997 to 2002 and from 2004 to the present Mr. Hendrix served as a director of Duke Energy. From 2002 until 2004 Mr. Hendrix served on the boards of Allied Waste Industries and Newfield Exploration Company, including serving as lead director of Allied Waste since December 2002, as well as Grant Prideco, Inc.

Michael E.J. Phelps is currently Chairman of Dornoch Capital Inc., an investment capital company, a position he assumed in 2003, and Chairman of Duke Energy Canadian Advisory Council, a position he assumed in 2002. He served as Chairman and CEO of Westcoast Energy Inc. from 1992 to 2002. He is a director of Canfor Corporation, Canadian Pacific Railway Company, Fairborne Energy Trust and Inco Limited.

Composition of the Board of Directors

Prior to our anticipated listing on the New York Stock Exchange, we expect our certificate of incorporation and by-laws to be amended to divide our board of directors into three classes with staggered terms, which means that the directors in one of these classes will be elected each year for a new three-year term. We expect that Class I directors will have an initial term expiring in 2007, Class II directors will have an initial term expiring in 2008 and Class III directors will have an initial term expiring in 2009. We also expect that Class I will be comprised of Messrs. Fowler, Esrey, and Hendrix, Class II will be comprised of Messrs. Anderson and Agnelli and Class III will be comprised of Ms. Wyrsch and Mr. Phelps.

Committees

Effective upon the completion of the separation, our board of directors will have the following committees:

Audit Committee

Our Audit Committee will have responsibility to select and retain a firm of independent public accountants to conduct audits of our accounts. It also will review with the independent registered public accountants the scope and results of their audits, as well as the review of our accounting procedures, internal controls, and accounting and financial reporting policies and practices, and make reports and recommendations to our board of directors as it deems appropriate. The audit committee will also be responsible for approving all audit and permissible non-audit services provided to us by our independent public accountants.

Compensation Committee

Our Compensation Committee will have oversight responsibility for the compensation and benefits programs for our executive officers and certain other employees.

Governance Committee

Our Governance Committee will have responsibility for matters related to corporate governance and will formulate our governance principles. This committee will recommend the size and composition of the board of directors and its committees and will recommend potential successors to the Chief Executive Officer. This committee will also recommend to the board of directors the slate of nominees, including any nominees recommended by shareholders, for director for each year’s annual meeting and, when vacancies occur, names of individuals who would make suitable directors of Spectra Energy.

Finance and Risk Management Committee

Our Finance and Risk Management Committee will have responsibility for matters related to our financial and capital investment policies and objectives, including specific actions required to achieve those objectives. The committee will recommend dividend policies to the board of directors, review our financial exposure and review our systems, processes and organizational structure for finance and risk functions.

Compensation Committee Interlocks and Insider Participation

With the exception of those listed above, none of our executive officers will serve as a member of our board of directors. In addition, Mr. Fowler and Ms. Wyrsch will not serve on our Compensation Committee. Following

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the separation, none of our executive officers will serve as a member of the compensation committee of any entity that has one or more executive officers serving on our Compensation Committee. Because Mr. Anderson will not be independent pursuant to the rules and regulations of the Securities and Exchange Commission and the New York Stock Exchange until at least January 1, 2010, Mr. Anderson will not serve on our Audit, Compensation or Governance Committee.

Board of Directors’ Compensation

Cash and Equity-Based Compensation

We intend to pay each non-employee director, for services following the distribution, as follows:

• an annual retainer of $50,000 for serving on the board;

• an annual retainer of $20,000 for the chair of the Audit Committee, and $8,500 for the directors who chair the other committees;

• a fee of $2,500 for special in-person meetings not held in conjunction with board meetings;

• a fee of $2,000 for attendance at each meeting of the board, a fee of $3,000 for in-person attendance (and $2,000 for telephonic meetings or participation) at each Audit Committee meeting and a fee of $2,000 for attendance at other committee meetings, whether attended in-person or by telephone; and

• an annual grant of equity-based compensation equal to $75,000, the form of which can vary from year-to-year.

We intend to reimburse directors for expenses reasonably incurred in connection with attendance and participation at board and committee meetings.

We do not intend to pay any director who is also an employee any compensation for serving as a director.

Deferred Compensation Plan for Outside Directors

We intend to adopt a deferred compensation plan for non-employee directors. Under the plan, all non-employee directors will be permitted to defer the receipt of all or a portion of the compensation they would otherwise receive for serving on our board of directors until termination of their service on our board of directors. The amounts deferred will be credited to participants’ accounts. The amounts credited to the accounts will vary based on increases and decreases in the value of investment alternatives to be offered under the plan.

Matching Gift Program

We intend to adopt a matching gift program for non-employee directors. Under this program, we will match gifts by participating directors to certain tax-exempt organizations of up to $5,000 per year.

Stock Ownership Guidelines

In order to align our directors’ interests with that of our shareholders, we intend to adopt stock ownership guidelines which establish a target level of ownership of our stock (or common stock equivalents).

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Executive Compensation

Summary Compensation Table

The following table contains compensation information concerning 2005, 2004 and 2003 for our Chief Executive Officer and the four of our other executive officers who, based on employment with Duke Energy and its subsidiaries, were the most highly compensated for the year ended December 31, 2005 (collectively, the “Named Executive Officers”). We are also including compensation information on our Chairman. All of the information included in this table reflects compensation earned by the individuals for services with Duke Energy and its subsidiaries. All references in the following tables to stock and stock options relate to awards of stock and stock options granted by Duke Energy. Such amounts do not necessarily reflect the compensation such persons will receive following the distribution, which could be higher or lower, because historical compensation was determined by Duke Energy and future compensation levels will be determined based on the compensation policies, programs and procedures to be established by our Compensation Committee.

		Annual Compensation				Long-Term Compensation
					Awards		Payouts
Name and Principal Position	Year	Salary ($)	Bonus ($)	Other Annual Compensation ($)	Restricted Stock Award(s) ($)1	Securities Underlying Options/ SARS (#)	LTIP Payouts ($)	All Other Compensation ($)2
Paul M. Anderson Chairman of the Board	2005 2004 2003	0 0 0	0 0 0	324,1703 365,296 0	04 0 11,255,250	0 0 1,100,000	0 0 0	0 0 0
Fred J. Fowler President and Chief Executive Officer	2005 2004 2003	755,496 729,996 670,009	1,129,550 1,062,509 603,000	70,477 67,282 46,237	1,246,607 1,204,413 878,113	0 0 201,000	0 0 0	113,982 84,882 44,102
Martha B. Wyrsch President and Chief Executive Officer, Gas Transmission Business	2005 2004 2003	470,004 450,000 325,000	475,679 439,335 162,500	249,6395 27,597 26,400	470,082 450,052 157,253	0 0 36,000	0 0 0	56,164 38,280 20,571
Alan N. Harris Chief Development Officer	2005 2004 2003	285,000 256,050 230,000	223,802 164,000 128,248	0 0 0	410,432 117,321 81,787	0 0 22,500	0 0 0	28,375 24,323 17,554
Gregory L. Ebel6 Chief Financial Officer	2005 2004 2003	253,995 200,004 180,000	173,957 137,283 83,520	224,3267 30,040 49,675	87,712 75,009 37,730	0 0 8,600	0 17,736 16,517	39,282 246,058 100,268
Sabra L. Harrington Vice President and Controller	2005 2004 2003	169,269 153,000 138,885	111,469 83,198 53,761	0 0 0	48,790 45,946 16,249	0 0 9,700	0 0 0	12,943 12,534 9,575

1 Messrs. Fowler, Harris and Ebel and Mses. Wyrsch and Harrington received one-half the value of the long-term incentive component of their 2005 compensation in the form of phantom stock; the other half was received as performance shares and, for 2005, is described in “Long-Term Incentive Plan—Awards in Last Fiscal Year” below. All awards were granted under the Duke Energy 1998 Long-Term Incentive Plan. Phantom stock is represented by units denominated in shares of Duke Energy common stock. As granted, each phantom stock unit that vests represents the right to receive one share of Duke Energy common stock. The phantom stock awards also grant an equal number of dividend equivalents, which represent the right to receive cash payments, equivalent to the cash dividends paid on the number of shares of Duke Energy common stock represented by unvested phantom units, while the award remains unvested. See “Equitable Adjustments to Outstanding Duke Energy Equity-Based Awards” below for a description of the treatment of these phantom stock awards in connection with the distribution.

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2005 Award. One fifth of the 2005 phantom stock award vests on each of the first five anniversaries of the grant date provided the recipient continues to be employed by Duke Energy or his or her employment terminates on account of retirement. If the recipient’s employment terminates as a result of death, disability, or by Duke Energy without cause or as a result of a divestiture, units in the award are reduced to reflect actual service during the installment vesting period and are immediately vested, and any remaining unvested units are forfeited. In the event employment is terminated by Duke Energy without cause within two years following a “change in control” of Duke Energy, as defined in the plan, all outstanding unvested units will vest. Vesting ceases if, at the time the recipient’s Duke Energy employment terminates, he or she is retirement eligible, as defined in the award agreement, and subsequent to such termination of employment becomes employed by, or otherwise provides service to, a Duke Energy competitor to the detriment of Duke Energy.

As described below in “Equitable Adjustments to Outstanding Duke Energy Equity-Based Awards,” certain features of the 2005 awards as described above will be modified in connection with the distribution.

The aggregate number of phantom stock units held by Messrs. Anderson, Fowler, Harris and Ebel, Mses. Wyrsch and Harrington at December 31, 2005, and their fair market values on that date (based on the closing price of a share of Duke Energy common stock as reported on the New York Stock Exchange Composite Transactions Tape on such date, which was $27.45) are as follows:

	Number of Phantom Stock Units	Value At December 31, 2005
Paul M. Anderson	285,000	$	7,823,250
Fred J. Fowler	90,568	$	2,486,092
Martha B. Wyrsch	33,998	$	933,245
Alan N. Harris	9,592	$	263,300
Gregory L. Ebel	6,008	$	164,920
Sabra L. Harrington	3,500	$	96,075

Mr. Harris received an award of restricted stock on February 1, 2005 granted under the Duke Energy 1998 Long-Term Incentive Plan. Mr. Harris’ aggregate restricted stock holdings at December 31, 2005 were 10,000 shares, with a fair market value on that date of $274,500 (based on the closing price of a share of Duke Energy common stock as reported on the New York Stock Exchange Composite Transactions Tape on December 30, 2005, which was $27.45). Dividends are paid on the restricted shares. All shares covered by the award are subject to a five-year service-based vesting requirement. See “Equitable Adjustments to Outstanding Duke Energy Equity-Based Awards” below for a description of the treatment of restricted stock awards in connection with the distribution. Phantom stock units are paid upon vesting, except that Mr. Anderson’s phantom stock units will be paid upon his termination of employment upon consummation of the distribution.

2 All Other Compensation column includes the following for 2005:

	Paul M. Anderson	Fred J. Fowler		Martha B. Wyrsch		Alan N. Harris		Gregory L.  Ebel		Sabra L. Harrington
Matching Contributions Under the Duke Energy Retirement Savings Plan	—	$	12,600	$	12,600	$	12,600	$	0	$	12,600
Make-Whole Matching Contribution Credits Under the Duke Energy Corporation Executive Savings Plan	—		96,480		41,960		14,340		0		0
Matching Contributions Under the Westcoast Energy Inc. Executive Share Purchase Plan	—		0		0		0		22,290		0
Economic Value of Life Insurance Coverage Provided Under Life Insurance Plans	—		4,902		1,604		1,435		0		343
Payment for Forfeited Company Match Contributions and Pension Benefit Accruala	—		0		0		0		16,992		0
Total	—	$	113,982	$	56,164	$	28,375	$	39,282	$	12,943

^a Payment for forfeited company match contributions under the Duke Energy Retirement Savings Plan and forfeited pension benefits under the Duke Energy Retirement Cash Balance Plan associated with Mr. Ebel’s short-term incentive bonus earned in 2004 and paid in 2005. Such forfeitures resulted from Mr. Ebel’s short- term incentive bonus becoming ineligible for benefits under the referenced plans upon accepting his current assignment with Union Gas Limited effective January 1, 2005.

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3 This amount includes $199,246 associated with the incremental cost to Duke Energy for personal use of company aircraft by Mr. Anderson.

4 Mr. Anderson received an award of performance shares granted under the Duke Energy 1998 Long-Term Incentive Plan upon the commencement of his employment with Duke Energy in 2003. Performance shares are represented by units denominated in shares of Duke Energy common stock. Each performance share, to the extent earned and vested, represents the right to receive one share of Duke Energy common stock payable upon Mr. Anderson’s termination of employment with Duke Energy upon consummation of the distribution. One hundred fourteen thousand (114,000) shares vested as of December 31, 2005, based upon achievement of 2005 performance goals, and 120,000 shares vested as of December 31, 2004, based upon achievement of 2004 performance goals. An additional 6,000 of the performance shares that could have vested on December 31, 2005, were forfeited, based upon the extent of Mr. Anderson’s achievement of 2005 performance goals. Up to 70,000 shares will vest on December 31, 2006, subject to achievement of performance goals established for calendar year 2006. Any shares subject to vesting in calendar year 2006 that do not vest upon achievement of goals associated with that year will be forfeited. The performance share award also grants an equal number of dividend equivalents, which represent the right to receive cash payments, equivalent to the cash dividends paid on the number of shares of Duke Energy common stock represented by vested and unvested performance shares, while the award remains outstanding but unpaid. Mr. Anderson’s aggregate performance share holdings (both vested and unvested but excluding the shares that were subsequently determined to have been forfeited based on the extent of achievement of 2005 performance goals) at December 30, 2005, were 354,000 shares, with a value on that date of $9,717,300, based on the closing price that day of a share of Duke Energy common stock as reported on the New York Stock Exchange Composite Transaction Tape, which was $27.45.

5 Includes $180,953 associated with the relocation of Ms. Wyrsch’s principal residence to Houston, Texas, including reimbursement of the related tax liability.

6 Most of Mr. Ebel’s 2005 compensation was provided in Canadian dollars and has been converted to U.S. dollars using the Bank of Canada noon rate of $0.8577 on December 30, 2005.

7 For 2005, includes $85,185 associated with the relocation of Mr. Ebel’s principal residence to Chatham, Ontario and also includes $79,236 for reimbursement of taxes representing the difference between Canadian taxes paid by Mr. Ebel on his income from Duke Energy versus the U.S. taxes Mr. Ebel would have paid on such income had it been earned in the U.S., pursuant to a tax equalization arrangement in connection with Mr. Ebel’s current assignment in Canada. For each of 2003, 2004 and 2005, includes $20,000 of principal, imputed interest ($1,839 for 2005, $1,394 for 2004 and $1,393 for 2003) and related tax gross-up amounts associated with a loan to Mr. Ebel that was partially forgiven by Duke Energy pursuant to the terms of a promissory note dated June 12, 2002.

Option/SAR Grants in 2005

Duke Energy did not grant any stock options or stock appreciation rights (SARs) in 2005 to the Named Executive Officers or any other persons.

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Option Exercises and Year-End Values

This table shows aggregate exercises of options during 2005 by the Named Executive Officers and our Chairman and the aggregate year-end value of the unexercised options held by them. The value assigned to each unexercised “in-the-money” stock option is based on the positive spread between the per share exercise price of the stock option and the closing price of a share of Duke Energy common stock as reported on the New York Stock Exchange Composite Transactions Tape on December 30, 2005, which was $27.45. The ultimate value of a stock option will depend on the market value of the underlying shares at the time of exercise. See “Equitable Adjustments to Outstanding Duke Energy Equity-Based Awards” below for a description of the treatment of these Duke Energy stock options in connection with the distribution.

Aggregated Option/SAR Exercises in Last Fiscal Year and Fiscal Year-End Option/SAR Values

Name	Shares Acquired on Exercise (#)	Value Realized ($)	Number of Securities Underlying Unexercised Options/SARS at FY-End1 (#)	Value of Unexercised In-the-Money Options/ SARS at FY-End1 ($)
			Exercisable/ Unexercisable	Exercisable/ Unexercisable
Paul M. Anderson	—	—	—  /1,100,000	—  /11,000,000
Fred J. Fowler	25,064	344,635	943,488 /100,500	1,891,240 / 1,374,840
Martha B. Wyrsch	—	—	131,700 /18,000	344,090 / 246,240
Alan N. Harris	4,600	71,603	41,875 / 9,875	27,038 / 123,700
Gregory L. Ebel	—	—	25,610 /5,858	146,058 / 58,824
Sabra L. Harrington	7,850	94,715	8,025/2,175	5,794/25,308

¹ Duke Energy has not granted any SARs to the Named Executive Officers or any other persons.

Executive Compensation

Long-Term Incentive Plan—Awards in Last Fiscal Year

As explained above in note 1 to the Summary Compensation Table, Messrs. Fowler, Harris and Ebel and Mses. Wyrsch and Harrington received one-half the value of the long-term incentive component of their 2005 compensation in the form of performance shares. The following table provides information concerning those performance share awards, which were made under the Duke Energy 1998 Long-Term Incentive Plan. Additional information in regard to these awards is set out following the table. For a description of the treatment of these performance share awards in connection with the distribution, see the section entitled “Equitable Adjustments to Outstanding Duke Energy Equity-Based Awards.”

Name	Number of Performance Shares1	Performance or Other Period	Estimated Future Payouts Under Non-Stock Price-Based Plans #
			Threshold	Target	Maximum
Paul M. Anderson	—	—	—	—	—
Fred J. Fowler	56,850	1/1/05-12/31/07	—	45,480	56,850
Martha B. Wyrsch	21,440	1/1/05-12/31/07	—	17,150	21,440
Alan N. Harris	6,500	1/1/05-12/31/07	—	5,200	6,500
Gregory L. Ebel	4,000	1/1/05-12/31/07	—	3,200	4,000
Sabra L. Harrington	2,230	1/1/05-12/31/07	—	1,780	2,230

¹ The number of shares awarded represents the number of shares of Duke Energy common stock payable upon achievement of the TSR goal at the maximum performance level (i.e., 125% of target award shares).

The determination of the actual number of performance shares earned is based on Duke Energy’s total shareholder return over the three-year performance period from January 1, 2005, to December 31, 2007, as compared to the total shareholder return of the S&P 500 for that period. The actual number of performance

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shares that can be earned ranges from 0% to 125% of target award shares. Performance shares begin to be earned if Duke Energy’s total shareholder return ranking is above the 40th percentile. To achieve the target and maximum payments indicated above, Duke Energy’s total shareholder return ranking must be at the 70th percentile and at the 80th percentile, respectively. Performance shares earned are interpolated for total shareholder return performance between these percentiles. For each performance share earned, participants receive one share of Duke Energy common stock. Payment of any shares earned will be made following the determination in early 2008 of the extent to which the performance goal has been achieved, unless an election (to the extent permitted by applicable law) is made by the executive to defer payment of the performance shares until termination of employment. Any shares not earned are forfeited. In addition, following a determination that the performance goal has been achieved, participants will receive a cash payment equal to the amount of cash dividends paid on one share of Duke Energy common stock during the performance period multiplied by the number of performance shares earned, unless an election is made by the executive to defer payment of the performance shares and tandem dividend equivalents until termination of employment. If the recipient’s employment terminates during the performance period as a result of retirement, death, disability, or by Duke Energy without cause or as a result of a divestiture, following determination that the total shareholders’ return goal has been achieved the number of shares earned will be adjusted to reflect actual service during the performance period. If the recipient’s employment terminates during the performance period for any other reason, all shares in the award will be forfeited. In the event of a “change in control” (as defined in the Duke Energy 1998 Long-Term Incentive Plan) prior to December 31, 2007, achievement of target total shareholder return performance is assumed and the number of shares earned are adjusted to reflect actual service during the performance period prior to the change in control. Vesting ceases if, at the time the recipient’s Duke Energy employment terminates, he or she is retirement eligible, as defined in the award agreement, and subsequent to such termination of employment becomes employed by, or otherwise provides service to, a Duke Energy competitor to the detriment of Duke Energy.

As described below in “Equitable Adjustments to Outstanding Duke Energy Equity-Based Awards,” certain features of these performance share awards as described above will be modified in connection with the distribution. In particular, effective as of the distribution, measurement of total shareholder return will be based upon two equity components, weighted 50% each, consisting respectively of Duke Energy common stock and our common stock.

Employment Contracts and Termination of Employment and Change-in-Control Arrangements

Mr. Anderson

Duke Energy entered into an employment agreement with Mr. Anderson which became effective November 1, 2003, upon his election as Chairman of the Board of Duke Energy and Chief Executive Officer and which, as amended April 4, 2006 to reflect Duke Energy’s merger with Cinergy Corp. and certain other matters, will expire by its terms on December 31, 2006.

We do not yet know the final details that will govern Mr. Anderson’s employment relationship with us, but we do expect that Mr. Anderson will be paid approximately $500,000 annually and (as is presently the case with his employment with Duke Energy) that substantially all of his compensation from us for services will be in the form of equity-based awards.

Named Executive Officers

Duke Energy is currently a party to change-in-control agreements with Mr. Fowler and Ms. Wyrsch, a separate severance agreement with Mr. Fowler and a letter agreement and loan with Mr. Ebel. Effective as of the distribution Duke Energy intends to terminate the change-in-control agreements with Mr. Fowler and Ms. Wyrsch, the severance agreement with Mr. Fowler and the letter agreement with Mr. Ebel. No payments will be made to either Messrs. Fowler or Ebel or Ms. Wyrsch in connection with the termination of such agreements. Effective as of the distribution, we intend to enter into agreements with each of the Named Executive Officers on

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terms substantially similar to the terms of the existing change-in-control agreements between Duke Energy and each of Mr. Fowler and Ms. Wyrsch. The principal terms and conditions of the existing change-in-control and severance agreements with Duke Energy are described below.

The change-in-control agreements have an initial term of two years, after which time the agreements automatically extend, unless six months prior written notice is provided, from the first date of each month for one additional month. They provide for payments and benefits to the executive in the event of termination of employment within two years after a “change in control” (or, with respect to our new agreements, in certain circumstances before a change in control, provided a change in control does ultimately occur) by Duke Energy without “cause” or by the executive for “good reason” (each such term as defined in the agreements and as they will be modified to reference a change in control of Spectra Energy) as follows:

• a lump-sum cash payment equal to a pro-rata amount of the executive’s target bonus for the year in which the termination occurs;

• a lump-sum cash payment equal to two times the sum of the executive’s annual base salary and target annual bonus opportunity in effect immediately prior to termination or, if higher, in effect immediately prior to the first occurrence of an event or circumstance constituting “good reason”;

• continued medical, dental and basic life insurance coverage for a two-year period following termination or, alternatively, a lump-sum cash payment equal to the aggregate cost of such coverage based on the premium costs of such coverage for former employees under COBRA, or the anticipated cost for such coverage for internal accounting purposes;

• a lump-sum cash payment representing the present value of the amount that Duke Energy would have allocated or contributed to the executive’s qualified and nonqualified defined benefit pension plan and defined contribution savings plan accounts during the two years following the termination date, plus the unvested portion, if any, of the executive’s accounts as of the date of termination that would have vested during such two year period; and

• continued vesting of long-term incentive awards, including awards of stock options but excluding awards of restricted stock, held but not vested or exercisable on the termination date, in accordance with their terms for two years following the termination date, with any options or similar rights thereafter remaining exercisable for 90 days, if their terms have not expired.

The executives are also entitled to reimbursement of up to $50,000 for the cost of certain legal fees incurred by them in connection with claims under the agreements. In the event that any payments or benefits provided to an executive would constitute an “excess parachute payment” (as defined in Section 280G of the Internal Revenue Code), the amount of payments or benefits would be reduced to the maximum level that would not result in excise tax under Section 4999 of the Internal Revenue Code if such a reduction would cause the executive to retain an after-tax amount in excess of what would be retained if no reduction were made. If an executive becomes entitled to payments and benefits under the change-in-control agreement, they would be subject to a one-year noncompetition and nonsolicitation provision from the date of termination, in addition to certain confidentiality and cooperation provisions. A “change-in-control” under the agreements does not include the distribution.

The severance agreement for Mr. Fowler is currently in effect on a month-to-month basis or for such longer period as may be mutually agreed upon by the parties. It provides for severance payments and benefits to Mr. Fowler in the event of termination of employment other than upon death, disability, for “cause” (as defined in the severance agreement) by Duke Energy. As noted above, we expect that the severance agreement will no longer be effective after the distribution.

Also as noted above, Duke Energy also is party to an offer letter with Mr. Ebel, dated June 1, 2005, in connection with his becoming President of Union Gas Limited effective January 1, 2005, the principal terms of which are as follows. The offer letter provides that Mr. Ebel’s annual base salary is CAN $290,000 with a short- term incentive target of 45% of salary. The offer letter further provides that Mr. Ebel will have a long-term

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incentive opportunity of 75% of salary and that he will receive a supplemental executive retirement benefit to

provide the pension benefits to which he would be entitled but for the application of Canadian income tax limits. Mr. Ebel was paid in a lump sum the value of the benefits that would have been provided under Duke Energy’s Retirement Savings Plan and Executive Cash Balance Plan in respect of 2004 short-term incentive payments had he not accepted his position with Union Gas Limited, relocated to Canada and ceased to be eligible under those plans. Mr. Ebel is entitled to reimbursement for certain club memberships and medical examinations. All payments to Mr. Ebel are tax adjusted such that he does not pay any more or less income and social security taxes than he would have paid had he not accepted his position with Union Gas Limited and relocated to Canada.

Retirement Plan Information

Prior to the distribution, our employees in the United States, including each of the Named Executive Officers, (other than Mr. Anderson and Mr. Ebel, who is currently working in Canada), will continue to earn benefits under the Duke Energy Retirement Cash Balance Plan (the “Retirement Cash Balance Plan”) which is a noncontributory, defined benefit retirement plan that is intended to satisfy the requirements for qualification under Section 401(a) of the Internal Revenue Code. Mr. Anderson participates in the Retirement Cash Balance Plan only for purposes of determining his eligibility to qualify for early or normal retirement. Selected management employees, including each of the Named Executive Officers other than Mr. Anderson and Mr. Ebel, also will continue to earn benefits under Duke Energy’s Executive Cash Balance Plan (the “Executive Cash Balance Plan”), which is a noncontributory, defined benefit retirement plan that is not intended to satisfy the Internal Revenue Code qualification requirements. Benefits earned in the Executive Cash Balance Plan are attributable to (i) compensation in excess of the annual compensation limit ($220,000 for 2006) under the Internal Revenue Code that applies to the determination of pay credits under the Retirement Cash Balance Plan, (ii) certain deferred compensation that is not recognized by the Retirement Cash Balance Plan, (iii) restoration of benefits in excess of a defined benefit plan maximum annual benefit limit ($175,000 for 2006) under the Internal Revenue Code that applies to the Retirement Cash Balance Plan, and (iv) supplemental benefits, if any, granted to a particular participant. Generally, benefits earned in the Retirement Cash Balance Plan and the Executive Cash Balance Plan vest upon completion of five years of service, and vested benefits become payable upon termination of employment and attainment of age 55. In connection with the Pension Protection Act of 2006, Duke Energy intends to amend the Retirement Cash Balance Plan’s (and potentially the Executive Cash Balance Plan’s) vesting schedule and distribution provisions; however, final details about these amendments have not been determined.

The benefit accrual formula used to determine pay credits under the Retirement Cash Balance Plan and the Executive Cash Balance Plan is based upon eligible pay, generally consisting of base pay, overtime, short-term incentives and lump-sum merit increases. The Retirement Cash Balance Plan excludes eligible pay in excess of the annual compensation limit under the Internal Revenue Code, while the Executive Cash Balance Plan excludes eligible pay up to such limit. The Retirement Cash Balance Plan excludes deferred compensation other than deferrals pursuant to Sections 401(k) or 125 of the Internal Revenue Code. Under the Retirement Cash Balance Plan and Executive Cash Balance Plan benefit accrual formula, a participating employee’s account receives a pay credit at the end of each month in which the employee remains eligible for the respective plan and receives eligible pay for services. The monthly pay credit is equal to a percentage of the employee’s monthly eligible pay. The percentage depends on age and completed years of service at the beginning of the year, as shown below:

Age and Service	Monthly Pay Credit Percentage
34 or less	4	%
35 to 49	5	%
50 to 64	6	%
65 or more	7	%

In addition, there is an additional 4% pay credit for any portion of eligible pay above the Social Security taxable wage base ($94,200 for 2006). Participant accounts also receive monthly interest credits on their balances. The

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rate of the interest credit is adjusted quarterly and equals the yield on 30-year U.S. Treasury Bonds during the third week of the last month of the previous quarter, subject to a minimum rate of 4% per year and a maximum rate of 9% per year.

We intend to adopt, effective as of the distribution, a noncontributory, defined benefit retirement plan that is intended to satisfy the requirements for qualification under Section 401(a) of the Internal Revenue Code and that is substantially similar to the Retirement Cash Balance Plan effective as of the time of distribution. We also intend to adopt, effective as of the distribution, a nonqualified, noncontributory defined benefit retirement plan that replicates the Executive Cash Balance Plan. Assuming that Messrs. Fowler, Harris, Ebel, and Mses. Wyrsch and Harrington continue in their present positions at their present salaries and target bonus opportunities until retirement at age 65, their estimated annual pensions in a single life annuity form under the Retirement Cash Balance Plan and Executive Cash Balance Plan plans that we intend to adopt, which amount is determined as if their service and compensation at Duke Energy is taken into account under our plans, would be: Mr. Fowler, $316,248; Ms. Wyrsch, $257,601; Mr. Harris, $105,324; Ms. Harrington, $30,988; and Mr. Ebel $128,023. These estimates are calculated assuming interest credits at an annual rate of 4% and using a 2006 Social Security taxable wage base equal to $94,200, increasing 4.5% annually. With respect to Mr. Ebel, a portion of the estimated benefit was earned prior to January 1, 2005, when Mr. Ebel worked in the United States and participated in the Retirement Cash Balance Plan and Executive Cash Balance Plan, and a portion of the estimated benefit was determined by assuming, consistent with our expectation, that Mr. Ebel will resume earning benefits in these plans commencing upon the distribution.

Mr. Ebel currently earns benefits under the Executive provisions of the Pension Choices Plan sponsored by Westcoast Energy, Inc. for employees of Westcoast Energy, Inc. and its affiliated companies, a noncontributory defined benefit pension plan that is intended to satisfy the requirements of the Canadian Income Tax Act and which we intend to assume effective as of the distribution. The Pension Choices Plan generally provides a life annuity (with a minimum guarantee of 120 monthly payments) commencing at normal retirement age (age 65) equal to 2% of final average earnings (generally equal to salary and short-term incentives) times years of credited service. The amount of benefits is adjusted if the benefits are paid in different available forms or commence other than at normal retirement age. Westcoast Energy will pay any portion of the benefit that, because of Canadian Income Tax Act limits, cannot be paid under the Pension Choices Plan. Although benefits under the Pension Choices Plan are not reduced in respect of Canadian Old Age Security (OAS) Benefits, OAS benefits are subject to a “claw back” if an individual’s annual income exceeds specified limits. Mr. Ebel is fully vested in his Pension Choices Plan benefit. As of December 31, 2005, Mr. Ebel was credited with 5.48 years of credited service under the Pension Choices Plan. Assuming that Mr. Ebel continues in his present position at his present salary and target bonus opportunity until the distribution (at which time we expect him to cease earning benefits under the Pension Choices Plan and commence earning benefits under the Retirement Cash Balance Plan and Executive Cash Balance Plan), his estimated annual pension in a single life annuity form (with a minimum guarantee of 120 monthly payments) under the Pension Choices Plan, including the portions in excess of the Canadian Income Tax Act Limits, would be approximately $53,177. Benefits provided under the Pension Choices Plan are provided in Canadian dollars and have been converted to U.S. dollars using the Bank of Canada noon rate of $0.8577 on December 30, 2005.

Equitable Adjustments to Outstanding Duke Energy Equity-Based Awards

In connection with the distribution, equitable adjustments will be made to outstanding restricted stock, phantom stock, performance share and stock option awards that currently relate to Duke Energy common stock to the extent necessary to maintain the equivalent value of such awards upon the distribution.

Effective as of the distribution, each holder (including Duke Energy current and former employees and our current and former employees) of Duke Energy restricted stock will be issued additional restricted shares of our common stock (i.e., as with other Duke Energy shareholders, 0.5 shares of our common stock for each restricted Duke Energy share). The new restricted shares of our common stock and the existing Duke Energy restricted shares will become vested on the date on which the shares would have vested in accordance with the terms of the existing Duke Energy restricted stock vesting schedule (with appropriate adjustments to performance metrics in

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the case of performance vesting), subject to applicable tax withholdings. For purposes of the vesting of restricted

stock, continued employment with Duke Energy or us will be viewed as continued employment with the issuer of the restricted stock.

Effective as of the distribution, each holder (including Duke Energy current and former employees and our current and former employees) of Duke Energy phantom stock and performance shares (for purposes of this paragraph, “stock units” or “units”) will be issued a number of additional units relating to our common stock equal to the number of shares of our common stock that such holder would have received in the distribution assuming the stock units relating to Duke Energy common stock represented actual shares of Duke Energy common stock (i.e., a ratio of 0.5 units relating to our common stock for each unit relating to Duke Energy common stock). The new stock units relating to our common stock and the existing Duke Energy stock units will become vested on the date on which such units would have vested in accordance with the terms of the existing Duke Energy unit vesting schedule (with appropriate adjustments to performance metrics in the case of performance units) and will be settled in shares of our common stock or Duke Energy common stock as the case may be (subject to applicable tax withholdings). For purposes of the vesting of such stock units, continued employment with Duke Energy or us will be viewed as continued employment with the issuer of the units.

Effective as of the distribution (immediately prior for participants subject to Canadian income taxes), equitable adjustments will be made with respect to stock options relating to Duke Energy common stock held by Duke Energy directors, officers and employees (including our current and former directors, officers and employees). All such options will be adjusted into two separate options, one relating to Duke Energy common stock and one relating to our common stock. Such adjustment is expected to be made such that (i) the number of shares relating to the option covering our common stock will be equal to the number of shares of our common stock that the option holder would have received in the distribution had the Duke Energy option shares represented outstanding shares of Duke Energy common stock (i.e., 0.5 shares of our common stock for each share of Duke Energy common stock), and (ii) the per share option exercise price of the original Duke Energy stock option will be proportionally allocated between the two types of stock options taking into account the distribution ratio and the relative per share trading prices following the distribution. The resulting Duke Energy options and options covering our common stock will continue to be subject to the vesting schedule under the existing Duke Energy option. For purposes of vesting and the post-termination exercise periods applicable to the options, continued employment with Duke Energy or us will be viewed as continued employment with the issuer of the options.

Annual Incentive Plan

We have adopted, contingent upon the consummation of the distribution, an Annual Incentive Plan covering our senior management (the “AIP”). The AIP will be administered by our Compensation Committee or such other committee as our board of directors shall appoint from time to time to administer the AIP and to otherwise exercise and perform the authority and functions assigned to such committee under the AIP (for purposes of this description of the AIP, the “Committee”).

We also expect that from time to time we will adopt additional short-term incentive programs for employees other than our senior management. The terms of any such plans may differ from the AIP.

We describe below some of the terms of the AIP. However, the description is not intended to be a complete description of the terms of the AIP, and it is qualified in its entirety by the terms of the AIP, a form of which was filed as an exhibit to our registration statement on Form 10, of which a form of this Information Statement is a part.

The Committee in its discretion will determine which senior management members will participate in the AIP for any year and we expect that, before the end of the first quarter of each year, the Committee will establish performance targets and corresponding target awards for each AIP participant for that year. The Committee may establish a performance target as a specified level of a business measure and provide that the performance target will be determined by eliminating the financial effects of specified transactions or occurrences. The performance

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targets may track the following business measures (or others) for us or any of our subsidiaries or business units: total shareholder return; stock price increase; return on equity; return on capital; earnings per share; EBIT (earnings before interest and taxes); EBITDA (earnings before interest, taxes, depreciation and amortization); ongoing earnings (as defined by management); cash flow (including operating cash flow, free cash flow, discounted cash flow return on investment, and cash flow in excess of costs of capital); EVA (economic value added); economic profit (net operating profit after tax, less a cost of capital charge); SVA (shareholder value added); revenues; net income; operating income; pre-tax profit margin; performance against business plan; customer service; corporate governance quotient or rating; market share; employee satisfaction; safety; employee engagement; supplier diversity; workforce diversity; operating margins; credit rating; dividend payments; expenses; retained earnings; completion of acquisitions, divestitures and corporate restructuring; and individual goals based on objective business criteria underlying the goals listed above and which pertain to individual effort as to achievement of those goals or to one or more business criteria in the areas of litigation, human resources, information services, production, inventory, support services, site development, plant development, building development, facility development, government relations, product market share or management.

Achievement of the business measures listed above (or others) may be determined on a stand-alone basis or as compared to a peer group. In addition, the Committee may establish strategic objectives, instead of business measures, as performance targets for awards. Awards will be payable in cash and the total amount of all award payments to any AIP participant will not exceed $4,000,000 for any given year.

We expect that, soon after the close of each year, the Committee will certify in writing the extent to which the performance targets have been achieved and that, if any targets have been achieved, the Committee will determine for each participant the amount of the award that has been earned, based on a predetermined formula. The Committee may retain authority to reduce the amount of any of these awards based upon its assessment of individual performance, the failure of the participant to remain employed by us or our subsidiaries throughout the year, or for any other reason, and the Committee will have the authority to allow participants to defer payment of all or part of any awards.

The Committee has the authority to amend or modify the AIP in its discretion, but no amendment or modification will be effective without approval by our board of directors or our shareholders to the extent required by applicable exchange listing requirements or laws (including, as and when applicable, the requirements of Section 162(m) of the Internal Revenue Code).

2007 Long-Term Incentive Plan

We have adopted, and Duke Energy as our sole shareholder, has approved, contingent upon the consummation of the distribution, a 2007 Long-Term Incentive Plan (the “LTIP”). The LTIP permits the issuance of long-term incentive awards in connection with the distribution in partial substitution of long-term incentive awards previously issued by Duke Energy and its affiliates (the “Substitution Awards”) as more fully described above under “Equity Adjustments to Outstanding Equity-Based Awards.” The LTIP will be administered by our Compensation Committee or such other committee as our board of directors shall appoint from time to time to administer the LTIP and to otherwise exercise and perform the authority and functions assigned to such committee under the LTIP (for purposes of this description of the LTIP, the “Committee”).

In addition to authorizing the issuance of Substitution Awards, the purpose of the LTIP is to attract, motivate and retain our key employees, non-employee directors and consultants and to align their interests with the interests of our other shareholders. The LTIP is designed to meet this purpose by providing such key employees, non-employee directors and consultants with a proprietary interest in us. The awards made under the LTIP may be subject to terms and conditions that differ from the terms and conditions applicable to the Substitution Awards.

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We describe below some of the terms of the LTIP. However, the description is not intended to be a complete description of the terms of the LTIP, and it is qualified in its entirety by reference to the full text of the LTIP, a form of which was filed as an exhibit to our registration statement on Form 10, of which a form of this Information Statement is a part.

Reservation Of Shares. We have reserved 30,000,000 shares of common stock for issuance under the LTIP plus the number of shares of common stock that are covered by Substitution Awards, which may include authorized but unissued shares, treasury shares, or a combination thereof. Shares issued in connection with Substitution Awards shall not count against the 30,000,000 limit described above, and shares of common stock that are issued in connection with all awards other than stock options and stock appreciation rights will be counted against the 30,000,000 limit described above as four shares of common stock for every one share of common stock that is issued in connection with an award.

Shares covered by an award granted under the LTIP will not be counted as used unless and until they are actually issued and delivered to a participant. Shares covering awards that expire, are forfeited or are cancelled will again be available for issuance under the LTIP, and upon payment in cash of the benefit provided by any award granted under the LTIP, any shares that were covered by that award will be available for issue or transfer under the LTIP. However, the following shares of common stock will not be added back to the aggregate plan limit described above: (1) shares tendered in payment of the option price of a stock option; (2) shares withheld by us to satisfy a tax withholding obligation; and (3) shares that are repurchased by us in connection with the exercise of a stock option granted under the LTIP. Moreover, all shares covered by a stock appreciation right, to the extent that it is exercised and settled in shares, and whether or not shares are actually issued to the participant upon exercise of the right, will be considered issued or transferred pursuant to the LTIP.

In addition to the aggregate limit on awards described above, the LTIP imposes various sub-limits on the number of shares that may be issued or transferred thereunder. The aggregate number of shares actually issued or transferred upon the exercise of incentive stock options, other than Substitution Awards, may not exceed 30,000,000 shares. In anticipation of the eventual application of the limitations (and exceptions from the application) of Section 162(m) of the Internal Revenue Code, the LTIP imposes the following additional sub-limits, which apply except with respect to Substitution Awards: (i) no participant will be granted option rights for more than 3,000,000 shares during any calendar year, (ii) no participant will be granted stock appreciation rights for more than 3,000,000 shares during any calendar year, (iii) no participant will be granted restricted shares for more than 600,000 shares during any calendar year, (iv) no participant will be granted performance shares for more than 600,000 shares during any calendar year, and (v) no participant will be granted performance units having an aggregate maximum value as of their date of grant in excess of $3,750,000 during any calendar year.

The maximum number of shares which may be awarded under the LTIP and the various sub-limits described above will be subject to adjustment in the event of any merger, consolidation, liquidation, issuance of rights or warrants to purchase securities, recapitalization, reclassification, stock dividend, spin-off, split-off, stock split, reverse stock split or other distribution with respect to the shares of common stock, or any similar corporate transaction or event in respect of our common stock.

Administration. As noted above, the LTIP will be administered by the Committee. Subject to the limitations set forth in the LTIP, the Committee will have the authority to determine the persons to whom awards are granted, the types of awards to be granted, the time at which awards will be granted, the number of shares, units or other rights subject to each award, the exercise, base or purchase price of an award (if any), the time or times at which the award will become vested, exercisable or payable, the performance criteria, performance goals and other conditions of an award, and the duration of the award. The Committee may provide for the acceleration of the vesting or exercise period of an award at any time prior to its termination or upon the occurrence of specified events. With the consent of the affected participant, the Committee has the authority to cancel and replace awards previously granted with new awards for the same or a different number of shares and for the same or different exercise or base price and may amend the terms of any outstanding award, provided that the Committee does not have the authority to reduce the exercise or base price of an award by amendment or cancellation and substitution

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of an existing award without approval of our shareholders. The Committee has the right, from time to time, to delegate to one or more of our officers the authority to grant and determine the terms and conditions of awards under the LTIP, subject to such limitations as the Committee may determine. With respect to awards granted under the LTIP to non-employee members of our board of directors, all rights, powers and authorities vested in the Committee under the LTIP will instead be exercised by the board of directors.

Eligibility. All of our key employees and all key employees of any of our subsidiaries (or any person who has agreed to serve in such capacity), all non-employee members of our board of directors and individuals serving us or our subsidiaries as consultants (or any person who has agreed to serve in such capacity) are eligible to be granted awards under the LTIP, as selected from time to time by the Committee in its sole discretion.

Stock Options. The LTIP authorizes the grant of nonqualified stock options and incentive stock options. Nonqualified stock options may be granted to employees, non-employee directors and consultants. Incentive stock options may only be granted to employees. The exercise price of an option will be determined by the Committee, provided that the exercise price per share of an option may not be less than the fair market value of a share of common stock on the date of grant (which date may not be earlier than the date that the Committee takes action with respect thereto). The value of common stock (determined at the date of grant) that may be subject to incentive stock options that become exercisable by any one employee in any one year will be limited to $100,000. The maximum term of stock options granted under the LTIP will be ten years from the date of grant. The Committee will determine the extent to which an option will become and/or remain exercisable in the event of termination of employment or service of a participant under certain circumstances, including retirement, death or disability, subject to certain limitations for incentive stock options. Under the LTIP, the exercise price of an option will be payable by the participant (i) in cash, (ii) in the discretion of the Committee, in shares of common stock that are already owned by the option holder and have a value at the time of exercise equal to the option price, (iii) in the discretion of the Committee, from the proceeds of sale through a broker on the date of exercise of some or all of the shares of common stock to which the exercise relates, (iv) in the discretion of the Committee, by withholding from delivery shares of common stock for which the option is otherwise exercised, or (v) by any other method approved of by the Committee.

Stock Appreciation Rights. The LTIP authorizes the grant of awards of stock appreciation rights. A stock appreciation right may be granted either in tandem with an option or without relationship to an option. A stock appreciation right entitles the holder, upon exercise, to receive a payment based on the difference between the base price of the stock appreciation right and the fair market value of a share of common stock on the date of exercise, multiplied by the number of shares as to which such stock appreciation right will have been exercised. A stock appreciation right granted in tandem with an option will have a base price per share equal to the per share exercise price of the option, will be exercisable only at such time or times as the related option is exercisable and will expire no later than the time when the related option expires. Exercise of the option or the stock appreciation right as to a number of shares will result in the cancellation of the same number of shares under the tandem right. A stock appreciation right granted without relationship to an option will be exercisable as determined by the Committee, but in no event after ten years from the date of grant. The base price assigned to a stock appreciation right granted without relationship to an option will not be less than 100% of the fair market value of a share of common stock on the date of grant (which date may not be earlier than the date that the Committee takes action with respect thereto). Stock appreciation rights will be payable in cash, in shares of common stock, or in a combination of cash and shares of common stock, in the discretion of the Committee.

Performance Awards. The LTIP authorizes the grant of performance awards, which are units denominated on the date of grant either in shares of common stock (“performance shares”) or in specified dollar amounts (“performance units”). Performance awards will be payable upon the achievement of performance criteria established by the Committee at the beginning of the performance period, which may not exceed ten years from the date of grant. At the time of grant, the Committee will establish the number of units, the duration of the performance period or periods, the applicable performance criteria, and, in the case of performance units, the target unit value or range of unit values for the performance awards. At the end of the performance period, the Committee will determine the payment to be made based on the extent to which the performance goals have been

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achieved. Performance awards will be payable in cash, in shares of common stock, or in a combination of cash and shares of common stock, in the discretion of the Committee.

The Committee eventually will grant performance awards that are intended to qualify for the exemption for performance-based compensation under Section 162(m) of the Internal Revenue Code, as well as performance awards that are not intended to so qualify. The performance criteria for a Section 162(m) qualified award, which may relate to us, any subsidiary, any business unit or any participant, and may be measured on an absolute or relative to peer group or other market measure basis, are limited to: total shareholder return; stock price increase; return on equity; return on capital; earnings per share; EBIT (earnings before interest and taxes); EBITDA (earnings before interest, taxes, depreciation and amortization); ongoing earnings (as defined by management); cash flow (including operating cash flow, free cash flow, discounted cash flow return on investment, and cash flow in excess of costs of capital); EVA (economic value added); economic profit (net operating profit after tax, less a cost of capital charge); SVA (shareholder value added); revenues; net income; operating income; pre-tax profit margin; performance against business plan; customer service; corporate governance quotient or rating; market share; employee satisfaction; safety; employee engagement; supplier diversity; workforce diversity; operating margins; credit rating; dividend payments; expenses; retained earnings; completion of acquisitions, divestitures and corporate restructurings; and individual goals based on objective business criteria underlying the goals listed above and which pertain to individual effort as to achievement of those goals based on objective business criteria underlying the goals listed above and which pertain to individual effort as to achievement of those goals or to one or more business criteria in the areas of litigation, human resources, information services, production, inventory, support services, site development, plant development, building development, facility development, government relations, product market share or management. In the case of a performance award that is not intended to qualify for exemption from Section 162(m) of the Internal Revenue Code, the Committee will designate performance criteria from among the foregoing or such other business criteria as it shall determine it its sole discretion.

Restricted Stock Awards. The LTIP authorizes the grant of awards of restricted stock. An award of restricted stock represents shares of common stock that are issued subject to such restrictions on transfer and on incidents of ownership and such forfeiture conditions as the Committee deems appropriate. The restrictions imposed upon an award of restricted stock will lapse in accordance with the vesting requirements specified by the Committee in the award agreement. Such vesting requirements may be based on the continued employment or service of the participant for a specified time period (not less than one year) or on the attainment of specified business goals or performance criteria established by the Committee. The Committee may, in connection with an award of restricted stock, require the payment of a specified purchase price. Subject to the transfer restrictions and forfeiture restrictions relating to the restricted stock award, the participant will otherwise have the rights of our shareholders, including all voting and dividend rights, during the period of restriction unless the Committee determines otherwise at the time of the grant. The Committee may grant awards of restricted stock that are intended to qualify for exemption from Section 162(m) of the Internal Revenue Code, as well as awards that are not intended to so qualify. An award of restricted stock that is intended to qualify for exemption from Section 162(m) will have its vesting requirements limited to the performance criteria described above under the section entitled “2007 Long-Term Incentive Plan—Performance Awards.”

Phantom Stock. The LTIP authorizes the grant of awards of phantom stock. An award of phantom stock gives the participant the right to receive payment at the end of a fixed vesting period based on the value of a share of common stock at the time of vesting. No vesting period will exceed ten years from the date of grant. Phantom stock units will be subject to such restrictions and conditions to payment as the Committee determines are appropriate. Phantom stock awards will be payable in cash or in shares of common stock having an equivalent fair market value on the applicable vesting dates, or in a combination thereof, in the discretion of the Committee.

Stock Bonus. The LTIP authorizes the grant of stock bonuses. A stock bonus represents a specified number of shares of common stock that are issued without restrictions on transfer or forfeiture conditions. The Committee may require the payment of a specified purchase price.

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Dividend Equivalents. The LTIP authorizes the grant of awards of dividend equivalents. Dividend equivalent awards entitle the holder to a right to receive cash payments determined by reference to dividends declared on our common stock (if any) during the term of the award, which will not exceed ten years from the date of grant. Dividend equivalent awards may be granted on a stand-alone basis or in tandem with other awards under the LTIP. Dividend equivalent awards granted on a tandem basis with other awards will expire at the time the underlying award is exercised, otherwise becomes payable, or expires. Dividend equivalent awards will be payable in cash or in shares of common stock, as determined by the Committee.

Change in Control. The Committee has the authority to provide for the effect of a “change in control” (as defined in the LTIP or in an award agreement granted thereunder) on an award granted under the LTIP. Such provisions may include (i) the acceleration or extension of time periods for purposes of exercising, vesting in, or realizing gain from an award, (ii) the waiver or modification of performance or other conditions related to payment or other rights under an award, (iii) providing for the cash settlement of an award, or (iv) such other modification or adjustment to an award as the Committee deems appropriate to maintain and protect the rights and interests of participants upon or following the change in control.

Adjustments to Awards. In the event of any merger, consolidation, liquidation, issuance of rights or warrants to purchase securities, recapitalization, reclassification, stock dividend, spin-off, split-off, stock split, reverse stock split or other distribution with respect to our shares of common stock, or any similar corporate transaction or event in respect of our common stock, the Committee has the authority, in the manner and to the extent that it deems appropriate and equitable to the participants and consistent with the terms of the LTIP, to cause a proportionate adjustment to be made in the number and kind of shares of common stock, share units, or other rights subject to the then-outstanding awards, the price for each share or unit or other right subject to then outstanding awards with or without change in the aggregate purchase price or value as to which such awards remain exercisable or subject to restrictions, the performance targets or goals appropriate to any outstanding performance awards (subject to such limitations as appropriate for awards intended to qualify for exemption from Section 162(m) of the Internal Revenue Code) or any other terms of an award that are affected by the event. Moreover, in the event of any such transaction or event, the Committee, in its discretion, has the authority to provide in substitution for any or all outstanding awards under the LTIP such alternative consideration (including cash) as it, in good faith, may determine to be equitable under the circumstances and may require in connection therewith the surrender of all awards so replaced.

Transferability of Awards. In general, awards granted under the LTIP are not transferable by a participant other than by will or the laws of descent and distribution and, during the lifetime of a participant, will be exercisable only by such participant or by his or her guardian or legal representative. However, the Committee may provide in the terms of an award agreement that the participant will have the right to designate a beneficiary or beneficiaries who will be entitled to any rights, payments or other specified benefits under an award following the participant’s death. Moreover, to the extent permitted by the Committee, nonqualified stock options may be transferred to members of a participant’s immediate family, to certain other entities which are owned or controlled by members of a participant’s immediate family, or to any persons or entities approved of in advance by the Committee.

Non-United States Participants. The Committee has the authority to provide for such special terms for awards to participants who are foreign nationals, who are employed by us or any subsidiary outside of the United States of America or who provide services to us under an agreement with a foreign nation or agency, as the Committee may consider necessary or appropriate to accommodate differences in local law, tax policy or custom. Moreover, the Committee is authorized to approve such supplements to, or amendments, restatements or alternative versions of, the LTIP as it may consider necessary or appropriate for such purposes. However, no such special terms, supplements, amendments or restatements will include any provisions that are inconsistent with the terms of the LTIP unless it could have been amended to eliminate such inconsistency without further approval by our shareholders.

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Term and Amendment. The LTIP has a term of ten years, subject to earlier termination or amendment by our board of directors. The board of directors will have the authority to amend the LTIP at any time, except that shareholder approval will be required for amendments that would change the persons eligible to participate in the LTIP, increase the number of shares of common stock reserved for issuance under the LTIP, allow the grant of stock options or stock appreciation rights at an exercise price below fair market value, or allow the repricing of stock options or stock appreciation rights without shareholder approval.

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

As of the date hereof, all of the outstanding shares of our common stock are owned by Duke Energy. After the distribution, Duke Energy will own none of our common stock.

Beneficial Ownership of Duke Energy

The following table provides information with respect to the beneficial ownership of Duke Energy common stock by (i) each of our shareholders who we believe will be a beneficial owner of more than 5% of our outstanding common stock, (ii) each of the persons nominated to serve as our directors, (iii) each officer named in the Summary Compensation Table and (iv) all of our executive officers and directors nominees as a group. We based the share amounts on each person’s beneficial ownership of Duke Energy common stock as of November 15, 2006, unless we indicate some other basis for the share amounts. We based the percent of class amounts on 1,255,469,411 shares of Duke Energy common stock outstanding as of November 15, 2006.

Except as otherwise noted in the footnotes below, each person or entity identified below has sole voting and investment power with respect to such securities.

Name of Identity of Group	Total Shares Beneficially Owned1	Percent of Class
5% Shareholders
State Street Bank and Trust Company2	83,413,245	6.6
Directors and Executive Officers
Roger Agnelli	1,521	*
Paul M. Anderson	1,769,054	*
Gregory L. Ebel	32,232	*
William T. Esrey	84,352	*
Fred J. Fowler	1,247,423	*
Sabra L. Harrington	15,869	*
Alan N. Harris	67,810	*
Dennis R. Hendrix	252,966	*
Michael E.J. Phelps	50,675	*
Martha B. Wyrsch	167,865	*
All directors and executive officers as a group (12 persons)	3,645,091	*

^* Represents less than 1%.

¹ Includes the following number of shares with respect to which directors and executive officers have the right to acquire beneficial ownership within sixty days of the record date: Mr. Anderson—1,100,000; Mr. Ebel—29,318; Mr. Esrey—43,373; Mr. Fowler—972,850; Mr. Harrington—9,396; Mr. Harris 42,550; Mr. Hendrix—8,000; Mr. Phelps—48,831; Ms. Wyrsch—140,700; and all directors and executive officers as a group—1,960,518.

² Based on information filed in a report on Schedule 13G/A with the SEC on February 13, 2006, State Street Bank and Trust Company, acting in various fiduciary capacities, has: (a) sole voting power over 28,634,998 shares; (b) shared voting power over 54,778,247 shares, (c) sole dispositive power over 0 shares, and shared dispositive power over 83,413,245 shares. The address for State Street Bank and Trust Company is 225 Franklin Street, Boston, MA 02110.

To the extent our directors and officers own Duke Energy common stock at the time of the separation, they will participate in the distribution on the same terms as other holders of Duke Energy common stock. In addition, following the distribution, we expect Duke Energy stock-based awards held by these individuals will be equitably adjusted to become separate awards relating to both Duke Energy common stock and our common stock. Such awards relating to our common stock are reflected in the table below based upon our expected

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adjustment formula. For a description of the equitable adjustments expected to be made to Duke Energy stockbased awards, see the section entitled “Management—Executive Compensation—Employee Benefit Plans—Equitable Adjustments to Outstanding Duke Energy Equity-Based Awards.”

Beneficial Ownership of Spectra Energy

The following table provides information with respect to the expected beneficial ownership of our common stock by (i) each of our shareholders who we believe will be a beneficial owner of more than 5% of our outstanding common stock, (ii) each of the persons nominated to serve as our directors, (iii) each officer named in the Summary Compensation Table and (iv) all of our executive officers and directors nominees as a group. We based the share amounts on each person’s beneficial ownership of Duke Energy common stock as of November 15, 2006, unless we indicate some other basis for the share amounts, and assuming a distribution ratio of share of our common stock for each share of Duke Energy common stock.

Except as otherwise noted in the footnotes below, each person or entity identified below has sole voting and investment power with respect to such securities. Following the distribution, we will have outstanding an aggregate of approximately 630 million shares of common stock, based upon approximately 1.26 billion shares of Duke Energy common stock outstanding on November 30, 2006, excluding treasury shares and assuming no exercise of Duke Energy options, and applying the distribution ratio of 0.5 shares of our common stock for each share of Duke Energy common stock held as of the record date.

Name of Beneficial Owner	# of Shares to be Owned	% of Class	Of the Total # of Shares Beneficially Owned, Shares which May be Acquired within 60 days
5% Shareholders
State Street Bank and Trust Company1	41,706,622	6.6	—
Directors and Executive Officers
Roger Agnelli	760	*	—
Paul M. Anderson	884,527	*	550,000
Gregory L. Ebel	16,116	*	14,659
William T. Esrey	42,176	*	21,686
Fred J. Fowler	623,711	*	486,425
Sabra L. Harrington	7,934	*	4,698
Alan N. Harris	33,905	*	21,275
Dennis R. Hendrix	126,483	*	4,000
Michael E.J. Phelps	25,338	*	24,416
Martha B. Wyrsch	83,932	*	70,350
All directors and executive officers as a group (12 persons)	1,847,546	*	980,259

¹ Based on information filed in a report on Schedule 13G/A with the SEC on February 13, 2006, State Street Bank and Trust Company, acting in various fiduciary capacities, will have: (a) sole voting power over 14,317,499 shares; (b) shared voting power over 27,389,123 shares, (c) sole dispositive power over 0 shares, and shared dispositive power over 41,706,622 shares. The address for State Street Bank and Trust Company is 225 Franklin Street, Boston, MA 02110.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

The Distribution from Duke Energy

The distribution will be accomplished by Duke Energy distributing all of its shares of our common stock to holders of Duke Energy common stock entitled to such distribution, as described in the section entitled “The Separation.” Completion of the distribution will be subject to satisfaction or waiver by Duke Energy of the conditions to the separation and distribution described below.

Agreements with Duke Energy

We have entered into a Separation and Distribution Agreement and several other agreements with Duke Energy to effect the separation and provide a framework for our relationships with Duke Energy after the separation. These agreements will govern the relationship between us, subsequent to the completion of the separation plan, and provide for the allocation between us, of certain of Duke Energy’s assets, liabilities and obligations (including employee benefits and tax-related assets and liabilities) attributable to periods prior to, at and after our separation from Duke Energy. In addition to the Separation and Distribution Agreement (which contains many of the key provisions related to our separation from Duke Energy and the distribution of our shares of common stock to Duke Energy shareholders), these agreements include:

• the Transition Services Agreement,

• the Tax Matters Agreement, and

• the Employee Matters Agreement.

The agreements described below were filed as exhibits to our registration statement on Form 10, of which a form of this information statement is a part, and the summaries of each of these agreements set forth the terms of the agreements that we believe are material. These summaries are qualified in their entireties by reference to the full text of the applicable agreements, which are incorporated by reference into this information statement.

The terms of the agreements described below that will be in effect following our separation have not yet been finalized; changes, some of which may be material, may be made prior to our separation from Duke Energy.

Separation Costs

Duke Energy expects to incur pre-tax separation costs of approximately $200 million of which approximately $130 million will be allocated to Spectra Energy in the separation or incurred by Spectra Energy post-separation. Over the 12 months following the separation, the portion of these pre-tax costs incurred by us is expected to be approximately $60 to $70 million. Certain of the separation costs, primarily costs for the development of new information systems, are expected to be capitalized.

The expected costs include:

• fees for professional services including: legal, financial advisors and other business consultants;

• costs for branding the new company, replacing signage, investor and other stakeholder communications;

• costs for building and/or reconfiguring the required information systems to run the stand-alone companies and restacking of building facilities as required;

• costs for relocating, recruiting and severing employees; and

• tax costs incurred as part of the reorganization and separation.

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Separation and Distribution Agreement

The Separation and Distribution Agreement will set forth our agreements with Duke Energy regarding the principal transactions necessary to separate us from Duke Energy. It will also set forth other agreements that govern certain aspects of our relationships with Duke Energy after the completion of the separation plan. We intend to enter into the Separation and Distribution Agreement immediately before the record date for the distribution of our shares of common stock to Duke Energy shareholders, and the Separation and Distribution Agreement will become effective upon such distribution. No fees are to be paid by either party to the other party under the Separation Agreement.

Transfer of Assets and Assumption of Liabilities

The Separation and Distribution Agreement will identify assets to be transferred, liabilities to be assumed and contracts to be assigned to each of us and Duke Energy as part of the separation of Duke Energy into two companies, and it will describe when and how these transfers, assumptions and assignments will occur, although, many of the transfers, assumptions and assignments may have already occurred prior to the parties’ entering into the Separation and Distribution Agreement. In particular, the Separation and Distribution Agreement will provide that, subject to the terms and conditions contained in the Separation and Distribution Agreement:

• All of the assets and liabilities (including whether accrued, contingent or otherwise) primarily related to our businesses (the business and operations of Duke Energy’s Natural Gas Transmission and Field Services segments) will be retained by or transferred to us or one of our subsidiaries.

• All of the assets and liabilities (including whether accrued, contingent or otherwise) primarily related to the businesses and operations of Duke Energy’s Franchised Electric, Commercial Power, and International segments, as well as Crescent, Duke Energy’s real estate business will be retained by Duke Energy.

• Liabilities (including whether accrued, contingent or otherwise) related to, arising out of or resulting from businesses of Duke Energy that were previously terminated or divested will be allocated among the parties to the extent formerly owned or managed by or associated with such parties or their respective businesses, among other things, liabilities associated with most trading and marketing and merchant trading businesses will be allocated to Duke Energy.

• Each party or one of its subsidiaries will assume or retain any liabilities (including under applicable federal and state securities laws) relating to, arising out of or resulting from any registration statement or similar disclosure document which offers for sale any security after the separation.

• Each party or one of its subsidiaries will assume or retain any liabilities (including under applicable federal and state securities laws) relating to, arising out of or resulting from any registration statement or similar disclosure document which offers for sale any security prior to the separation to the extent such liabilities arise out of, or result from, matters related to businesses, operations, assets or liabilities allocated to the party in the separation.

• Duke Energy will assume or retain any liability relating to, arising out of or resulting from any registration statement or similar disclosure document related to the separation (including the Form 10 and this information statement), but only to the extent such liability derives from a material misstatement or omission contained in the section entitled “Letter to Duke Energy Shareholders,” “The Separation,” and “Certain Relationships and Related Party Transactions—Agreements with Duke Energy” and the section entitled “Summary” only to the extent it is summarizing the preceding sections; we will assume or retain any other liability relating to, arising out of or resulting from any registration statement or similar disclosure document related to the separation.

• Each party or one of its subsidiaries will assume or retain any liabilities relating to, arising out of or resulting from any of its or its subsidiaries’ or controlled affiliates’ indebtedness (including debt

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securities and asset-backed debt), regardless of the issuer of such indebtedness, exclusively relating to its business or secured exclusively by its assets.

• Each party or one of its subsidiaries will assume or retain any liabilities relating to, arising out of or resulting from any guarantees exclusively relating to its business or secured exclusively by its assets.

• We will assume 33 ¹/3% and Duke Energy will assume 66 ²/3% of certain contingent and other corporate liabilities of Duke Energy or its subsidiaries, which we refer to in this information statement as Unallocated Liabilities, which are not primarily related to either our business or Duke Energy’s business, including liabilities of Duke Energy and its subsidiaries related to, arising out of or resulting from any actions with respect to the separation plan or the distributions (other than actions arising out of disclosure documents distributed or filed relating to the securities or indebtedness of one of the four businesses) made or brought by any third party.

In addition, we and Duke Energy have agreed to share specified liabilities, including a purported class action contesting the cash balance in certain of Duke Energy’s pension plans and, on the basis of each Party’s proportionate liability, as may be determined. For further description of these litigation matters see “Business—Employees, Properties and Facilities, Government Regulation and Legal Proceedings—Legal Proceedings.”

• We will be entitled to receive 33 ¹/3% and Duke Energy to receive 66 ²/3% of the proceeds from certain contingent corporate assets of Duke Energy, which we refer to in this information statement as Unallocated Assets, which are not primarily related to our business or Duke Energy’s business.

• Except as otherwise provided in the Separation and Distribution Agreement or any ancillary agreement, other than the costs and expenses relating to legal counsel, financial advisors and accounting advisory work incurred prior to the separation, we will be responsible for any costs or expenses we incur in connection with the separation.

• Except as otherwise provided in the Separation and Distribution Agreement or any ancillary agreement, Duke Energy will be responsible for any costs or expenses it incurs in connection with the separation and the costs and expenses relating to legal counsel, financial advisors and accounting advisory work related to the separation.

Except as may expressly be set forth in the Separation and Distribution Agreement or any ancillary agreement, all assets will be transferred on an “as is,” “where is” basis and the respective transferees will bear the economic and legal risks that (i) any conveyance will prove to be insufficient to vest in the transferee good title, free and clear of any security interest and (ii) any necessary consents or governmental approvals are not obtained or that any requirements of laws or judgments are not complied with.

Information in this information statement with respect to the assets and liabilities of the parties following the separation is presented based on the allocation of such assets and liabilities pursuant to the Separation and Distribution Agreement, unless the context otherwise requires. Certain of the liabilities and obligations to be assumed by one party or for which one party will have an indemnification obligation under the Separation and Distribution Agreement and the other agreements relating to the separation are, and following the separation may continue to be, the legal or contractual liabilities or obligations of another party. Each such party that continues to be subject to such legal or contractual liability or obligation will rely on the applicable party that assumed the liability or obligation or the applicable party that undertook an indemnification obligation with respect to the liability or obligation, as applicable, under the Separation and Distribution Agreement, to satisfy the performance and payment obligations or indemnification obligations with respect to such legal or contractual liability or obligation.

Future Claims

The Separation and Distribution Agreement will provide for the formation of a contingent claim committee, which will have the responsibility for determining whether any newly discovered asset or liability is an asset or

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liability of Duke Energy or us, or is an Unallocated Asset or Unallocated Liability. The contingent claim committee will be comprised of one representative each from Duke Energy and Spectra Energy. Resolution of a matter submitted to the contingent claim committee will require the unanimous approval of the representatives.

Intercompany Accounts

The Separation and Distribution Agreement will provide that, subject to any provisions in the Separation and Distribution Agreement or any ancillary agreement to the contrary and except for specified intercompany accounts, prior to the separation from Duke Energy, intercompany accounts will be scheduled and either (i) repaid at closing, (ii) continue in effect post closing, or (iii) deemed satisfied prior to the Effective Time, with such satisfaction being treated as a distribution and a contribution to capital for United States federal income tax purposes, as appropriate.

Cash Balances

The Separation and Distribution Agreement will provide that all Spectra Energy bank and brokerage accounts linked to Duke Energy accounts, and all Duke Energy bank and brokerage accounts linked to Spectra Energy accounts, will be “de-linked” prior to the distribution date. Spectra Energy will establish, prior to the distribution date, an independent cash management system and accounts to support its activities. There will be a target Spectra Energy cash amount on the distribution date of $200 million (subject to adjustment to reflect developments prior to the distribution). Duke Energy and Spectra Energy will use their commercially reasonable efforts to cause Spectra Energy to have the targeted cash amount. However, neither Spectra Energy nor Duke Energy will have any recourse if, after the Distribution Date, Spectra Energy’s targeted cash amount is in excess of or less than the target amount.

Trademarks

Except as otherwise specifically provided in any ancillary agreement and subject to certain limitations, the Separation and Distribution Agreement will provide that the “Duke” name will be retained by Duke Energy. From and after the separation, each of Spectra Energy and Duke Energy will promptly (and in any event no later than three months following the separation) cease using the trademarks and other intellectual property allocated to the other party, with the exception that Duke Energy will grant to Spectra Energy a perpetual, non-exclusive, royalty free and non-transferable license to use certain of Duke Energy’s trademarks in connection with its internal operations.

Releases

Except as otherwise provided in the Separation and Distribution Agreement or any ancillary agreement, each party will release and forever discharge the other party and its respective subsidiaries and affiliates from all liabilities existing or arising from any acts or events occurring or failing to occur or alleged to have occurred or to have failed to occur or any conditions existing or alleged to have existed on or before the separation from Duke Energy. The releases will not extend to obligations or liabilities under any agreements between the parties that remain in effect following the separation pursuant to the Separation and Distribution Agreement or any ancillary agreement.

Indemnification

In addition, the Separation and Distribution Agreement will provide for cross-indemnities principally designed to place financial responsibility for the obligations and liabilities of our business with us and financial responsibility for the obligations and liabilities of Duke Energy’s business with Duke Energy. Specifically, each party will indemnify, defend and hold harmless the other party, its affiliates and subsidiaries and its officers, directors, employees and agents for any losses arising out of or otherwise in connection with:

• the liabilities each such party assumed or retained pursuant to the Separation and Distribution Agreement;

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• such party’s specified percentage of Unallocated Liabilities; and

• any breach by such party of the Separation and Distribution Agreement.

Legal Matters

Each party to the Separation and Distribution Agreement will assume the liability for, and control of, all pending and threatened legal matters related to its own business or assumed or retained liabilities and will indemnify the other parties for any liability arising out of or resulting from such assumed legal matters.

Each party to a claim will agree to cooperate in defending any claims against both parties for events that took place prior to, on or after the date of the separation of such party from Duke Energy.

Unless otherwise specified in the Separation and Distribution Agreement or agreed to by the parties, Duke Energy will act as managing party and manage and assume control of all legal matters related to any Unallocated Asset or Unallocated Liability. The parties shall each be responsible for their respective share of all out-of-pocket costs and expenses related thereto.

Insurance

The Separation and Distribution Agreement will provide for the allocation among the parties of benefits under existing insurance policies for occurrences prior to each separation and sets forth procedures for the administration of insured claims. In addition, the agreement will allocate among the parties the right to proceeds and the obligation to incur deductibles under certain insurance policies. In addition, the Separation and Distribution Agreement provides that Duke Energy will obtain, subject to the terms of the agreement, certain directors and officers insurance policies to apply against certain pre-separation claims, if any. Finally, the Separation and Distribution Agreement provides that prior to the Distribution Date, Spectra Energy will establish a captive insurer which will initially be capitalized with assets sufficient to meet such captive insurer’s minimum regulatory capital requirements. Bison Insurance Company Limited, Duke Energy’s captive insurer, as the new Spectra Energy captive insurer will enter into 100% Quota-Share Reinsurance Agreement whereby Spectra Energy’s captive insurer will reinsure, on an indemnity basis, all risks retained by Bison relating to policies covering the businesses of Spectra Energy, net of an collectible third party recoverables. In exchange, Bison will transfer assets to Spectra Energy’s captive insurer in an amount equal to the total amount of loss and expense reserves estimated as of the Distribution Date. Spectra Energy’s captive insurer will hold such assets as collateral in a trust which shall name Bison as its sole beneficiary.

Further Assurances

To the extent that any transfers contemplated by the Separation and Distribution Agreement have not been consummated on or prior to the date of the applicable separation, the parties will agree to cooperate to effect such transfers as promptly as practicable following the date of the applicable separation. In addition, each of the parties will agree to cooperate with each other and use commercially reasonable efforts to take or to cause to be taken all actions, and to do, or to cause to be done, all things reasonably necessary under applicable law or contractual obligations to consummate and make effective the transactions contemplated by the Separation and Distribution Agreement and the ancillary agreements.

Dispute Resolution

In the event of any dispute arising out of the Separation and Distribution Agreement, the general counsels of the parties will negotiate for a reasonable period of time to resolve any disputes among the parties. If the parties are unable to resolve disputes in this manner, the disputes will be resolved through binding arbitration.

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The Distribution

The Separation and Distribution Agreement will also govern the rights and obligations of the parties regarding the proposed distribution. Prior to the distribution, we will distribute to Duke Energy as a stock dividend the number of shares of such our common stock distributable in the distribution. Duke Energy will cause its agent to distribute to Duke Energy shareholders that hold shares of Duke Energy common stock as of the applicable record date all the issued and outstanding shares of our common stock.

Additionally, the Separation and Distribution Agreement will provide that the distributions are subject to several conditions that must be satisfied or waived by Duke Energy in its sole discretion. For further information regarding our separation from Duke Energy, see “The Separation—Conditions to the Distribution.”

Other Matters Governed by the Separation and Distribution Agreement

Other matters governed by the Separation and Distribution Agreement include access to financial and other information, confidentiality, access to and provision of records and treatment of outstanding guarantees and similar credit support.

Transition Services Agreement

We have entered into a transition services agreement with Duke Energy in connection with the separation. We refer to this agreement in this information statement as the “Transition Services Agreement.” Under the Transition Services Agreement we and Duke Energy will agree to provide certain services to each other for a specified period following the separation. The services to be provided may include services regarding business continuity and management, facilities management, data archiving, including services relating to human resources and employee benefits, payroll, financial systems management, treasury and cash management, accounts payable services, telecommunications services and information technology services.

The recipient of any services will generally pay an agreed upon service charge and reimburse the provider any out-of-pocket expenses, including the cost of any third-party consents required. The charges for these services will be billed at cost to the company receiving the services with an increase by a specified percentage for services provided for 180 days after the separation. The Transitional Services Agreement will generally require the services to be provided until December 31, 2007.

Tax Matters Agreement

We have entered into a Tax Matters Agreement with Duke Energy that generally will govern Duke Energy’s and our respective rights, responsibilities and obligations after the distribution with respect to taxes, including ordinary course of business taxes and taxes, if any, incurred as a result of any failure of the distribution to qualify as a tax-free distribution for U.S. federal income tax purposes within the meaning of Sections 355 and 368(a)(1)(D) of the Code (including as a result of Section 355(e) of the Code). Under the Tax Matters Agreement, we expect that, with certain exceptions, we generally will be responsible for the payment of all income and non-income taxes attributable to our operations, and the operations of our direct and indirect subsidiaries, whether or not such tax liability is reflected on a consolidated or combined tax return filed by Duke Energy. No fees will be paid by either party to the other party under the Tax Matters Agreement.

Notwithstanding the foregoing, we expect that, under the Tax Matters Agreement, we also generally will be responsible for any taxes imposed on Duke Energy that arise from the failure of the distribution to qualify as a tax-free distribution for U.S. federal income tax purposes within the meaning of Sections 355 and 368(a)(1)(D) of the Code, to the extent that such failure to qualify is attributable to actions, events or transactions relating to our stock, assets or business, or a breach of the relevant representations or covenants made by us in the Tax

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Matters Agreement. In addition, we generally will be responsible for 33 ¹/3% of any taxes that arise from the failure of the distribution to qualify as a tax-free distribution for U.S. federal income tax purposes within the meaning of Sections 355 and 368(a)(1)(D) of the Code, if such failure is for any reason for which neither we nor Duke Energy is responsible. The Tax Matters Agreement also is expected to impose restrictions on our and Duke Energy’s ability to engage in certain actions following our separation from Duke Energy and to set forth the respective obligations among us and Duke Energy with respect to filing of tax returns, the administration of tax contests, assistance and cooperation and other matters.

Employee Matters Agreement

We have entered into an Employee Matters Agreement with Duke Energy prior to the distribution that will govern our compensation and employee benefit obligations with respect to our current and former employees. The employee matters agreement will allocate liabilities and responsibilities relating to employee compensation and benefits plans and programs and other related matters in connection with the distribution including, without limitation, the treatment of outstanding Duke Energy equity awards, certain outstanding annual and long-term incentive awards, existing deferred compensation obligations and certain retirement and welfare benefit obligations. In connection with the distribution, we initially expect to adopt, for the benefit of our employees, a variety of compensation and employee benefits plans that are generally comparable in the aggregate to those provided to employees immediately prior to the distribution. Once we establish our own compensation and benefits plans, we reserve the right to amend, modify or terminate each such plan in accordance with the terms of that plan. With certain possible exceptions, the employee matters agreement will provide that as of the close of the distribution, our employees will generally cease to be active participants in, and we will generally cease to be a participating employer in, the benefit plans and programs maintained by Duke Energy. As of such time, our employees will generally become eligible to participate in all of our applicable plans. In general, we will credit each of our employees with his or her service with Duke Energy prior to the distribution for all purposes under plans maintained by us, to the extent the corresponding Duke Energy plans give credit for such service and such crediting does not result in a duplication of benefits.

The Employee Matters Agreement will provide that as of the distribution date, except as specifically provided therein, we generally will assume, retain and be liable for all wages, salaries, welfare, incentive compensation and employee-related obligations and liabilities for all current and former employees of our business. Except as provided in the employee matters agreement, Duke Energy will generally retain responsibility for, and will pay and be liable for, all wages, salaries, welfare, incentive compensation and employment-related obligations and liabilities with respect to former employees not associated with our business and current employees who are not otherwise transferred to employment with us in connection with the distribution. The Employee Matters Agreement will also provide for the transfer of assets and liabilities relating to the pre-distribution participation of our employees and former employees of our business in various Duke Energy retirement, welfare, incentive compensation and employee benefit plans from such plans to the applicable plans we adopt for the benefit of our employees. Other than the assets being transferred pursuant to the Employee Matters Agreement, no fees will be paid by any party to the other party under the Employee Matters Agreement.

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DESCRIPTION OF SPECTRA ENERGY STOCK

The following summary of our capital stock is subject in all respects to the applicable provisions of the Delaware General Corporation Law, or DGCL, our amended and restated certificate of incorporation referred to herein as our “certificate of incorporation” and our amended and restated by-laws, referred to herein as our “by-laws”, that we expect to be in place immediately prior to our listing on the New York Stock Exchange.

General

The total number of authorized shares of capital stock of Spectra Energy will consist of one billion shares of common stock, par value $0.001 per share, and 22 million shares of preferred stock, par value $0.001 per share.

Common Stock

The holders of our common stock are entitled to one vote per share. Directors are elected by a plurality of the votes cast by shares entitled to vote. Other matters to be voted on by our shareholders must be approved by a majority of the votes cast on the matter by the holders of common stock present in person or represented by proxy, voting together as a single voting group at a meeting at which a quorum is present, subject to any voting rights granted to holders of any outstanding shares of preferred stock. Approval of an amendment to our Certificate of Incorporation, a merger, a share exchange, a sale of all our property or a dissolution must be approved by a majority of all votes entitled to be cast by the holders of common stock, voting together as a single voting group. Holders of our common stock will not have the right to cumulate votes in elections of directors.

In the event of our liquidation, dissolution or winding up, holders of our common stock will be entitled to their proportionate share of any assets in accordance with each holder’s holdings remaining after payment of liabilities and any amounts due to other claimants, including the holders of any outstanding shares of preferred stock. Holders of our common stock have no preemptive rights and no right to convert or exchange their common stock into any other securities. No redemption or sinking fund provisions will apply to our common stock. All outstanding shares of common stock are, and all shares of common stock to be outstanding upon completion of the separation will be, fully paid and non-assessable.

Holders of common stock will share equally on a per share basis in any dividend declared by our board of directors, subject to any preferential rights of holders of any outstanding shares of preferred stock.

Preferred Stock

Our certificate of incorporation authorizes our board of directors, without shareholder approval, to issue up to twenty-two million shares of preferred stock in one or more series and to fix the rights, preferences, privileges and restrictions granted to or imposed upon the preferred stock, including voting rights, dividend rights, conversion rights, terms of redemption, liquidation preference, sinking fund terms, subscription rights and the number of shares constituting any series or the designation of a series. Our board of directors can issue preferred stock with voting and conversion rights that could adversely affect the voting power of the holders of common stock, without shareholder approval. No shares of preferred stock are currently outstanding and we have no present plan to issue any shares of preferred stock.

Business Combinations

We are governed by Section 203 of the General Corporation Law of the State of Delaware. Section 203, subject to certain exceptions, prohibits a Delaware corporation from engaging in any business combination with any interested shareholder for a period of three years following the time that such shareholder became an interested shareholder, unless:

• prior to such time, the board of directors of the corporation approved either the business combination or the transaction which resulted in the shareholder becoming an interested shareholder; or

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• upon consummation of the transaction that resulted in the shareholder becoming an interested shareholder, the interested shareholder owned at least 85.0% of the voting stock of the corporation outstanding at the time the transaction commenced, excluding specified shares; or

• at or subsequent to such time, the business combination is approved by the board of directors and authorized at an annual or special meeting of shareholders, by the affirmative vote of at least 66 ²/3% of the outstanding voting stock that is not owned by the interested shareholder. The shareholders cannot authorize the business combination by written consent.

The application of Section 203 may limit the ability of shareholders to approve a transaction that they may deem to be in their best interests.

In general, Section 203 defines “business combination” to include:

• any merger or consolidation involving the corporation and the interested shareholder; or

• any sale, lease, exchange, mortgage, pledge, transfer or other disposition of 10.0% or more of the assets of the corporation to or with the interested shareholder; or

• subject to certain exceptions, any transaction which results in the issuance or transfer by the corporation of any of its stock to the interested shareholder; or

• any transaction involving the corporation which has the effect of increasing the proportionate share of the stock of any class or series of the corporation beneficially owned by the interested shareholder; or

• the receipt by the interested shareholder of the benefit of any loans, advances, guarantees, pledges or other financial benefits provided by or through the corporation.

In general, Section 203 defines an “interested shareholder” as any person that is:

• the owner of 15% or more of the outstanding voting stock of the corporation; or

• an affiliate or associate of the corporation who was the owner of 15% or more of the outstanding voting stock of the corporation at any time within three years immediately prior to the relevant date; or

• the affiliates and associates of the above.

Under specific circumstances, Section 203 makes it more difficult for an “interested shareholder” to effect various business combinations with a corporation for a three-year period, although the shareholders may, by adopting an amendment to the corporation’s certificate of incorporation or by-laws, elect not to be governed by this section, effective twelve months after adoption.

Our certificate of incorporation and by-laws do not exclude us from the restrictions imposed under Section 203. We anticipate that the provisions of Section 203 may encourage companies interested in acquiring us to negotiate in advance with our board of directors since the shareholder approval requirement would be avoided if a majority of the directors then in office approve either the business combination or the transaction that resulted in the shareholder becoming an interested shareholder.

Classified Board of Directors

Our certificate of incorporation provides for our board to be divided into three classes of directors, as nearly equal in number as possible, serving staggered terms. Approximately one-third of our board will be elected each year. Under Section 141 of the General Corporation Law of the State of Delaware, directors serving on a classified board can only be removed for cause. The provision for our classified board may be amended, altered or repealed only upon the affirmative vote of the holders of 80% of our common shares.

The provision for a classified board could prevent a party that acquires control of a majority of the outstanding voting stock from obtaining control of our board until the second annual shareholders meeting

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following the date the acquiror obtains the controlling stock interest. The classified board provision could have the effect of discouraging a potential acquiror from making a tender offer for our shares or otherwise attempting to obtain control of us and could increase the likelihood that our incumbent directors will retain their positions.

We believe that a classified board will help to assure the continuity and stability of our board and our business strategies and policies as determined by our board, because a majority of the directors at any given time will have prior experience on our board. The classified board provision should also help to ensure that our board, if confronted with an unsolicited proposal from a third party that has acquired a block of our voting stock, will have sufficient time to review the proposal and appropriate alternatives and to seek the best available result for all shareholders.

We expect that Class I directors will have an initial term expiring in 2007, Class II directors will have an initial term expiring in 2008 and Class III directors will have an initial term expiring in 2009. After the separation, we expect our board will consist of 10 directors.

After the initial term of each class, our directors will serve three-year terms. At each annual meeting of shareholders, a class of directors will be elected for a three-year term to succeed the directors of the same class whose terms are then expiring.

Our by-laws further provide that generally, vacancies resulting from newly created directorships in our board may only be filled by the vote of a majority of our board provided that a quorum is present and any director so chosen will hold office until the next election of the class for which such director was chosen. Other vacancies may be filled by a majority even if no quorum is present or by the sole remaining member.

Shareholder Action; Special Meetings

Our certificate of incorporation provides that shareholder action only can be taken at an annual or special meeting of shareholders except that shareholder action by written consent can be taken if the consent is signed by all the holders of our issued and outstanding capital stock entitled to vote thereon. Our by-laws provide that, except as otherwise required by law, special meetings of the shareholders can only be called by the chairman of our board or by a majority of our directors by resolution.

Quorum at Shareholder Meetings

The holders of not less than a majority of the shares entitled to vote at any meeting of the shareholders, present in person or by proxy, shall constitute a quorum at all shareholder meetings.

Shareholder Proposals

At an annual meeting of shareholders, only business that is properly brought before the meeting will be conducted or considered. To be properly brought before an annual meeting of shareholders, business must be specified in the notice of the meeting (or any supplement to that notice), brought before the meeting by or at the direction of the directors (or any duly authorized committee of the board of directors) or properly brought before the meeting by a shareholder.

To be timely, a shareholder’s notice of business to be brought before the meeting must be delivered to or mailed and received at our principal executive offices not less than 90 nor more than 120 calendar days prior to the date of the immediately preceding annual meeting. However, in the event that the date of the annual meeting is more than 30 days before or 60 days after the anniversary of the prior annual meeting, the shareholder’s notice must be received not later than the close of business on the tenth day following the day on which notice of the date of the annual meeting was mailed or public disclosure of the date of the annual meeting was made, whichever first occurs. For 2007 only, the anniversary of the preceding annual meeting is deemed to be May 1, 2007.

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A shareholder’s notice must set forth, among other things, as to each matter the shareholder proposes to bring before the meeting:

• a brief description of the business proposed to be brought before the meeting and the reason for conducting such business;

• the name and record address of such shareholder;

• the class or series and number of shares that are owned of record and beneficially by the shareholder proposing the business;

• if a such shareholder intends to solicit proxies in support of such proposal, a representation to such effect

Similarly, at a special meeting of shareholders, only such business as is properly brought before the meeting will be conducted or considered. To be properly brought before a special meeting, business must be specified in the notice of the meeting (or any supplement to that notice) given by or at the direction of the chairman of our board or otherwise properly brought before the meeting by or at the direction of the board.

Nomination of Candidates for Election to Our Board

Under our by-laws, only persons that are properly nominated will be eligible for election to be members of our board. To be properly nominated, a director candidate must be nominated at an annual meeting of the shareholders by or at the direction of our board or a committee of our board, or properly nominated by a shareholder. To properly nominate a director, a shareholder must:

• be a shareholder of record on the date of the giving of the notice for the meeting;

• be entitled to vote at the meeting; and

• have given timely written notice of the business to our secretary.

To be timely, a shareholder’s notice must be delivered to or mailed and received at our principal executive offices not less than 90 nor more than 120 calendar days prior to the date of the immediately preceding annual meeting. However, that in the event that the date of the annual meeting is more than 30 days before or 60 days after the anniversary of the prior annual meeting, the shareholders notice must be received not later than the close of business on the tenth day following the day on which notice of the date of the annual meeting was mailed or public disclosure of the date of the annual meeting was made, whichever first occurs. For 2007 only, the anniversary of the preceding annual meeting is deemed to be May 1, 2007.

In the event of a special meeting, to be timely a shareholder’s notice must be received not earlier than 90 days prior nor later than 60 days prior to such meeting, or ten business days following public announcement of the date of the special meeting.

To be in proper written form, such shareholder’s notice must include, among other things,

• the name and address of the stockholder who intends to make the nomination and of the person or persons to be nominated;

• a representation that the stockholder is a holder of record of stock of the Corporation entitled to vote at such meeting and intends to appear in person or by proxy at the meeting to nominate the person or persons specified in the notice;

• a description of all arrangements or understandings between the stockholder and each nominee and any other person or persons (naming such person or persons) pursuant to which the nomination or nominations are to be made by the stockholder;

• such other information regarding each nominee proposed by such stockholder as would have been required to be included in a proxy statement filed pursuant to the proxy rules of the Securities and Exchange Commission had each nominee been nominated, or intended to be nominated, by the Board;

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• the consent of each nominee to serve as a Director if so elected; and

• if the stockholder intends to solicit proxies in support of such stockholder’s nominee(s), a representation to that effect.

Amendment of By-laws

Except as otherwise provided by law, our certificate of incorporation or our by-laws, our by-laws may be amended, altered or repealed at a meeting of the shareholders provided that notice of such amendment, alteration or appeal is contained in the notice of such meeting or a meeting of our board of directors.

All such amendments must be approved by either the holders of a majority of the common stock or by a majority of the entire board of directors then in office.

Amendment of the Certificate of Incorporation

Any proposal to amend, alter, change or repeal any provision of our certificate of incorporation, except as may be provided in the terms of any preferred stock, requires approval by the affirmative vote of both a majority of the members of our board then in office and a majority vote of the voting power of all of the shares of our capital stock entitled to vote generally in the election of directors, voting together as a single class. However, any proposal to amend, alter, change or repeal the provisions of our certificate of incorporation relating to:

• the classification of our board;

• appointment of directors to fill vacancies; or

• amendment of the certificate of incorporation;

requires approval by the affirmative vote of 80% of the voting power of all of the shares of our capital stock entitled to vote generally in the election of directors, voting together as a single class. Common stockholders generally are not entitled to vote on any amendment to the certificate of incorporation that relates to the terms of one or more outstanding classes of preferred stock.

Provisions that Have or May Have the Effect of Delaying or Prohibiting a Change in Control

Under our certificate of incorporation, our board of directors has the full authority permitted by Delaware law to determine the voting rights, if any, and designations, preferences, limitations and special rights of any class or any series of any class of the preferred stock. The certificate of incorporation also provides that a director only may be removed from office for cause and only by an affirmative vote of the holders of at least a majority of the combined voting power of the then outstanding shares of all classes entitled to vote. However, subject to applicable law, any director elected by the holders of any series of preferred stock may be removed without cause only by the holders of a majority of the shares of such series of preferred stock.

Our certificate of incorporation requires an affirmative vote of the holders of at least 80% of the combined voting power of the then outstanding shares of stock of all classes of entitled to vote generally in the election of directors, voting together as a single class, to amend, alter or repeal provisions in the certificate of incorporation which relate to the number of directors and vacancies and newly created directorships.

Our certificate of incorporation provides that any action required to be taken at any annual or special meeting of shareholders may be taken without a meeting and without prior notice only if consent in writing setting forth the action to be taken is signed by all the holders of our issued and outstanding capital stock entitled to vote in respect of such action.

Our by-laws provide that, except as expressly required by the certificate of incorporation or by applicable law, and subject to the rights of the holders of any series of preferred stock, special meetings of the shareholders

204

or of any series entitled to vote may be called for any purpose or purposes only by the Chairman of the board of directors or by the board of directors. Shareholders are not entitled to call special meetings.

Our certificate of incorporation and by-laws provide for a classified board, which could prevent a party that acquires control of a majority of the outstanding voting stock from obtaining control of our board until the second annual shareholders meeting following the date the acquiror obtains the controlling stock interest. The classified board provision could have the effect of discouraging a potential acquiror from making a tender offer for our shares or otherwise attempting to obtain control of us and could increase the likelihood that our incumbent directors will retain their positions.

The provisions of our certificate of incorporation and by-laws conferring on our board of directors the full authority to issue preferred stock, the restrictions on removing directors elected by holders of preferred stock or for cause, the supermajority voting requirements relating to the amendment, alteration or repeal of the provisions governing the classified board, number of directors and filling of vacancies and newly created directorships, the requirement that shareholders act at a meeting unless all shareholders agree in writing, and the inability of shareholders to call a special meeting, in certain instances could have the effect of delaying, deferring or preventing a change in control or the removal of existing management.

Transfer Agent and Registrar

The transfer agent and registrar for our common stock is The Bank of New York.

NYSE Listing

We have filed an application to list our shares of common stock on The New York Stock Exchange, Inc. We expect that our shares will trade under the ticker symbol “SE”.

Limitation on Liability of Directors and Indemnification of Directors and Officers

Section 145 of the DGCL provides that a corporation may indemnify directors and officers as well as other employees and individuals against expenses (including attorneys’ fees), judgments, fines and amounts paid in settlement in connection with any threatened, pending or completed action, suit or proceeding, whether civil, criminal, administrative or investigative, in which such person is made a party by reason of the fact that the person is or was a director, officer, employee or agent of the corporation (other than an action by or in the right of the corporation—a “derivative action”), if such person acted in good faith and in a manner such person reasonably believed to be in or not opposed to the best interests of the corporation and, with respect to any criminal action or proceeding, had no reasonable cause to believe such person’s conduct was unlawful. A similar standard is applicable in the case of derivative actions, except that indemnification only extends to expenses (including attorneys’ fees) incurred in connection with the defense or settlement of such action, and the statute requires court approval before there can be any indemnification where the person seeking indemnification has been found liable to the corporation. The statute provides that it is not exclusive of other indemnification that may be granted by a corporation’s by-laws, disinterested director vote, shareholder vote, agreement or otherwise.

Our certificate of incorporation provides that no director shall be liable to us or our shareholders for monetary damages for breach of fiduciary duty as a director, except as required by the DGCL, as now in effect or as amended. Currently, Section 102(b)(7) of the DGCL requires that liability be imposed for the following:

• any breach of the director’s duty of loyalty to our company or our shareholders;

• any act or omission not in good faith or which involved intentional misconduct or a knowing violation of law;

• unlawful payments of dividends or unlawful stock repurchases or redemptions as provided in Section 174 of the DGCL; and

205

• any transaction from which the director derived an improper personal benefit.

Our certificate of incorporation and by-laws provide that, to the fullest extent authorized or permitted by the DGCL, as now in effect or as amended, we will indemnify any person who was or is a party or is threatened to be made a party to any threatened, pending or completed action, suit or proceeding by reason of the fact that such person, or a person of whom he or she is the legal representative, is or was our director or officer, or while our director or officer is or was serving, at our request, as a director, officer, employee or agent of another corporation or of a partnership, joint venture, trust or other enterprise, including service with respect to employee benefit plans maintained or sponsored by us. We will indemnify such persons against expenses (including attorneys’ fees), judgments, fines and amounts paid in settlement actually and reasonably incurred in connection with such action if such person acted in good faith and in a manner reasonably believed to be in, or not opposed to, our best interests and, with respect to any criminal proceeding, had no reason to believe such person’s conduct was unlawful. Any amendment of this provision will not reduce our indemnification obligations relating to actions taken before an amendment.

We intend to obtain policies that insure our directors and officers and those of our subsidiaries against certain liabilities they may incur in their capacity as directors and officers. Under these policies, the insurer, on our behalf, may also pay amounts for which we have granted indemnification to the directors or officers.

206

DESCRIPTION OF MATERIAL INDEBTEDNESS

Description of Material Indebtedness

After the internal reorganizations described above under the heading “The Separation – Internal Reorganization” and our separation from Duke Energy, Duke Capital and other of our subsidiaries will continue to have material indebtedness outstanding under a variety of instruments. Set forth below is a description of the material indebtedness of Duke Capital and our subsidiaries that will be outstanding following the separation. Unless noted, the following debt securities are unsecured.

DUKE CAPITAL LLC UNCONSOLIDATED	Year Due	Amount
Notes:
4.331%	2006	$	350
7.50%	2009		500
4.37%	2009		148
6.25%	2013		500
5.50%	2014		149
5.668%	2014		408
6.75% Note B	2018		150
8.0%	2019		500
6.75%	2032		240
Subtotal, Notes			2,945
Fair Value Hedge Carrying Value Adjustment	2009-2025		14
Unamortized Debt Discount/Premium			(3	)
Subtotal, Duke Capital LLC Unconsolidated			2,956
TEXAS EASTERN TRANSMISSION
Notes:
5.25%	2007		300
7.30%	2010		300
Medium-term, Series A, 9.00% - 9.07%	2012		20
7.0%	2032		450
Subtotal, Texas Eastern Transmission			1,070
WESTCOAST ENERGY INC.
6.45% Series V	2006		112
5.70% MTN Series 5	2008		135
12.55% Series L	2010		90
7.20% MTN Series 7	2010		135
8.30% Series P	2013		90
8.50% Series U	2015		112
8.50% Series O	2018		135
9.90% Series S	2020		90
8.85% Series T	2025		135
8.80% MTN Series 2	2025		21
7.30% Series W	2026		112
6.75% MTN Series 4	2027		135
7.15% MTN Series 8	2031		180
Subtotal, Westcoast Energy Inc.			1,481

207

UNION GAS LIMITED
7.80% Series 1996	2006		67
5.19% MTN Series 4	2007		180
5.70% MTN Series 1	2008		90
13.50% Series 1983	2008		4
10.75% Series 1989	2009		27
7.20% MTN Series 2	2010		166
11.55% 1988 Series II	2010		48
6.65% MTN Series 3	2011		224
10.625% Series 1989	2011		112
7.90% Series 1994	2014		135
11.50% Series 1990	2015		135
4.64% MTN Series 5	2016		180
9.70% 1992 Series II	2017		112
8.75% Series 1993	2018		112
8.65% Series 1993	2018		67
8.65% Series 1995	2025		112
5.46% MTN Series 6	2036		148
Capitalized Leases			4
Subtotal, Union Gas Limited			1,923
MARITIMES & NORTHEAST PIPELINE, LLC (1)
Term Bank Loan (Floating Rate)	2009		100
7.7%	2019		240
Subtotal, Maritimes & Northeast Pipeline, LLC			340
MARITIMES & NORTHEAST PIPELINE, L.P. (1)
Term Bank Loan (Floating Rate)	2009		247
6.9%	2019		233
Other			23
Subtotal, Maritimes & Northeast Pipeline, L.P.			503
Duke Energy Facilities LP	2009		127
Algonquin Gas Transmission, 5.69% Notes (2)	2012		300
East Tennessee Natural Gas, 5.71% Notes (2)	2012		150
Other	Various		19
Total Material Indebtedness (as of September 30, 2006)		$	8,869

(1) A portion of the assets, ownership interest and business contracts in these projects are pledged as collateral.

(2) These notes have a change in control provision which requires the company to offer to redeem the notes at par upon separation. In September 2006, notices were sent to bondholders to communicate this redemption offer. No bondholders accepted the redemption offer.

Available Credit Facilities and Restrictive Debt Covenants

After the internal reorganizations described above under the heading “The Separation – Internal Reorganization” and our separation from Duke Energy, we or our subsidiaries will continue to be parties to various credit facilities pursuant to which Duke Capital and other of our subsidiaries may be obligated to repay sums previously borrowed and under which we or our subsidiaries may borrow in the future.

208

Our credit agreements contain various financial and other covenants. The significant financial covenants are described in the footnotes to the table below. Other covenants include timely reporting, payment of taxes, maintenance of existence, insurance and ownership of material subsidiaries, and limitations on liens, certain mergers and asset transfers, and transactions with non-subsidiary affiliates. Failure to meet those covenants beyond applicable grace periods could result in accelerated due dates and/or termination of the agreements. As of September 30, 2006, Duke Capital and its subsidiaries were in compliance with those covenants. In addition, our credit facilities allow for acceleration of payments or termination of the agreements due to nonpayment or to the acceleration of other significant indebtedness of the borrower or some of its subsidiaries. The issuance of commercial paper, letters of credit and other borrowings reduces the amount available under the available credit facilities.

Set forth below is a summary description of the credit facilities as of September 30, 2006 to which we or our subsidiaries will be parties following the separation. These facilities will be used principally as a back-stop for commercial paper programs at Spectra Energy subsidiaries. Approximately $350 million is expected to be utilized at the time of separation as a result of the maturity of senior unsecured notes in November 2006. Except as identified, no amounts are outstanding under any of these facilities.

Credit Facilities Summary as of September 30, 2006

	Expiration Date	Credit Facilities Capacity
		(in millions)
Duke Capital LLC (a)
$600 multi-year syndicated (b), (c), (d), (e)	June 2010	$	600
Westcoast Energy Inc.
$180 multi-year syndicated (f), (g)	June 2011		180
Union Gas Limited
$360 364-day syndicated (h)	June 2007		359
Total (i)		$	1,139

(a) In November 2006, Duke Capital LLC entered into a $350 million short-term bilateral facility with a maturity date of November 27, 2007. Borrowings under this facility were used to redeem the 4.331% $350 million Duke Capital LLC senior unsecured notes that were due in November 2006.

(b) Credit facility contains an option allowing borrowing up to the full amount of the facility on the day of initial expiration for up to one year.

(c) Credit facility contains a covenant requiring the debt-to-total capitalization ratio to not exceed 65%.

(d) Letters of credit outstanding under this facility total $122 million as of September 30, 2006 and are expected to be transferred to Duke Energy prior to the separation as they relate to the transferred businesses.

(e) In June 2006, credit facility expiration date was extended from June 2009 to June 2010.

(f) In June 2006, credit facility expiration date was extended from June 2010 to June 2011.

(g) Credit facility is denominated in Canadian dollars totaling 200 million Canadian dollars and contains a covenant that requires the debt-to-total capitalization ratio to not exceed 75%.

(h) In June 2006, credit facility was amended to increase the amount from 300 to 400 million Canadian dollars, in addition to extending the maturity from June 2006 to June 2007. It contains a covenant requiring the debt-to-total capitalization ratio to not exceed 75% and an option at maturity allowing for the conversion of all outstanding loans to a term loan repayable up to one year after maturity date but not exceeding 18 months from the date of draw.

(i) Various credit facilities that support ongoing and miscellaneous transactions are not included in this credit facilities summary. These facilities are denominated in Canadian dollars totalling CAN $125 million and had approximately CAN $62 million outstanding as of September 30, 2006.

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WHERE YOU CAN FIND MORE INFORMATION

We have filed a registration statement on Form 10 with the SEC with respect to the shares of our common stock that Duke Energy shareholders will receive in the distribution. For additional information relating to our company and the distribution, reference is made to the registration statement and the exhibits to the registration statement. Statements contained in this information statement as to the contents of any contract or document referred to are not necessarily complete and in each instance, if the contract or document is filed as an exhibit to the registration statement, we refer you to the copy of the contract or other document filed as an exhibit to the registration statement. Each such statement is qualified in all respects by reference to the applicable document.

We file annual, quarterly and special reports, proxy statements and other information with the SEC. We intend to furnish our shareholders with annual reports containing consolidated financial statements audited by an independent registered public accounting firm. The registration statement is, and any of these future filings with the SEC will be, available to the public over the Internet on the SEC’s website at http://www.sec.gov. You may read and copy any filed document at the SEC’s public reference room in Washington, D.C. at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Please call the SEC at 1 (800) SEC-0330 for further information about the public reference room.

We maintain an Internet site at http://www.spectraenergy.com. Our website and the information contained on that site, or connected to that site, are not incorporated into this information statement or the registration statement on Form 10.

210

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Item		Page
Spectra Energy Corp
	Report of Independent Registered Public Accounting Firm	F-2
	Balance Sheet as of July 31, 2006	F-3
	Notes to Financial Statements	F-4
Duke Capital LLC
	Report of Independent Registered Public Accounting Firm	F-7
	Consolidated Statements of Operations for the years ended December 31, 2005, 2004 and 2003	F-8
	Consolidated Balance Sheets as of December 31, 2005 and 2004	F-9
	Consolidated Statements of Cash Flows for the years ended December 31, 2005, 2004 and 2003	F-11
	Consolidated Statements of Member’s Equity and Comprehensive Income (Loss) for the years ended December 31, 2005, 2004 and 2003	F-13
	Notes to Consolidated Financial Statements	F-14
	Unaudited Consolidated Statements of Operations for the nine months ended September 30, 2006 and 2005.	F-101
	Unaudited Consolidated Balance Sheets as of September 30, 2006 and December 31, 2005	F-102
	Unaudited Consolidated Statements of Cash Flows for the nine months ended September 30, 2006 and 2005	F-104
	Unaudited Consolidated Statements of Member’s Equity and Comprehensive Income for the nine months ended September 30, 2006 and 2005	F-105
	Unaudited Notes to Consolidated Financial Statements	F-106
Duke Energy Field Services, LLC
	Report of Independent Auditors	F-146
	Consolidated Statement of Operations and Comprehensive Income for the year ended December 31, 2005	F-147
	Consolidated Balance Sheet as of December 31, 2005	F-148
	Consolidated Statement of Cash Flows for the year ended December 31, 2005	F-149
	Consolidated Statement of Members’ Equity for the year ended December 31, 2005	F-150
	Notes to Consolidated Financial Statements	F-151
TEPPCO Partners, L.P.
	Report of Independent Registered Public Accounting Firm	F-183
	Consolidated Balance Sheets as of December 31, 2005 and 2004 (as restated)	F-184
	Consolidated Statements of Income for the years ended December 31, 2005, 2004 (as restated) and 2003 (as restated)	F-185
	Consolidated Statements of Cash Flows for the years ended December 31, 2005, 2004 (as restated) and 2003 (as restated)	F-186
	Consolidated Statements of Partners’ Capital for the years ended December 31, 2005, 2004 (as restated) and 2003 (as restated)	F-187
	Consolidated Statements of Comprehensive Income for the years ended December 31, 2005, 2004 (as restated) and 2003 (as restated)	F-188
	Notes to Consolidated Financial Statements	F-189

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Stockholder of Spectra Energy Corp

We have audited the accompanying balance sheet of Spectra Energy Corp (formerly, Gas SpinCo, Inc.) (the “Company”), as of July 31, 2006. This financial statement is the responsibility of the Company’s management. Our responsibility is to express an opinion on this financial statement based on our audit.

We conducted our audit 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 balance sheet is 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 audit 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 includes examining, on a test basis, evidence supporting the amounts and disclosures in the balance sheet, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall balance sheet presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, such balance sheet presents fairly, in all material respects, the financial position of Spectra Energy Corp at July 31, 2006 in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Houston, Texas

November 13, 2006 (December 14, 2006 as to Note 2)

F-2

Spectra Energy Corp

Balance Sheet

	July 31, 2006
ASSETS
Total Assets	$	—
LIABILITIES AND STOCKHOLDER’S EQUITY
Stockholder’s Equity
Common stock, $0.001 par, 1,000 shares authorized, 1,000 shares outstanding at July 31, 2006	$	1
Less receivable from Duke Energy Corporation		(1	)
Total Liabilities and Stockholder’s Equity	$	—

See Notes to Financial Statements

F-3

Spectra Energy Corp

Notes to Financial Statements

(1) General

Gas SpinCo, Inc., was incorporated in the state of Delaware on July 28, 2006. Effective November 8, 2006, Gas SpinCo. Inc., changed its name to Spectra Energy Corp (the “Company”). On July 28, 2006, Duke Energy Corporation, the sole shareholder of the Company, subscribed for 1,000 shares of the Company’s common stock at par. The receivable from Duke Energy Corporation related to the subscription for 1,000 shares of the Company has been reflected as a deduction from stockholder’s equity on the accompanying balance sheet.

The Company was formed to hold the assets and liabilities associated with Duke Energy Corporation’s natural gas business, including the transmission and storage, distribution and gathering and processing businesses, which are proposed to be transferred by Duke Energy Corporation to the Company on January 1, 2007. Duke Energy Corporation proposes to distribute all of the shares of the Company to Duke Energy Corporation shareholders on January 1, 2007.

During the period from incorporation to the date of these financial statements, July 31, 2006, the Company had no operations and no cash flows.

(2) Subsequent Events

On December 8, 2006 Duke Energy Corporation (“Duke Energy”) announced that its Board of Directors formally approved the distribution (the “Distribution”) of all the shares of common stock of the Company to Duke Energy’s shareholders (on an as converted basis). Duke Energy will distribute one-half share of common stock of the Company, for each share of Duke Energy common stock held by Duke Energy shareholders of record as of the close of business on December 18, 2006, the record date for the Distribution.

In connection with the Distribution, the Company has entered into definitive agreements with Duke Energy that, among other things, set forth the terms and conditions of the Distribution and provide a framework for the Company’s relationship with Duke Energy after the Distribution. The definitive agreements entered into on December 13, 2006 are as follows:

Separation and Distribution Agreement

The Separation and Distribution Agreement (the “Separation Agreement”) addresses the principal transactions necessary to effect the Distribution of the Company from Duke Energy. The Separation Agreement also sets forth the other agreements that will govern certain aspects of the Company’s relationship with Duke Energy after completion of the Distribution.

Tax Matters Agreement

The Tax Matters Agreement (“Tax Matters Agreement”) governs the Company’s and Duke Energy’s respective rights, responsibilities, and obligations after the Distribution with respect to taxes, including ordinary course of business taxes and taxes, if any, incurred as a result of any failure to the Distribution to qualify as a tax-free distribution for U.S. federal income tax purposes within the meaning of Sections 355 and 368(a)(1)(D) of the Internal Revenue Code of 1986, as amended.

Transition Services Agreement

The Transition Services Agreement (“Transition Services Agreement”) identifies certain services that the Company and Duke Energy will provide to each other for a specified period following the Distribution. The

F-4

services to be provided may include services regarding business continuity and management, facilities services, data archiving, including services relating to human resources and employee benefits, payroll, financial systems management, treasury and cash management, accounts payable services, telecommunication services, and information technology services.

Employee Matters Agreement

The Employee Matters Agreement (“Employee Matters Agreement”) governs the Company’s compensation and employee benefits obligations with respect to Duke Energy’s current and former employees. It further allocates liabilities and responsibilities relating to employee compensation and benefits plans and programs and other related matters in connection with the Distribution, including without limitation, the treatment of outstanding Duke Energy equity awards, certain outstanding annual long-term incentive awards, existing deferred compensation agreements and certain retirement and welfare benefits.

In addition to the definitive agreements, on December 12, 2006 the Company amended and restated its certificate of incorporation and by-laws to, among other things, authorize one billion shares of common stock, par value $0.001 per share, and 22 million shares of preferred stock, par value $0.001 per share.

F-5

DUKE CAPITAL LLC

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	Page
Year-end Consolidated Financial Statements:
Report of Independent Registered Public Accounting Firm	F-7
Consolidated Statements of Operations for the years ended December 31, 2005, 2004 and 2003	F-8
Consolidated Balance Sheets as of December 31, 2005 and 2004	F-9
Consolidated Statements of Cash Flows for the years ended December 31, 2005, 2004 and 2003	F-11
Consolidated Statements of Member’s Equity and Comprehensive Income (Loss) for the years ended December 31, 2005, 2004 and 2003	F-13
Notes to Consolidated Financial Statements	F-14

F-6

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Member of Duke Capital LLC:

We have audited the accompanying consolidated balance sheets of Duke Capital LLC and subsidiaries (Duke Capital) as of December 31, 2005 and 2004, and the related consolidated statements of operations, member’s equity and comprehensive income (loss), and cash flows for each of the three years in the period ended December 31, 2005. 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 Duke Capital’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. Duke Capital 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 Duke Capital’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 Capital at December 31, 2005 and 2004, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

As discussed in Note 1, Duke Capital adopted the provisions of Statement of Financial Accounting Standards No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities,” as of July 1, 2003. As discussed in Note 1, Duke Capital adopted the provisions of Emerging Issues Task Force No. 02-3, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities,” as of January 1, 2003.

As discussed in Note 5, Duke Capital realigned certain subsidiaries which resulted in Duke Capital recognizing federal and state tax expense of approximately $1,030 million for the year ended December 31, 2004 to eliminate deferred tax assets at the time of the reorganization.

As discussed in Note 1, the accompanying consolidated financial statements have been recast and restated.

DELOITTE & TOUCHE LLP

Charlotte, North Carolina

March 27, 2006

(September 3, 2006 as to the effects of matters described in the “Recasting and Restatement of Previously Issued Financial Statements” section of Note 1, and the references to the subsequent events in Note 21)

F-7

DUKE CAPITAL LLC

CONSOLIDATED STATEMENTS OF OPERATIONS

(In millions)

	Years Ended December 31,
	2005			2004			2003
				As Restated (see Note 1)
Operating Revenues
Non-regulated electric, natural gas, natural gas liquids and other	$	7,670		$	12,187		$	10,135
Regulated natural gas and natural gas liquids		3,679			3,276			3,082
Total operating revenues		11,349			15,463			13,217
Operating Expenses
Natural gas and petroleum products purchased		6,290			10,156			8,476
Operation, maintenance and other		1,990			2,018			2,102
Fuel used in electric generation and purchased power		348			387			296
Depreciation and amortization		691			811			864
Property and other taxes		260			229			222
Impairment and other charges		140			64			1,216
Impairment of goodwill		—			—			254
Total operating expenses		9,719			13,665			13,430
Gains on Sales of Investments in Commercial and Multi-Family Real Estate		191			192			84
Gains (Losses) on Sales of Other Assets and Other, net		527			(408	)		(185	)
Operating Income (Loss)		2,348			1,582			(314	)
Other Income and Expenses
Equity in earnings of unconsolidated affiliates		479			154			123
Gains (Losses) on sales of equity investments		1,225			(3	)		279
Other income and expenses, net		149			292			216
Total other income and expenses		1,853			443			618
Interest Expense		771			980			1,020
Minority Interest Expense		538			200			41
Earnings (Loss) From Continuing Operations Before Income Taxes		2,892			845			(757	)
Income Tax Expense (Benefit) from Continuing Operations		1,212			1,341			(314	)
Income (Loss) From Continuing Operations		1,680			(496	)		(443	)
(Loss) Income From Discontinued Operations, net of tax		(1,002	)		382			(1,255	)
Income (Loss) Before Cumulative Effect of Change in Accounting Principle		678			(114	)		(1,698	)
Cumulative Effect of Change in Accounting Principle, net of tax and minority interest		(4	)		—			(160	)
Net Income (Loss)	$	674		$	(114	)	$	(1,858	)

See Notes to Consolidated Financial Statements

F-8

DUKE CAPITAL LLC

CONSOLIDATED BALANCE SHEETS

(In millions)

	December 31, 2005		December 31, 2004
ASSETS
Current Assets
Cash and cash equivalents	$	491	$	516
Short-term investments		521		1,134
Receivables (net of allowance for doubtful accounts of $121 at December 31, 2005 and $128 at December 31, 2004)		1,935		2,608
Inventory		444		537
Assets held for sale		1,528		40
Unrealized gains on mark-to-market and hedging transactions		90		962
Other		1,599		644
Total current assets		6,608		6,441
Investments and Other Assets
Investments in unconsolidated affiliates		1,931		1,292
Goodwill		3,775		4,148
Notes receivable		138		232
Unrealized gains on mark-to-market and hedging transactions		87		1,377
Assets held for sale		3,597		84
Investments in residential, commercial and multi-family real estate (net of accumulated depreciation of $17 at December 31, 2005 and $15 at December 31, 2004)		1,281		1,128
Other		737		630
Total investments and other assets		11,546		8,891
Property, Plant and Equipment
Cost		19,341		25,870
Less accumulated depreciation and amortization		3,655		5,171
Net property, plant and equipment		15,686		20,699
Regulatory Assets and Deferred Debits		1,216		1,152
Total Assets	$	35,056	$	37,183

See Notes to Consolidated Financial Statements

F-9

DUKE CAPITAL LLC

CONSOLIDATED BALANCE SHEETS

(In millions)

	December 31, 2005		December 31, 2004
LIABILITIES AND MEMBER’S EQUITY
Current Liabilities
Accounts payable	$	1,837	$	1,971
Notes payable and commercial paper		83		69
Taxes accrued		258		237
Interest accrued		155		213
Liabilities associated with assets held for sale		1,488		30
Current maturities of long-term debt		1,394		1,326
Unrealized losses on mark-to-market and hedging transactions		207		819
Other		1,892		1,450
Total current liabilities		7,314		6,115
Long-term Debt		8,790		11,288
Deferred Credits and Other Liabilities
Deferred income taxes		3,167		3,714
Unrealized losses on mark-to-market and hedging transactions		19		949
Liabilities associated with assets held for sale		2,085		14
Other		1,428		1,344
Total deferred credits and other liabilities		6,699		6,021
Commitments and Contingencies
Minority Interests		749		1,486
Member’s Equity
Member’s Equity		10,848		11,224
Accumulated other comprehensive income		656		1,049
Total member’s equity		11,504		12,273
Total Liabilities and Member’s Equity	$	35,056	$	37,183

See Notes to Consolidated Financial Statements

F-10

DUKE CAPITAL LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

	Years Ended December 31,
	2005			2004			2003
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	674		$	(114	)	$	(1,858	)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		774			1,014			1,114
Cumulative effect of change in accounting principle		4			—			133
Gains on sales of investments in commercial and multi-family real estate		(191	)		(201	)		(103	)
Gains on sales of equity investments and other assets		(1,639	)		(192	)		(107	)
Impairment charges		36			194			3,492
Deferred income taxes		(240	)		1,136			(695	)
Minority interest		538			195			39
Equity in earnings of unconsolidated affiliates		(479	)		(154	)		(123	)
Contribution to company-sponsored pension plans		(45	)		(29	)		(13	)
(Increase) decrease in
Net realized and unrealized mark-to-market and hedging transactions		559			208			(94	)
Receivables		(189	)		(251	)		1,135
Inventory		(74	)		17			16
Other current assets		(969	)		38			(11	)
Increase (decrease) in
Accounts payable		161			99			(1,025	)
Taxes accrued		56			314			60
Other current liabilities		558			86			(119	)
Capital expenditures for residential real estate		(355	)		(322	)		(196	)
Cost of residential real estate sold		294			268			167
Other, assets		1,488			(100	)		(81	)
Other, liabilities		136			31			48
Net cash provided by operating activities		1,097			2,237			1,779
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(997	)		(1,035	)		(1,374	)
Investment expenditures		(23	)		(25	)		(12	)
Acquisitions, net of cash acquired		(294	)		—			—
Purchases of available-for-sale securities		(31,674	)		(55,010	)		(25,221	)
Proceeds from sales and maturities of available-for-sale securities		31,462			54,537			24,984
Net proceeds from the sales of equity investments and other assets, and sales of and collections on notes receivable		2,372			1,651			1,883
Proceeds from the sales of commercial and multi-family real estate		372			606			314
Settlement of net investment hedges and other investing derivatives		(321	)		—			—
Distributions from equity investments		383			—			—
Other		(64	)		36			70
Net cash provided by investing activities		1,216			760			644

F-11

DUKE CAPITAL LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS—(Continued)

(In millions)

	Years Ended December 31,
	2005			2004			2003
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the issuance of long-term debt		543			153			216
Payments for the redemption of long-term debt					—
Long-term debt		(840	)		(2,815	)		(2,182	)
Preferred stock of a subsidiary		—			(176	)		(38	)
Guaranteed preferred beneficial interests in subordinated notes		—			—			(250	)
Notes payable and commercial paper		15			11			(1,048	)
Increase (decrease) in overdrafts		—			—			—
Distributions to minority interests		(861	)		(1,477	)		(2,508	)
Contributions from minority interests		779			1,277			2,432
Advances (to) from parent		(242	)		107			—
Capital contributions from parent		269			—			1,050
Distributions to parent		(2,100	)		—			—
Proceeds from Duke Energy Income Fund		110			18			—
Other		(14	)		—			(13	)
Net cash used in financing activities		(2,341	)		(2,902	)		(2,341	)
Changes in cash and cash equivalents included in assets held for sale		3			39			(55	)
Net (decrease) increase in cash and cash equivalents		(25	)		134			27
Cash and cash equivalents at beginning of period		516			382			355
Cash and cash equivalents at end of period	$	491		$	516		$	382
Supplemental Disclosures
Cash paid for interest, net of amount capitalized	$	833		$	1,044		$	1,051
Cash paid (refunded) for income taxes	$	486		$	(403	)	$	(179	)
Significant non-cash transactions:
Advances from parent converted to equity	$	761		$	—		$	—
Canadian midstream asset transfer	$	97		$	—		$	—
AFUDC—equity component	$	8		$	9		$	33
Debt retired in connection with disposition of businesses	$	—		$	840		$	—
Note receivable from sale of southeast plants	$	—		$	48		$	—
Remarketing of senior notes	$	—		$	1,625		$	—

See Notes to Consolidated Financial Statements

F-12

DUKE CAPITAL LLC

CONSOLIDATED STATEMENTS OF MEMBER’S EQUITY

AND COMPREHENSIVE INCOME (LOSS)

(In millions)

												Accumulated Other Comprehensive Income (Loss)
	Common Stock		Paid-in Capital			Retained Earnings			Member's Equity			Foreign Currency Adjustments			Net Gains (Losses) on Cash Flow Hedges			Minimum Pension Liability Adjustment			Other		Total
Balance December 31, 2002	$	—	$	7,545		$	4,665		$	—		$	(653	)	$	455		$	(14	)			$	11,998
Net loss		—		—			(1,858	)		—			—			—			—					(1,858	)
Other Comprehensive Loss																								—
Foreign currency translation adjustments(a)		—		—			—			—			986			—			—					986
Foreign currency translation adjustments reclassified into earnings as a result of the sale of European operations		—		—			—			—			(24	)		—			—					(24	)
Net unrealized gains on cash flow hedges(b)		—		—			—			—			—			113			—					113
Reclassification into earnings from cash flow hedges(c)		—		—			—			—			—			(252	)		—					(252	)
Minimum pension liability adjustment(d)		—		—			—			—			—			—			(11	)				(11	)
Total comprehensive loss																								(1,046	)
Capital contribution from parent		—		1,050			—			—			—			—			—					1,050
Other capital stock transactions, net		—		(32	)		(17	)		—			—			—			—					(49	)
Balance December 31, 2003	$	—	$	8,563		$	2,790		$	—		$	309		$	316		$	(25	)			$	11,953
Net loss		—		—			—			(114	)		—			—			—					(114	)
Conversion to Duke Capital LLC(e)		—		(8,563	)		(2,790	)		11,353			—			—			—					—
Other Comprehensive Income																								—
Foreign currency translation adjustments		—		—			—			—			279			—			—					279
Foreign currency translation adjustments reclassified into earnings as a result of the sale of Asia-Pacific Business		—		—			—			—			(54	)		—			—					(54	)
Net unrealized gains on cash flow hedges(b)		—		—			—			—			—			300			—					300
Reclassification into earnings from cash flow hedges(c)		—		—			—			—			—			(80	)		—					(80	)
Minimum pension liability adjustment(d)		—		—			—			—			—			—			4					4
Total comprehensive income																								335
Other, net		—		—			—			(15	)		—			—			—					(15	)
Balance December 31, 2004	$	—	$	—		$	—		$	11,224		$	534		$	536		$	(21	)			$	12,273
Net income		—		—			—			674			—			—			—					674
Other Comprehensive Income
Foreign currency translation adjustments		—		—			—			—			245			—			—					245
Net unrealized gains on cash flow hedges(b)		—		—			—			—			—			412			—					412
Reclassification into earnings from cash flow hedges(c)		—		—			—			—			—			(1,027	)		—					(1,027	)
Minimum pension liability adjustment(d)		—		—			—			—			—			—			(40	)				(40	)
Other(f)		—		—			—			—			—			—			—			17		17
Total comprehensive income																								281
Capital contribution from parent				—			—			269														269
Distributions to parent		—		—			—			(2,100	)		—			—			—			—		(2,100	)
Advances from parent converted to equity		—		—			—			761			—			—			—			—		761
Other, net		—		—			—			20			—			—			—					20
Balance December 31, 2005	$	—	$	—		$	—		$	10,848		$	779		$	(79	)	$	(61	)	$	17	$	11,504

(a) Foreign currency translation adjustments, net of $114 tax benefit in 2003.

(b) Net unrealized gains on cash flow hedges, net of $234 tax expense in 2005, $180 tax expense in 2004, and $56 tax expense in 2003.

(c) Reclassification into earnings from cash flow hedges, net of $584 tax benefit in 2005, $48 tax benefit in 2004, and $133 tax benefit in 2003. Reclassification into earnings from cash flow hedges for the year ended December 31, 2005, is due primarily to the recognition of Duke Energy North America's (DENA's) unrealized net gains related to hedges on forecasted transactions which will no longer occur as a result of the plan to sell or otherwise dispose of substantially all of DENA's assets and contracts outside of the Midwestern United States and certain contractual positions related to the Midwestern assets (see Notes 7 and 12).

(d) Minimum pension liability adjustment, net of $27 tax benefit in 2005, $2 tax expense in 2004, and $6 tax benefit in 2003.

(e) See Note 1 to Consolidated Financial Statements.

(f) Net of $10 tax expense in 2005.

See Notes to Consolidated Financial Statements

F-13

Duke Capital LLC

Notes To Consolidated Financial Statements

For the Years Ended December 31, 2005, 2004 and 2003

1. Summary of Significant Accounting Policies

Nature of Operations and Basis of Consolidation. Duke Capital LLC (collectively with its subsidiaries, Duke Capital), a wholly-owned subsidiary of Duke Energy Corporation (Duke Energy) is a leading energy company located in the Americas with a real estate subsidiary. On March 1, 2004, Duke Capital changed its form of organization from a corporation to a Delaware limited liability company by effecting a conversion pursuant to Section 266 of the General Corporation Law of the State of Delaware and Section 18-214 of the Delaware Limited Liability Company Act. Pursuant to the conversion, all rights and liabilities of Duke Capital Corporation in its previous corporate form vested in Duke Capital as a limited liability company. Duke Capital owns corporations who file as part of the Duke Energy consolidated federal income tax return and file their own respective foreign and state corporate income tax returns. The income tax expense related to these corporations is included in the income tax expense of Duke Capital.

These Consolidated Financial Statements include, after eliminating intercompany transactions and balances, the accounts of Duke Capital and all majority-owned subsidiaries where Duke Capital has control, and those variable interest entities where Duke Capital is the primary beneficiary.

Effective July 1, 2005, Duke Capital has deconsolidated Duke Energy Field Services, LLC (DEFS) due to a reduction in ownership and its inability to exercise control over DEFS (see Note 2). DEFS has been subsequently accounted for as an equity method investment.

Recasting and Restatement of Previously Issued Financial Statements.

Recasting of Previously Issued Financial Statements. Duke Energy Holding Corporation (Duke Energy HC) was incorporated in Delaware on May 3, 2005 as Deer Holding Corporation, a wholly-owned subsidiary of Duke Energy Corporation (Old Duke Energy). On April 3, 2006, in accordance with the previously announced merger agreement, Old Duke Energy and Cinergy Corp. (Cinergy) merged into two wholly-owned subsidiaries of Duke Energy HC, resulting in Duke Energy HC becoming the parent of Old Duke Energy and Cinergy. In connection with the closing of the merger transactions, Duke Energy HC changed its name to Duke Energy Corporation (New Duke Energy or Duke Energy) and, on April 3, 2006, Old Duke Energy converted its form of organization from a North Carolina corporation to a North Carolina limited liability company and was renamed Duke Power Company LLC (Duke Power). On April 3, 2006, Duke Power transferred to its parent, Duke Energy, all of its membership interests in its wholly-owned subsidiary Duke Capital. The term Duke Energy, as used in this report, refers to Old Duke Energy and New Duke Energy, as the context requires.

On April 1, 2006, in connection with the above transactions, Old Duke Energy transferred the operations of Duke Energy Merchants, LLC and Duke Energy Merchant Finance, LLC (collectively DEM) to Duke Capital. As a result of these transfers, prior periods have been retrospectively adjusted to include the results of operations, financial position and cash flows related to DEM as these transactions represent a transfer of assets between entities under common control.

Also on April 1, 2006, Duke Capital transferred the operations of its wholly-owned captive insurance subsidiary, Bison Insurance Company Limited (Bison), to New Duke Energy. Due to continuing involvement between Bison and Duke Capital entities, the results of operations of Bison do not qualify for discontinued operations treatment. Accordingly, Bison’s operations continue to be included in Duke Capital’s results of operations, financial position and cash flows for all periods presented.

Additionally in April 2006, Duke Capital indirectly transferred to The Cincinnati Gas & Electric Company (CG&E), a subsidiary of Cinergy, its ownership interest in Duke Energy North America’s (DENA’s) Midwestern

F-14

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

assets, representing a mix of combined cycle and peaking plants, with a combined capacity of approximately 3,600 megawatts (MWs). The results of operations of DENA’s Midwestern assets have been reflected as discontinued operations in the accompanying Consolidated Statements of Operations (see Note 12).

In conjunction with Duke Energy’s merger with Cinergy, Duke Capital adopted new business segments (see Note 3). Also, Duke Capital has reclassified management fees charged to an unconsolidated affiliate of Duke Capital (see Note 10).

Restatement of Previously Issued Financial Statements. Duke Capital’s consolidated results of operations for the year ended December 31, 2004 have been restated as the result of a correction of an error related to the classification of income taxes between income from continuing operations and discontinued operations in the Consolidated Statements of Operations. Duke Capital has determined that approximately $584 million of income tax expense for the year ended December 31, 2004 that was included in discontinued operations should have been included in continuing operations. The amount relates to tax attributes that were associated with operations that were appropriately classified as discontinued operations, but the associated income tax expense should have been included in income from continuing operations since the income tax expense resulted from a change in tax status of certain subsidiaries of Duke Capital. As a result, this error had no impact on Duke Capital’s net loss, financial position or cash flows as of and for the year ended December 31, 2004;

Except as required to reflect the legal entity changes, the correction of an error, the segment changes and reclassification discussed above, and to update subsequent events as discussed in Note 21, the financial statements have not been otherwise modified or updated from those presented in Duke Capital’s Form 10-K for the year ended December 31, 2005. These changes impacted Note 1, Note 2, Note 3, Note 5, Note 7, Note 10, Note 11, Note 12, Note 20, Note 21 and Note 22. The effect of these changes from amounts previously reported in Duke Capital’s financial statements is summarized below.

Year Ended December 31, 2005	As Previously Reported			Transfer of DEM	DENA’s Midwestern Assets(a)		Eliminations		As Adjusted
(in millions)
Earnings (Loss) from Continuing Operations Before Income Taxes	$	2,838		6	51		(3	)	$	2,892
Income Tax Expense (Benefit) from Continuing Operations		1,225		2	(15	)	—			1,212
Income (Loss) from Continuing Operations		1,613		4	66		(3	)		1,680
Income (Loss) from Discontinued Operations, net of tax		(939	)	—	(66	)	3			(1,002	)
Income (Loss) Before Cumulative Effect of Change in Accounting Principle		674		4	—		—			678
Cumulative Effect of Change in Accounting Principle, net of tax and minority interest		(4	)	—	—		—			(4	)
Net Income (Loss)	$	670		4	—		—		$	674

F-15

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

Year Ended December 31, 2004	As Previously Reported			Impact of Income Tax Error		Transfer of DEM	DENA’s Midwestern Assets(a)		Eliminations		As Adjusted
(in millions)
Earnings (Loss) from Continuing Operations Before Income Taxes	$	801		—		25	98		(79	)	$	845
Income Tax Expense (Benefit) from Continuing Operations		760		584		12	(15	)	—			1,341
Income (Loss) from Continuing Operations		41		(584	)	13	113		(79	)		(496	)
Income (Loss) from Discontinued Operations, net of tax		(168	)	584		—	(113	)	79			382
Income (Loss) Before Cumulative Effect of Change in Accounting Principle		(127	)	—		13	—		—			(114	)
Cumulative Effect of Change in Accounting Principle, net of tax and minority interest		—		—		—	—		—			—
Net Income (Loss)	$	(127	)	—		13	—		—		$	(114	)

Year Ended December 31, 2003	As Previously Reported			Transfer of DEM		DENA’s Midwestern Assets(a)		Eliminations		As Adjusted
(in millions)
Earnings (Loss) from Continuing Operations Before Income Taxes	$	(748	)	(58	)	77		(28	)	$	(757	)
Income Tax Expense (Benefit) from Continuing Operations		(306	)	(25	)	17		—			(314	)
Income (Loss) from Continuing Operations		(442	)	(33	)	60		(28	)		(443	)
Income (Loss) from Discontinued Operations, net of tax		(1,223	)	—		(60	)	28			(1,255	)
Income (Loss) Before Cumulative Effect of Change in Accounting Principle		(1,665	)	(33	)	—		—			(1,698	)
Cumulative Effect of Change in Accounting Principle, net of tax and minority interest		(133	)	(27	)	—		—			(160	)
Net Income (Loss)	$	(1,798	)	(60	)	—		—		$	(1,858	)

(a) Amounts include intercompany transactions.

Other Reclassifications and Revisions. In 2005, Duke Capital recorded a prior period reclassification adjustment of approximately $300 million related to removal costs for property within the natural gas operations. The impact of this adjustment on the Consolidated Balance Sheet as of December 31, 2004 was a decrease in accumulated depreciation and a corresponding increase in regulatory liabilities, which are included in Other within Deferred Credits and Other Liabilities.

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

F-16

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

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 to Consolidated Financial Statements. Although these estimates are based on management’s best available knowledge at the time, actual results could differ.

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

Short-term Investments. Duke Capital actively invests a portion of its available cash balances in various financial instruments, such as tax-exempt debt securities that frequently have stated maturities of 20 years or more and tax-exempt money market preferred securities. These instruments provide for a high degree of liquidity through features such as daily and seven day notice put options and 7, 28, and 35 day auctions which allow for the redemption of the investments at their face amounts plus earned income. As Duke Capital 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 Capital has classified all short-term investments that are debt securities as available-for-sale under Statement of Financial Accounting Standards (SFAS) No. 115, “Accounting For Certain Investments in Debt and Equity Securities” (SFAS No. 115), and they are carried at fair market value. Investments in money-market preferred securities that do not have stated redemptions are accounted for at their cost, as the carrying values approximate market values due to their short-term maturities and no credit risk. Realized gains and losses and dividend and interest income related to these securities, including any amortization of discounts or premiums arising at acquisition, are included in earnings as incurred. Purchases and sales of available-for-sale securities are presented on a gross basis within Investing Cash Flows in the accompanying Consolidated Statements of Cash Flows.

Inventory. Inventory consists primarily of materials and supplies and natural gas held in storage for transmission, processing and sales commitments. This inventory is recorded at the lower of cost or market value, primarily using the average cost method. At December 31, 2004, inventory contained $46 million of natural gas liquid (NGL) products related to DEFS, which was deconsolidated effective July 1, 2005.

Components of Inventory

	December 31,
	2005		2004
	(in millions)
Materials and supplies	$	130	$	144
Natural gas		269		312
Petroleum products		45		81
Total inventory	$	444	$	537

Accounting for Risk Management and Hedging Activities and Financial Instruments. Duke Capital uses a number of different derivative and non-derivative instruments in connection with its commodity price, interest rate and foreign currency risk management activities and its trading activities, including forward contracts, futures, swaps, options and swaptions. All derivative instruments not designated and qualifying for the normal purchases and normal sales exception under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS No. 133), as amended, are recorded on the Consolidated Balance Sheets at their fair value as Unrealized Gains or Unrealized Losses on Mark-to-Market and Hedging Transactions. Cash inflows and outflows related to derivative instruments, except those that contain financing elements and those related to net

F-17

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

investment hedges and other investing activities, are a component of operating cash flows in the accompanying Consolidated Statements of Cash Flows. Cash inflows and outflows related to derivative instruments containing financing elements are a component of financing cash flows in the accompanying Consolidated Statements of Cash Flows while cash inflows and outflows related to net investment hedges and derivatives related to other investing activities are a component of investing cash flows in the accompanying Consolidated Statements of Cash Flows.

Effective January 1, 2003, in connection with the implementation of the remaining provisions of Emerging Issues Task Force (EITF) 02-03, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities” (EITF 02-03), Duke Capital designated all energy commodity derivatives as either trading or non-trading. Gains and losses for all derivative contracts that do not represent physical delivery contracts are reported on a net basis in the Consolidated Statements of Operations. For each of the Duke Capital’s physical delivery contracts that are derivatives, the accounting model and presentation of gains and losses, or revenue and expense in the Consolidated Statements of Operations is shown below.

Classification of Contract	Duke Capital Accounting Model	Presentation of Gains & Losses or Revenue & Expense
Trading derivatives	Mark-to-market(a)	Net basis in Non-regulated Electric, Natural Gas, NGL, and Other
Non-trading derivatives:
Cash flow hedge	Accrual(b)	Gross basis in the same income statement category as the related hedged item
Fair value hedge	Accrual(b)	Gross basis in the same income statement category as the related hedged item
Normal purchase or sale	Accrual(b)	Gross basis upon settlement in the corresponding income statement category based on commodity type
Undesignated	Mark-to-market(a)	Net basis in the related income statement category for interest rate, currency and commodity derivatives

(a) An accounting term used by Duke Capital to refer to derivative contracts for which an asset or liability is recognized at fair value and the change in the fair value of that asset or liability is recognized in the Consolidated Statements of Operations, with the exception of Union Gas Limited’s (Union Gas) regulated business, which is recognized as a regulatory asset or liability. This term is applied to trading and undesignated non-trading derivative contracts. As this term is not explicitly defined within GAAP, Duke Capital’s application of this term could differ from that of other companies.

(b) An accounting term used by Duke Capital to refer to contracts for which there is generally no recognition in the Consolidated Statements of Operations for any changes in fair value until the service is provided, the associated delivery period occurs or there is hedge ineffectiveness. As discussed further below, this term is applied to derivative contracts that are accounted for as cash flow hedges, fair value hedges, and normal purchases or sales, as well as to non-derivative contracts used for commodity risk management purposes. As this term is not explicitly defined within GAAP, Duke Capital’s application of this term could differ from that of other companies.

F-18

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

Where Duke Capital’s derivative instruments are subject to a master netting agreement and the criteria of the Financial Accounting Standards Board (FASB) Interpretation No. 39, “Offsetting of Amounts Related to Certain Contracts—An Interpretation of Accounting Principles Board (APB) Opinion No. 10 and FASB Statement No. 105” (FIN 39), are met, Duke Capital presents its derivative assets and liabilities, and accompanying receivables and payables, on a net basis in the accompanying Consolidated Balance Sheets.

Cash Flow and Fair Value Hedges. Qualifying energy commodity and other derivatives may be designated as either a hedge of a forecasted transaction or future cash flows (cash flow hedge) or a hedge of a recognized asset, liability or firm commitment (fair value hedge). For all hedge contracts, Duke Capital provides formal documentation of the hedge in accordance with SFAS No. 133. In addition, at inception and on a quarterly basis Duke Capital formally assesses whether the hedge contract is highly effective in offsetting changes in cash flows or fair values of hedged items. Duke Capital documents hedging activity by transaction type (futures/swaps) and risk management strategy (commodity price risk/interest rate risk).

Changes in the fair value of a derivative designated and qualified as a cash flow hedge, to the extent effective, are included in the Consolidated Statements of Member’s Equity and Comprehensive Income (Loss) as Accumulated Other Comprehensive Income (Loss) (AOCI) until earnings are affected by the hedged transaction. Duke Capital discontinues hedge accounting prospectively when it has determined that a derivative no longer qualifies as an effective hedge, or when it is no longer probable that the hedged forecasted transaction will occur. When hedge accounting is discontinued because the derivative no longer qualifies as an effective hedge, the derivative is subject to the Mark-to-Market Model of Accounting (MTM Model) prospectively. Gains and losses related to discontinued hedges that were previously accumulated in AOCI will remain in AOCI until the underlying contract is reflected in earnings; unless it is probable that the hedged forecasted transaction will not occur at which time associated deferred amounts in AOCI are immediately recognized in current earnings.

For derivatives designated as fair value hedges, Duke Capital recognizes the gain or loss on the derivative instrument, as well as the offsetting loss or gain on the hedged item in earnings, to the extent effective, in the current period. All derivatives designated and accounted for as hedges are classified in the same category as the item being hedged in the Consolidated Statements of Cash Flows. In addition, all components of each derivative gain or loss are included in the assessment of hedge effectiveness.

Normal Purchases and Normal Sales. From July 1, 2001 through June 30, 2003, Duke Capital applied the normal purchase and normal sale scope exception in Derivative Implementation Group (DIG) Issue C15, “Scope Exceptions: Normal Purchases and Normal Sales Exception for Option-Type Contracts and Forward Contracts in Electricity” to certain forward sale contracts to deliver electricity. In connection with the adoption of SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities,” on July 1, 2003, Duke Capital has elected to designate the majority of all forward contracts to sell power entered into after July 1, 2003 as cash flow hedges. Certain remaining contracts that were being accounted for under the normal purchases and normal sales exception under SFAS No. 133 as of June 30, 2003 continue to be accounted for under the normal purchases and normal sales exception as long as the requirements for applying the exception are met. 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 MTM Model unless immediately designated as a cash flow or fair value hedge.

As a result of the September 2005 decision to pursue the sale or other disposition of substantially all of Duke Energy North America’s (DENA’s) remaining physical and commercial assets outside the Midwestern United States, DENA discontinued hedge accounting for forward natural gas and power contracts accounted for as cash flow hedges and disqualified other forward power contracts previously designated under the normal purchases normal sales exception effective September 2005.

F-19

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

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.

Goodwill. Duke Capital evaluates goodwill for potential impairment under the guidance of SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS No. 142). Under this provision, goodwill is subject to an annual test for impairment. Duke Capital has designated August 31 as the date it performs the annual review for goodwill impairment for its reporting units. Under the provisions of SFAS No. 142, Duke Capital performs the annual review for goodwill impairment at the reporting unit level, which Duke Capital has determined to be an operating segment or one level below.

Impairment testing of goodwill consists of a two-step process. The first step involves a comparison of the implied fair value of a reporting unit with its carrying amount. If the carrying amount of the reporting unit exceeds its fair value, the second step of the process involves a comparison of 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 implied fair value of that goodwill, an impairment loss is recognized in an amount equal to the excess. Additional impairment tests are performed between the annual reviews if events or changes in circumstances make it more likely than not that the fair value of a reporting unit is below its carrying amount.

Duke Capital uses a discounted cash flow analysis to determine fair value. Key assumptions in the determination of fair value include the use of an appropriate discount rate, estimated future cash flows and estimated run rates of operation, maintenance, and general and administrative costs. In estimating cash flows, Duke Capital incorporates expected growth rates, regulatory stability and ability to renew contracts as well as other factors into its revenue and expense forecasts.

Other Long-term Investments. Other long-term investments, primarily the captive insurance investment portfolio, 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 Capital’s Consolidated Balance Sheets. Unrealized holding gains and losses, net of tax, on all available-for-sale securities are reflected in AOCI in Duke Capital’s Consolidated Balance Sheets until they are realized and reflected in net income. Cash flows from purchases and sales of long-term investments are presented on a gross basis within investing cash flows in the accompanying Consolidated Statements of Cash Flows.

Property, Plant and Equipment. Property, plant and equipment are stated at the lower of historical cost less accumulated depreciation or the fair value, if impaired. Duke Capital capitalizes all construction-related direct labor and material costs, as well as indirect construction costs. Indirect costs include general engineering, taxes and the cost of funds used during construction. The cost of renewals and betterments that extend the useful life of property, plant and equipment is also capitalized. The cost of repairs, replacements and major maintenance projects, which do not extend the useful life or increase the expected output of property, plant and equipment, is expensed as it is incurred. Depreciation is generally computed over the asset’s estimated useful life using the straight-line method. The composite weighted-average depreciation rates were 3.60% for 2005, 3.84% for 2004 and 3.62% for 2003. Also, see “Allowance for Funds Used During Construction (AFUDC),” discussed below.

When Duke Capital 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

F-20

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

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

Duke Capital recognizes asset retirement obligations (ARO’s) in accordance with SFAS No. 143, “Accounting For Asset Retirement Obligations” (SFAS No. 143), for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset and FIN 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47), for conditional ARO’s in which the timing or method of settlement are conditional on a future event that may or may not be within the control of Duke Capital. 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. The implementation of FIN 47 did not have a material impact on the balance sheet or income statement of Duke Capital.

Investments in Residential, Commercial, and Multi-Family Real Estate. Investments in residential, commercial and multi-family real estate are carried at cost, net of any related depreciation, except for any properties meeting the criteria in SFAS No. 144, “Accounting for the Impairment or Disposal of Long-lived Assets” (SFAS No. 144), to be presented as Assets Held for Sale in the Consolidated Balance Sheets. Proceeds from sales of residential properties are presented within Operating Revenues and the cost of properties sold are included in Operation, Maintenance and Other in the Consolidated Statements of Operations. Cash flows related to the acquisition, development and disposal of residential properties are included in Cash Flows from Operating Activities in the Consolidated Statements of Cash Flows. Gains and losses on sales of commercial and multi-family properties as well as “legacy” land sales are presented as such in the Consolidated Statements of Operations, and cash flows related to these activities are included in Cash Flows from Investing Activities in the Consolidated Statements of Cash Flows.

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

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

Duke Capital 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

F-21

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

as held for sale within the Consolidated Balance Sheets, Duke Capital does not retrospectively adjust prior period balance sheets to conform to current year presentation.

Duke Capital uses the criteria in SFAS No. 144 and EITF 03-13, “Applying the Conditions in Paragraph 42 of FAS 144 in Determining Whether to Report Discontinued Operations” (EITF 03-13), to determine whether components of Duke Capital that are being disposed of or are classified as held for sale are required to be reported as discontinued operations in the Consolidated Statements of Operations. To qualify as a discontinued operation under SFAS No. 144, the component being disposed of must have clearly distinguishable operations and cash flows. Additionally, pursuant to EITF 03-13, Duke Capital must not have significant continuing involvement in the operations after the disposal (i.e. Duke Capital must not have the ability to influence the operating or financial policies of the disposed component) and cash flows of the assets sold must have been eliminated from Duke Capital’s ongoing operations (i.e. Duke Capital 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 Loss From Discontinued Operations, net of tax, in the Consolidated Statements of Operations. If an asset held for sale does not meet the requirements for discontinued operations classification, any impairments and gains or losses on sales are recorded in continuing operations as Gains (Losses) on Sales of Other Assets, net, in the Consolidated Statements of Operations. Impairments for all other long-lived assets, other than goodwill, are recorded as Impairment and Other Charges in the Consolidated Statements of Operations.

Captive Insurance Reserves. Duke Capital has captive insurance subsidiaries which provide insurance coverage to Duke Capital entities as well as certain third parties, on a limited basis, for various business risks and losses, such as workers compensation, property, business interruption and general liability. Liabilities include provisions for estimated losses incurred, but not yet reported (IBNR), as well as provisions for known claims which have been estimated on a claims-incurred basis. IBNR reserve estimates involve the use of assumptions and are primarily based upon historical loss experience, industry data and other actuarial assumptions. Reserve estimates are adjusted in future periods as actual losses differ from historical experience. Intercompany balances and transactions are eliminated in consolidation.

Duke Capital’s captive insurance entities also have reinsurance coverage, which provides reimbursement to Duke Capital for certain losses above a per incident and/or aggregate retention. Duke Capital’s captive insurance entities also have an aggregate stop-loss insurance coverage, which provides reimbursement from third parties to Duke Capital for its paid losses above certain per line of coverage aggregate amounts during a policy year. Duke Capital recognizes a reinsurance receivable for recovery of incurred losses under its captive’s reinsurance and stop-loss insurance coverage once realization of the receivable is deemed probable by its captive insurance companies.

During 2004, Duke Capital eliminated intercompany reserves at its captive insurance subsidiaries of approximately $59 million which was a correction of an immaterial accounting error related to prior periods. In addition, a $12 million pre-tax correction of an accounting error related to prior years was recorded. This correction was due to the recognition of reserves at Bison Insurance Company Limited (Bison) for reinsurance policies which have certain retrospective rating provisions.

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.

F-22

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

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

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

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

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

Stock-Based Compensation. Certain employees of Duke Capital participate in Duke Energy’s stock compensation plans. Through December 31, 2005, Duke Energy accounted for its stock-based compensation arrangements under the intrinsic value recognition and measurement principles of APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and FIN 44, “Accounting for Certain Transactions Involving Stock Compensation (an Interpretation of APB Opinion No. 25).” Since the exercise price for all options granted under those plans was equal to the market value of the underlying common stock on the date of grant, no compensation cost is recognized in the accompanying Consolidated Statements of Operations. Restricted stock grants, phantom stock awards and certain stock-based performance awards are recorded over the required vesting period as compensation cost, based on the market value on the date of the grant. Other stock-based performance awards are

F-23

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

recorded over the vesting period as compensation cost, and are adjusted for increases and decreases in market value up to the measurement date. Compensation expense for awards with pro-rata vesting is recognized in accordance with FASB Interpretation No 28 (FIN 28), “Accounting for Stock Appreciation Rights and Other Variable Stock Option or Award Plans.”

The following table shows what net income (loss) would have been for Duke Capital, if Duke Energy had applied the fair value recognition provisions of SFAS No. 123, “Accounting for Stock-Based Compensation,” and provisions of SFAS No. 148, “Accounting for Stock-Based Compensation—Transition and Disclosure (an amendment of FASB Statement No. 123),” to all stock-based compensation awards.

Pro Forma Stock-Based Compensation

	For the years ended December 31,
	2005			2004			2003
	(in millions)
Net Income (loss), as reported	$	674		$	(114	)	$	(1,858	)
Add: stock-based compensation expense included in reported net income (loss), net of related tax effects		24			14			6
Deduct: total stock-based compensation expense determined under fair value-based method for all awards, net of related tax effects		(26	)		(22	)		(26	)
Pro forma net income (loss), net of related tax effects	$	672		$	(122	)	$	(1,878	)

Effective January 1, 2006, Duke Energy adopted the provisions of SFAS No. 123 (Revised 2004), “Share Based Payment” (SFAS No. 123R). See “New Accounting Standards” below for impact of adoption.

Revenue Recognition. Revenues on sales of natural gas, natural gas transportation, storage and distribution as well as sales of petroleum products, primarily at Natural Gas Transmission and Field Services (prior to deconsolidation on July 1, 2005), are recognized when either the service is provided or the product is delivered. Revenues related to these services provided or products delivered, but not yet billed, are estimated each month. These estimates are generally based on contract data, regulatory information, estimated distribution usage based on historical data adjusted for heating degree days, commodity prices and preliminary throughput and allocation measurements. Final bills for the current month are billed and collected in the following month. Differences between actuals and estimates are immaterial.

Crescent LLC (Crescent) sells residential developed lots in North Carolina, South Carolina, Georgia, Florida, Texas and Arizona. Crescent recognizes revenues from the sale of residential developed lots at closing. Profit is recognized under the full accrual method using estimates of average gross profit per lot within a project or phase of a project based on total estimated project costs. Land and land development costs are allocated to land sold based on relative sales values. Crescent recognizes revenues from commercial and multi-family project sales at closing, or later using a deferral method when the criteria for sale accounting have not been met at closing. Profit is recognized based on the difference between the sales price and the carrying cost of the project. Crescent develops and sells condominium units in Florida, and revenue is recognized under the percentage-of-completion method.

AFUDC. AFUDC, recorded in accordance with SFAS No. 71, 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

F-24

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

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 Capital is permitted to recover these costs through inclusion in the rate base and in the depreciation provision. The total amount of AFUDC included in the Consolidated Statements of Operations was $17 million in 2005, which consisted of an after-tax equity component of $8 million and a before-tax interest expense component of $9 million. The total amount of AFUDC included in the Consolidated Statements of Operations was $17 million in 2004, which consisted of an after-tax equity component of $9 million and a before-tax interest expense component of $8 million. The total amount of AFUDC included in the Consolidated Statements of Operations was $54 million in 2003, which consisted of an after-tax equity component of $33 million and a before-tax interest expense component of $21 million.

Income Taxes. Duke Energy and its subsidiaries file a consolidated federal income tax return and other state and foreign jurisdictional returns as required. Federal income taxes have been provided by Duke Capital, with the exception of certain pass-through entities, on the basis of its separate company income and deductions in accordance with established practices of the consolidated tax group. Deferred income taxes have been provided for temporary differences between the GAAP and tax carrying amounts of assets and liabilities, with the exception of certain pass-through entities. These differences create taxable or tax-deductible amounts for future periods. Investment tax credits have been deferred and are being amortized over the estimated useful lives of the related properties.

Excise and Other Pass-Through Taxes. Certain excise taxes levied by state or local governments are collected by Duke Capital from its customers. These taxes, which are required to be paid regardless of Duke Capital’s ability to collect from the customer, are accounted for on a gross basis. When Duke Capital 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.

Emission Allowances. Duke Capital accounts for emission allowances in the Consolidated Balance Sheets as intangible assets, which are included in Other within Investments and Other Assets in the accompanying Consolidated Balance Sheets. Emission allowances are initially recorded on a historical cost basis. The cost of emission allowances is charged to income as the allowances are used. Cash flows associated with emission allowances are presented as investing activities within the Consolidated Statements of Cash Flows.

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 Capital’s defined business segments. SFAS No. 131 also establishes standards and related disclosures about the way the operating segments were determined, products and services, geographic areas and major customers, differences between the measurements used in reporting segment information and those used in the company’s general-purpose financial statements, and changes in the measurement of segment amounts from period to period. The description of Duke Capital’s reportable segments, consistent with how business results are reported internally to management and the disclosure of segment information in accordance with SFAS No. 131, are presented in Note 3.

F-25

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

Foreign Currency Translation. The local currencies of Duke Capital’s foreign operations have been determined to be their functional currencies, except for certain foreign operations whose functional currency has been determined to be the U.S. Dollar, based on an assessment of the economic circumstances of the foreign operation, in accordance with SFAS No. 52, “Foreign Currency Translation.” Assets and liabilities of foreign operations, except for those whose functional currency is the U.S. Dollar, are translated into U.S. Dollars at current exchange rates. Translation adjustments resulting from fluctuations in exchange rates are included as a separate component of AOCI. Revenue and expense accounts of these operations are translated at average exchange rates prevailing during the year. Transaction gains and losses, which were not material for all periods presented, are included in the results of operations of the period in which they occur. Deferred taxes are not provided on translation gains and losses where Duke Capital expects earnings of a foreign operation to be permanently reinvested. Gains and losses relating to derivatives designated as hedges of the foreign currency exposure of a net investment in foreign operations are reported in foreign currency translation as a separate component of AOCI.

Distributions from Equity Investees. Duke Capital 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 Capital adopted the provisions of FIN 47. In accordance with the transition guidance of this standard, Duke Capital recorded a net-of-tax cumulative effect adjustment of approximately $4 million.

As of January 1, 2003, Duke Capital adopted the remaining provisions of EITF 02-03 and SFAS No. 143. In accordance with the transition guidance for these standards, Duke Capital recorded a net-of-tax and minority interest cumulative effect adjustment for change in accounting principles of $160 million as a reduction in earnings.

In October 2002, the EITF reached a final consensus on EITF 02-03. Primarily, the final consensus provided for (1) the rescission of the consensus reached on EITF 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities,” (2) the reporting of gains and losses on all derivative instruments considered to be held for trading purposes to be shown on a net basis in the income statement, and (3) gains and losses on non-derivative energy trading contracts to be similarly presented on a gross or net basis, in connection with the guidance in EITF 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent.”

As a result of the consensus on EITF 02-03, Duke Capital recorded a cumulative effect adjustment of $150 million (net of tax and minority interest) in the first quarter 2003 as a reduction to earnings. The recorded value on January 1, 2003 of all non-derivative energy trading contracts that existed on October 25, 2002 were written-off and inventories that were recorded at fair values were adjusted to historical cost.

In June 2001, the FASB issued SFAS No. 143, which addresses financial accounting and reporting for 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. For obligations related to non-regulated operations, a cumulative effect adjustment of $10 million (net of tax and minority interest) was recorded in the first quarter of 2003, as a reduction in earnings.

F-26

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

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

SFAS No. 153, “Exchanges of Nonmonetary Assets—an amendment of APB Opinion No. 29” (SFAS No. 153). In December 2004, the FASB issued SFAS No. 153 which amends APB Opinion No. 29, “Accounting for Nonmonetary Transactions,” by eliminating the exception to the fair-value principle for exchanges of similar productive assets, which were accounted for under APB Opinion No. 29 based on the book value of the asset surrendered with no gain or loss recognition. SFAS No. 153 also eliminates APB Opinion No. 29’s concept of culmination of an earnings process. The amendment requires that an exchange of nonmonetary assets be accounted for at fair value if the exchange has commercial substance and fair value is determinable within reasonable limits. Commercial substance is assessed by comparing the entity’s expected cash flows immediately before and after the exchange. If the difference is significant, the transaction is considered to have commercial substance and should be recognized at fair value. SFAS No. 153 is effective for nonmonetary transactions occurring on or after July 1, 2005. The adoption of SFAS No. 153 did not have a material impact on Duke Capital’s consolidated results of operations, cash flows or financial position.

FASB Interpretation No. 47 “Accounting for Conditional Asset Retirement Obligations” (FIN 47). In March 2005, the FASB issued FIN 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 47 were effective for Duke Capital as of December 31, 2005. See Note 6.

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

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

FASB Interpretation No. 46, “Consolidation of Variable Interest Entities” (FIN 46). In January 2003, the FASB issued FIN 46 which requires the primary beneficiary of a variable interest entity’s activities to

F-27

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

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

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

Duke Capital has not identified any material variable interest entities created, or interests in variable entities obtained, after January 31, 2003, which require consolidation or disclosure under FIN 46R. Under the provisions of FIN 46R, effective March 31, 2004, Duke Capital has consolidated certain non-special purpose operating entities, previously accounted for under the equity method of accounting. These entities, which are substantive entities, had an immaterial amount of total assets as of December 31, 2005 and approximately $230 million as of December 31, 2004. In addition, as of December 31, 2005 and 2004, Duke Capital has recorded Net Property, Plant and Equipment of $109 million and $112 million, respectively, and Long-term Debt of $173 million and $168 million, respectively, on the Consolidated Balance Sheets, associated with a variable interest entity that is consolidated by Duke Capital. Duke Capital leases a natural gas processing plant from this entity, and retains all rights and obligations associated with the operations of this plant. This variable interest entity was consolidated on Duke Capital’s Consolidated Financial Statements prior to March 31, 2004 (the effective date of FIN 46R) primarily due to Duke Capital’s guarantee of the residual value of the assets. The impact of consolidating these entities on Duke Capital’s consolidated financial statements was not material.

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

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

• The long-term rate of return on plan assets, along with a narrative discussion on the basis for selecting the rate of return used

• Information about plan assets for each major asset category (i.e. equity securities, debt securities, real estate, etc.) along with the targeted allocation percentage of plan assets for each category and the actual allocation percentages at the measurement date

F-28

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

• The amount of benefit payments expected to be paid in each of the next five years and the following five-year period in the aggregate

• The current best estimate of the range of contributions expected to be made in the following year

• The accumulated benefit obligation for defined-benefit pension plans

• Disclosure of the measurement date utilized.

Additionally, interim reports require additional disclosures related to the components of net periodic pension costs and the amounts paid or expected to be paid to the plan in the current fiscal year, if materially different than amounts previously disclosed. The provisions of SFAS No. 132R do not change the measurement or recognition provisions of defined-benefit pension and post-retirement plans as required by previous accounting standards. The provisions of SFAS No. 132R were applied by Duke Capital effective December 31, 2003 with the interim period disclosures applied beginning with the quarter ended March 31, 2004, except for the disclosure provisions of estimated future benefit payments which were effective for Duke Capital for the year ended December 31, 2004. (See Note 19 for the additional related disclosures).

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

The provisions of FSP No. FAS 106-2 were effective for the first interim period beginning after June 15, 2004. Duke Capital adopted FSP No. FAS 106-2 retroactively to the date of enactment of the Modernization Act, December 8, 2003, as allowed by the FSP.

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

Under the guidance in FSP No. FAS 109-1, which was issued in December 2004, the deduction will be treated as a “special deduction” as described in SFAS No. 109, “Accounting for Income Taxes” (SFAS No. 109). As such, for Duke Capital, the special deduction had no material impact on deferred tax assets and liabilities existing at the enactment date. Rather, the impact of this deduction is reported in the periods in which the deductions are claimed on the tax returns. For the year ended December 31, 2005, Duke Capital recognized a benefit of approximately $3 million relating to the deduction from qualified domestic activities.

F-29

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

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

The following new accounting standards were issued, but have not yet been adopted by Duke Capital as of December 31, 2005:

SFAS No. 123R. In December of 2004, the FASB issued SFAS No. 123R, which replaces SFAS No. 123 and supersedes APB Opinion No. 25. SFAS No. 123R 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, timing for implementation of SFAS No. 123R is January 1, 2006. The pro forma disclosures previously permitted under SFAS No. 123 will no longer be an acceptable alternative. Instead, Duke Capital will be required to record compensation expense in the Consolidated Statements of Operations for stock options. Under SFAS No. 123R, Duke Energy must determine an appropriate expense for stock options and the transition method to be used effective January 1, 2006. The transition methods include prospective and retroactive adoption options. Both methods record compensation expense for all unvested awards beginning January 1, 2006. Under the retroactive method, prior periods presented are also restated for awards which have vested prior to January 1, 2006.

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

Duke Energy plans to implement SFAS No. 123R using the prospective transition method and currently there are no plans to change the option-pricing model used for share-based compensation awards issued to employees in future periods. SFAS No. 123R, which was adopted by Duke Energy effective January 1, 2006, is not anticipated to have a material impact on its 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 Capital in periods subsequent to adoption of SFAS No. 123R will be largely dependent upon the nature of any new share-based compensation awards issued to employees.

F-30

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

Staff Accounting Bulletin (SAB) No. 107, “Share-Based Payment” (SAB 107). On March 29, 2005, the Securities and Exchange Commission (SEC) staff issued SAB 107 to express the views of the staff regarding the interaction between SFAS No. 123R and certain SEC rules and regulations and to provide the staff’s views regarding the valuation of share-based payment arrangements for public companies. Duke Energy is currently in the process of implementing SFAS No. 123R, effective as of January 1, 2006, and will take into consideration the additional guidance provided by SAB 107 in connection with the implementation of SFAS No. 123R.

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

2. Acquisitions and Dispositions

Acquisitions. Duke Capital 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 98-3, “Determining Whether a Nonmonetary Transaction Involves Receipt of Productive Assets or of a Business” (EITF 98-3), is recorded as goodwill. The allocation of the purchase price may be adjusted if additional information on known contingencies existing at the date of acquisition becomes available within one year after the acquisition, and longer for certain income tax items.

On May 9, 2005, Duke Energy and Cinergy Corp. (Cinergy) announced they entered into a definitive merger agreement. Upon consummation of the transaction set forth in the merger agreement, each common share of Cinergy will be converted into 1.56 shares of common stock of a newly-created holding company (to be renamed Duke Energy Corporation) and each common share of Duke Energy will be converted into one share of the holding company. Based on Cinergy shares outstanding at December 31, 2005, the holding company would issue approximately 310 million shares to convert the Cinergy common shares. The merger will be accounted for under the purchase method of accounting with Duke Energy treated as the acquirer for accounting purposes.

The merger agreement has been unanimously approved by both companies’ Boards of Directors. Closing of the transaction is currently anticipated for the second quarter of 2006. Completion of the merger is subject to a number of conditions. Duke Energy and Cinergy shareholders approved the merger at special meetings of shareholders held on March 10, 2006. See further discussion of regulatory filings in Note 4. The merger agreement contains certain cross-approval provisions whereby Duke Energy and Cinergy are required to continue to operate their businesses in the ordinary course of business and must obtain the other party’s consent prior to making new investments, disposing of businesses, or entering into new debt above specified thresholds, among other provisions. Among other things, the merger agreement contemplates potential transactions that could involve the transfer of certain assets, including DENA’s Midwestern generation assets (as discussed further in Note 12), out of Duke Capital in connection with the merger. However, any potential transactions involving assets of Duke Capital and related consideration remain subject to change (see Notes 1 and 21).

F-31

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

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

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

In the second quarter of 2005, United Bridgeport Energy LLC (UBE), the owner of a 33 ¹/3% interest in Bridgeport Energy LLC (Bridgeport), exercised its “put right” requiring DENA to purchase UBE’s interest in Bridgeport as provided for in the LLC Agreement. DENA and UBE have finalized a settlement for the purchase price of UBE’s ownership interest. This settlement will not have a material adverse effect on Duke Capital’s future consolidated results of operations, cash flows or financial position. Upon closing of this transaction, DENA will own 100% of Bridgeport. The assets and liabilities of Bridgeport have been classified as Assets Held for Sale in the accompanying Consolidated Balance Sheet as of December 31, 2005, and will be included as part of DENA’s power generation assets to be sold to a subsidiary of LS Power Equity Partners (LS Power) (see Notes 12 and 21).

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

In the third quarter of 2004, Field Services acquired additional interest in three separate entities (for which DEFS owned less than 100%, but had been consolidating) for a total purchase price of $4 million, and the exchange of some Field Services’ assets. Two of these acquisitions, Mobile Bay Processing Partners (MBPP) and Gulf Coast NGL Pipeline, LLC (GC), resulted in 100% ownership by Field Services. The MBPP transaction involved MBPP transferring certain long-lived assets to El Paso Corporation for El Paso Corporation’s interest in MBPP. As a result of this non-monetary transaction, the assets transferred were written-down to their estimated fair value which resulted in Duke Capital recognizing a pre-tax impairment of approximately $13 million, which was approximately $4 million net of minority interest. An additional 12% interest in Dauphin Island Gathering Partners (DIGP) was also purchased for $2 million, which resulted in 84% ownership by Field Services. MBPP owns processing assets in the Onshore Gulf of Mexico. GC owns a 16.67% interest in two equity investments. DIGP owns gathering and transmission assets in the Offshore Gulf of Mexico.

The pro forma results of operations for Duke Capital as if those acquisitions which closed prior to December 31, 2005 occurred as of the beginning of the periods presented do not materially differ from reported results.

Dispositions. For the year ended December 31, 2005, the sale of other assets, businesses and equity investments resulted in approximately $2.3 billion in proceeds, pre-tax gains of $527 million recorded in Gains (Losses) on Sales of Other Assets, net, on the accompanying Consolidated Statements of Operations and pre-tax gains of $1,225 million recorded in Gains (Losses) on Sales and Impairments of Equity Method Investments on the accompanying Consolidated Statements of Operations. These sales exclude assets that were held for sale and reflected in discontinued operations, both of which are discussed in Note 12, and commercial and multi-family

F-32

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

real estate sales by Crescent which are discussed separately below. Significant sales of other assets and equity investments during 2005 are detailed as follows:

• In February 2005, DEFS sold its wholly owned subsidiary Texas Eastern Products Pipeline Company, LLC (TEPPCO GP), which is the general partner of TEPPCO Partners, LP (TEPPCO LP), for approximately $1.1 billion and Duke Capital 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, which were recorded in Gains (Losses) on Sales and Impairments of Equity Method Investments in the Consolidated Statements of Operations. Minority Interest Expense of $343 million was recorded in the accompanying Consolidated Statements of Operations to reflect ConocoPhillips’ proportionate share in the pre-tax gain on sale of TEPPCO GP.

Additionally, in July 2005, Duke Energy caused a Duke Capital subsidiary to complete the previously announced agreement with ConocoPhillips, Duke Capital’s co-equity owner in DEFS, to reduce Duke Capital’s ownership interest in DEFS from 69.7% to 50% (the DEFS disposition transaction), which results in Duke Capital and ConocoPhillips becoming equal 50% owners in DEFS. Duke Capital has received, directly and indirectly through its ownership interest in DEFS, a total of approximately $1.1 billion from ConocoPhillips and DEFS, consisting of approximately $1.0 billion in cash and approximately $0.1 billion of assets. The DEFS disposition transaction resulted in a pre-tax gain of approximately $575 million, which was recorded in Gains (Losses) on Sales of Other Assets, net, in the accompanying Consolidated Statements of Operations. The DEFS disposition transaction includes the transfer to Duke Capital of DEFS’ Canadian natural gas gathering and processing facilities. Additionally, the DEFS disposition transaction included the acquisition of ConocoPhillips’ interest in the Empress System. Subsequent to the closing of the DEFS disposition transaction, effective on July 1, 2005, DEFS is no longer consolidated into Duke Capital’s consolidated financial statements and is accounted for by Duke Capital as an equity method investment. See Note 7 for the impacts of this transaction on certain cash flow hedges. The Canadian natural gas gathering and processing facilities and the Empress System are included in the Natural Gas Transmission segment.

• In December 2005, the Duke Energy Income Fund (Income Fund), a Canadian income trust fund, was created to acquire all of the common shares of Duke Capital Midstream Services Canada Corporation (Duke Midstream) from a subsidiary of Duke Capital. The Income Fund sold an approximate 40% ownership interest in Duke 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. Duke Capital retains an ownership interest in the Income Fund of approximately 58% and will continue to operate and manage this business. Duke Capital continues to consolidate the results of this business.

• In December 2005, Commercial Power recorded a $75 million charge related to the termination of structured power contracts in the Southeast, which was recorded in Gains (Losses) on Sales of Other Assets, net on the accompanying Consolidated Statements of Operations.

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 recorded in Gains on Sales of Investments in Commercial and Multi-Family Real Estate on the Consolidated Statements of Operations. 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 which was recognized in Other Income and Expenses, net, in the accompanying Consolidated Statements of Operations.

F-33

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

For the year ended December 31, 2004, the sale of other assets and businesses (which excludes assets held for sale as of December 31, 2004 and discontinued operations, both of which are discussed in Note 12, and sales by Crescent which are discussed separately below) resulted in approximately $736 million in cash proceeds plus a $48 million note receivable from the buyers, and net pre-tax losses of $408 million recorded in Gains (Losses) on Sales of Other Assets, net and pre-tax losses of $3 million recorded in Gains (Losses) on Sales and Impairments of Equity Method Investments on the Consolidated Statements of Operations. Gains (Losses) on Sales and Impairments of Equity Method Investments included a $23 million impairment charge, which is discussed in Note 11. Significant sales of other assets in 2004 are detailed as follows:

• Natural Gas Transmission’s asset sales totaled $25 million in net proceeds. Those sales resulted in total pre-tax gains of approximately $33 million, of which $17 million was recorded in Gains (Losses) on Sales of Other Assets, net and $16 million was recorded in Gains (Losses) on Sales and Impairments of Equity Method Investments in the Consolidated Statements of Operations. Significant sales included the sale of storage gas related to the Canadian distribution operations, the sale of Natural Gas Transmission’s interest in the Millennium Pipeline, and the sale of land.

• Field Services asset sales totaled $13 million in net proceeds. Those sales resulted in gains of $2 million which were recorded in Gains (Losses) on Sales of Other Assets, net in the Consolidated Statements of Operations. These sales consisted of multiple small sales.

• Commercial Power’s asset sales totaled approximately $420 million in net proceeds and a $48 million note receivable. Those sales resulted in pre-tax losses of $360 million which were recorded in Gains (Losses) on Sales of Other Assets, net in the Consolidated Statements of Operations. Significant sales included:

• DENA’s eight natural gas-fired merchant power plants in the Southeastern United States: Hot Spring (Arkansas); Murray and Sandersville (Georgia); Marshall (Kentucky); Hinds, Southaven, Enterprise and New Albany (Mississippi); and certain other power and gas contracts (collectively, the Southeast Plants). Duke Capital decided to sell the Southeast Plants in 2003, and recorded an impairment charge of $1.3 billion in 2003 since the assets’ carrying values exceeded their estimated fair values (see Note 11). The sale of those assets to KGen Partners LLC (KGen) obtained all required regulatory approvals and consents and closed on August 5, 2004. This transaction resulted in a pre-tax loss of approximately $360 million recorded in Gains (Losses) on Sales of Other Assets, net in the 2004 Consolidated Statement of Operations. Nearly all of the loss was recognized in the first quarter of 2004 to reduce the assets’ carrying values to their estimated fair values, and approximately $4 million of the loss was recognized in the third quarter of 2004 upon closing. The fair value of the plants used for recording the loss in the first quarter was based on the sales price of approximately $475 million, as announced on May 4, 2004. The actual sales price consisted of $420 million of cash and a $48 million note receivable from KGen, which bears variable interest at the London Interbank Offered Rate (LIBOR) plus 13.625% per annum, compounded quarterly. The note is secured by a fourth lien on (i) substantially all of KGen’s assets and (ii) stock of KGen LLC (KGen’s owner), each subject to certain permitted liens and a first lien on cash in certain KGen accounts. The note was repaid in full during 2005.

Duke Capital retained certain guarantees related to the sold assets. In conjunction with the sale, Duke Capital arranged a letter of credit with a face amount of $120 million in favor of Georgia Power Company, to secure obligations of a KGen subsidiary under a seven-year power sales agreement, commencing in May 2005, under which KGen will provide power from one of the plants to Georgia Power. Duke Capital is the primary obligor to the letter of credit provider, but KGen has an obligation to reimburse Duke Capital for any payments made by it under the letter of credit, as well

F-34

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

as expenses incurred by Duke Capital in connection with the letter of credit. DENA will continue to provide services under a long-term operating agreement for one of the plants. As a result of DENA’s significant continuing involvement in the operations of the plants, this transaction did not qualify for discontinued operations presentation, as prescribed by SFAS No. 144. However, this continuing involvement did not prohibit sale accounting under SFAS No. 66, “Accounting for Sales of Real Estate.”

• International Energy completed the sale of its 30% equity interest in Compañia de Nitrógeno de Cantarell, S.A. de C.V. (Cantarell) a nitrogen production and delivery facility in the Bay of Campeche, Gulf of Mexico on September 8, 2004. The sale resulted in $60 million in net proceeds and an approximate $2 million pre-tax gain recorded to Gains (Losses) on Sales and Impairments of Equity Method Investments on the Consolidated Statements of Operations. A $13 million non-cash charge to Operation, Maintenance and Other expenses on the Consolidated Statements of Operations, related to a note receivable from Cantarell, was recorded in the first quarter of 2004.

• Additional asset and business sales in 2004 totaled $217 million in net proceeds. Those sales resulted in net pre-tax losses of $60 million, of which a $61 million loss was recorded in Gains (Losses) on Sales of Other Assets, net and a $1 million gain was recorded in Gains (Losses) on Sales and Impairments of Equity Method Investments in the Consolidated Statements of Operations. Significant sales included:

• Some Duke Energy Trading and Marketing, LLC (DETM) contracts. DETM held a net liability position in those contracts and, as part of the sale, DETM paid a third party net cash payments of $99 million related to the sale of these assets which are included in Cash Flows from Operating Activities. This resulted in a net loss of $65 million recorded in Gains (Losses) on Sales of Other Assets, net in the 2004 Consolidated Statement of Operations.

• Duke Energy Royal LLC’s interest in six energy service agreements and DukeSolutions Huntington Beach, LLC.

• DEM’s 15% interest in Caribbean Nitrogen Company and refined products operation in the eastern United States.

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

The sale of other assets and businesses for approximately $1,110 million in proceeds plus the assumption of $70 million of debt by the buyers for 2003 resulted in net losses of $185 million recorded in Gains (Losses) on Sales of Other Assets, net on the Consolidated Statements of Operations, and gains of $279 million recorded in Gains (Losses) on Sales and Impairments of Equity Method Investments in the Consolidated Statements of Operations. Significant sales of other assets and businesses in 2003 (other than discontinued operations as presented in Note 12) are detailed by business segment as follows:

• Natural Gas Transmission’s sales of assets and businesses totaled $610 million in proceeds, and the assumption of $70 million of debt by the buyers. Those sales resulted in gains of $90 million which were recorded in Gains (Losses) on Sales and Impairments of Equity Method Investments in the Consolidated Statements of Operations, and gains of $7 million which were recorded in Gains (Losses) on Sales of Other Assets, net in the Consolidated Statements of Operations. Significant sales included

F-35

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

the sale of its remaining limited partnership interests in Northern Border Partners L.P.; the sale of its investments in the Alliance Pipeline and the associated Aux Sable NGL plant, Foothills Pipe Lines Ltd., and Vector Pipeline LP (Vector); the sale of Pacific Northern Gas Ltd., and the sale of two office buildings.

• Field Services sales of assets totaled $141 million in proceeds. Those sales resulted in gains of $11 million which were recorded in Gains (Losses) on Sales and Impairments of Equity Method Investments in the Consolidated Statements of Operations. Significant sales included Field Services’ Class B units of TEPPCO Partners, L.P.

• Other asset and business sales in 2003 included:

• The sale of DENA’s 50% ownership interest in Duke/UAE Ref-Fuel LLC (Ref-Fuel) resulted in proceeds of $325 million and a gain of $178 million, which was recorded in Gains (Losses) on Sales and Impairments of Equity Method Investments in the Consolidated Statements of Operations

• Impairment charges and net losses on sales, primarily related to the sale of DETM contracts, resulted in a net loss of $124 million, which was recorded in Gains (Losses) on Sales of Other Assets, net in the Consolidated Statements of Operations. Impairment charges and losses on the DETM contracts resulted from DENA’s decision to wind-down DETM’s operations. As a result, DENA and Exxon Mobil, its partner, are executing a reduction of DETM business in scope and scale and soliciting interest from selected parties for a significant portion of DETM’s contract portfolio. The ultimate financial impact to DENA of the reduction in the scope and sale of DETM and related liquidation of its contract portfolio cannot be reasonably estimated. However, it is possible that DENA will incur additional losses as a result of liquidating the DETM contracts.

• Some turbines and surplus equipment. This sale was anticipated in 2003 and therefore a loss of $66 million was recorded in Gains (Losses) on Sales of Other Assets, net in the 2003 Consolidated Statement of Operations Net proceeds of $44 million were received in 2004.

3. Business Segments

In conjunction with the merger between Duke Energy and Cinergy (see Note 1), Duke Capital has adopted new business segments that management believes properly align the various operations of the new corporate structure with how the chief operating decision maker views the business and monitors performance. Prior period segment information has been retrospectively adjusted to conform to the new segment structure. Accordingly, Duke Capital’s reportable business segments are: Natural Gas Transmission, Field Services, Commercial Power, International Energy and Crescent.

Duke Capital’s chief operating decision maker regularly reviews financial information about each of these business units in deciding how to allocate resources and evaluate performance. All of the Duke Capital business units are considered reportable segments under SFAS No. 131. There is no aggregation within Duke Capital’s defined business segments.

Natural Gas Transmission provides transportation and storage of natural gas for customers along the U.S. East Coast, the Southeast, and in Canada. Natural Gas Transmission also provides natural gas sales and distribution service to retail customers in Ontario, natural gas processing services to customers in Western Canada and other energy related services. Natural Gas Transmission does business primarily through Duke Energy Gas Transmission, LLC. Duke Energy Gas Transmission, LLC’s natural gas transmission and storage operations in the U.S. are primarily subject to the FERC’s and the U.S. Department of Transportation’s (DOT’s) rules and regulations, while natural gas gathering, processing, transmission, distribution and storage operations in

F-36

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

Canada are primarily subject to the rules and regulations of the National Energy Board (NEB) and the Ontario Energy Board (OEB). Prior period segment results for Natural Gas Transmission have been retrospectively adjusted to include the results of operations of the McMahon facility and the Canadian gathering and processing facilities transferred to Natural Gas Transmission from DENA and Field Services, respectively, during 2005.

Field Services gathers, compresses, treats, processes, transports, trades and markets, and stores natural gas; and fractionates, transports, trades and markets, and stores NGLS. It conducts operations primarily through DEFS, which is owned 50 percent by ConocoPhillips and 50 percent by Duke Capital. Field Services gathers raw natural gas through gathering systems located in seven major natural gas producing regions: Permian Basin, Mid-Continent, ArklaTex, Gulf Coast, South, Central and the Rocky Mountains.

In February 2005, DEFS sold its wholly owned subsidiary TEPPCO GP, which is the general partner of TEPPCO LP, and Duke Capital sold its limited partner interest in TEPPCO LP, in each case to Enterprise GP Holdings LP, an unrelated third party. As a result of the DEFS disposition transaction discussed in Note 2, Duke Capital deconsolidated its investment in DEFS effective July 1, 2005 and subsequently has accounted for it as an investment utilizing the equity method of accounting. In connection with the DEFS disposition transaction, DEFS transferred its Canadian natural gas gathering and processing facilities to Duke Capital’s Natural Gas Transmission segment. Prior period segment results for Field Services have been retrospectively adjusted to exclude the results of operations of these Canadian gathering and processing facilities, while prior period segment results for Natural Gas Transmission have been retrospectively adjusted to include the results of operations of these Canadian gathering and processing facilities.

Commercial Power consists of a portion of Duke Capital’s operations formerly known as Duke Energy North America (DENA). Commercial Power operates and manages power plants and related contractual positions in the Midwestern and Southeastern United States. As indicated in Note 1, Commercial Power’s Midwestern generation assets, consisting of approximately 3,600 megawatts of power generation, and certain contracts related to the Midwestern generating facilities were transferred to Cinergy in April 2006. As such the results of operations of the Midwestern assets have been reflected as discontinued operations in the accompanying Consolidated Statements of Operations (see Note 12). Commercial Power’s continuing operations prior to 2005 consist primarily of DENA’s eight natural gas-fired merchant power plants in the Southeastern United States and certain other power and gas contracts (collectively, the Southeast Plants). Duke Capital sold the Southeast Plants in August 2004 (see also Note 2). Additionally during 2005, DENA transferred its 50% investment in the McMahon facility in British Columbia, Canada to Natural Gas Transmission.

International Energy operates and manages power generation facilities, and engages in sales and marketing of electric power and natural gas outside the U.S. and Canada. It conducts operations primarily through Duke Energy International, LLC (DEI) and its activities target power generation in Latin America. Additionally, International Energy owns an equity investment in National Methanol Company, located in Saudi Arabia, which is a leading regional producer of methanol and methyl tertiary butyl ether (MTBE).

Crescent develops and manages high-quality commercial, residential and multi-family real estate projects primarily in the Southeastern and Southwestern United States. Some of these projects are developed and managed through joint ventures. Crescent also manages “legacy” land holdings in North and South Carolina.

The remainder of Duke Capital’s operations is presented as “Other”. While it is not considered a business segment, Other primarily includes the following:

• The remaining portion of Duke Capital’s business formerly known as DENA, including its 100% owned affiliates Duke Energy Marketing America, LLC and Duke Energy Marketing Canada Corp. DENA also

F-37

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

participates in DETM. DETM is 40% owned by Exxon Mobil Corporation and 60% owned by Duke Capital. 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 DENA’s remaining assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets. The exit plan was completed in the second quarter of 2006 (see Note 21). As a result of this exit plan, the results of operations for most of DENA’s businesses have been reflected as discontinued operations in the accompanying Consolidated Statements of Operations for all years presented. Continuing operations within Other consist primarily of DETM, which management continues to wind down.

• Other also includes certain unallocated corporate costs, certain discontinued hedges, DukeNet, Bison (Duke Capital’s wholly owned, captive insurance subsidiary) and Duke Capital’s 50% interest in D/FD. DukeNet develops, owns and operates a fiber optic communications network, primarily in the Carolinas, serving wireless, local and long-distance communications companies, internet service providers and other businesses and organizations. Duke Capital’s wholly owned captive insurance subsidiary’s principal activities include the insurance and reinsurance of various business risks and losses, such as workers compensation, property, business interruption and general liability of subsidiaries and affiliates of Duke Capital. This subsidiary also participates in reinsurance activities with certain third parties, on a limited basis. D/FD is a 50/50 partnership between subsidiaries of Duke Capital and Fluor Corporation (Fluor). During 2003, Duke Capital and Fluor announced that they would dissolve D/FD and adopted a plan for an orderly wind-down of the D/FD business. The wind-down has been substantially completed as of December 31, 2005 and is expected to be finalized by December 2006. Previously, D/FD provided comprehensive engineering, procurement, construction, commissioning and operating plant services for fossil-fueled electric power generating facilities worldwide.

• During 2003, Duke Capital determined that it would exit the refined products business at DEM in an orderly manner, and continues to unwind its portfolio of contracts. As of December 31, 2005, DEM had exited the majority of its business.

• During 2003, Duke Capital also decided to exit the merchant finance business conducted by Duke Capital Partners, LLC (DCP). At December 31, 2005, Duke Capital had exited the merchant finance business, and all of the results of operations for DCP have been classified as discontinued operations in the accompanying Consolidated Statements of Operations.

• During the first quarter of 2005, Duke Capital discontinued hedge accounting for certain contracts related to Field Services’ commodity price risk and changes in the fair value of these contracts subsequent to hedge discontinuance have been classified in Other. See Note 7 for further discussion.

Duke Capital’s reportable segments offer different products and services and are managed separately as business units. Accounting policies for Duke Capital’s segments are the same as those described in Note 1. 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 Capital, so the associated realized and unrealized gains and losses from foreign currency transactions and interest and dividend income on those balances are excluded from the segments’ EBIT.

Transactions between reportable segments are accounted for on the same basis as revenues and expenses in the accompanying Consolidated Financial Statements.

F-38

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

Business Segment Data^(a)

	Unaffiliated Revenues			Intersegment Revenues			Total Revenues			Segment EBIT/ Consolidated Earnings (Loss) from Continuing Operations before Income Taxes			Depreciation and Amortization		Capital and Investment Expenditures			Segment Assets(b)
	(in millions)
Year Ended December 31, 2005
Natural Gas Transmission	$	3,955		$	100		$	4,055		$	1,388		$	458	$	930		$	18,823
Field Services(e)		5,470			60			5,530			1,946			143		86			1,377
Commercial Power		—			—			—			(66	)		—		2			1,619
International Energy		745			—			745			314			64		23			2,962
Crescent(c)		495			—			495			314			1		599			1,507
Total reportable segments		10,665			160			10,825			3,896			666		1,640			26,288
Other		684			(82	)		602			(295	)		25		29			8,533
Eliminations and reclassifications		—			(78	)		(78	)		—			—		—			235
Interest expense		—			—			—			(771	)		—		—			—
Interest income and other(d)		—			—			—			62			—		—			—
Total consolidated	$	11,349		$	—		$	11,349		$	2,892		$	691	$	1,669		$	35,056
Year Ended December 31, 2004
Natural Gas Transmission	$	3,238		$	113		$	3,351		$	1,329		$	431	$	544		$	17,783
Field Services(e)		10,172			(128	)		10,044			367			285		202			6,265
Commercial Power		—			104			104			(408	)		8		6			1,646
International Energy		619			—			619			222			58		28			3,058
Crescent(c)		437			—			437			240			2		568			1,317
Total reportable segments		14,466			89			14,555			1,750			784		1,348			30,069
Other		997			371			1,368			77			27		34			7,058
Eliminations and reclassifications		—			(460	)		(460	)		—			—		—			56
Interest expense		—			—			—			(980	)		—		—			—
Interest income and other(d)		—			—			—			(2	)		—		—			—
Total consolidated	$	15,463		$	—		$	15,463		$	845		$	811	$	1,382		$	37,183
Year Ended December 31, 2003
Natural Gas Transmission	$	3,025		$	228		$	3,253		$	1,333		$	404	$	773		$	16,864
Field Services(e)		7,921			617			8,538			176			281		204			5,907
Commercial Power		(54	)		141			87			(1,233	)		81		336			2,583
International Energy		597			—			597			215			57		71			4,399
Crescent(c)		284			—			284			134			6		290			1,594
Total reportable segments		11,773			986			12,759			625			829		1,674			31,347
Other		1,444			607			2,051			(365	)		35		(92	)		8,538
Eliminations and reclassifications		—			(1,593	)		(1,593	)		—			—		—			7
Interest expense		—			—			—			(1,020	)		—		—			—
Interest income and other(d)		—			—			—			3			—		—			—
Total consolidated	$	13,217		$	—		$	13,217		$	(757	)	$	864	$	1,582		$	39,892

(a) Segment results exclude results of entities classified as discontinued operations

(b) Includes assets held for sale

(c) Capital expenditures for residential real estate are included in operating cash flows and were $355 million in 2005, $322 million in 2004 and $196 million in 2003.

(d) Other includes foreign currency transaction gains and losses, and additional minority interest expense not allocated to the segment results.

(e) In July 2005, Duke Energy caused a Duke Capital subsidiary to complete the previously announced agreement with ConocoPhillips to reduce Duke Capital’s ownership interest in DEFS from 69.7% to 50%. Field Services segment data includes DEFS as a consolidated entity for periods prior to July 1, 2005 and an equity method investment for periods after June 30, 2005.

F-39

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

Geographic Data

	U.S.		Canada		Latin America		Other Foreign		Consolidated
	(in millions)
2005
Consolidated revenues	$	7,252	$	3,313	$	741	$	43	$	11,349
Consolidated long-lived assets		14,823		10,790		2,432		403		28,448
2004
Consolidated revenues	$	11,498	$	3,297	$	612	$	56	$	15,463
Consolidated long-lived assets		17,808		10,163		2,399		372		30,742
2003
Consolidated revenues	$	7,599	$	4,935	$	556	$	127	$	13,217
Consolidated long-lived assets		19,964		9,532		2,449		1,589		33,534

4. Regulatory Matters

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

Duke Capital’s Regulatory Assets and Liabilities:

	As of December 31,				Recovery/Refund Period Ends
	2005		2004
	(in millions)
Regulatory Assets(a)
Net regulatory asset related to income taxes(b)	$	954	$	893	(h)
Project costs(c)(d)(e)		40		16	2024
Gas purchase costs(c)		34		—	2006
Deferred debt expense(d)		14		17	2011
Vacation accrual(c)		9		9	2006
Environmental cleanup costs(c)		7		8	2017
Hedge costs and other deferrals(c)		—		10	2005
Other(c)		5		—	(k)
Total Regulatory Assets	$	1,063	$	953
Regulatory Liabilities(a)
Removal costs(d)(g)(j)	$	350	$	317	(i)
Pipeline rate credit(g)		37		38	2041
Storage and transportation liability(f)		9		16	2006
Earnings sharing liability(f)		9		11	2006
Other deferred tax credits(d)(g)		8		11	(k)
Gas purchase costs(f)		—		32	2005
Other(g)		7		—	2006
Total Regulatory Liabilities	$	420	$	425

(a) All regulatory assets and liabilities are excluded from rate base unless otherwise noted.

F-40

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

(b) Amounts are expected to be included in future rate filings.

(c) Included in Other Regulatory Assets and Deferred Debits on the Consolidated Balance Sheets.

(d) Included in rate base.

(e) Earns a return.

(f) Included in Accounts Payable on the Consolidated Balance Sheets.

(g) Included in Other Deferred Credits and Other Liabilities on the Consolidated Balance Sheets.

(h) Recovery/refund is over the life of the associated asset or liability.

(i) Liability is extinguished over the lives of the associated assets.

(j) 2004 amounts reflect reclassification of approximately $300 million related to removal costs for property within the natural gas operations (see Note 1).

(k) $5 million to be refunded through 2007 and the remaining balance will be included in future rate filing.

Duke Energy Merger with Cinergy. As discussed in Note 2, on May 9, 2005, Duke Energy and Cinergy announced they entered into a definitive merger agreement. Approval of the merger by several federal and state agencies is required; all of the approvals have been obtained. All of the approved state settlements include a most favored nations clause related to merger savings sharing in other jurisdictions. Duke Energy and Cinergy shareholders approved the merger at special meetings of shareholders held on March 10, 2006 (see Notes 1 and 21).

Natural Gas Transmission. Rate Related Information. The British Columbia Pipeline System’s (BC Pipeline) pipeline and field services businesses in Western Canada recorded regulatory assets related to deferred income tax liabilities of approximately $640 million as of December 31, 2005 and $612 million as of December 31, 2004. Under the current NEB-authorized rate structure, income tax costs are recovered in tolls based on the current income tax payable and do not include accruals for deferred income tax. However, as income taxes become payable as a result of the reversal of timing differences that created the deferred income taxes, it is expected that the transportation and field services tolls will be adjusted to recover these taxes. Since most of these timing differences are related to property, plant and equipment costs, this recovery is expected to occur over a 20 to 30 year period.

When evaluating the recoverability of the BC Pipeline and field services’ regulatory assets, management takes into consideration the NEB regulatory environment, natural gas reserve estimates for reserves located, or expected to be located, near these assets, the ability to remain competitive in the markets served, and projected demand growth estimates for the areas served by BC Pipeline and field services business. Based on current evaluation of these factors, management believes that recovery of these tax costs is probable over the periods described above.

In November 2005, BC Pipeline filed an application with the NEB for interim and final tolls for 2006. In December 2005, the NEB approved the 2006 interim tolls as filed. BC Pipeline has started negotiations with its shippers to reach a settlement on final tolls for years 2006, 2007 and 2008. Union Gas has rates that are approved by the OEB. Rates for the sale of gas are adjusted quarterly to reflect updated commodity price forecasts. The difference between the approved and the actual cost of gas incurred in the current period is deferred for future recovery from or return to customers, subject to approval by the OEB. These differences are directly flowed through to customers and, therefore, no rate of return is earned on the related deferred balances. The OEB’s review and approval of these gas purchase costs primarily considers the prudence of the costs incurred.

The OEB also implemented an asymmetrical earnings sharing mechanism for Union Gas, effective January 1, 2005. Earnings in 2005, above the 9.63% benchmark return on equity (ROE), normalized for weather, were shared equally between ratepayers and Union Gas. No rate relief will be provided if Union Gas earns below

F-41

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

the allowed ROE, normalized for weather. This earnings sharing mechanism reduced Union Gas’ earnings by approximately $9 million during the year ended December 31, 2005.

In December 2005, the OEB approved the 2006 rates for Union Gas implementing items previously approved by the OEB, incorporating an earnings sharing mechanism for 2006 with the characteristics similar to those ordered by the OEB for 2005.

On March 30, 2005, the OEB issued a report containing plans for refining natural gas sector regulation. The OEB has endorsed the concept of a multi-year incentive regulation plan. It has scheduled a series of proceedings over the next three years to establish key parameters underpinning this framework. Union Gas will participate in these proceedings.

Effective January 1, 2005, new rates for Maritimes & Northeast Pipeline L.L.C. (M&N) took effect, subject to refund, as a result of a rate case filed by M&N in 2004. In June 2005, a settlement agreement to resolve the proceeding was reached with customers that would provide for a rate increase over rates charged prior to January 1, 2005. This settlement agreement has been filed with FERC for its review and approval.

On November 1, 2005, East Tennessee Natural Gas, LLC placed into effect new rates approved by FERC as a result of a rate settlement with customers. The settlement agreement includes a five year rate moratorium and certain operational changes.

FERC Accounting Order. In June 2005, FERC issued an Order on Accounting for Pipeline Assessment Costs that requires most pipeline inspection and integrity assessment activities to be recognized as expenses, as incurred. In the Order, FERC confirmed that pipeline betterments and replacements, including those resulting from integrity inspections, will continue to be capitalized when appropriate. This FERC Order is effective for pipeline inspection and integrity assessment costs incurred on or subsequent to January 1, 2006 and is expected to increase annual expenses within Natural Gas Transmission by approximately $15 million to $20 million. Pipeline inspection and integrity assessment costs capitalized prior to the effective date of the rule are not impacted.

Management believes that the effects of these matters will have no material adverse effect on Duke Capital’s future consolidated results of operations, cash flows or financial position.

International Energy. Brazil Regulatory Environment. In 2004, a new energy law enacted in Brazil changed the electricity sector’s regulatory framework. The new energy law created a regulated and non-regulated market that coexist. The regulated market consists of auctions conducted by the government for the sale of power to distribution companies, who are required to fully contract their estimated electricity demand, principally through the regulated auctions. In the non-regulated market, generators, traders and non-regulated customers are permitted to enter into bi-lateral electricity purchase and sale contracts. The first regulated auction was held December 7, 2004, and the second on April 2, 2005. In those auctions, distribution companies contracted for their estimated electricity demand for the period from 2005 to 2016. The contracts offered in the auctions were eight-year contracts with delivery periods commencing in each of the years 2005 through 2008. Duke Capital’s Brazilian affiliate, Duke Energy International, Geracao Paranapanema S.A. (Paranapanema), participated in these auctions as a seller of electricity and elected to commit to eight-year contracts for delivery of 214 Megawatts (MW) beginning in 2005, 58 MW for delivery beginning in 2006, and 218 MW for delivery beginning in 2007. Paranapanema elected not to commit any capacity to the 2008 contract, and withheld some available capacity from the 2006 and 2007 contracts, due to low pricing and in order to preserve the capability to capture higher value alternatives in the future.

F-42

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

5. Income Taxes

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

Income Tax Expense (Benefit) from Continuing Operations

	For the Years Ended December 31,
	2005			2004 As Restated (see Note 1)			2003
	(in millions)
Current income taxes
Federal	$	1,004		$	121		$	(160	)
State		102			40			(42	)
Foreign		99			83			113
Total current income taxes		1,205			244			(89	)
Deferred income taxes
Federal		(48	)		1,048			(206	)
State		(19	)		6			(9	)
Foreign		74			43			(8	)
Total deferred income taxes		7			1,097			(223	)
Investment tax credit amortization		—			—			(2	)
Total income tax expense (benefit) from continuing operations		1,212			1,341			(314	)
Total income tax (benefit) expense from discontinued operations		(181	)		(128	)		(749	)
Total income tax benefit from cumulative effect of change in accounting principle		(1	)		—			(93	)
Total income tax expense (benefit) presented in Consolidated Statements of Operations	$	1,030		$	1,213		$	(1,156	)

Earnings (Loss) from Continuing Operations before Income Taxes

	For the Years Ended December 31,
	2005		2004		2003
	(in millions)
Domestic	$	2,302	$	379	$	(1,084	)
Foreign		590		466		327
Total earnings (loss) from continuing operations before income taxes	$	2,892	$	845	$	(757	)

F-43

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

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

	For the Years Ended December 31,
	2005			2004			2003
				As Restated (see Note 1)
				(in millions)
Income tax expense (benefit), computed at the statutory rate of 35%	$	1,012		$	296		$	(265	)
State income tax, net of federal income tax effect		54			30			(33	)
Tax differential on foreign earnings		(34	)		(37	)		(9	)
Pass-through of income tax expense(a)		137			48			—
Deferred taxes on restructuring of certain subsidiaries		—			991			—
Other items, net		43			13			(7	)
Total income tax expense (benefit) from continuing operations	$	1,212		$	1,341		$	(314	)
Effective tax rate		41.9	%		158.7	%		41.5	%

(a) Since Duke Capital is an LLC, the tax benefit of losses on DENA’s operations are passed-through to Duke Energy.

During 2004, Duke Capital recorded a $52 million income tax benefit from the reduction of state and federal income tax reserves based on the resolution in the second quarter of 2004 of several tax issues. The $52 million benefit is included in the Statutory Rate Reconciliation as follows: a $39 million state benefit is included in “State income tax, net of federal income tax effect” and a $13 million federal benefit is included in “Other items, net”.

On July 2, 2004, Duke Energy realigned certain subsidiaries resulting in all of its wholly owned merchant generation facilities being owned by a newly created entity, Duke Energy Americas LLC (DEA), a directly wholly owned subsidiary of Duke Capital. DEA and Duke Capital are pass-through entities for U.S. income tax purposes. As this reorganization is considered a change in tax status, Duke Capital recognized federal and state tax expense in continuing operations of approximately $1,030 million in the third quarter of 2004.

The $1,030 million income tax expense in continuing operations is included in the Statutory Rate Reconciliation as follows: a $991 million expense is included in “Deferred taxes on restructuring of certain subsidiaries” and a $39 million expense is included in “State income tax, net of federal income tax effect”.

Net Deferred Income Tax Liability Components

	December 31,
	2005			2004
	(in millions)
Deferred credits and other liabilities	$	589		$	593
Total deferred income tax assets		589			593
Valuation allowance		(26	)		(38	)
Net deferred income tax assets		563			555
Investments and other assets		(865	)		(607	)
Accelerated depreciation rates		(1,386	)		(2,307	)
Regulatory assets and deferred debits		(1,097	)		(997	)
Total deferred income tax liabilities		(3,348	)		(3,911	)
Total net deferred income tax liabilities	$	(2,785	)	$	(3,356	)

F-44

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

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

Deferred Tax Liabilities

	December 31,
	2005			2004
	(in millions)
Current deferred tax assets, included in other current assets	$	168		$	202
Non-current deferred tax assets, included in other investments and other assets		254			159
Current deferred tax liabilities, included in other current liabilities		(40	)		(3	)
Non-current deferred tax liabilities		(3,167	)		(3,714	)
Total net deferred income tax liabilities	$	(2,785	)	$	(3,356	)

Although the outcome of tax audits is uncertain, management believes that adequate provisions for income and other taxes have been made for potential liabilities resulting from such matters. As of the year ended December 31, 2005, Duke Capital has total provisions, including interest, of approximately $115 million for uncertain tax positions, as compared to $125 million as of December 31, 2004. Management is not aware of any issues for open tax years that upon final resolution are expected to have a material adverse effect on Duke Capital’s consolidated results of operations, cash flows or financial position.

Valuation allowances have been established for certain foreign and state net operating loss carryforwards that reduce deferred tax assets to an amount that will, more likely than not, be realized. The net change in the total valuation allowance is included in “Tax differential on foreign earnings” and “State income tax, net of federal income tax effect” lines of the Statutory Rate Reconciliation.

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

Under the guidance in FSP No. FAS 109-1, which was issued in December 2004, the deduction will be treated as a “special deduction” as described in SFAS No. 109. As such, for Duke Capital, the special deduction had no material impact on deferred tax assets and liabilities existing at the enactment date. Rather, the impact of this special deduction will be reported in the periods in which the deductions are claimed on the tax returns. For the year ended December 31, 2005, Duke Capital recognized a benefit of approximately $3 million relating to the deduction from qualified domestic activities.

In addition to the qualified domestic production activities deduction discussed above, the Act creates a temporary incentive for U.S. corporations to repatriate accumulated income earned abroad by providing an 85 percent dividends received deduction for certain dividends from controlled foreign corporations. FSP No. FAS 109-2, which was issued in December 2004, states that a company is allowed time beyond the financial reporting period of enactment to evaluate the effect of the Act on its plan for reinvestment or repatriation of foreign earnings, as it applies to the application of SFAS No. 109. During 2004, Duke Energy recorded a $45 million income tax expense for the repatriation of approximately $500 million of foreign earnings that was anticipated to occur during 2005 related to the American Jobs Creation Act. Included in the $45 million is $5 million of foreign income tax expense recorded at Duke Capital. During this repatriation process, Duke Energy reorganized various entities and reestimated its liability which enabled it to reduce the $45 million tax liability to a $39 million tax liability. This reorganization also caused Duke Capital to increase the $5 million tax liability to a $39 million tax liability. Duke Capital had paid off this $39 million tax liability to the respective jurisdictions as of December 31, 2005.

F-45

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

Deferred income taxes and foreign withholding taxes have not been provided on the remaining undistributed earnings of Duke Capital’s foreign subsidiaries as such amounts are deemed to be permanently reinvested. The cumulative undistributed earnings as of December 31, 2005 on which Duke Capital has not provided deferred income taxes and foreign withholding taxes, is approximately $290 million.

6. Asset Retirement Obligations

In June 2001, the FASB issued SFAS No. 143 which 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. Asset retirement obligations at Duke Capital relate primarily to the retirement of certain gathering pipelines and processing facilities, the retirement of some gas-fired power plants, obligations related to right-of-way agreements and contractual leases for land use. SFAS No. 143 was effective for fiscal years beginning after June 15, 2002, and was adopted by Duke Capital on January 1, 2003.

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.

In accordance with SFAS No. 143, Duke Capital identified certain assets that have an indeterminate life, and thus the fair value of the retirement obligation is not reasonably estimable. These assets included on-shore and some off-shore pipelines, certain processing plants and distribution facilities and some gas-fired power plants. A liability for these asset retirement obligations will be recorded when a fair value is determinable.

Upon adoption of SFAS No. 143, Duke Capital’s regulated natural gas operations classified removal costs for property that does not have an associated legal retirement obligation as a regulatory liability, in accordance with regulatory treatment. The total amount of removal costs included in Other Deferred Credits and Other Liabilities on the Consolidated Balance Sheets was $350 million and $317 million as of December 31, 2005 and 2004, respectively. As discussed further in Note 1, Duke Capital recorded a prior period reclassification adjustment of approximately $300 million related to removal costs for property within the natural gas operations. The impact of this adjustment on the accompanying Consolidated Balance Sheets as of December 31, 2004 was a decrease in accumulated depreciation and a corresponding increase in regulatory liabilities, which are included in Other within Deferred Credits and Other Liabilities on the accompanying Consolidated Balance Sheets.

The adoption of SFAS No. 143 resulted in a net-of-tax cumulative effect of a change in accounting principle adjustment of $10 million being recorded in the first quarter of 2003 as a reduction in earnings.

In March 2005, the FASB issued FIN 47. As a result of the adoption of FIN 47 in 2005, net property, plant and equipment increased $7 million and ARO liabilities increased $11 million. In addition, a net-of-tax cumulative effect adjustment of approximately $4 million was recorded in the fourth quarter of 2005 as a reduction in earnings (see Note 1).

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

F-46

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

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.

Reconciliation of Asset Retirement Obligation Liability

	Years Ended December 31,
	2005			2004
	(in millions)
Balance as of January 1,	$	62		$	76
Liabilities incurred due to new acquisitions		—			8
Liabilities settled(a)		(46	)		(2	)
Accretion expense		1			5
Revisions in estimated cash flows		1			(27	)
Adoption of FIN 47		11			—
Foreign currency adjustment		—			2
Balance as of December 31,	$	29		$	62

(a) Primarily represents a decrease in ARO liabilities during 2005 due to the deconsolidation of DEFS on July 1, 2005.

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

Duke Capital is exposed to the impact of market fluctuations in the prices of natural gas, electricity and other energy-related products marketed and purchased as a result of its ownership of energy related assets, interests in structured contracts and remaining proprietary trading activities. Exposure to interest rate risk exists as a result of the issuance of variable and fixed rate debt and commercial paper. Duke Capital is exposed to foreign currency risk from investments in international affiliate businesses owned and operated in foreign countries and from certain commodity-related transactions within domestic operations. Duke Capital employs established policies and procedures to manage its risks associated with these market fluctuations using various commodity and financial derivative instruments, including forward contracts, futures, swaps, options and swaptions.

Duke Capital’s Derivative Portfolio Carrying Value as of December 31, 2005

Asset/(Liability)	Maturity in 2006			Maturity in 2007		Maturity in 2008		Maturity in 2009 and Thereafter		Total Carrying Value
	(in millions)
Hedging	$	(23	)	$	—	$	—	$	21	$	(2	)
Trading		—			2		1		2		5
Undesignated		(93	)		16		9		16		(52	)
Total	$	(116	)	$	18	$	10	$	39	$	(49	)

The amounts in the table above represent the combination of amounts presented as assets and (liabilities) for unrealized gains and losses on mark-to-market and hedging transactions on Duke Capital’s Consolidated Balance Sheets, excluding approximately $3.3 billion of derivative assets and $3.5 billion of derivative liabilities which were transferred to assets and liabilities held for sale, as a result of the plan to exit DENA’s operations outside of the Midwestern United States (see Note 12).

F-47

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

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 DENA’s remaining assets and contracts outside the Midwestern United States, approximately 6,100 megawatts of power generation, and certain contractual positions related to the Midwestern assets (see Note 12). As a result, DENA recognized a pre-tax loss of approximately $1.9 billion in the third quarter of 2005 for the disqualification of its power and gas forward sales contracts previously designated under the normal purchases normal sales exception. This loss is partially offset by the recognition of a pre-tax gain of approximately $1.2 billion for the discontinuance of hedge accounting for natural gas and power cash flow hedges. As of December 31, 2005, there are approximately $20 million of pre-tax deferred net losses in AOCI related to DENA cash flow hedges, which will be recognized within the next twelve months.

In April 2006, Duke Capital indirectly transferred the Midwestern generation assets of DENA, representing approximately 3,600 megawatts of power generation to Cinergy. As a result, the results of operations for DENA’s Midwestern assets have been reflected as discontinued operations in the accompanying Consolidated Statements of Operations.

As a result of the transfer of 19.7% interest in DEFS to ConocoPhillips and the third quarter 2005 deconsolidation of its investment in DEFS (see Note 2), Duke Capital discontinued hedge accounting for certain contracts held by Duke Capital 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. As a result, approximately $314 million of realized and unrealized pre-tax losses related to these contracts were recognized in earnings by Duke Capital as of December 31, 2005. These charges have been classified in the accompanying Consolidated Statements of Operations for the year ended December 31, 2005 as follows: upon the discontinuance of hedge accounting approximately $120 million of pre-tax losses were recognized as a component of Impairments and Other Charges while approximately $130 million of losses recognized subsequent to the discontinuance of hedge accounting prior to the deconsolidation of DEFS were recognized as a component of Non-Regulated Electric, Natural Gas, Natural Gas Liquids, and Other Revenues and $64 million of losses recognized subsequent to discontinuance of hedge accounting after the deconsolidation of DEFS were recognized as a component of Other Income and Expenses. Cash settlements on these contracts since the deconsolidation of DEFS on July 1, 2005 of approximately $160 million are classified as a component of net cash provided by investing activities in the accompanying Consolidated Statements of Cash Flows.

Commodity Cash Flow Hedges. Some Duke Capital subsidiaries are exposed to market fluctuations in the prices of various commodities related to their ongoing power generating and natural gas gathering, distribution, processing and marketing activities. Duke Capital closely monitors the potential impacts of commodity price changes and, where appropriate, enters into contracts to protect margins for a portion of future sales and generation revenues and fuel expenses. Duke Capital uses commodity instruments, such as swaps, futures, forwards and options, as cash flow hedges for natural gas, electricity and natural gas liquid transactions. Duke Capital is hedging exposures to the price variability of these commodities for a maximum of 1 year.

The ineffective portion of commodity cash flow hedges resulted in pre-tax losses of $12 million in 2005, a pre-tax gain of $3 million in 2004, and a pre-tax gain of $6 million in 2003 and are reported primarily in Loss From Discontinued Operations, net of tax in the Consolidated Statements of Operations. The amount recognized for transactions that no longer qualified as cash flow hedges was a gain of approximately $1.2 billion in 2005 and is reported in Loss From Discontinued Operations, net of tax, in the Consolidated Statements of Operations, not

F-48

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

material in 2004, and was a gain of $285 million in 2003, pre-tax. Additionally, as a result of the DENA exit plan discussed in Note 12, during 2005 approximately $200 million of pre-tax deferred gains in AOCI have been recognized in earnings, as a component of Loss From Discontinued Operations, net of tax. The 2003 disqualified cash flow hedges were primarily associated with gas hedges related to DENA’s Southeast Plants and partially completed plants.

As of December 31, 2005, $40 million of the pre-tax deferred net losses on derivative instruments related to commodity cash flow hedges that were accumulated on the Consolidated Balance Sheets in a separate component of member’s equity, in AOCI, and are expected to be recognized in earnings during the next twelve months as the hedged transactions occur. This amount includes approximately $10 million pre-tax deferred net losses related to the DENA exit plan discussed in Note 12. However, due to the volatility of the commodities markets, the corresponding value in AOCI will likely change prior to its reclassification into earnings.

Commodity Fair Value Hedges. Some Duke Capital subsidiaries are exposed to changes in the fair value of some unrecognized firm commitments to sell generated power or natural gas due to market fluctuations in the underlying commodity prices. Duke Capital actively evaluates changes in the fair value of such unrecognized firm commitments due to commodity price changes and, where appropriate, uses various instruments to hedge its market risk. These commodity instruments, such as swaps, futures and forwards, serve as fair value hedges for the firm commitments associated with generated power. The ineffective portion of commodity fair value hedges resulted in a pre-tax loss of $4 million in 2005 and was not material in 2004 or 2003, and is reported primarily in Loss From Discontinued Operations, net of tax on the Consolidated Statements of Operations.

Normal Purchases and Normal Sales Exception. Duke Capital has applied the normal purchases and normal sales scope exception, as provided in SFAS No. 133 and interpreted by DIG Issue C15, to certain contracts involving the purchase and sale of electricity at fixed prices in future periods. These contracts, which relate primarily to the delivery of electricity over the next 9 years, are not included in the table above. As discussed above, during 2005, Duke Capital recognized a pre-tax loss of approximately $1.9 billion for the disqualification of its power and gas forward sales contracts. As discussed in the following paragraph, a portion of the charge in DENA in 2003 related to contracts that were being accounted for as normal purchases and sales.

Certain forward power contracts related to DENA’s Southeast Plants and the deferred plants had been primarily designated as normal purchases and sales in accordance with SFAS No. 133. In addition, certain forward gas contracts related to the long-lived assets had been designated as cash flow hedges in accordance with SFAS No. 133. As a result of the change in management intent for the long-lived assets, the related forward power and gas contracts were de-designated as normal purchases and sales and hedges. As a result, a net pre-tax charge of $262 million was recorded in 2003, of which a pre-tax charge of $452 million was recognized in Loss From Discontinued Operations, net of tax. (See Note 12). The amount recognized for transactions that no longer qualified as hedged firm commitments was not material in 2004.

Interest Rate (Fair Value or Cash Flow) Hedges. Changes in interest rates expose Duke Capital to risk as a result of its issuance of variable-rate debt and commercial paper. Duke Capital manages its interest rate exposure by limiting its variable-rate and fixed-rate exposures to percentages of total capitalization and by monitoring the effects of market changes in interest rates. Duke Capital 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 Capital’s existing interest rate derivative instruments and related ineffectiveness were not material to its consolidated results of operations, cash flows or financial position in 2005, 2004, and 2003.

F-49

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

Foreign Currency (Fair Value, Net Investment or Cash Flow) Hedges. Duke Capital is exposed to foreign currency risk from investments in international affiliate businesses owned and operated in foreign countries and from certain commodity-related transactions within domestic operations. To mitigate risks associated with foreign currency fluctuations, contracts may be denominated in or indexed to the U.S. dollar and/or local inflation rates, or investments may be hedged through debt denominated or issued in the foreign currency. Duke Capital may also use foreign currency derivatives, where possible, to manage its risk related to foreign currency fluctuations. A net gain of $1 million, net losses of $43 million and $113 million were included in the cumulative translation adjustment for hedges of net investments in foreign operations, during 2005, 2004, and 2003, respectively. To monitor its currency exchange rate risks, Duke Capital uses sensitivity analysis, which measures the impact of devaluation of foreign currencies.

During the first quarter of 2005, Duke Capital settled certain hedges which were documented and designated as net investment hedges of the investment in Westcoast Energy, Inc. (Westcoast) on their scheduled maturity and paid approximately $162 million. These settlements are classified as a component of net cash provided by investing activities in the accompanying Consolidated Statements of Cash Flows. Losses recognized on this net investment hedge have been classified in AOCI as a component of foreign currency adjustments and will not be recognized in earnings unless the complete or substantially complete liquidation of Duke Capital’s investment in Westcoast occurs.

Other Derivative Contracts. Trading. Duke Capital is exposed to the impact of market fluctuations in the prices of natural gas, electricity and other energy-related products marketed and purchased as a result of proprietary trading activities. During 2003, Duke Capital prospectively discontinued proprietary trading and therefore the fair value of trading contracts as of December 31, 2005 relates to contracts entered into prior to the announced discontinuation of proprietary trading activities. Duke Capital’s exposure to commodity price risk is influenced by a number of factors, including contract size, length, market liquidity, location and unique or specific contract terms.

Undesignated. In addition, Duke Capital uses derivative contracts to manage the market risk exposures that arise from energy supply, structured origination, marketing, risk management, and commercial optimization services to large energy customers, energy aggregators and other wholesale companies, and to manage interest rate and foreign currency exposures. This category includes changes in fair value for derivatives that no longer qualify for the normal purchase and normal sales scope exception and disqualified hedge contracts, unless the derivative contract is subsequently re-designated as a hedge. The contracts in this category are primarily associated with forward power sales and gas purchases for the DENA exit activity announced in 2005 (see Note 12), hedges related to the DENA Southeast Plants, hedges related to the partially completed plants which were disqualified in 2003 and certain contracts held by Duke Capital related to Field Services commodity price risk.

In connection with the Barclays Bank PLC (Barclays) transaction discussed in Note 13, Duke Capital entered into a series of Total Return Swaps (TRS) with Barclays, which are accounted for as mark-to-market derivatives. The TRS offsets the net fair value of the contracts being sold to Barclays. The fair value of the TRS as of December 31, 2005 is an asset of approximately $553 million, which offsets the net fair value of the underlying contracts, which is a liability of approximately $553 million. The TRS will be cancelled as the underlying contracts are transferred to Barclays.

Credit Risk. Duke Capital’s principal customers for power and natural gas marketing and transportation services are industrial end-users, marketers, local distribution companies and utilities located throughout the U.S., Canada and Latin America. Duke Capital has concentrations of receivables from natural gas and electric utilities and their affiliates, as well as industrial customers and marketers throughout these regions. These

F-50

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

concentrations of customers may affect Duke Capital’s overall credit risk in that risk factors can negatively impact the credit quality of the entire sector. Where exposed to credit risk, Duke Capital 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 Capital’s industry has historically operated under negotiated credit lines for physical delivery contracts. Duke Capital frequently uses master collateral agreements to mitigate certain credit exposures, primarily in its trading and 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.

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 covers trading, normal purchases and normal sales, and hedging contracts outstanding. Duke Capital 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 Capital and its counterparties’ publicly disclosed credit ratings impact the amounts of additional collateral to be posted. Likewise, downgrades in credit ratings of counterparties could require counterparties to post additional collateral to Duke Capital and its affiliates.

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

Duke Capital 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.

Included in Other Current Assets in the Consolidated Balance Sheets as of December 31, 2005 and December 31, 2004 are collateral assets of approximately $1,279 million and $301 million, respectively, which represents cash collateral posted by Duke Capital with other third parties. This increase in cash collateral posted by Duke Capital is primarily due to changes in commodity prices. Included in Other Current Liabilities in the Consolidated Balance Sheets as of December 31, 2005 and December 31, 2004 are collateral liabilities of approximately $608 million and $430 million, respectively, which represents cash collateral posted by other third parties to Duke Capital. Subsequent to December 31, 2005, in connection with the sale to Barclays of contracts related to DENA’s energy marketing and management activities, Barclays provided DENA cash equal to the net cash collateral posted by DENA under the contracts. Net cash collateral received by Duke Capital from Barclays in January 2006 was approximately $540 million based on current market prices of the contracts (see Note 12).

Financial Instruments. The fair value of financial instruments, excluding derivatives included in Notes 7 and 12, is summarized in the following table. Judgment is required in interpreting market data to develop the estimates of fair value. Accordingly, the estimates determined as of December 31, 2005 and 2004, are not necessarily indicative of the amounts Duke Capital could have realized in current markets.

F-51

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

Financial Instruments

	Years Ended December 31,
	2005				2004
	Book Value		Approximate Fair Value		Book Value		Approximate Fair Value
	(in millions)
Long-term debt(a)	$	10,184	$	11,072	$	12,612	$	14,016
Long-term SFAS 115 securities		231		231		185		185

(a) Includes current maturities.

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

8. Marketable Securities

Short-term investments. At December 31, 2005 and 2004 Duke Capital had $521 million and $1,134 million, respectively, of short-term investments consisting primarily of highly liquid tax-exempt debt securities. These instruments are classified as available-for-sale securities under SFAS No. 115 as management does not intend to hold them to maturity nor are they bought and sold with the objective of generating profits on short-term differences in price. The carrying value of these instruments approximates their fair value as they contain floating rates of interest. During 2005, Duke Capital purchased approximately $30,115 million and received proceeds on sale of approximately $29,892 million of short-term investments. During 2004, Duke Capital purchased approximately $54,295 million and received proceeds on sale of approximately $53,768 million of short-term investments. During 2003, Duke Capital purchased approximately $24,097 million and received proceeds on sale of approximately $23,981 million of short-term investments. The weighted-average maturity of these debt securities is less than 1 year.

Other Long-term investments. Duke Capital also invests in debt and equity securities that are principally held in the captive insurance investment portfolio that are classified as available-for-sale under SFAS No. 115 and therefore are carried at estimated fair value based on quoted market prices. These investments are classified as long-term as management does not intend to use them in current operations. Duke Capital’s captive insurance investment portfolio ($203 million at December 31, 2005) consists of approximately 87% debt securities and 13% equity securities with a weighted-average maturity of the debt securities of approximately 17 years. The cost of securities sold is determined using the specific identification method. During 2005, Duke Capital purchased approximately $1,559 million and received proceeds on sales of approximately $1,570 million on other long-term investments. During 2004, Duke Capital purchased approximately $715 million and received proceeds on sales of approximately $769 million on other long-term investments. During 2003, Duke Capital purchased approximately $1,124 million and received proceeds on sales of approximately $1,003 million on other long-term investments.

F-52

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

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

	As of December 31,
	2005						2004
	Gross Unrealized Holding Gains		Gross Unrealized Holding Losses		Estimated Fair Value		Gross Unrealized Holding Gains		Gross Unrealized Holding Losses		Estimated Fair Value
Short-term Investments	$	—	$	—	$	521	$	—	$	—	$	1,134
Total short-term investments	$	—	$	—	$	521	$	—	$	—	$	1,134
Equity Securities	$	31	$	—	$	54	$	3	$	—	$	30
Corporate Debt Securities		—		1		51		1		—		35
U.S. Government Bonds		—		—		17		—		—		56
Other		—		1		109		1		—		64
Total long-term investments	$	31	$	2	$	231	$	5	$	—	$	185

For the years ended December 31, 2005, 2004, and 2003 gains of approximately $3 million, $3 million and $4 million, respectively, were reclassified out of AOCI into earnings.

9. Goodwill

Duke Capital evaluates the impairment of goodwill under the guidance of SFAS No. 142. As a result of the annual impairment tests required by SFAS No. 142, no charge for the impairment of goodwill was recorded in 2005 or 2004.

In 2003, Duke Capital recorded a goodwill impairment charge of $254 million to write off goodwill, most of which related to DENA’s trading and marketing business. This impairment charge reflected the reduction in scope and scale of DETM’s business and the continued deterioration of market conditions affecting DENA during 2003. Duke Capital used a discounted cash flow analysis to determine fair value. Key assumptions in the analysis included the use of an appropriate discount rate, estimated future cash flows and an estimated run rate of general and administrative costs. In estimating cash flows, Duke Capital incorporated current market information, historical factors and fundamental analysis, and other factors into its forecasted commodity prices. This charge is recorded in the Consolidated Statements of Operations as Impairment of Goodwill.

Changes in the Carrying Amount of Goodwill

	Balance December 31, 2004		Impairments		Dispositions		Other(a)(b)			Balance December 31, 2005
	(in millions)
Natural Gas Transmission	$	3,416	$	—	$	—	$	96		$	3,512
Field Services		480		—		—		(480	)		—
International Energy		245		—		—		11			256
Crescent		7		—		—		—			7
Total consolidated	$	4,148	$	—	$	—	$	(373	)	$	3,775

F-53

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

	Balance December 31, 2003		Impairments		Dispositions		Other(b)		Balance December 31, 2004
	(in millions)
Natural Gas Transmission	$	3,241	$	—	$	—	$	175	$	3,416
Field Services		476		—		—		4		480
International Energy		238		—		—		7		245
Crescent		7		—		—		—		7
Total consolidated	$	3,962	$	—	$	—	$	186	$	4,148

(a) As a result of the deconsolidation of DEFS in July 2005 goodwill decreased by a net amount of $462 million, which includes the effects of an $18 million transfer of goodwill between Field Services and Natural Gas Transmission as a result of the transfer of Canadian assets in connection with the DEFS disposition transaction. (see Note 2).

(b) Except as noted in (a), other amounts consist primarily of foreign currency translation.

10. Investments in Unconsolidated Affiliates and Related Party Transactions

Investments in domestic and international affiliates that are not controlled by Duke Capital, but over which it has significant influence, are accounted for using the equity method. Duke Capital received distributions of $856 million in 2005 from those investments. Of these distributions, $473 million are included in Other, assets within Cash Flows from Operating Activities on the accompanying Consolidated Statements of Cash Flows and $383 million are included in Distributions from Equity Investments within Cash Flows from Investing Activities on the accompanying Consolidated Statements of Cash Flows. Duke Capital received distributions of $139 million in 2004 and $263 million in 2003 from those investments. These amounts are included in Other, assets within Cash Flows from Operating Activities on the accompanying Consolidated Statements of Cash Flows. Duke Capital’s share of net earnings from these unconsolidated affiliates is reflected in the Consolidated Statements of Operations as Equity in Earnings of Unconsolidated Affiliates. (See Note 2 for 2005 dispositions.)

As of December 31, 2005, the carrying amount of investments in affiliates approximated the amount of underlying equity in net assets. As of December 31, 2004, investments in affiliates were carried at approximately $91 million less than the amount of underlying equity in net assets (7% as of December 31, 2004). This amount is related to the difference in the carrying amount and the underlying net assets of investments owned by Field Services. Such difference has been fully allocated to the respective investee’s long-lived assets and the amounts are being amortized into income over the life of the underlying related long-lived assets. In July 2005, as a result of the DEFS disposition transactions (see below), Duke Capital deconsolidated the investments owned by Field Services.

Natural Gas Transmission. As of December 31, 2005, investments primarily included a 50% interest in Gulfstream Natural Gas System, LLC (Gulfstream). Gulfstream is an interstate natural gas pipeline that extends from Mississippi and Alabama across the Gulf of Mexico to Florida. Although Duke Capital owns a significant portion of Gulfstream, it is not consolidated as Duke Capital does not hold a majority of voting control or have the ability to exercise control over Gulfstream.

Field Services. In July 2005, Duke Energy caused a Duke Capital subsidiary to complete the transfer of a 19.7% interest in DEFS to ConocoPhillips, Duke Capital’s co-equity owner in DEFS, which reduced Duke Capital’s ownership interest in DEFS from 69.7% to 50% (the DEFS disposition transactions) and resulted in

F-54

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

Duke Capital and ConocoPhillips becoming equal 50% owners in DEFS. As a result of the DEFS disposition transaction, Duke Capital deconsolidated its investment in DEFS and subsequently has accounted for as an investment utilizing the equity method of accounting (see Note 2). Additionally, in February 2005, DEFS sold its wholly owned subsidiary TEPPCO GP, which is the general partner of TEPPCO LP, for approximately $1.1 billion and Duke Capital 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.

International Energy. As of December 31, 2005, investments primarily included a 25% indirect interest in National Methanol Company, which owns and operates a methanol and MTBE business in Jubail, Saudi Arabia. International Energy also has a 50% ownership in Compañia de Servicios de Compresión de Campeche, S.A. de C.V. (Campeche), a natural gas compression facility in the Cantarell oil field in the Gulf of Mexico, and a 38% ownership in Aguaytia, a natural gas facility in Peru.

Campeche project revenues are generated from the gas compression services agreement (GCSA) with the Mexican national oil company (PEMEX). The current five year GCSA expires on November 7, 2006 and PEMEX has the option to renew the GCSA for an additional four years. See Note 11 for a discussion of the impairment recognized on the Campeche investment.

Crescent. As of December 31, 2005, investments included various real estate development projects.

Other. As of December 31, 2005 investments primarily included:

• a 50% interest in Southwest Power Partners, LLC. Southwest Power Partners, LLC is a gas-fired combined-cycle facility (Griffith Energy) in Arizona that serves markets in Arizona, Nevada and California. Although Duke Capital owns a significant portion of this investment, it is not consolidated as it does not hold a majority of voting control or have the ability to exercise control over this investment. Southwest Power Partners, LLC is included in DENA’s Western United States generation assets that qualify for discontinued operations classification for current and prior periods (see Note 12). As a result, the investment is classified as Assets Held for Sale in the accompanying Consolidated Balance Sheets as of December 31, 2005 and earnings and losses from this investment are classified as Discontinued Operations, net of tax in the accompanying Consolidated Statements of Operations.

• participation in various construction and support activities for fossil-fueled generating plants through D/FD.

Investments in Unconsolidated Affiliates

	As of:
	December 31, 2005						December 31, 2004
	Domestic		International		Total		Domestic		International		Total
	(in millions)
Natural Gas Transmission	$	428	$	20	$	448	$	769	$	21	$	790
Field Services(a)		1,290		—		1,290		157		—		157
International Energy		—		155		155		—		167		167
Crescent		17		—		17		20		—		20
Other		14		7		21		151		7		158
Total	$	1,749	$	182	$	1,931	$	1,097	$	195	$	1,292

(a) Includes Duke Capital’s 50 percent interest in DEFS subsequent to deconsolidation of DEFS on July 1, 2005.

F-55

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

Equity in Earnings of Unconsolidated Affiliates

	For the Years Ended:
	December 31, 2005								December 31, 2004						December 31, 2003
	Domestic			International		Total			Domestic		International		Total		Domestic		International			Total
	(in millions)
Natural Gas Transmission	$	42		$	5	$	47		$	26	$	4	$	30	$	19	$	13		$	32
Field Services(a)		308			—		308			60		—		60		56		—			56
International Energy		—			114		114			—		51		51		—		27			27
Crescent		(1	)		—		(1	)		3		—		3		—		—			—
Other(b)		11			—		11			9		1		10		13		(5	)		8
Total	$	360		$	119	$	479		$	98	$	56	$	154	$	88	$	35		$	123

(a) Includes Duke Capital’s 50 percent equity in earnings of DEFS subsequent to deconsolidation on July 1, 2005.

(b) Includes equity investments at the corporate level.

Summarized Combined Financial Information of Unconsolidated Affiliates

	As of December 31,
	2005			2004
	(in millions)
Balance Sheet
Current assets	$	3,395		$	1,413
Non-current assets		7,744			6,028
Current liabilities		(3,392	)		(1,118	)
Non-current liabilities		(3,237	)		(2,078	)
Net assets	$	4,510		$	4,245

	For the Years Ended December 31,
	2005		2004		2003
	(in millions)
Income Statement
Operating revenues	$	8,799	$	7,326	$	6,253
Operating expenses		7,650		6,872		5,526
Net income		1,076		415		550

Related Party Transactions.

Balances due to or due from Duke Energy included in the Consolidated Balance Sheets as of December 31, 2005 and 2004 are as follows:

Assets/(Liabilities)	2005			2004
	(in millions)
Advances receivable(b)	$	—		$	33
Taxes receivable(a)		187			13
Other current liabilities(d)		(2	)		—
Other non-current liabilities(c)		(30	)		—

F-56

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

(a) The balances are classified as Other Current Assets on the Consolidated Balance Sheets.

(b) Advances receivable are included in Other within Investments and Other Assets on the Consolidated Balance Sheets. The advances do not bear interest, are carried as open accounts and are not segregated between current and non-current amounts.

(c) The balance is classified as Other Deferred Credits and Other Liabilities on the Consolidated Balance Sheets.

(d) The balance is classified as Other Current Liabilities on the Consolidated Balance Sheets.

During the year ended December 31, 2005, Duke Capital distributed $2.1 billion to its parent, Duke Energy, to principally provide funding for the execution of Duke Energy’s accelerated share repurchase transaction and to provide funding support for Duke Energy’s dividend. The distribution was principally obtained from Duke Capital’s portion of the cash proceeds realized from the recent sale by DEFS of TEPPCO GP and Duke Capital’s sale of its limited partner interest in TEPPCO LP.

During 2004, $267 million of cash advances were received by Duke Capital from Duke Energy. During the first quarter of 2005, Duke Energy forgave these advances of $267 million and Duke Capital classified the $267 million as an addition to Member’s Equity. Additionally, during the third quarter of 2005, Duke Energy forgave additional advances of $494 million and Duke Capital classified the $494 million as an addition to Member’s Equity. These forgivenesses are presented as a non-cash financing activity in the Consolidated Statements of Cash Flows for the year ended December 31, 2005.

During 2005, Duke Capital received capital contributions of $269 million from Duke Energy, which Duke Capital classified as an addition to Member’s Equity. Additionally, during 2005, Duke Capital advanced $242 million to Duke Energy. These transactions are presented as a component of net cash used in financing activities in the accompanying Consolidated Statements of Cash Flows for the year ended December 31, 2005.

During the first half of 2004, Duke Capital received $160 million from Duke Energy as payment related to certain tax losses that were anticipated to be realized at Duke Capital during 2004. This $160 million is reflected in the 2004 Consolidated Statement of Cash Flows as changes from Taxes Accrued in net cash provided by operating activities. However, in connection with Duke Energy’s realignment of certain subsidiaries as of July 2, 2004, as discussed in Note 5, the related tax attributes were transferred to Duke Energy and therefore not realized at Duke Capital. Accordingly, the $160 million is presented in the December 31, 2004, Consolidated Balance Sheet as a component of the net advances receivable in Investments and Other Assets. Subsequent to the July 2, 2004 realignment of the subsidiaries, Duke Capital received an additional $107 million in advances from Duke Energy, which is reflected as a component of net cash used in financing activities in the 2004 Consolidated Statement of Cash Flows. Subsequent to December 31, 2004, Duke Energy forgave these advances of $267 million (see above).

For the years ended December 31, 2005, 2004 and 2003, Duke Capital recorded income in the amount of $68 million, $155 million and $134 million, respectively, related to management fees charged to Duke Power Company (Duke Power), an unconsolidated affiliate of Duke Capital. These amounts are recorded in Other income and expenses, net on the Consolidated Statements of Operations. Previously, these amounts were recorded as Operating Revenue on the Consolidated Statements of Operations. Prior period amounts have been reclassified to conform to the 2005 presentation. Additionally, for the years ended December 31, 2005, 2004 and 2003, Duke Capital recognized recoveries of expenses in the amount of $466 million, $416 million and $451 million, respectively. These amounts represent recoveries of direct and allocated corporate governance and shared services costs charged to Duke Power and are reflected as an offset within Operation, maintenance, and other and Depreciation and amortization within Operating Expenses on the Consolidated Statements of Operations.

F-57

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

Included in the Consolidated Statements of Operations for the years ended December 31, 2005 and 2004 are net expenses of $26 million and $104 million, respectively, primarily consisting of settlements expensed to Duke Energy for crude, NGLs, and gas hedges as well as Trading and Marketing net margin. Operating revenues, including Trading and Marketing net margin and management fees, are $17 million for 2003 related to intercompany sales to Duke Energy.

NorthSouth Insurance Company Limited is a subsidiary of Bison which insures exposures of Duke Power. Included in Other Current Liabilities within the Consolidated Balance Sheets are unearned premiums of approximately $2 million as of December 31, 2005. No unearned premiums were recorded as of December 31, 2004. Included in Non-regulated Electric, Natural Gas, Natural Gas Liquids, and Other within the Consolidated Statements of Operations are earned premiums of approximately $26 million for 2005, $16 million for 2004 and $8 million for 2003.

Outstanding notes receivable from unconsolidated affiliates were $50 million as of December 31, 2005 and $89 million as of December 31, 2004. Amounts are included in Notes Receivable on the Consolidated Balance Sheets. The balance outstanding as of December 31, 2005 represents International Energy’s note receivable from the Campeche project, a 50% owned joint venture. The outstanding note receivable had an interest rate at current market rates.

International Energy loaned money to Campeche to assist in the costs to build. During 2005, International Energy received principal and interest payments of approximately $5 million from Campeche, a 50% owned DEI affiliate. Payments from Campeche in 2004 and 2003 were $7 million and $8 million, respectively.

Natural Gas Transmission has a 50% ownership in two pipeline companies, Gulfstream, an operating pipeline, and Islander East, LLC, a development stage pipeline as well as a 50% ownership in a power plant, McMahon Cogeneration Plant, a cogeneration natural gas fired facility transferred to Natural Gas Transmission from DENA during 2005. Natural Gas Transmission provides certain administrative and other services to the pipeline companies and the power plant. Natural Gas Transmission recorded recoveries of costs from these affiliates of $12 million, $8 million, and $12 million during 2005, 2004, and 2003, respectively. The outstanding receivable from these affiliates was $2 million and $1 million for 2005 and 2004, respectively.

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

Field Services sells a portion of its residue gas and NGLs to, purchases raw natural gas and other petroleum products from, and provides gathering and transportation services to unconsolidated affiliates (primarily TEPPCO GP, which was sold in February 2005). Total revenues from these affiliates were approximately $98 million for the six months ended June 30, 2005, and $278 million and $166 million for the years ended December 31, 2004 and 2003, respectively. Total purchases from these affiliates were approximately $77 million for the six months ended June 30, 2005, and $125 million and $98 million for the years ended December 31, 2004 and 2003, respectively. Total operating expenses were approximately $1 million for the six months ended June 30, 2005, and $4 million and $4 million for the years ended December 31, 2004 and 2003, respectively. Reductions in revenues and purchases in 2005 as compared to 2004 are principally due to the sale of TEPPCO GP and deconsolidation of DEFS, effective July 1, 2005.

F-58

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

In July 2005, DEFS was deconsolidated due to the transfer of a 19.7% interest to ConocoPhillips and has been subsequently accounted for as an equity investment (see Note 2). Duke Capital’s 50% of equity in earnings of DEFS for the period of July 1, 2005 to December 31, 2005 was $292 million and Duke Capital’s investment in DEFS as of December 31, 2005 was $1,286 million, which is included in Investments in Unconsolidated Affiliates in the accompanying Consolidated Balance Sheets. Between July 1, 2005 and December 31, 2005, Duke Capital had gas sales to, purchases from, and other operating revenues from affiliates of DEFS of approximately $67 million, $65 million and $12 million, respectively. As of December 31, 2005, Duke Capital had trade receivables from and trade payables to DEFS amounting to approximately $18 million and $47 million, respectively. Additionally, Duke Capital received approximately $360 million for its share of distributions paid by DEFS in 2005. Additionally, Duke Capital has recognized an approximate $90 million receivable as of December 31, 2005 due to its share of quarterly tax distributions declared by DEFS in 2005 to be paid in 2006. Of these distributions, $287 million was included in Other, assets within Cash Flows from Operating Activities and approximately $73 million was included in Distributions from Equity Investments within Cash Flows from Investing Activities, within the accompanying Consolidated Statements of Cash Flows. Summary financial information for DEFS, which has been accounted for under the equity method since July 1, 2005 is as follows:

	Six-months Ended December 31, 2005
	(in millions)
Operating revenues	$	7,463
Operating expenses	$	6,814
Operating income	$	649
Net income	$	584
	December 31, 2005
	(in millions)
Current assets	$	2,706
Non-current assets	$	5,005
Current liabilities	$	3,068
Non-current liabilities	$	2,038
Minority interest	$	95

As of December 31, 2005, there was an immaterial basis difference between Duke Capital’s carrying value of the investment in DEFS and the value of Duke Capital’s proportionate share of the underlying net assets in DEFS.

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

In 2005, DEFS formed DCP Midstream Partners, LP (a master limited partnership). DCP Midstream Partners, LP (DCPLP) completed an initial public offering (IPO) transaction in December that resulted in net proceeds of approximately $210 million. As a result, DEFS has a 42 percent ownership interest in DCPLP, consisting of a 40 percent limited partner ownership interest and a 2 percent general partner ownership interest. DEFS’ ownership interest in the general partner of DCPLP is 100 percent. The gain on the IPO transaction has been deferred by DEFS until DEFS converts its subordinated units in DCP to common units, which will occur no earlier than December 31, 2008.

F-59

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

D/FD is a 50/50 partnership between subsidiaries of Duke Capital and Fluor Corporation. During 2003, Duke Capital and Fluor Corporation announced that they would dissolve D/FD and have adopted a plan for an orderly wind-down D/FD’s business. The wind-down has been substantially completed as of December 31, 2005 and is expected to be finalized by December 2006. Previously, D/FD provided comprehensive engineering, procurement, construction, commissioning and operating plant services for fossil-fueled electric power generating facilities worldwide. D/FD was the primary builder of DENA’s merchant generation plants. D/FD has built some plants for Duke Power. Fifty percent of the profit earned by D/FD for the construction of affiliates’ generation plants, which is associated with Duke Capital’s ownership, is either deferred in consolidation until the plant is sold or, once the plant becomes operational, the deferred profit is amortized over the plant’s useful life or on an accelerated basis if the plants are impaired. Fifty percent of the profit earned by D/FD for operating and maintenance services for Duke Capital owned plants is eliminated in consolidation. For the year ended December 31, 2005, Duke Capital did not record deferred profit for D/FD construction contracts and did not eliminate any profit for operating and maintenance services. For the year ended December 31, 2004, Duke Capital deferred profit of $2 million for construction contracts and did not eliminate any profit for operating and maintenance services. In addition, as part of the D/FD partnership agreement, excess cash is loaned at current market rates to Duke Capital and Fluor Enterprises, Inc. (See Note 14.)

In the normal course of business, Duke Capital’s consolidated subsidiaries enter into energy trading contracts or other derivatives with one another. On a separate company basis, each subsidiary accounts for such contracts as if they were transacted with a third party and records the contracts using the MTM Model or the Accrual Model of Accounting, as applicable. In the consolidation process, the effects of these intercompany contracts are eliminated, and not reflected in Duke Capital’s Consolidated Financial Statements.

Also see Note 14, Note 16, and Note 17 for additional related party information.

11. Impairments, Severance, and Other Charges

	For the Years Ended December 31,
	2005		2004		2003
	(in millions)
Field Services	$	125	$	22	$	—
Commercial Power		—		—		1,106
Crescent		15		42		—
Other		—		—		110
Total Impairment and other charges	$	140	$	64	$	1,216

Field Services. See Note 7 for a discussion of the impacts of the DEFS disposition transaction on certain cash flow hedges.

In the third quarter of 2004, Field Services recorded impairments of approximately $22 million related to some of Field Services’ operating assets.

Additionally, in the third quarter of 2004, Field Services recorded an impairment of approximately $23 million related to equity method investments at Field Services. The impairment is included in Gains (Losses) on Sales and Impairments of Equity Method Investments on the Consolidated Statements of Operations. The impairment charge was related to management’s assessment of the recoverability of some equity method

F-60

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

investments. Field Services determined that these assets, which are located in the Gulf Coast, were impaired; therefore they were written down to fair value. Fair value was determined based on management’s best estimates of sales value and/or discounted future cash flow models.

International Energy. International Energy owns a 50% joint venture interest in Campeche. Campeche project revenues are generated from the GCSA with PEMEX. The current five year GCSA expires on November 7, 2006 and PEMEX has the option to renew the GCSA for an additional four years. As a result of ongoing discussions between Campeche and PEMEX to either sell the Campeche investment or renew the GCSA, 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. This impairment is classified as a component of Gains (Losses) on Sales and Impairments of Equity Method Investments in the accompanying Consolidated Statements of Operations. An additional impairment charge could be recognized if the ultimate outcome of the above discussions is materially different than management’s current expectations.

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 impairment was recognized as a component of Impairment and Other Charges in the accompanying Consolidated Statements of Operations. 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.

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

Commercial Power. In the fourth quarter of 2003, as a result of deteriorating market conditions in the merchant energy industry, Duke Capital decided to exit the merchant power generation business in the Southeastern U.S. The carrying value of the Southeast Plants exceeded the fair value, resulting in an impairment charge in 2003 of approximately $1.3 billion. The fair value of the Southeast Plants was estimated primarily based on third party comparable sales, analysis from outside advisors and information available from efforts to sell certain of these assets. These assets were subsequently sold in the second quarter of 2004 (see Note 2).

Certain forward power contracts related to the Southeast Plants had been primarily designated as normal purchases and sales in accordance with SFAS No. 133. In addition, certain forward gas contracts related to the long-lived assets had been designated as cash flow hedges in accordance with SFAS No. 133. As a result of the change in management intent for the long-lived assets, the related forward power and gas contracts were de-designated as normal purchases and sales and hedges. As a result, a benefit of $190 million was recorded as an offset to the impairment charge.

As a result of the decisions discussed above, Commercial Power recorded impairment charges in 2003 of approximately $1.1 billion, primarily related to electric generation plants which are classified as Property, Plant and Equipment on the Consolidated Balance Sheets and to mark the derivative contracts to market value and reclassify the hedge amounts previously included in AOCI in accordance with SFAS No. 133.

F-61

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

Other. DENA recorded an impairment charge of $60 million in 2003, primarily associated with a plan to sell an investment in Bayside, an unconsolidated affiliate. Fair value of these assets was estimated based primarily on discounted cash flow analysis. The 2003 charges were due primarily to the abandonment of a corporate risk management information system, primarily due to DENA exiting the proprietary trading business and the reduction of scope and scale of DETM’s business.

Severance. As discussed further in Note 12, during the third quarter of 2005, the Board of Directors of Duke Energy authorized and directed management to execute the sale or disposition of substantially all of DENA’s remaining assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets. As a result of this exit plan, during the year ended December 31, 2005, DENA recorded a severance accrual of approximately $22 million, under its ongoing severance plan, related to the anticipated involuntary termination of approximately 400 DENA employees by the end of the second quarter of 2006. This severance accrual is included in Other. Approximately $2 million of the related pre-tax expense is reflected in Operation, Maintenance and Other and approximately $20 million is reflected in Loss from Discontinued Operations, net of tax in the accompanying Consolidated Statements of Operations for the year ended December 31, 2005. Additionally, DENA is also offering certain enhanced severance benefits to employees expected to be involuntarily terminated in connection with the DENA disposition plan, which are being recognized over the remaining service period. Approximately $3 million of enhanced severance benefits were accrued during the fourth quarter of 2005. Management anticipates future severance costs incurred related to this exit plan will be approximately $20 million to $25 million. These amounts are reflected in Other in the table below.

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

Severance Reserve

	Balance at January 1, 2005		Provision/ Adjustments(d)		Noncash Adjustments			Cash Reductions			Balance at December 31, 2005
	(in millions)
Natural Gas Transmission	$	6	$	1	$	(1	)	$	(3	)	$	3
Field Services(c)		—		1		(1	)		—			—
International Energy		1		—		(1	)		—			—
Other(d)		4		26		—			(2	)		28
Total(a)	$	11	$	28	$	(3	)	$	(5	)	$	31
	Balance at January 1, 2004		Provision/ Adjustments		Noncash Adjustments			Cash Reductions			Balance at December 31, 2004
Natural Gas Transmission	$	29	$	1	$	(6	)	$	(18	)	$	6
Field Services(c)		6		1		—			(7	)		—
International Energy		6		—		(4	)		(1	)		1
Other(d)		49		3		(5	)		(43	)		4
Total(a)	$	90	$	5	$	(15	)	$	(69	)	$	11

F-62

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

	Balance at January 1, 2003		Provision/ Adjustments		Noncash Adjustments			Cash Reductions			Balance at December 31, 2003
Natural Gas Transmission	$	33	$	20	$	1		$	(25	)	$	29
Field Services(c)		—		6		—			—			6
International Energy		4		6		(4	)		—			6
Other(b)(d)		47		37		(2	)		(33	)		49
Total(a)(b)	$	84	$	69	$	(5	)	$	(58	)	$	90

(a) Substantially all expected severance costs will be applied to the reserves within one year.

(b) Provision in 2003 excludes $22 million of curtailment costs related to other post-retirement benefits.

(c) Includes minority interest.

(d) Severance expense included in Loss from Discontinued Operations, net of tax in the Consolidated Statements of Operations was $22 million, $1 million and $7 million for 2005, 2004 and 2003, respectively.

12. Discontinued Operations and Assets Held for Sale

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

Discontinued Operations

			Operating Income (Loss)									Net Gain (Loss) on Dispositions
	Operating Revenues		Pre-tax Operating Income (Loss)			Income Tax Expense (Benefit)			Operating Income (Loss), Net of Tax			Pre-tax Gain (Loss) on Dispositions			Income Tax Expense (Benefit)			Gain (Loss) on Dispositions, Net of Tax			Loss from Discontinued Operations, Net of Tax
	(in millions)
Year Ended December 31, 2005
Field Services	$	4	$	—		$	—		$	—		$	—		$	—		$	—		$	—
Commercial Power(b)		10		(58	)		16			(74	)		—			—			—			(74	)
International Energy		—		(3	)		1			(4	)		—			—			—			(4	)
Crescent		2		1			—			1			10			4			6			7
Other(a)		2,203		(652	)		(142	)		(510	)		(481	)		(60	)		(421	)		(931	)
Total consolidated	$	2,219	$	(712	)	$	(125	)	$	(587	)	$	(471	)	$	(56	)	$	(415	)	$	(1,002	)
Year Ended December 31, 2004
Field Services	$	79	$	3		$	1		$	2		$	(17	)	$	(6	)	$	(11	)	$	(9	)
Commercial Power(b)		65		(7	)		2			(9	)		—			—			—			(9	)
International Energy		85		(12	)		(1	)		(11	)		295			22			273			262
Crescent		2		—			—			—			9			4			5			5
Other(a)		2,190		(18	)		(150	)		132			1			—			1			133
Total consolidated	$	2,421	$	(34	)	$	(148	)	$	114		$	288		$	20		$	268		$	382
Year Ended December 31, 2003
Field Services	$	345	$	9		$	3		$	6		$	19		$	7		$	12		$	18
Commercial Power(b)		80		(46	)		(28	)		(18	)		—			—			—			(18	)
International Energy		740		(53	)		(4	)		(49	)		(242	)		(119	)		(123	)		(172	)
Crescent		5		—			—			—			18			7			11			11
Other(a)		4,146		(1,681	)		(604	)		(1,077	)		(28	)		(11	)		(17	)		(1,094	)
Total consolidated	$	5,316	$	(1,771	)	$	(633	)	$	(1,138	)	$	(233	)	$	(116	)	$	(117	)	$	(1,255	)

F-63

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

(a) Other includes the results for Duke Energy North America’s (DENA) discontinued operations outside of the Midwestern United States, which were previously reported in the DENA segment

(b) Commercial Power includes results of DENA’s discontinued operations in Midwestern United States, which were previously reported in Other

The following table presents the carrying values of the major classes of assets and associated liabilities held for sale in the accompanying Consolidated Balance Sheets as of December 31, 2005 and 2004.

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

	December 31, 2005		December 31, 2004
	(in millions)
Current assets	$	1,528	$	40
Investments and other assets		2,059		12
Property, plant and equipment, net		1,538		72
Total assets held for sale	$	5,125	$	124
Current liabilities	$	1,488	$	30
Long-term debt		61		14
Deferred credits and other liabilities		2,024		—
Total liabilities associated with assets held for sale	$	3,573	$	44

Field Services

In December 2004, based upon management’s assessment of the probable disposition of some plant and transportation assets in Wyoming, Field Services classified these assets as Assets Held for Sale in the Consolidated Balance Sheets as of December 31, 2004. The book value of those assets was written down by $4 million ($3 million net of minority interest) to $10 million in December 2004, which represents the estimated fair value less cost to sell. The after tax loss and results of operations related to these assets were included in Loss from Discontinued Operations, net of tax, in the accompanying Consolidated Statements of Operations. In February 2005, these assets were exchanged for certain gathering assets in Oklahoma of equivalent fair value.

In December 2004, Field Services sold gas system and treating plant assets in Southeast New Mexico and South Texas, respectively. Field Services sold these assets for proceeds of approximately $6 million, with the carrying value being approximately equal to the sales price. The after tax loss and related results of operations were included in Loss from Discontinued Operations, net of tax, in the accompanying Consolidated Statements of Operations.

In September 2004, Field Services recorded a pre-tax impairment charge of approximately $23 million ($16 million net of minority interest) related to management’s current assessment of some additional gathering, processing, compression and transportation assets in Wyoming being held for sale. The estimated fair value of these assets less cost to sell was $27 million and classified as Assets Held for Sale in the Consolidated Balance Sheets as of December 31, 2004. The after tax loss and results of operations were included in Loss from Discontinued Operations, net of tax, in the accompanying Consolidated Statements of Operations. In the first quarter of 2005, Field Services sold these assets for proceeds of $28 million, with the carrying value being approximately equal to the sales price.

F-64

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

In February 2004, Field Services sold gas gathering and processing plant assets in West Texas to a third party purchaser for a sales price of approximately $62 million, which approximated these assets’ carrying value. The after tax gain and results of operations related to these assets were included in Loss from Discontinued Operations, net of tax, in the accompanying Consolidated Statements of Operations.

In 2003, Field Services sold two packages of assets for a total sales price of $90 million. The after tax gain on these sales of $12 million and related operating results were included in Loss from Discontinued Operations, net of tax, in the accompanying Consolidated Statements of Operations. The assets sold consisted of various gas processing plants and gathering pipelines in Mississippi, Texas, Alabama, Louisiana and Oklahoma.

Commercial Power

In conjunction with Duke Energy’s merger with Cinergy, in April 2006, Duke Capital transferred its ownership interest in DENA’s Midwestern generation assets, consisting of 3,600 MW of power generation, and certain related contracts to CG&E, which will provide a sustainable business model for these assets (see also Note 1). Thus, the results of operations for DENA’s Midwestern assets have been reflected as discontinued operations in the accompanying Consolidated Statements of Operations.

During 2004, a 25% undivided interest in DENA’s Vermillion facility was sold for proceeds of approximately $44 million. This sale was anticipated in 2003 and therefore pre-tax losses of $18 million were recorded in Loss from Discontinued Operations, net of tax, in the 2003 Consolidated Statement of Operations. The remaining 75% interest in the Vermillion facility was transferred to CG&E in 2006.

International Energy

In order to eliminate exposure to international markets outside of Latin America and Canada, International Energy decided in 2003 to pursue a possible sale or IPO of International Energy’s Asia-Pacific power generation and natural gas transmission business (the Asia-Pacific Business). As a result of this decision, International Energy recorded an after tax loss of $233 million during the fourth quarter of 2003, which represented the excess of the carrying value over the estimated fair value of the business, less estimated costs to sell. Fair value of the business was estimated based primarily on comparable third party sales and analysis from outside advisors. This after tax loss was included in Loss from Discontinued Operations, net of tax, in the accompanying Consolidated Statements of Operations.

In the first quarter of 2004, International Energy determined it was likely that a bid in excess of the originally determined fair value would be accepted and thus recorded a $238 million after tax gain related to International Energy’s Asia-Pacific Business. The after tax gain was included in Loss from Discontinued Operations, net of tax, in the accompanying Consolidated Statements of Operations and restored the loss recorded during the fourth quarter of 2003.

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

F-65

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

In 2003, International Energy restructured and began exiting its operations in Europe. International Energy sold its Dutch gas marketing business for $84 million and sold a power generation plant in France for $79 million. An after tax net gain of $11 million on these sales was included in Loss from Discontinued Operations, net of tax, in the accompanying Consolidated Statements of Operations. An income tax benefit of approximately $101 million was also recorded in 2003, primarily associated with the $194 million goodwill impairment recognized in 2002 for the gas marketing business in Europe, the 2003 sale of that business and certain other exit costs. This tax benefit was included in Loss from Discontinued Operations, net of tax, in the accompanying Consolidated Statements of Operations.

Associated with the sale of the European Business, International Energy holds a receivable from Norsk Hydro ASA with a fair value of $42 million as of December 31, 2005 and $54 million as of December 31, 2004. This balance is included in Receivables in the Consolidated Balance Sheets as of December 31, 2005 and 2004. In 2004, International Energy recorded a $14 million ($9 million after tax) allowance against the carrying value of the note based on management’s assessment of the probability of not collecting the entire note. The after tax loss was included in Loss from Discontinued Operations, net of tax, in the accompanying Consolidated Statements of Operations.

In 2003, International Energy completed the sale of its 85.7% majority interest in P.T. Puncakjaya Power (PJP) in Indonesia for $78 million. The sale resulted in a reduction to Duke Capital’s consolidated indebtedness of $259 million. International Energy recorded an immaterial after tax loss on the sale, which was included in Loss from Discontinued Operations, net of tax, in the accompanying Consolidated Statements of Operations.

The operating results related to these operations were included in Loss from Discontinued Operations, net of tax, in the accompanying Consolidated Statements of Operations.

Crescent

Crescent routinely develops real estate projects and operates those facilities until they are substantially leased and a sales agreement is finalized. If Crescent does not retain any significant continuing involvement after the sale, Crescent classifies the project as “discontinued operations” as required by SFAS No. 144.

In 2005, Crescent sold three commercial properties resulting in sales proceeds of approximately $44 million. The $6 million after tax gain on these sales was included in Loss from Discontinued Operations, net of tax, in the accompanying Consolidated Statements of Operations.

In 2004, Crescent sold one multi-family, two residential and two commercial properties resulting in sales proceeds of approximately $52 million. The $5 million after tax gain on these sales was included in Loss from Discontinued Operations, net of tax, in the accompanying Consolidated Statements of Operations.

In 2003, Crescent sold three retail centers and one apartment complex, all located in Florida, for a total sales price of approximately $77 million. The $11 million after tax gain on these sales was included in Loss from Discontinued Operations, net of tax, in the accompanying Consolidated Statements of Operations.

F-66

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

Other

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 DENA’s remaining assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets. The DENA assets to be divested include:

• Approximately 6,100 MW of power generation located primarily in the Western and Eastern United States, including all of the commodity contracts (primarily forward gas and power contracts) related to these facilities,

• All remaining commodity contracts related to DENA’s Southeastern generation operations, which were substantially disposed of in 2004, and certain commodity contracts related to DENA’s Midwestern power generation facilities, and

• Contracts related to DENA’s energy marketing and management activities, which include gas storage and transportation, structured power and other contracts.

The exit plan is expected to be completed by the end of the second quarter of 2006. The financial statement presentation for the assets and contracts to be sold, and the related results of operations, are discussed below.

In connection with this exit plan, Duke Capital recognized pre-tax losses of approximately $1.1 billion in 2005 in Loss From Discontinued Operations, net of tax, in the Consolidated Statement of Operations. These losses principally related to:

• The discontinuation of the normal purchase/normal sale exception for certain forward power and gas contracts (an approximate $1.9 billion pre-tax charge)

• The reclassification of approximately $1.2 billion of pre-tax deferred net gains in AOCI for cash flow hedges of forecasted gas purchase and power sale transactions that will no longer occur as a result of the exit plan

• Pre-tax impairments of approximately $0.2 billion to reduce the carrying value of the plants that are expected to be sold to their estimated fair value less cost to sell. Fair value of the assets that are expected to be sold was estimated based upon the signed agreement with LS Power, as discussed below.

• Pre-tax losses of approximately $400 million as the result of selling certain gas transportation and structured contracts (as discussed further below), and

• Pre-tax deferred gains in AOCI of approximately $200 million related to the discontinued cash flow hedges of forecasted gas purchase and power sale transactions, which were recognized as the forecasted transactions occurred.

Additionally, approximately $10 million of pre-tax deferred net losses remain in AOCI at December 31, 2005 related to hedges of forecasted transactions that are expected to occur prior to the anticipated disposal of the generation assets. This amount will be reclassified to earnings during 2006 as the forecasted transactions occur. In addition, 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 includes approximately $40 million to $60 million of severance, retention and other transaction costs (see Note 11). Approximately $500 million was incurred as of December 31, 2005, approximately $400 million of which was recognized in Loss From Discontinued Operations, net of tax. The actual amount of future additional charges related to the DENA

F-67

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

exit plan will vary depending upon changes in market conditions and other factors, and could differ materially from the original estimate. DENA may also realize future potential gains on sales of certain plants which will be recognized when sold.

During 2005, DENA has entered into agreements to sell or terminate certain of its contract portfolio, including certain transportation contracts. The total cash paid by Duke Capital under such contract sales or terminations during 2005 was approximately $400 million, excluding approximately $100 million of cash paid to Barclays, as discussed hereafter. These transactions resulted in pre-tax losses on sale of approximately $400 million, which are included in the $600 million to $800 million range of additional anticipated charges, as discussed above. Included in these amounts are the effects of DENA’s November 2005 agreement to sell substantially all of its commodity contracts related to the Southeastern generation operations, which were substantially disposed of in 2004, certain commodity contracts related to DENA’s Midwestern power generation facilities, and contracts related to DENA’s energy marketing and management activities. Excluded from the contracts sold to Barclays are commodity contracts associated with the near-term value of DENA’s West and Northeastern generation assets and with remaining gas transportation and structured power contracts. Among other things, the agreement provides that effective immediately all economic benefits and burdens under the contracts were transferred to Barclays. Cash consideration paid to Barclays amounted to approximately $100 million in 2005 and approximately $600 million in January 2006. Additionally, in January 2006 Barclays provided DENA with cash equal to the net cash collateral posted by DENA under the contracts of approximately $540 million. DENA will continue to service the contracts until novation or assignment for a monthly fee. The novation or assignment of physical power contracts was subject to FERC approval, which has been received in January 2006.

In January 2006, a Duke Capital subsidiary signed an agreement to sell to LS Power DENA’s entire fleet of power generation assets outside the Midwest, representing approximately 6,100 megawatts of power generation located in the Western and Northeast United States, for approximately $1.5 billion. Duke Capital recognized a pre-tax gain of approximately $380 million in the fourth quarter of 2005, which offsets a portion of the impairment of approximately $0.6 billion recognized in the third quarter of 2005. The transaction is subject to FERC and Hart-Scott-Rodino approvals and is expected to close in the second quarter of 2006.

The net impairments of approximately $0.2 billion have been classified as a component of Loss from Discontinued Operations, net of tax, in the accompanying Consolidated Statements of Operations. See Note 7 for further details on the hedge accounting implications of this exit activity. The charge for the discontinuance of the normal purchase/normal sale exception and the reclassification of deferred gains in AOCI for cash flow hedges have been classified as a component of Loss from Discontinued Operations, net of tax, in the Consolidated Statements of Operations.

As of December 31, 2005, DENA’s assets and liabilities to be disposed of under the exit plan were classified as Assets Held for Sale in the Consolidated Balance Sheets, except the Ft. Frances generation facility which was sold in October 2005 for proceeds approximating carrying value.

The results of operations of DENA’s Western and Eastern United States generation assets, including related commodity contracts, certain contracts related to DENA’s energy marketing and management activities and certain general and administrative costs, are required to be classified as discontinued operations for current and prior periods in the accompanying Consolidated Statements of Operations. GAAP requires an ongoing assessment of the continued qualification for discontinued operations presentation for the period up through one year following disposal. While this assessment requires judgment, management is not currently aware of any matters or events that are likely to occur that would impact the presentation of these operations as discontinued operations.

F-68

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

As discussed further in Note 2, DENA’s Southeastern generation operations, including related commodity contracts do not meet the requirements for discontinued operations classification due to Duke Capital’s continuing involvement with these operations.

See Note 3 for a discussion of the impacts of this exit activity on Duke Capital’s segment presentation.

In the first quarter of 2005, DENA’s Grays Harbor facility was sold to an affiliate of Invenergy LLC, resulting in a pre-tax gain of approximately $21 million (excludes any potential contingent consideration).

In the third quarter of 2005, DENA completed the sale of Bayside Power L.P. (Bayside) to affiliates of Irving Oil Limited (Irving), under which Irving would purchase DENA’s 75% interest in Bayside. The after tax gain on this sale is included in Loss from Discontinued Operations, net of tax, in the accompanying Consolidated Statements of Operations. Bayside was consolidated with the adoption of FIN 46R on March 31, 2004. Therefore, Bayside’s operating results after March 31, 2004 are included in Loss from Discontinued Operations, net of tax, in the accompanying Consolidated Statements of Operations. Prior operating results are not included in Discontinued Operations, as Bayside was previously accounted for as an equity method investment.

For the year ended December 31, 2004, DENA incurred net operating losses on its discontinued operations. DENA’s discontinued operations also included sales and impairments of merchant power plants located in Washington (“Grays Harbor” plant), Nevada (“Moapa” plant) and New Mexico (“Luna” plant) (collectively, the deferred plants). The deferred plants were a component of DENA’s Western United States generation assets that meets the requirements for discontinued operations classification for current and prior periods in the accompanying Consolidated Statements of Operations. Details are as follows:

• The partially completed Moapa facility was sold to Nevada Power Company and resulted in $186 million in net proceeds and a pre-tax gain of approximately $140 million recorded in Loss from Discontinued Operations, net of tax, in the 2004 Consolidated Statement of Operations.

• The partially completed Luna facility was sold to PNM Resources, Tucson Electric Power and Phelps Dodge Corporation. This sale resulted in net proceeds of $40 million and a pre-tax gain of $40 million recorded in Loss from Discontinued Operations, net of tax, in the 2004 Consolidated Statements of Operations.

• In December 2004, DENA agreed to sell the partially completed Grays Harbor facility to an affiliate of Invenergy LLC.

Also, effective December 31, 2004, Duke Capital terminated it capital lease associated with the dedicated pipeline which would have transported natural gas to the plant. This termination resulted in a $20 million pre-tax charge recorded in Loss from Discontinued Operations, net of tax, in the 2004 Consolidated Statements of Operations. As discussed above, in the first quarter of 2005, Grays Harbor was sold.

For the year ended December 31, 2003, DENA’s net operating loss from discontinued operations was due primarily to the following:

• In the fourth quarter of 2003, Duke Capital decided not to fund completion of construction of three DENA deferred plants. The carrying value of these assets exceeded the fair value, resulting in an impairment charge of approximately $1.1 billion pre-tax ($515 million for Moapa, $270 million for Luna and $362 million for Grays Harbor) which was recorded in Loss from Discontinued Operations, net of tax, in the 2003 Consolidated Statement of Operations. The fair value of the deferred plants was estimated based primarily on analysis from outside advisors and information available from efforts to sell certain of these assets.

F-69

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

• Certain forward power contracts related to the deferred plants had been primarily designated as normal purchases and normal sales in accordance with SFAS No. 133. In addition, certain forward gas contracts related to the long-lived assets had been designated as cash flow hedges in accordance with SFAS No. 133. As a result of the change in management intent for the long-lived assets, the related forward power and gas contracts were de-designated as normal purchases and sales and hedges. As a result, a pre-tax charge of $452 million was recorded.

• A power generation plant in Maine. During 2003, Duke Capital agreed to sell this plant and recorded a pre-tax impairment charge of $72 million for the portion of the carrying value in excess of the negotiated sales price for the plant. The sale that was anticipated did not occur. This plant was a component of DENA’s Eastern United States generation assets that meet the requirements for discontinued operations classification for current and prior periods in the accompanying Consolidated Statements of Operations.

• An impairment charge of $64 million in 2003 associated with a change in the expected dispatch of Morro Bay, a plant in California. Fair value of this asset was estimated based primarily on discounted cash flow analysis.

Other also includes discontinued operations associated with DCP. During 2003, Duke Capital decided to exit the merchant finance business conducted by DCP. As a result, Duke Capital recorded an approximately $17 million after tax loss, which represents the excess of the carrying value of the notes receivable over the fair value, less costs to sell. Fair value of the notes receivable was estimated based primarily on discounted cash flow analysis. The after tax loss was included in Loss from Discontinued Operations, net of tax, in the accompanying Consolidated Statements of Operations. The sale or collection of substantially all of DCP’s notes receivable was completed during 2004. DCP’s operating results are included in Loss from Discontinued Operations, net of tax, in the accompanying Consolidated Statements of Operations. During 2004, Duke Capital received approximately $58 million from the sale or collection of all of DCP’s notes receivable. An immaterial after tax gain related to this transaction was included in Loss from Discontinued Operations, net of tax, in the accompanying Consolidated Statements of Operations.

F-70

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

13. Property, Plant and Equipment

	Estimated Useful Life	December 31,
		2005			2004
	(Years)	(in millions)
Land	—	$	264		$	189
Plant—Regulated
Natural gas transmission and distribution	20–82		10,810			10,178
Gathering and processing facilities	20–25		1,570			1,465
Other buildings and improvements	16–50		70			55
Plant—Unregulated
Electric generation(a)	20–50		3,899			5,693
Natural gas transmission and distribution	20–82		32			1,224
Gathering and processing facilities(a)	20–25		678			4,878
Other buildings and improvements(a)	16–50		27			64
Equipment(a)	3–40		446			598
Vehicles	3–20		97			104
Construction in process	—		415			314
Other(a)	5–122		1,033			1,108
Total property, plant and equipment			19,341			25,870
Total accumulated depreciation—regulated(b)			(2,758	)		(2,509	)
Total accumulated depreciation—unregulated(b)			(897	)		(2,662	)
Total net property, plant and equipment		$	15,686		$	20,699

(a) Includes capitalized leases: $48 million for 2005 and $87 million for 2004.

(b) Includes accumulated amortization of capitalized leases: $19 million for 2005 and $33 million for 2004.

Capitalized interest, which includes the interest expense component of AFUDC, amounted to $13 million for 2005, $11 million for 2004 and $44 million for 2003.

14. Debt and Credit Facilities

Summary of Debt and Related Terms

	Weighted- Average Rate			December 31,
			Year Due	2005			2004
	(in millions)
Unsecured debt	7.0	%	2006–2032	$	8,857		$	11,241
Secured debt	6.4	%	2006–2024		1,270			1,114
Capital leases	8.2	%	2006–2025		10			195
Other debt	1.2	%	2006–2017		29			35
Commercial paper(a)	3.3	%			83			68
Fair value hedge carrying value adjustment			2006–2032		21			37
Unamortized debt discount and premium, net					(3	)		(7	)
Total debt(b)					10,267			12,683
Current maturities of long-term debt					(1,394	)		(1,326	)
Short-term notes payable and commercial paper(c)					(83	)		(69	)
Total long-term debt(d)				$	8,790		$	11,288

F-71

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

(a) The weighted-average days to maturity were 3 days as of December 31, 2005 and 9 days as of December 31, 2004.

(b) As of December 31, 2005, $501 million of debt was denominated in Brazilian Reals and $3,917 million of debt was denominated in Canadian dollars. As of December 31, 2004, $485 million of debt was denominated in Brazilian Reals and $3,720 million of debt was denominated in Canadian dollars.

(c) Weighted-average rates on outstanding short-term notes payable and commercial paper was 3.3% as of December 31, 2005 and 2.5% as of December 31, 2004.

(d) The current and non-current portions of DEFS’ long-term debt balances of approximately $600 million and approximately $1,650 million, respectively, as of December 31, 2004, are no longer included in Duke Capital’s consolidated debt balance due to the deconsolidation of DEFS in July 2005.

Unsecured Debt. In November 2005, DEI issued floating rate debt in Guatemala for $87 million (in USD) and in El Salvador for $75 million (in USD). These debt issuances have variable interest rate terms and mature in 2015.

On September 21, 2005, Union Gas entered into a fixed-rate financing agreement denominated in 200 million Canadian dollars (approximately $171 million in U.S. dollar equivalents as of the issuance date) due in 2016 with an interest rate of 4.64%.

In August 2005, DEI issued project-level debt in Peru, of which $75 million is denominated in U.S. dollars and approximately $34 million (in U.S. dollar equivalents as of the issuance date) is denominated in Peru Nuevos Soles. This debt has terms ranging from four to six years as well as variable or fixed interest rate terms, as applicable.

On March 1, 2005, redemption notices were sent to the bondholders of the $100 million PanEnergy 8.625% bonds due in 2025. These bonds were redeemed on April 15, 2005 at a redemption price of 104.03 or approximately $104 million.

In February 2004, Duke Capital remarketed $875 million of senior notes due in 2006, underlying its 8.25% Equity Units and reset the interest rate from 5.87% to 4.302%. As this action was contemplated in the original Equity Units issuance, the transaction had no immediate accounting implications. Subsequently, Duke Capital exchanged $475 million of the remarketed senior notes for $200 million of 4.37% senior unsecured notes due in 2009, and $288 million of 5.5% senior unsecured notes due in 2014. In accordance with EITF 96-19, “Debtors Accounting for a Modification or Exchange of Debt Instruments,” the $475 million of remarketed senior notes issued earlier at 4.302% was extinguished. This exchange transaction resulted in an approximate $11 million loss, which was included in Interest Expense in the Consolidated Statements of Operations for the year ended December 31, 2004. Proceeds from the remarketed notes were used to purchase U.S. Treasury securities that were held by the collateral agent and, upon maturity, were used to satisfy the forward stock purchase contract component of the 8.25% Equity Units in May of 2004.

Additionally, Duke Capital remarketed $750 million of its 4.32% senior notes due in 2006, underlying Duke Energy’s 8.00% Equity Units on August 11, 2004. As a result of the remarketing, the interest rate on the notes was reset to 4.331%, effective August 16, 2004. Duke Capital subsequently exchanged $400 million of the 4.331% notes for $408 million of 5.668% notes due in 2014. This transaction resulted in an approximate $6 million loss, which was included in Interest Expense in the Consolidated Statements of Operations for the year end December 31, 2004. Proceeds from the remarketed notes were used to purchase U.S. Treasury securities held by the collateral agent and, upon maturity, were used to satisfy the forward stock purchase contract component of the Duke Energy 8% Equity Units in November 2004.

F-72

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

Secured Debt. In December 2004, Duke Capital reached an agreement to sell its partially completed Grays Harbor power generation facility to an affiliate of Invenergy LLC. In 2004, Duke Capital also terminated its capital lease with the dedicated pipeline which would have transported natural gas to Grays Harbor. As a result of this termination, approximately $94 million was paid by Duke Capital in January 2005.

Other Assets Pledged as Collateral. As of December 31, 2005, secured debt also consisted of various project financings, including Maritimes & Northeast Pipeline, LLC, Maritimes & Northeast Pipeline, LP (collectively, M&N Pipeline) and certain projects at Crescent. A portion of the assets, ownership interest and business contracts in these various projects are pledged as collateral.

Floating Rate Debt. Unsecured debt, secured debt and other debt included approximately $1,213 million of floating-rate debt as of December 31, 2005, and approximately $500 million as of December 31, 2004. As of December 31, 2005 and 2004, $488 million and $462 million of Brazilian debt that is indexed annually to Brazilian inflation was included in floating rate debt. Floating-rate debt is primarily based on commercial paper rates or a spread relative to an index such as a London Interbank Offered Rate for debt denominated in U.S. dollars, and Banker’s Acceptances for debt denominated in Canadian dollars. As of December 31, 2005, the average interest rate associated with floating-rate debt was 7.2%.

Related Party Debt. Other debt included $4 million related to a loan with D/FD as of December 31, 2005, and $17 million as of December 31, 2004. As part of the D/FD partnership agreement, excess cash has been loaned, without stated repayment terms, at current market rates to Duke Capital and Fluor Enterprises, Inc. The weighted-average rate of this loan was 3.47% as of December 31, 2005 and 1.98% as of December 31, 2004. D/FD is a 50/50 partnership between subsidiaries of Duke Capital and Fluor. During 2003, Duke Capital and Fluor announced that they would dissolve D/FD and adopted a plan for an orderly wind-down of D/FD’s business. The wind-down has been substantially completed as of December 31, 2005 and is expected to be finalized by December 2006. The entire outstanding balance of the loan with D/FD has been classified as Current Maturities of Long-term Debt on the December 31, 2005 and 2004 Consolidated Balance Sheets.

Maturities, Call Options and Acceleration Clauses.

Annual Maturities as of December 31, 2005

	(in millions)
2006	$	1,394
2007		634
2008		434
2009		1,089
2010		877
Thereafter		5,756
Total long-term debt(a)	$	10,184

(a) Excludes short-term notes payable and commercial paper of $83 million.

Annual maturities after 2010 include $112 million of long-term debt with call options, which provide Duke Capital with the option to potentially repay the debt early. Based on the years in which Duke Capital may first exercise its redemption options, it could potentially repay $112 million in 2007.

F-73

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

Available Credit Facilities and Restrictive Debt Covenants. During the year ended December 31, 2005, Duke Capital’s consolidated credit capacity increased by approximately $425 million compared to December 31, 2004. Duke Capital added two new $100 million, 364-day bi-lateral credit facilities to provide additional letter of credit issuing capacity and at renewal increased its expiring 364-day letter of credit facility by $200 million. In addition, Duke Capital added three new 364-day credit facilities totaling $260 million to provide additional credit support. Westcoast and Union Gas renewed and replaced their credit facilities at existing levels. Duke Capital amended the $600 million multi-year syndicated facility to extend the expiration date. The credit facilities of DEFS ($250 million at December 31, 2004) are no longer included in Duke Capital’s consolidated available credit facilities due to the deconsolidation of Duke Capital’s investment in DEFS in July 2005 (see Note 2). In February of 2006, Duke Capital cancelled the $100 million 364-day bi-lateral credit facility and the $100 million one-year bi-lateral credit facility.

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

Duke Capital’s 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, 2005, Duke Capital was in compliance with those covenants. In addition, some credit agreements may allow for acceleration of payments or termination of the agreements due to nonpayment, or to the acceleration of other significant indebtedness of the borrower or some of its subsidiaries. None of the debt or credit agreements contain material adverse change clauses.

Credit Facilities Summary as of December 31, 2005

		Amounts Outstanding
	Expiration Date	Credit Facilities Capacity		Commercial Paper		Letters of Credit		Total
	(in millions)
Duke Capital LLC
$800 364-day syndicated(a),(b)	June 2006
$600 multi-year syndicated(a),(b)	June 2009
$130 three-year bi-lateral(b)	October 2007
$120 multi-year bi-lateral(b)	July 2009
$100 one-year bi-lateral(b)	June 2006
$260 364-day bi-lateral(a),(b)	June 2006
$100 364-day bi-lateral(b)	October 2006
Total Duke Capital LLC		$	2,110	$	—	$	857	$	857
Westcoast Energy Inc.
$86 364-day syndicated(b),(c)	June 2006
$172 multi-year syndicated(b),(d)	June 2010
Total Westcoast Energy Inc.			258		—		—		—
Union Gas
$258 364-day syndicated(e),(f)	June 2006		258		83		—		83
Total		$	2,626	$	83	$	857	$	940

(a) Credit facility contains an option allowing borrowing up to the full amount of the facility on the day of initial expiration for up to one year.

F-74

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

(b) Credit facility contains a covenant requiring the debt-to-total capitalization ratio to not exceed 65%.

(c) Credit facility is denominated in Canadian dollars totaling 100 million Canadian dollars.

(d) Credit facility is denominated in Canadian dollars totaling 200 million Canadian dollars.

(e) Credit facility contains a covenant requiring the debt-to-total capitalization ratio to not exceed 75%. Credit facility is denominated in Canadian dollars totaling 300 million Canadian dollars.

(f) Credit facility contains an option at maturity allowing for the conversion of all outstanding loans to a term loan repayable up to one year after maturity date but not exceeding 18 months from the date of draw.

Duke Capital has approximately $1,600 million of credit facilities which expire in 2006. It is Duke Capital’s intent to resyndicate less than the total amount of expiring credit facilities.

15. Preferred and Preference Stock at Duke Capital’s Subsidiaries

In connection with the Westcoast acquisition in 2002, Duke Capital assumed approximately $411 million of authorized and issued redeemable preferred and preference shares at Westcoast and Union Gas. These preferred and preference shares at Westcoast and Union Gas totaled $225 million at both December 31, 2005 and 2004. Since these preferred and preference shares are redeemable at the option of holder, as well as Westcoast and Union Gas, these preferred and preference shares do not meet the definition of a mandatorily redeemable instrument under SFAS No. 150. As such, these preferred and preference shares are considered contingently redeemable shares and are included in Minority Interests on the Consolidated Balance Sheets.

16. Commitments and Contingencies

General Insurance

Duke Capital carries, through its captive insurance company, Bison, and its affiliates, insurance and reinsurance coverages consistent with companies engaged in similar commercial operations with similar type properties. Duke Capital’s insurance coverage includes (1) commercial general public liability insurance for liabilities arising to third parties for bodily injury and property damage resulting from Duke Capital’s 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) financial services insurance policies in support of the indemnification provisions of the company’s 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 business interruption/extra expense. All coverages are subject to certain deductibles, terms and conditions common for companies with similar types of operations.

Bison is a member of Oil Insurance Limited (OIL) and sEnergy Insurance Limited (sEnergy), which provides property and business interruption reinsurance coverage respectively for Duke Capital’s facilities, and accounts for its membership under the cost method, as Duke Capital does not have the ability to exert significant influence. Should Bison terminate its membership in either OIL, sEnergy or both, it could be liable for additional premium assessments. Bison continues to be a member of OIL and sEnergy in 2006 and purchases coverages provided by both companies.

NorthSouth Insurance Company Limited, a subsidiary of Bison, insures exposures of Duke Power, an unconsolidated affiliate of Duke Capital (see Note 10).

Duke Capital 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.

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

Environmental

Duke Capital is subject to international, federal, state and local regulations regarding air and water quality, hazardous and solid waste disposal and other environmental matters.

Remediation activities. Like others in the energy industry, Duke Capital and its affiliates are responsible for environmental remediation at various contaminated sites. These include some properties that are part of ongoing Duke Capital operations, sites formerly owned or used by Duke Capital 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 Capital or its affiliates could potentially be held responsible for contamination caused by other parties. In some instances, Duke Capital may share liability associated with contamination with other potentially responsible parties, and may also benefit from insurance policies or contractual indemnities that cover some or all cleanup costs. All of these sites generally are managed in the normal course of business or affiliate operations. Management believes that completion or resolution of these matters will have no material adverse effect on Duke Capital’s consolidated results of operations, cash flows or financial position.

Clean Water Act. The U. S. Environmental Protection Agency’s (EPA’s) final Clean Water Act Section 316(b) rule became effective July 9, 2004. The rule establishes 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. Duke Capital’s three natural gas-fired generating facilities in California are affected sources under the rule. The three California facilities are part of the DENA business and are expected to be divested by the second quarter of 2006 as part of the transaction announced in January 2006 (see Note 12). The rule requires a Comprehensive Demonstration Study (CDS) for each affected facility to provide information needed to determine necessary facility-specific modifications and cost estimates for implementation. These studies will be completed over the next three to five years. Once compliance measures are determined and approved by regulators, a facility will typically have five or more years to implement the measures. Due to the wide range of measures potentially applicable to a given facility, and since the final selection of compliance measures will be at least partially dependent upon the CDS information, Duke Capital is not able to estimate its cost for complying with the rule at this time.

Extended Environmental Activities, Accruals. Included in Other Current Liabilities and Other Deferred Credits and Other Liabilities on the Consolidated Balance Sheets were total accruals related to extended environmental-related activities of approximately $50 million as of December 31, 2005 and $76 million as of December 31, 2004. These accruals represent Duke Capital’s provisions for costs associated with remediation activities at some of its current and former sites, as well as other relevant environmental contingent liabilities. Management believes that completion or resolution of these matters will have no material adverse effect on Duke Capital’s consolidated results of operations, cash flows or financial position.

Litigation

Western Energy Litigation and Regulatory Matters. Since 2000, plaintiffs have filed 50 lawsuits in four Western states against Duke Capital affiliates, current and former Duke Energy executives, and other energy companies. Most of the suits seek class-action certification on behalf of electricity and/or natural gas purchasers.

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The plaintiffs allege that the defendants manipulated the electricity and/or natural gas markets in violation of state and/or federal antitrust, unfair business practices and other laws. Plaintiffs in some of the cases further allege that such activities, including engaging in “round trip” trades, providing false information to natural gas trade publications and unlawfully exchanging information, resulted in artificially high energy prices. Plaintiffs seek aggregate damages or restitution of billions of dollars from the defendants.

• To date, one suit has been voluntarily dismissed by plaintiffs. Fourteen suits have been dismissed on filed rate and/or federal preemption grounds. The plaintiffs in these dismissed suits have appealed or are expected to appeal, and the U.S. Ninth Circuit Court of Appeals has affirmed the dismissals of eight of these lawsuits. The plaintiff in one of the dismissed actions affirmed by the Ninth Circuit petitioned the U.S. Supreme Court for certiorari, and, on June 27, 2005, the U.S. Supreme Court denied certiorari.

• In July 2004, Duke Energy reached an agreement in principle resolving class-action litigation involving the purchase of electricity filed on behalf of ratepayers and other electricity consumers in California, Washington, Oregon, Utah and Idaho. This agreement is part of a more comprehensive settlement involving FERC refunds and other proceedings related to the Western energy markets during 2000-2001 (the California Settlement). The California Settlement resolved issues that arose under several investigations and regulatory proceedings at the state and federal levels involving Duke Capital, along with other energy suppliers and producers, that looked into the causes of high wholesale electricity prices in the Western United States during 2000 and 2001. FERC approved all provisions of the California Settlement (except for the class action portion which was subject to court approval) in December 2004. In December 2004, Duke Capital tendered all of the settlement proceeds except for $7 million relating to the class-action settlement. On December 14, 2005, the court issued an order giving final approval to the settlement of these class action lawsuits with respect to Duke Capital, and these remaining funds were paid in 2005.

• Suits filed on behalf of electricity ratepayers in other Western states, on behalf of entities that purchased electricity directly from a generator and on behalf of natural gas purchasers, remain pending. It is not possible to predict with certainty whether Duke Capital will incur any liability or to estimate the damages, if any, that Duke Capital might incur in connection with these lawsuits, but Duke Capital does not presently believe the outcome of these matters will have a material adverse effect on its consolidated results of operations, cash flows or financial position.

In 2002, Southern California Edison Company (SCE) initiated arbitration proceedings regarding disputes with DETM relating to amounts owed in connection with the termination of bi-lateral power contracts between the parties in early 2001. SCE disputes DETM’s termination calculation and seeks in excess of $86 million plus interest. This matter proceeded to hearing in November 2005. In January 2006, the parties reached an agreement in principle to resolve the matters at issue in the arbitration. The agreement will require regulatory approval. Based on the level of damages claimed by the plaintiff, Duke Capital’s assessment of possible outcomes in this matter, and the referenced agreement in principle, Duke Capital does not expect that the resolution of this matter will have a material adverse effect on its consolidated results of operations, cash flows or financial position.

Trading Related Litigation. By letter dated April 16, 2004, Duke Energy received notice that a shareholder reactivated a litigation demand sent to Duke Energy in 2002. Arising out of the same “round trip” trades issues raised in the shareholder lawsuits dismissed by the courts in 2003 and affirmed on appeal, the notice stated that the shareholder intended to initiate derivative shareholder litigation within 90 days from the date of the letter if Duke Energy did not initiate litigation within the stated timeframe. Duke Energy’s Board of Directors appointed a special committee to review the demand. The committee determined that there are no grounds supporting the allegations made in the derivative demand to commence or maintain an action on behalf of Duke Energy against

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the individuals named in the derivative demand, and that, accordingly, it would not be in the best interests of Duke Energy to bring such claims. By letter dated January 21, 2005, another shareholder reactivated a 2002 litigation demand. The reactivated demand arises out of the same issues that were raised in the April 16 reactivated demand as well as matters that were the subject of the California Settlement. On March 16, 2005, the special committee determined that there are no grounds supporting the allegations made in the derivative demand to commence or maintain an action on behalf of Duke Energy against the individuals named in the derivative demand, and that, accordingly, it would not be in the best interests of Duke Energy to bring such claims.

Commencing August 2003, plaintiffs filed three class-action lawsuits in the U.S. District Court for the Southern District of New York on behalf of entities who bought and sold natural gas futures and options contracts on the New York Mercantile Exchange during the years 2000 through 2002. DETM, along with numerous other entities, is named as a defendant. The plaintiffs claim that the defendants violated the Commodity Exchange Act by reporting false and misleading trading information to trade publications, resulting in monetary losses to the plaintiffs. Plaintiffs seek class action certification, unspecified damages and other relief. On September 24, 2004, the court denied a motion to dismiss the plaintiffs’ claims filed on behalf of DETM and other defendants, and on September 30, 2005, the court certified the class. DETM has reached an agreement with the plaintiffs in these consolidated cases to resolve all issues and on February 8, 2006, the court granted preliminary approval of this settlement. The agreement is subject to final court approval after notification to all class members. Duke Capital does not expect that the resolution of this matter will have a material adverse effect on its consolidated results of operations, cash flows or financial position.

On January 28, 2005, four plaintiffs filed suit in Tennessee Chancery Court against Duke Capital affiliates and other energy companies seeking class action certification on behalf of indirect purchasers of natural gas who allege that they have been harmed by defendants’ manipulation of the natural gas markets by various means, including providing false information to natural gas trade publications and unlawfully exchanging information, resulting in artificially high natural gas prices paid by plaintiffs in the State of Tennessee. Alleging that defendants violated state antitrust laws and other laws, plaintiffs seek unspecified damages and other relief. Defendants removed this case to the United States District Court for the Western District of Tennessee in March 2005, and the case was transferred to a federal judge in Nevada in Multidistrict Litigation (MDL) proceeding 1566. Plaintiffs filed a motion to remand the case to state court, and the defendants filed motions to dismiss the complaint on various grounds, including the filed rate doctrine and federal preemption. The court has yet to rule on these motions. Duke Capital is unable to express an opinion regarding the probable outcome of these matters at this time.

On August 8, 2005, a plaintiff filed a lawsuit in state court in Kansas against Duke Energy and DETM, as well as other energy companies, claiming that the plaintiff was harmed by the defendants’ alleged manipulation of the natural gas markets by various means, including providing false information to natural gas trade publications and entering into unlawful arrangements and agreements. Duke Energy removed this case to the United States District Court for the District of Kansas on September 8, 2005, and the case was subsequently transferred to a federal judge in the MDL 1566 proceeding. On September 26, 2005, a class action petition was filed by two plaintiffs in state court in Kansas against various defendants including Duke Energy and DETM, based on substantially similar allegations. This matter also was moved to federal court, and defendants are seeking to have the case transferred to the MDL 1566 proceeding. Plaintiffs have filed a motion to remand the case to state court. The plaintiffs in the foregoing cases claim the defendants violated Kansas’ antitrust laws and seek damages in unspecified amounts. Duke Capital is unable to express an opinion regarding the probable outcome of these matters at this time.

Trading Related Investigations. In 2002 and 2003, Duke Energy responded to information requests and subpoenas from the Securities and Exchange Commission (SEC) and to grand jury subpoenas issued by the U.S.

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Attorney’s office in Houston, Texas. The information requests and subpoenas sought documents and information related to trading activities, including so-called “round-trip” trading. Duke Energy received notice in 2002 that the SEC formalized its trading-related investigation. In July 2005 the SEC approved Duke Energy’s offer of settlement to resolve the issues that were the subject of the SEC’s investigation regarding conduct that occurred in 2000 through June 2002. The terms of the settlement included the issuance of an order to Duke Energy to cease and desist from violating internal controls and books and records requirements under Sections 13(b)(2)(A) and 13(b)(2)(B) of the Securities Exchange Act of 1934, but did not include a penalty or finding of fraud. Prior to 2005, Duke Capital subsidiaries took actions to remediate the issues that were raised in the SEC’s investigation regarding internal controls.

In April 2004, the Houston-based federal grand jury issued indictments for three former employees of DETMI Management Inc. (DETMI), which is one of two members of DETM. The indictments state that the employees “did knowingly devise, intend to devise, and participate in a scheme to defraud and to obtain money and property from Duke Energy by means of materially false and fraudulent pretenses, representations and promises, and material omissions, and to deprive Duke Energy and its shareholders of the intangible right to the honest services of employees of Duke Energy.” They further state that the alleged conduct was purportedly motivated, in part, by a desire to increase individual bonuses. Statements made by the U.S. Attorney’s office characterized Duke Energy as a victim in this activity and commended Duke Energy for its cooperation with the investigation. The alleged conduct was identified in the spring and summer of 2002 and was related to DETM’s Eastern Region trading activities. In 2002, Duke Capital recorded the appropriate financial adjustments associated with the cited activities, and did not consider the financial effect to be material. In February 2005, one of the three indicted former DETMI employees pled guilty to a “books and records” violation, and a superseding indictment was filed against the other two former employees, providing more detail and adding an allegation that the former employees intentionally circumvented internal accounting controls. After trial of the two remaining former DETMI employees in the fall of 2005, one was acquitted of all charges and the other was acquitted of seven out of nineteen charges. The trial judge declared a mistrial on the remaining counts and subsequently granted the U.S. Attorney’s request to dismiss the remaining counts against the former employee. In addition, the former employee who pled guilty to a “books and records” violation was permitted to withdraw his guilty plea.

Beginning in February 2004, Duke Energy has received requests for information from the U.S. Attorney’s office in Houston focused on the natural gas price reporting activities of certain individuals involved in DETM trading operations. Duke Energy has cooperated with the government in this investigation and Duke Capital is unable to express an opinion regarding the probable outcome at this time.

In February 2005, the Commodity Futures Trading Commission initiated a civil action against a former DETM trader asserting charges of delivering false reports and attempted manipulation of prices through index price reporting. Neither Duke Energy nor Duke Capital is named in this action.

Sonatrach/Sonatrading Arbitration. Duke Energy LNG Sales Inc. (Duke LNG), a subsidiary of Duke Capital, claims in an arbitration commenced in January 2001 in London that Sonatrach, the Algerian state-owned energy company, together with its subsidiary, Sonatrading Amsterdam B.V. (Sonatrading), breached their shipping obligations under a liquefied natural gas (LNG) purchase agreement and related transportation agreements (the LNG Agreements) relating to Duke LNG’s purchase of LNG from Algeria and its transportation by LNG tanker to Lake Charles, Louisiana. Duke LNG seeks damages of approximately $27 million. Sonatrading and Sonatrach counter claim that Duke LNG repudiated the LNG Agreements by allegedly failing to diligently perform LNG marketing obligations. Sonatrading and Sonatrach seek damages in the amount of approximately $250 million. In 2003, an arbitration tribunal issued a Partial Award on liability issues, finding that Sonatrach and Sonatrading breached their obligations to provide shipping. The tribunal also found that Duke LNG breached

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the LNG Purchase Agreement by failing to perform marketing obligations. The hearing on damages issues commenced in September 2005 and will continue through the first quarter of 2006.

Citrus Trading Corporation (Citrus) Litigation. In conjunction with the Sonatrach LNG Agreements, Duke LNG entered into a natural gas purchase contract (the Citrus Agreement) with Citrus. Citrus filed a lawsuit in March 2003 in the U.S. District Court for the Southern District of Texas against Duke LNG and PanEnergy Corp alleging that Duke LNG breached the Citrus Agreement by failing to provide sufficient volumes of gas to Citrus. Duke LNG contends that Sonatrach caused Duke LNG to experience a loss of LNG supply that affected Duke LNG’s obligations and termination rights under the Citrus Agreement. Citrus seeks monetary damages and a judicial determination that Duke LNG did not experience such a loss. After Citrus filed its lawsuit, Duke LNG terminated the Citrus Agreement and filed a counterclaim asserting that Citrus had breached the agreement by, among other things, failing to provide sufficient security under a letter of credit for the gas transactions. Citrus denies that Duke LNG had the right to terminate the agreement and contends that Duke LNG’s termination of the agreement was itself a breach, entitling Citrus to terminate the agreement and recover damages in the amount of approximately $187 million. The parties filed cross motions for partial summary judgment regarding the letter of credit issue which were subsequently denied by the Court. Other motions for partial summary judgment remain pending. No trial date has been set. It is not possible to predict with certainty whether Duke Capital will incur any liability or to estimate the damages, if any, that Duke Capital might incur in connection with the Sonatrach and Citrus matters.

Exxon Mobil Disputes. In April 2004, Mobil Natural Gas, Inc. (MNGI) and 3946231 Canada, Inc. (3946231, and collectively with MNGI, Exxon Mobil) filed a Demand for Arbitration against Duke Energy, DETMI, DTMSI Management Ltd. (DTMSI) and other subsidiaries of Duke Capital. MNGI and DETMI are the sole members of DETM. DTMSI and 3946231 are the sole beneficial owners of Duke Energy Marketing Limited Partnership (DEMLP, and with DETM, the Ventures). Among other allegations, Exxon Mobil alleges that DETMI and DTMSI engaged in wrongful actions relating to affiliate trading, payment of service fees, expense allocations and distribution of earnings in breach of agreements and fiduciary duties relating to the Ventures. Exxon Mobil seeks to recover actual damages, plus attorneys’ fees and exemplary damages; aggregate damages were not specified in the arbitration demand. Duke Energy denies these allegations, and has filed counterclaims asserting that Exxon Mobil breached its Ventures obligations and other contractual obligations. By order dated May 2, 2005, the arbitrators granted Duke Energy’s Motion for Partial Summary Judgment, effectively eliminating a significant portion of Exxon Mobil’s claims. Exxon Mobil filed a motion for reconsideration of the ruling as well as for an extension of the date for the arbitration hearing. Exxon Mobil also filed a motion to dismiss certain of Duke Energy’s counterclaims. Following a hearing in December 2005 on the motion for reconsideration, the arbitrators issued their ruling on January 26, 2006, generally reaffirming the original order, with a limited exception with respect to affiliate trades that is not expected to have a significant impact on the case. The panel also dismissed one of Duke Energy’s counterclaims. In response to a request from Exxon Mobil, the arbitration panel has postponed the commencement date of the arbitration hearing from January 2006 to October 2006 in Houston, Texas. On February 28, 2006, Duke Energy filed an expert report in support of its claims. On the same date, Exxon Mobil also filed a Second Amended Statement of Claim and various expert reports in support of its claims. Duke Energy is evaluating Exxon Mobil’s filings and expects to respond by August 2006. In August 2004, DEMLP initiated arbitration proceedings in Canada against certain Exxon Mobil entities asserting that those entities wrongfully terminated two gas supply agreements with the Ventures and wrongfully failed to assume certain related gas supply agreements with other parties. A hearing in the Canadian arbitration, originally scheduled to commence in August 2005 in Calgary, Canada, began in March 2006. It is not possible to predict with certainty the damages that might be incurred by Duke Capital as a result of these matters.

Other Litigation and Legal Proceedings. Duke Capital and its subsidiaries are involved in other legal, tax and regulatory proceedings in various forums regarding performance, contracts, royalty disputes,

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mismeasurement and mispayment claims (some of which are brought as class actions), and other matters arising in the ordinary course of business, some of which involve substantial amounts. Management believes that the final disposition of these proceedings will have no material adverse effect on Duke Capital’s consolidated results of operations, cash flows or financial position.

Duke Capital has exposure to certain legal matters that are described herein. As of December 31, 2005, Duke Capital has recorded reserves of approximately $150 million for these proceedings and exposures. These reserves represent management’s best estimate of probable loss as defined by SFAS No. 5.

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

Other Commitments and Contingencies

Hurricane Damage. Duke Capital continues to assess and monitor damage assessments related to Hurricanes Katrina and Rita in the Gulf Coast in 2005. Duke Capital has recorded all losses known to date, and is currently not aware of any additional damages incurred which will have a material adverse impact on its consolidated results of operations, cash flows, or financial position. Duke Capital incurred net expenses of approximately $40 million (net of reinsurance receivables) related to Hurricanes Katrina and Rita.

Other. As part of its normal business, Duke Capital is a party to various financial guarantees, performance guarantees and other contractual commitments to extend guarantees of credit and other assistance to various subsidiaries, investees and other third parties. To varying degrees, these guarantees involve elements of performance and credit risk, which are not included on the Consolidated Balance Sheets. The possibility of Duke Capital having to honor its contingencies is largely dependent upon future operations of various subsidiaries, investees and other third parties, or the occurrence of certain future events. (For further information see Note 17.)

In addition, Duke Capital enters into various fixed-price, non-cancelable commitments to purchase or sell power (tolling arrangements or power purchase contracts), take-or-pay arrangements, transportation or throughput agreements and other contracts that may or may not be recognized on the Consolidated Balance Sheets. Some of these arrangements may be recognized at market value on the Consolidated Balance Sheets as trading contracts or qualifying hedge positions included in Unrealized Gains or Losses on Mark-to-Market and Hedging Transactions.

In 1999, the Industrial Development Corp of the City of Edinburg, Texas (IDC) issued approximately $100 million in bonds to purchase equipment for lease to Duke Hidalgo (Hidalgo), a subsidiary of Duke Capital. Duke Capital unconditionally and irrevocably guaranteed the lease payments of Hidalgo to IDC through 2028. In 2000, Hidalgo was sold to Calpine Corporation and Duke Capital remained obligated under the lease guaranty. Total maximum exposure under the guarantee obligation as of December 31, 2005 is approximately $200 million, including principal and interest payments. In January 2006, Hidalgo and its subsidiaries filed for bankruptcy protection in connection with the previous bankruptcy filing by its parent, Calpine Corporation in December 2005. Duke Capital does not believe a loss under the guarantee obligation is probable as of December 31, 2005, but continues to evaluate the situation. Therefore, no reserves have been recorded for any contingent loss as of December 31, 2005. No demands for payment have been made under the guarantee. If losses are incurred under the guarantee, Duke Capital has certain rights which should allow it to economically recover such loss. As such recovery is a contingent gain, the timing of recognition of as well as the value of any future recovery may vary.

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Operating and Capital Lease Commitments

Duke Capital leases assets in several areas of its operations. Consolidated rental expense for operating leases was $80 million in 2005, $79 million in 2004 and $81 million in 2003, and included in Operation, Maintenance and Other on the Consolidated Statements of Operations. Amortization of assets recorded under capital leases was included in Depreciation and Amortization on the Consolidated Statements of Operations. 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, and capital leases as of December 31, 2005:

	Operating Leases		Capital Leases
	(in millions)
2006	$	39	$	3
2007		31		2
2008		28		2
2009		26		2
2010		23		—
Thereafter		94		1
Total future minimum lease payments	$	241	$	10

17. Guarantees and Indemnifications

Duke Capital and its subsidiaries have various financial and performance guarantees and indemnifications which are issued in the normal course of business. As discussed below, these contracts include performance guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications. Duke Capital and its subsidiaries enter into these arrangements to facilitate a commercial transaction with a third party by enhancing the value of the transaction to the third party.

Mixed Oxide (MOX) Guarantees. Duke COGEMA Stone & Webster, LLC (DCS) is the prime contractor to the DOE under a contract (the Prime Contract) pursuant to which DCS will design, construct, operate and deactivate a domestic MOX fuel fabrication facility (the MOX FFF) and provide for the irradiation of the MOX fuel. The domestic MOX fuel project was prompted by an agreement between the United States and the Russian Federation to dispose of excess plutonium in their respective nuclear weapons programs by fabricating MOX fuel and irradiating such MOX fuel in commercial nuclear reactors. As of December 31, 2005, Duke Capital, through its indirect wholly owned subsidiary, Duke Project Services Group Inc. (DPSG), held a 40% ownership interest in DCS.

The Prime Contract consists of a “Base Contract” phase and three successive option phases. The DOE has the right to extend the term of the Prime Contract to cover the option phases on a sequential basis, subject to DCS and the DOE reaching agreement, through good-faith negotiations on certain remaining open terms applying to each of the option phases. As of December 31, 2005, DCS’ performance obligations under the Prime Contract included only the Base Contract phase and an initial segment of the first option phase covering mission reactor modifications.

DPSG and the other owners of DCS have issued a guarantee to the DOE, which in conjunction with the applicable guarantee provisions (as clarified by an April 2004 amendment) in the Prime Contract (collectively, the DOE Guarantee), obligates the owners of DCS to jointly and severally guarantee to the DOE that the owners of DCS will reimburse the DOE (in the event that DCS fails to provide such reimbursement) for any payments made by the DOE to DCS pursuant to the Prime Contract that DCS expends on costs that are not “allowable”

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under certain applicable federal acquisition regulations. DPSG has recourse to the other owners of DCS for any amounts paid under the DOE Guarantee in excess of its proportional ownership percentage of DCS. Although the DOE Guarantee does not provide for a specific limitation on a guarantor’s reimbursement obligations, Duke Capital estimates that the maximum potential amount of future payments DPSG could be required to make under the DOE Guarantee is immaterial. As of December 31, 2005, Duke Capital had no liabilities recorded on its Consolidated Balance Sheets for the DOE Guarantee due to the immaterial amount of the estimated fair value of such guarantee.

In connection with the Prime Contract, Duke Energy, through Duke Power has entered into a subcontract with DCS (the Duke Power Subcontract) pursuant to which Duke Power will prepare its McGuire and Catawba nuclear reactors (the Mission Reactors) for use of the MOX fuel, and which also includes terms and conditions applicable to Duke Power’s purchase of MOX fuel produced at the MOX FFF for use in the Mission Reactors. The Duke Power Subcontract consists of a “Base Subcontract” phase and two successive option phases. DCS has the right to extend the term of the Duke Power Subcontract to cover the option phases on a sequential basis, subject to Duke Power and DCS reaching agreement, through good-faith negotiations on certain remaining open terms applying to each of the option phases. As of December 31, 2005, DCS’ performance obligations under the Duke Power Subcontract included only the Base Subcontract phase and an initial segment of the first option phase covering mission reactor modifications.

DPSG and the other owners of DCS have issued a guarantee to Duke Power (the Duke Power Guarantee) pursuant to which the owners of DCS jointly and severally guarantee to Duke Power all of DCS’ obligations under the Duke Power Subcontract or any other agreement between DCS and Duke Power implementing the Prime Contract. DPSG has recourse to the other owners of DCS for any amounts paid under the Duke Power Guarantee in excess of its proportional ownership percentage of DCS. Even though the Duke Power Guarantee does not provide for a specific limitation on a guarantor’s guarantee obligations, it does provide that any liability of such guarantor under the Duke Power Guarantee is directly related to and limited by the terms and conditions in the Duke Power Subcontract and any other agreements between Duke Power and DCS implementing the Duke Power Subcontract. Duke Capital is unable to estimate the maximum potential amount of future payments DPSG could be required to make under the Duke Power Guarantee due to the uncertainty of whether:

• DCS will exercise its options under the Duke Power Subcontract, which will depend upon whether the DOE will exercise its options under the Prime Contract, which, in turn, will depend on whether the U.S. Congress will authorize funding for DCS’ work under the Prime Contract, and

• The parties to the Prime Contract and the Duke Power Subcontract, respectively, will reach agreement on the remaining open terms for each option phase under the contracts, and if so, what the terms and conditions might be.

Duke Capital has not recorded on its Consolidated Balance Sheets any liability for the potential exposure under the Duke Power Guarantee per FIN 45 because DPSG and Duke Power are under common control.

In February 2006, Duke Capital sold all of its ownership interest in DPSG to a third party, without retaining any of DPSG’s obligations under the DOE Guarantee or the Duke Power Guarantee. As a result of such sale, Duke Capital ceased to have any indirect ownership interest in DCS. However, the sale did not include any changes to the Duke Power Subcontract, under which Duke Power is a subcontractor to DCS with respect to the domestic MOX fuel project.

Other Guarantees and Indemnifications. Duke Capital has issued performance guarantees to customers and other third parties that guarantee the payment and performance of other parties, including certain non-wholly

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owned entities. The maximum potential amount of future payments Duke Capital could have been required to make under these performance guarantees as of December 31, 2005 was approximately $575 million. Of this amount, approximately $375 million relates to guarantees of the payment and performance of less than wholly owned consolidated entities. Approximately $50 million of the performance guarantees expire between 2006 and 2008, with the remaining performance guarantees expiring after 2008 or having no contractual expiration. Additionally, Duke Capital has issued joint and several guarantees to some of the D/FD project owners, guaranteeing the performance of D/FD under its engineering, procurement and construction contracts and other contractual commitments. These guarantees have no contractual expiration and no stated maximum amount of future payments that Duke Capital could be required to make. Additionally, Fluor Enterprises Inc., as 50% owner in D/FD, has issued similar joint and several guarantees to the same D/FD project owners. In accordance with the D/FD partnership agreement, each of the partners is responsible for 50% of any payments to be made under those guarantees.

Westcoast has issued performance guarantees to third parties guaranteeing the performance of unconsolidated entities, such as equity method investments, and of entities previously sold by Westcoast to third parties. Those guarantees require Westcoast to make payment to the guaranteed third party upon the failure of such unconsolidated or sold entity to make payment under some of its contractual obligations, such as debt, purchase contracts and leases. The maximum potential amount of future payments Westcoast could have been required to make under those performance guarantees as of December 31, 2005 was approximately $15 million. Of those guarantees, approximately $10 million expire in 2006, with the remainder having no contractual expiration.

Duke Capital uses bank-issued stand-by letters of credit to secure the performance of non-wholly owned entities to a third party or customer. Under these arrangements, Duke Capital has payment obligations to the issuing bank which are triggered by a draw by the third party or customer due to the failure of the non-wholly owned entity to perform according to the terms of its underlying contract. The maximum potential amount of future payments Duke Capital could have been required to make under these letters of credit as of December 31, 2005 was approximately $525 million. Substantially all of these letters of credit were issued on behalf of less than wholly owned consolidated entities and expire in 2006.

Duke Capital has guaranteed certain issuers of surety bonds, obligating itself to make payment upon the failure of a non-wholly owned entity to honor its obligations to a third party. As of December 31, 2005, Duke Capital had guaranteed approximately $10 million of outstanding surety bonds related to obligations of non-wholly owned entities. The majority of these bonds expire in various amounts in 2006.

Natural Gas Transmission, International Energy, and Crescent have issued guarantees of debt and performance guarantees associated with non-consolidated entities and less than wholly owned consolidated entities. If such entities were to default on payments or performance, Natural Gas Transmission, International Energy, or Crescent would be required under the guarantees to make payment on the obligation of the less than wholly owned entity. As of December 31, 2005, Natural Gas Transmission was the guarantor of approximately $15 million of debt at Westcoast associated with less than wholly owned entities, which expire in 2019. International Energy was the guarantor of approximately $10 million of performance guarantees associated with less than wholly owned entities. Substantially all of these guarantees expire between 2006 and 2008. Crescent was the guarantor of approximately $15 million of debt associated with less than wholly owned entities, which expire in 2006.

Duke Capital has issued guarantees to customers or other third parties related to the payment or performance obligations of certain entities that were previously wholly owned by Duke Capital but which have been sold to

F-84

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

third parties, such as DukeSolutions, Inc. (DukeSolutions) and Duke Engineering & Services, Inc. (DE&S). These guarantees are primarily related to payment of lease obligations, debt obligations, and performance guarantees related to provision of goods and services. Duke Capital has received back-to-back indemnification from the buyer of DE&S indemnifying Duke Capital for any amounts paid by Duke Capital related to the DE&S guarantees. Duke Capital also received indemnification from the buyer of DukeSolutions for the first $2.5 million paid by Duke Capital related to the DukeSolutions guarantees. Further, Duke Capital granted indemnification to the buyer of DukeSolutions with respect to losses arising under some energy services agreements retained by DukeSolutions after the sale, provided that the buyer agreed to bear 100% of the performance risk and 50% of any other risk up to an aggregate maximum of $2.5 million (less any amounts paid by the buyer under the indemnity discussed above). Additionally, for certain performance guarantees, Duke Capital has recourse to subcontractors involved in providing services to a customer. These guarantees have various terms ranging from 2005 to 2019, with others having no specific term. Duke Capital is unable to estimate the total maximum potential amount of future payments under these guarantees, since some of the underlying agreements have no limits on potential liability.

In connection with Duke Capital’s sale of the Murray merchant generation facility to KGen, in August 2004, Duke Capital guaranteed in favor of a bank the repayment of any draws under a $120 million letter of credit issued by the bank to Georgia Power Company. The letter of credit, which expires in 2006, is related to the obligation of a KGen subsidiary under a seven-year power sales agreement, commencing in May 2005. Duke Capital will be required to ensure reissuance of this letter of credit or issue similar credit support until the power sales agreement expires in 2012. Duke Capital will operate the sold Murray facility under an operation and maintenance agreement with the KGen subsidiary. As a result, the guarantee has an immaterial fair value. Further, KGen has agreed to indemnify Duke Capital for any payments Duke Capital makes with respect to the $120 million letter of credit.

In 1999, IDC issued approximately $100 million in bonds to purchase equipment for lease to Hidalgo, a subsidiary of Duke Capital. Duke Capital unconditionally and irrevocably guaranteed the lease payments of Hidalgo to IDC through 2028. In 2000, Hidalgo was sold to Calpine Corporation and Duke Capital remained obligated under the lease guaranty. Total maximum exposure under the guarantee obligation as of December 31, 2005 is approximately $200 million, including principal and interest payments. In January 2006, Hidalgo and its subsidiaries filed for bankruptcy protection in connection with the previous bankruptcy filing by its parent, Calpine Corporation in December 2005. Duke Capital does not believe a loss under the guarantee obligation is probable as of December 31, 2005, but continues to evaluate the situation. Therefore, no reserves have been recorded for any contingent loss as of December 31, 2005. No demands for payment have been made under the guarantee. If losses are incurred under the guarantee, Duke Capital has certain rights which should allow it to economically recover such loss. As such recovery is a contingent gain, the timing of recognition of as well as the value of any future recovery may vary.

Duke Capital has entered into various indemnification agreements related to purchase and sale agreements and other types of contractual agreements with vendors and other third parties. These agreements typically cover environmental, tax, litigation and other matters, as well as breaches of representations, warranties and covenants. Typically, claims may be made by third parties for various periods of time, depending on the nature of the claim. Duke Capital’s potential exposure under these indemnification agreements can range from a specified amount, such as the purchase price, to an unlimited dollar amount, depending on the nature of the claim and the particular transaction. Duke Capital is unable to estimate the total potential amount of future payments under these indemnification agreements due to several factors, such as the unlimited exposure under certain guarantees.

As of December 31, 2005, the amounts recorded for the guarantees and indemnifications mentioned above are immaterial, both individually and in the aggregate.

F-85

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

18. Stock-Based Compensation

Certain employees of Duke Capital participate in Duke Energy’s stock compensation plans, including options, restricted stock awards, performance awards and phantom stock awards. Duke Energy’s 1998 Long-term Incentive Plan, as amended (the 1998 Plan), reserved 60 million shares of common stock for awards to employees and outside directors. Under the 1998 Plan, the exercise price of each option granted cannot be less than the market price of Duke Energy’s common stock on the date of grant and the maximum option term is 10 years. The vesting periods range from immediate to five years.

Upon the acquisition of Westcoast, Duke Energy converted all stock options outstanding under the 1989 Westcoast Long-term Incentive Share Option Plan to Duke Energy stock options. Certain of these options also provide for share appreciation rights under which the holder of a stock option may, in lieu of exercising the option, exercise the share appreciation right. The exercise price of these options equals the market price on the date of grant and the maximum option term is 10 years. The vesting periods range from immediate to four years.

The following tables show information regarding options to purchase Duke Energy’s common stock granted to employees of Duke Capital.

Stock Option Activity

	Options		Weighted-Average Exercise Price
	(in thousands)
Outstanding at December 31, 2002	26,077		$	34
Granted	6,972			15
Exercised	(334	)		11
Forfeited	(6,660	)		34
Outstanding at December 31, 2003	26,055			29
Exercised	(760	)		15
Forfeited	(3,057	)		32
Outstanding at December 31, 2004	22,238			29
Exercised	(1,716	)		20
Forfeited	(1,029	)		34
Outstanding at December 31, 2005	19,493		$	29

F-86

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

Stock Options at December 31, 2005

	Outstanding				Exercisable
Range of Exercise Prices	Number	Weighted-Average Remaining Life	Weighted-Average Exercise Price		Number	Weighted-Average Exercise Price
	(in thousands)	(in years)			(in thousands)
$9 to $14	3,229	7.1	$	14	1,272	$	14
$15 to $20	1,572	7.2		18	387		18
$21 to $24	298	2.5		22	298		22
$25 to $28	3,605	3.6		26	3,605		26
$29 to $33	2,691	2.8		30	2,668		30
$34 to $37	731	5.9		34	591		34
$38 to $39	4,333	6.0		38	4,299		38
> $39	3,034	5.0		43	3,034		43
Total	19,493	5.2	$	29	16,154	$	32

On December 31, 2004, certain employees of Duke Capital had 16.6 million exercisable options with a $32 weighted-average exercise price. On December 31, 2003, certain employees of Duke Capital had 15.9 million exercisable options with a $32 weighted-average exercise price.

There were no option grants during the years ended December 31, 2005 and 2004. The weighted-average fair value per option granted in 2003 was $4. The fair value of each option grant was estimated on the date of grant using the Black-Scholes option-pricing model.

Weighted-Average Assumptions for Option-Pricing

	2003
Stock dividend yield	3.5	%
Expected stock price volatility	37.5	%
Risk-free interest rates	3.6	%
Expected option lives	7 years

The 1998 Plan allows for a maximum of twelve million shares of common stock to be issued under restricted stock awards, performance awards and phantom stock awards. Stock-based performance awards granted under the 1998 Plan vest over periods from three to seven years. Vesting can occur in three years, at the earliest if performance is met. Duke Energy awarded 1,005,020 shares (fair value of approximately $27 million at grant dates) in 2005, 1,442,140 shares (fair value of approximately $31 million at grant dates) in 2004, and 75,000 shares (fair value of approximately $2 million at grant dates) in 2003. Compensation expense for the performance awards is charged to earnings over the vesting period and totaled $20 million in 2005, $8 million in 2004 and $2 million in 2003.

Phantom stock awards granted under the 1998 Plan vest over periods from one to five years. Duke Energy awarded 924,170 shares (fair value of approximately $25 million at grant dates) in 2005, 1,169,090 shares (fair value of approximately $25 million at grant dates) in 2004, and 285,000 shares (fair value of approximately $5 million at grant dates) in 2003. Compensation expense for the phantom awards is charged to earnings over the vesting period and totaled $17 million in 2005, $11 million in 2004 and $6 million in 2003.

F-87

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

Restricted stock awards granted under the 1998 Plan vest over periods from one to five years. Duke Energy awarded 47,000 shares (fair value of approximately $1 million at grant dates) in 2005, 169,160 shares (fair value of approximately $4 million at grant dates) in 2004, and 19,897 shares (fair value of less than $1 million at grant dates) in 2003. Compensation expense for restricted awards is charged to earnings over the vesting period and totaled $1 million in 2005, less than $1 million in 2004 and $1 million in 2003.

Duke Energy’s 1996 Stock Incentive Plan (the 1996 Plan) allowed four million shares of common stock for awards to employees. The 1996 Plan is not available for new awards and there are no awards outstanding under this plan. Compensation expense for restricted awards is charged to earnings over the vesting period and totaled $0 in 2005 and less than $1 million in 2004 and 2003.

19. Employee Benefit Plans

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

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 did not make any contributions to its defined benefit retirement plan in 2005. Duke Energy made voluntary contributions of $250 million in 2004 and $181 million in 2003. Duke Energy does not anticipate making a contribution to the plan in 2006.

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 retirement plan is 12 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 over five years. Duke Energy uses a September 30 measurement date for its defined benefit retirement plan.

The fair value of Duke Energy’s plan assets was $2,948 million as of September 30, 2005 and $2,477 million as of September 30, 2004. The projected benefit obligation was $2,853 million as of September 30, 2005 and $2,693 million as of September 30, 2004. The accumulated benefit obligation was $2,753 million at September 30, 2005 and $2,607 million at September 30, 2004.

Duke Capital’s net periodic pension benefit for the U.S. plan, as allocated by Duke Energy, was $21 million for 2005, $28 million for 2004 and $25 million for 2003.

Assumptions Used for Duke Energy’s U.S. Pension Benefits Accounting

	2005	2004	2003
	(percents)
Benefit Obligations
Discount rate	5.50	6.00	6.00
Salary increase	5.00	5.00	5.00
Net Period Benefit Cost
Discount rate	6.00	6.00	6.75
Salary increase	5.00	5.00	5.00
Expected long-term rate of return on plan assets	8.50	8.50	8.50

F-88

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

Duke Energy also sponsors, and Duke Capital 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 Capital expensed plan contributions, as allocated by Duke Energy, of $20 million in 2005, $20 million in 2004 and $24 million in 2003.

Duke Energy also maintains, and Duke Capital participates in, a non-qualified, non-contributory defined benefit retirement plan which covers certain U.S. executives. There are no plan assets. The projected benefit obligation for this plan was $86 million as of September 30, 2005 and $86 million as of September 30, 2004. Duke Capital recorded net periodic pension cost, as allocated by Duke Energy, of $4 million in 2005, $5 million in 2004, and $6 million in 2003.

Westcoast Canadian Retirement Plans. Westcoast and its subsidiaries maintain contributory and non-contributory defined benefit (DB) and defined contribution (DC) retirement plans covering substantially all employees. The DB plans provide retirement benefits based on each plan participant’s years of service and final average earnings. Under the DC plans, company contributions are determined according to the terms of the plan and based on each plan participant’s age, years of service and current eligible earnings.

Westcoast’s policy is to fund the DB plans on an actuarial basis and in accordance with Canadian pension standards legislation, in order to accumulate assets sufficient to meet benefits to be paid. Contributions to the DC plans are determined in accordance with the terms of the plan. Duke Energy made contributions to the Westcoast DB plans of approximately $42 million in 2005, $26 million in 2004, and $10 million in 2003. Duke Energy anticipates that it will make contributions of approximately $40 million to the Westcoast DB plans in 2006. Duke Energy also made contributions to the DC plans of $3 million in 2005, $3 million in 2004, and $3 million in 2003. Duke Energy anticipates that it will make contributions to the DC plans of approximately $4 million in 2006.

The prior service cost and 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 DB retirement plans is 12 years. Westcoast uses a September 30 measurement date for its plans.

Components of Net Periodic Pension Costs for Westcoast—for the years ended December 31,

	2005			2004			2003
	(in millions)
Service cost benefit earned during the year	$	9		$	8		$	7
Interest cost on projected benefit obligation		29			26			23
Expected return on plan assets		(27	)		(24	)		(24	)
Amortization of prior service cost		1			—			—
Curtailment (gain)/loss		—			—			2
Amortization of loss		4			3			—
Special termination benefit cost		—			1			5
Net periodic pension costs	$	16		$	14		$	13

F-89

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

Reconciliation of Funded Status to Net Amount Recognized for Westcoast—as of December 31,

	2005			2004
	(in millions)
Change in Projected Benefit Obligation
Obligation at prior measurement date	$	480		$	434
Service cost		9			8
Interest cost		29			26
Actuarial (gain)/loss		89			(7	)
Participant contributions		3			2
Plan amendments		—			6
Special termination benefits		—			6
Benefits paid		(28	)		(26	)
Obligation assumed from acquisition		11			—
Foreign currency exchange rate change		23			31
Obligation at measurement date	$	616		$	480
Change in Fair Value of Plan Assets
Plan assets at prior measurement date	$	362		$	324
Actual return on plan assets		63			27
Benefits paid		(28	)		(26	)
Employer contributions		48			11
Plan participants’ contributions		3			2
Assets received on acquisition		10			—
Foreign currency exchange rate change		17			24
Plan assets at measurement date	$	475		$	362
Funded status	$	(141	)	$	(118	)
Unrecognized net experience loss		122			68
Unrecognized prior service cost		8			9
Contributions made after measurement date		13			19
Net amount recognized	$	2		$	(22	)

For Westcoast, the accumulated benefit obligation was $562 million at September 30, 2005 and $435 million at September 30, 2004.

Amounts Recognized in the Consolidated Balance Sheets for Westcoast Consist of:—as of December 31,

	2005			2004
	(in millions)
Accrued pension liability	$	(76	)	$	(53	)
Intangible asset		7			—
Deferred income tax asset		25			13
Accumulated other comprehensive income		46			18
Net amount recognized	$	2		$	(22	)

F-90

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

Additional Information for Westcoast:

	2005		2004
	(in millions)
Increase/(decrease) in minimum liability included in other comprehensive income, net of tax	$	28	$	(3	)

Information for Plans with Accumulated Benefit Obligation in Excess of Plan Assets for Westcoast

	2005		2004
	(in millions)
Projected benefit obligation	$	602	$	479
Accumulated benefit obligation		551		434
Fair value of plan assets		464		361

Assumptions Used for Pension Benefits Accounting for Westcoast

	2005	2004	2003
	(percents)
Benefit Obligations
Discount rate	5.00	6.25	6.00
Salary increase	3.25	3.25	3.25
Net Period Benefit Cost
Discount rate	6.25	6.00	6.50
Salary increase	3.25	3.25	3.25
Expected long-term rate of return on plan assets	7.50	7.50	7.75

For Westcoast the discount rate used to determine the pension obligation is prescribed as the yield on Canadian corporate AA bonds at the measurement date of September 30. The yield is selected based on bonds with cash flows that match the timing and amount of the expected benefit payments under the plan.

Plan Assets Westcoast:

	Target Allocation		Percentage of Plan Assets at September 30
Asset Category			2005		2004
Canadian equity securities	30	%	42	%	40	%
US equity securities	15		11		12
EAFE securities(a)	15		15		16
Debt securities	40		32		32
Total	100	%	100	%	100	%

(a) EAFE—Europe, Australasia, Far East

Westcoast assets for registered pension plans are maintained by a Master Trust. The investment objective of the master trust is to achieve reasonable returns on trust assets, subject to a prudent level of portfolio risk, for the purpose of enhancing the security of benefits for participants. The asset allocation targets were set after

F-91

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

considering the investment objective and the risk profile with respect to the trust. Canadian equities are held for their high expected return. Non-Canadian equities are held for their high expected return as well as diversification relative to Canadian equities and debt securities. Debt securities are also held for diversification.

The long-term rate of return of 7.25% as of September 30, 2005 for the Westcoast assets was developed using a weighted-average calculation of expected returns based primarily on future expected returns across classes considering the use of active asset managers. The weighted-average returns expected by asset classes were 2.7% for Canadian equities, 1.4% for U.S. equities, 1.45% for Europe, Australasia and Far East equities, and 1.7% for fixed income securities.

The following benefit payments, which reflect expected future service, as appropriate, as expected to be paid over the next five years and thereafter:

Expected Benefit Payments

	Westcoast Plans
	(in millions)
2006	$	31
2007		31
2008		32
2009		32
2010		34
2011-2015		198

Westcoast also provides non-registered defined benefit supplemental pensions to all employees who retire under a defined benefit registered pension plan and whose pension is limited by the maximum pension limits under the Income Tax Act (Canada). Westcoast recognized net periodic pension expense of $5 million in 2005, $4 million in 2004, and $4 million in 2003. There are no plan assets. The projected benefit obligation was $84 million as of September 30, 2005 and $66 million as of September 30, 2004.

Duke Energy U.S. Other Post-Retirement Benefits. Duke Capital and most of its subsidiaries, in conjunction with Duke Energy provide 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 14 years.

The fair value of Duke Energy’s plan assets was $242 million as of September 30, 2005 and $243 million as of September 30, 2004. The accumulated post-retirement benefit obligation was $791 million as of September 30, 2005 and $782 million as of September 30, 2004.

Duke Capital’s net periodic post-retirement benefit cost, as allocated by Duke Energy, was $19 million for 2005 and 2004 and $24 million for 2003.

F-92

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

Assumptions Used in Duke Energy’s U.S. Other Postretirement Benefits Accounting

	2005	2004	2003
	(percents)
Benefit Obligations
Discount rate	5.50	6.00	6.00
Salary increase	5.00	5.00	5.00
Net Period Benefit Cost
Discount rate	6.00	6.00	6.75
Salary increase	5.00	5.00	5.00
Expected long-term rate of return on plan assets	8.50	8.50	8.50

For measurement purposes, the net per capita cost of covered health care benefits for employees who are not eligible for Medicare is assumed to have an initial annual rate of increase of 8.5% in 2005 that will gradually decrease to 5.5% in 2009. For employees who are eligible for Medicare, an initial annual rate of increase of 11.5% in 2005 will gradually decrease to 5.5% in 2012. Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A 1% increase or decrease in the assumed health care trend rate would change the allocated net periodic post-retirement benefit cost for Duke Capital to increase or decrease by approximately $1 million.

Westcoast Other Post-Retirement Benefits. Westcoast provides health care and life insurance benefits for retired employees on a non-contributory basis. Employees are eligible for these benefits if they have met age and service requirements at retirement, as defined in the plans. Effective December 31, 2003, a new plan was implemented for all non bargaining employees and the majority of bargaining employees. The new plan will apply for employees retiring on and after January 1, 2006. The new plan is predominantly a defined contribution plan as compared to the existing defined benefit program.

Other post-retirement benefit costs are accrued over an employee’s active service period to the date of full benefits eligibility. Actuarial gains and losses are amortized over the average remaining service period of the active employees covered by the plans. The average remaining service period of the active employees is 18 years.

Components of Net Periodic Post-Retirement Benefit Costs for Westcoast—for the years ended December 31,

	2005			2004			2003
	(in millions)
Service cost benefit earned during the year	$	3		$	3		$	2
Interest cost on accumulated post-retirement benefit obligation		6			5			4
Amortization of prior service cost		(1	)		(1	)		—
Curtailment loss		—			—			1
Amortization of loss		1			1			—
Net periodic post-retirement benefit costs	$	9		$	8		$	7

F-93

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

Reconciliation of Funded Status to Accrued Post-Retirement Benefit Costs—as of December 31,

	2005			2004
	(in millions)
Change in Benefit Obligation
Accumulated post-retirement benefit obligation at prior measurement date	$	86		$	81
Service cost		3			3
Interest cost		6			5
Actuarial (gain) loss		21			(5	)
Benefits paid		(3	)		(3	)
Foreign currency impact		4			5
Accumulated post-retirement benefit obligation at measurement date	$	117		$	86
Change in Fair Value of Plan Assets
Plan assets at prior measurement date	$	—		$	—
Benefits paid		(3	)		(3	)
Employer contributions		3			3
Plan assets at measurement date	$	—		$	—
Funded status	$	(117	)	$	(86	)
Employer contributions made after measurement date		1			1
Unrecognized net experience loss		49			28
Unrecognized prior service cost		(11	)		(12	)
Accrued post-retirement benefit costs	$	(78	)	$	(69	)

Assumptions Used for Post-Retirement Benefits Accounting for Westcoast

	2005	2004	2003
	(percents)
Benefit Obligations
Discount rate	5.00	6.25	6.00
Salary increase	3.25	3.25	3.25
Net Period Benefit Cost
Discount rate	6.25	6.00	6.50
Salary increase	3.25	3.25	3.25

For Westcoast the discount rate used to determine the post-retirement obligation is prescribed as the yield on Canadian corporate AA bonds at the measurement date of September 30. The yield is selected based on bonds with cash flows that match the timing and amount of the expected benefit payments under the plan.

Assumed Health Care Cost Trend Rates for Westcoast

	2005		2004
Health care cost trend rate assumed for next year	7.00	%	8.00	%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)	5.00	%	5.00	%
Year that the rate reaches the ultimate trend rate	2008		2008

F-94

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

Sensitivity to Changes in Assumed Health Care Cost Trend Rates Westcoast Plans

	1-Percentage- Point Increase		1-Percentage- Point Decrease
	(millions)
Effect on total service and interest costs	$	1	$	(1	)
Effect on post-retirement benefit obligation		15		(13	)

Westcoast expects to make the future benefit payments, which reflect expected future service, as appropriate. The following benefit payments are expected to be paid over each of the next five years and thereafter.

Expected Benefit Payments

	Westcoast Plans
	(in millions)
2006	$	4
2007		4
2008		4
2009		4
2010		5
2011-2015		27

20. Other Income and Expense, net

The components of Other Income and Expenses, net on the Consolidated Statements of Operations for the years ended December 31, 2005, 2004 and 2003 are as follows:

	For the years ended December 31,
	2005			2004		2003
	(in millions)
Income/(Expense)
Management fees charged to Duke Power	$	68		$	155	$	134
Interest income		69			67		14
Foreign exchange (losses) gains		(9	)		22		2
AFUDC allowance		8			9		33
Realized and unrealized mark-to-market impact on discontinued hedges		(64	)		—		—
Income related to a distribution from an investment at Crescent		45			—		—
Other		32			39		33
Total	$	149		$	292	$	216

21. Subsequent Events

For information on subsequent events related to acquisitions and dispositions, regulatory matters, risk management and hedging activities, credit risk, and financial instruments, discontinued operations and assets held for sale, debt and credit facilities, commitments and contingencies, and guarantees and indemnifications, see Notes 2, 4, 7, 12, 14, 16, and 17.

F-95

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

Subsequent events have not been otherwise modified or updated from those presented in Duke Capital’s Form 10-K for the year ended December 31, 2005, except for the following sections discussed below:

• Acquisitions and Dispositions—Cinergy

• Acquisitions and Dispositions—Gas Spin

• Discontinued Operations—Other/DENA

• Impairments and Other Charges—DEI

Acquisitions and Dispositions—Cinergy. On April 3, 2006, Duke Energy completed its previously announced merger with Cinergy. See Note 1 for more information. In conjunction with the merger, Duke Energy transferred the operations of Duke Energy Merchants, LLC and Duke Energy Merchant Finance, LLC (collectively DEM) to Duke Capital, Duke Capital transferred the operations of its wholly-owned captive insurance subsidiary, Bison Insurance Company Limited (Bison), to Duke Energy and Duke Capital indirectly transferred to CG&E, a subsidiary of Cinergy, its ownership interest in DENA’s Midwestern assets.

In connection with the transfer of the Midwestern assets, Duke Capital transferred to CG&E approximately $1.6 billion of assets at their carrying value and approximately $0.1 billion of liabilities at their carrying value, for a net transfer of approximately $1.5 billion. In connection with the transfer of DENA’s Midwestern assets, Duke Capital and CG&E entered into an arrangement through April 2016, unless otherwise extended by the parties, whereby Duke Capital will reimburse CG&E in the event of certain cash shortfalls that may result from CG&E’s ownership of the Midwestern assets.

As a result of Duke Energy’s merger with Cinergy, Duke Capital and its subsidiaries entered into a tax sharing agreement with Duke Energy, effective April 1, 2006, where the separate return method is used to allocate income taxes to the subsidiaries based on the results of their operations. The accounting for income taxes essentially represents the income taxes that Duke Capital would incur if Duke Capital were a separate company filing its own tax return as a C-Corporation. Prior to entering into this tax sharing agreement, Duke Capital and Duke Energy Americas (DEA) were pass-through entities for U.S. income tax purposes. As a result, on April 1, 2006, all deferred taxes related to Duke Capital and DEA, which previously flowed through to Duke Capital’s parent, Duke Energy, were reinstated, resulting in an increase in Member’s Equity of approximately $37 million.

Acquisitions and Dispositions—Gas Spin. In June 2006, the Board of Directors of Duke Energy authorized management to pursue a plan to create two separate publicly traded companies by spinning off Duke Energy’s natural gas business to Duke Energy shareholders. The new gas company, which would be named Spectra Energy, would consist primarily of Duke Capital’s Natural Gas Transmission and Field Services businesses segments. Prior to the distribution, Duke Energy expects to implement an internal reorganization pursuant to which all of the businesses and assets of Duke Capital other than Duke Energy’s natural gas transmission and storage, distribution, and gathering and processing businesses (i.e., such as Crescent, Commercial Power, and Duke Energy International), will be transferred to a new, wholly-owned, direct subsidiary of Duke Energy. Duke Capital will then be transferred to and will thereafter be a direct, wholly-owned subsidiary of Spectra Energy. Duke Energy is targeting a January 1, 2007 effective date for the transaction. As a result of the spin-off, Duke Capital is expected to indemnify Duke Energy for certain amounts paid under existing guarantees of wholly-owned subsidiaries that will become guarantees of third party performance upon the separation of the gas and power businesses.

Discontinued Operations—Other (DENA). In January 2006, a Duke Capital subsidiary signed an agreement with LS Power to purchase DENA’s remaining fleet of power generation assets outside the Midwest

F-96

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

(see Note 12 for additional information). In May 2006, the transaction with LS Power closed and total proceeds from the sale were approximately $1.56 billion, including certain working capital adjustments.

In conjunction with the exit plan, management estimated that additional charges would be incurred of $600 million to $800 million. Approximately $700 million of costs had been incurred from the announcement date through June 30, 2006. Management does not anticipate any additional material charges related to the DENA exit plan.

Impairments and Other Charges—DEI. During the three months ended June 30, 2006, International Energy recorded a $55 million other-than temporary impairment charge related to an investment in Compañía de Servicios de Compresión de Campeche, S.A. de C.V. (Campeche), a natural gas compression facility in the Cantarell oil field in the Gulf of Mexico. Campeche project revenues are generated from the gas compression services agreement (GCSA) with the Mexican National Oil Company (PEMEX). The current GCSA expires on November 7, 2006 and there have been ongoing discussions between Campeche and PEMEX to either sell the Campeche investment or renew the GCSA. In the second quarter of 2006, based on ongoing discussions with PEMEX, it was determined that there was a limited future need for Campeche’s gas compression services. Management of International Energy determined that it is probable that the Campeche investment will ultimately be sold or the GCSA will be renewed for a significantly lower rate. An other-than-temporary impairment loss was recorded to reduce the carrying value to $14 million, which is management’s best estimate of realizable value.

22. Quarterly Financial Data (Unaudited)

	First Quarter		Second Quarter		Third Quarter			Fourth Quarter		Total
	(In millions, except per share data)
2005
Operating revenues	$	4,063	$	4,048	$	1,424		$	1,814	$	11,349
Operating income		432		547		993			376		2,348
Net income (loss)		652		129		(534	)		427		674
2004
Operating revenues	$	3,855	$	3,552	$	3,659		$	4,397	$	15,463
Operating income		158		493		441			490		1,582
Net income (loss)		102		291		(1,009	)		502		(114	)

During the first quarter of 2005, Duke Capital recorded the following unusual or infrequently occurring items: an approximate $0.9 billion (net of minority interest of approximately $0.3 billion) pre-tax gain on sale of Duke Energy Field Services, LLC’s wholly-owned subsidiary, Texas Eastern Products Pipeline Company, LLC (see Note 2); an approximate $100 million pre-tax gain on sale of Duke Capital’s limited partner interest in TEPPCO Partners, L.P. (see Note 2); an approximate $21 million pre-tax gain on sale of DENA’s partially completed Grays Harbor power plant in Washington State (see Note 2); and an approximate $230 million of unrealized pre-tax losses on certain 2005 and 2006 derivative contracts hedging Field Services commodity price risk which were discontinued as cash flow hedges as a result of the anticipated deconsolidation of DEFS by Duke Capital (see Note 2).

During the third quarter of 2005, Duke Capital recorded the following unusual or infrequently occurring items: an approximate $1.3 billion pre-tax charge for the impairment of assets and the discontinuance of hedge accounting for certain positions at DENA, as a result of the decision to exit substantially all of DENA’s remaining assets and

F-97

Duke Capital LLC

Notes To Consolidated Financial Statements—(Continued)

For the Years Ended December 31, 2005, 2004 and 2003

contracts (see Note 12); an approximate $575 million pre-tax gain associated with the transfer of 19.7% of Duke Capital’s interest in DEFS to ConocoPhillips, Duke Capital’s co-equity owner in DEFS, which reduced Duke Capital’s ownership interest in DEFS from 69.7% to 50% (see Note 2); an approximate $105 million of unrealized and realized pre-tax losses on certain 2005 and 2006 derivative contracts hedging Field Services commodity price risk which were discontinued as cash flow hedges as a result of the deconsolidation of DEFS by Duke Capital (see Note 2); and approximately $90 million of gains at Crescent due primarily to income related to a distribution from an interest in a portfolio of office buildings and a large land sale.

During the fourth quarter of 2005, Duke Capital recorded the following unusual or infrequently occurring items: pre-tax gain of approximately $380 million, which reverses a portion of the third quarter DENA impairment, attributable to the planned asset sales to LS Power; and pre-tax losses of approximately $475 million for portfolio exit costs including severance, retention and other transaction costs at DENA (see Note 12).

During the first quarter of 2004, Duke Capital recorded the following unusual or infrequently occurring items: a $256 million pre-tax gain on sale of International Energy’s Asia-Pacific Business (see Note 12); and an approximate $360 million pre-tax charge in 2004 associated with the sale of DENA’s Southeast Plants (see Note 2).

During the second quarter of 2004, Duke Capital recorded the following unusual or infrequently occurring items: a $109 million (net of minority interest of $5 million) pre-tax gain related to the settlement of the Enron bankruptcy proceedings; a $39 million net increase in the pre-tax gains ($30 million increase to the after tax gains) originally recorded on the sales of International Energy’s Asia-Pacific Business (see Note 12) and its European Business; a $52 million release of various income tax reserves (see Note 5); and a $105 million pre-tax charge related to the California and Western U.S. energy markets settlement (see Note 16).

During the third quarter of 2004, Duke Capital recorded the following unusual or infrequently occurring items: a $48 million tax benefit related to the realignment of certain subsidiaries of Duke Capital and the pass-through structure of these for U.S. income tax purposes ($20 million is included in continuing operations, see Note 5, the remainder is in discontinued operations); a $1,030 million one time tax expense in 2004 related to the realignment of certain subsidiaries of Duke Capital and the pass-through structure of these for U.S. income tax purposes (included in income from continuing operations as discussed in Note 1); and impairments of $45 million (net of minority interest of $26 million) related to asset impairments, losses on asset sales and write-down of equity investments at Field Services (see Note 11).

During the fourth quarter of 2004, Duke Capital recorded the following unusual or infrequently occurring items: $180 million of pre-tax gains associated with the sales of two DENA partially completed facilities, Luna and Moapa (see Note 12); a $59 million pre-tax correction of immaterial accounting errors related to the elimination of intercompany reserves at Bison (see Note 1); a $28 million pre-tax charge at Bison for reinsurance policies which have certain retrospective rating provisions ($12 million of which relates to the correction of an immaterial accounting error related to prior years) (see Note 1); a $51 million pre-tax charge related to the sale of DETM contracts that were held in a net liability position; $20 million in contract termination charges related to the DENA partially completed plant at Grays Harbor (see Note 12); approximately $42 million of impairment charges related to two Crescent residential developments in Payson, Arizona and one in Austin, Texas (see Note 11); and $8 million in bad debt charges recorded by Crescent related to notes receivable due from Rim Golf Investor LLC and Chaparral Pines Investor LLC. The bad debt charges are recorded in Operation, Maintenance and Other on the Consolidated Statement of Operations.

F-98

DUKE CAPITAL LLC

SCHEDULE II—VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

			Additions
	Balance at Beginning of Period		Charged to Expense		Charged to Other Accounts		Deductions(a)		Balance at End of Period
	(In millions)
December 31, 2005:
Allowance for doubtful accounts	$	128	$	21	$	10	$	38	$	121
Other(b)		691		320		54		395		670
	$	819	$	341	$	64	$	433	$	791
December 31, 2004:
Allowance for doubtful accounts	$	272	$	66	$	3	$	213	$	128
Other(b)		969		219		94		591		691
	$	1,241	$	285	$	97	$	804	$	819
December 31, 2003:
Allowance for doubtful accounts	$	351	$	46	$	14	$	139	$	272
Other(b)		1,042		341		4		418		969
	$	1,393	$	387	$	18	$	557	$	1,241

(a) Principally cash payments and reserve reversals.

(b) Principally property insurance reserves and litigation and other reserves, included in Other Current Liabilities, or Deferred Credits and Other Liabilities on the Consolidated Balance Sheets.

F-99

DUKE CAPITAL LLC

INDEX TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS

Item		Page
	UNAUDITED CONSOLIDATED STATEMENTS OF OPERATIONS FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2006 AND 2005.	F-101
	UNAUDITED CONSOLIDATED BALANCE SHEETS AS OF SEPTEMBER 30, 2006 AND DECEMBER 31, 2005	F-102
	UNAUDITED CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2006 AND 2005	F-104
	UNAUDITED CONSOLIDATED STATEMENTS OF MEMBER’S EQUITY AND COMPREHENSIVE INCOME FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2006 AND 2005	F-105
	UNAUDITED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS	F-106

F-100

Duke Capital LLC

Consolidated Statements of Operations

(Unaudited)

(In millions)

	Nine Months Ended September 30,
	2006			2005
Operating Revenues
Non-regulated electric, natural gas, natural gas liquids and other	$	1,584		$	6,881
Regulated natural gas and natural gas liquids		2,927			2,654
Total operating revenues		4,511			9,535
Operating Expenses
Natural gas and petroleum products purchased		1,258			5,677
Operation, maintenance and other		1,205			1,411
Fuel used in electric generation and purchased power		285			290
Depreciation and amortization		436			550
Property and other taxes		186			201
Impairment and other charges		—			140
Total operating expenses		3,370			8,269
Gains on Sales of Investments in Commercial and Multi-Family Real Estate		201			117
Gains on Sales of Other Assets and Other, net		276			588
Operating Income		1,618			1,971
Other Income and Expenses
Equity in earnings of unconsolidated affiliates		551			256
(Losses) Gains on sales and impairments of equity investments		(20	)		1,225
Gain on sale of subsidiary stock		15			—
Other income and expenses, net		123			76
Total other income and expenses		669			1,557
Interest Expense		542			596
Minority Interest Expense		50			508
Earnings From Continuing Operations Before Income Taxes		1,695			2,424
Income Tax Expense from Continuing Operations		616			950
Income From Continuing Operations		1,079			1,474
Income (Loss) From Discontinued Operations, net of tax		(90	)		(1,227	)
Net Income	$	989		$	247

See Notes to Unaudited Consolidated Financial Statements

F-101

Duke Capital LLC

Consolidated Balance Sheets

(Unaudited)

(In millions)

	September 30, 2006		December 31, 2005
ASSETS
Current Assets
Cash and cash equivalents	$	577	$	491
Short-term investments		338		521
Receivables (net of allowance for doubtful accounts of $93 at September 30, 2006 and $121 at December 31, 2005)		822		1,935
Inventory		500		444
Assets held for sale		36		1,528
Unrealized gains on mark-to-market and hedging transactions		6		90
Other		339		1,599
Total current assets		2,618		6,608
Investments and Other Assets
Investments in unconsolidated affiliates		2,069		1,931
Goodwill		3,900		3,775
Notes receivable		68		138
Unrealized gains on mark-to-market and hedging transactions		65		87
Assets held for sale		157		3,597
Investments in residential, commercial and multi-family real estate (net of accumulated depreciation of $17 at December 31, 2005)		—		1,281
Other		724		737
Total investments and other assets		6,983		11,546
Property, Plant and Equipment
Cost		18,688		19,341
Less accumulated depreciation and amortization		3,936		3,655
Net property, plant and equipment		14,752		15,686
Regulatory Assets and Deferred Debits		1,138		1,216
Total Assets	$	25,491	$	35,056

See Notes to Unaudited Consolidated Financial Statements

F-102

Duke Capital LLC

Consolidated Balance Sheets

(Unaudited)

(In millions)

	September 30, 2006		December 31, 2005
LIABILITIES AND MEMBER’S EQUITY
Current Liabilities
Accounts payable	$	282	$	1,837
Notes payable and commercial paper		—		83
Taxes accrued		289		258
Interest accrued		165		155
Liabilities associated with assets held for sale		36		1,488
Current maturities of long-term debt		1,151		1,394
Unrealized losses on mark-to-market and hedging transactions		73		207
Other		791		1,892
Total current liabilities		2,787		7,314
Long-term Debt		8,778		8,790
Deferred Credits and Other Liabilities
Deferred income taxes		3,102		3,167
Unrealized losses on mark-to-market and hedging transactions		31		19
Liabilities associated with assets held for sale		119		2,085
Other		1,210		1,428
Total deferred credits and other liabilities		4,462		6,699
Commitments and Contingencies
Minority Interests		792		749
Member’s Equity
Member’s Equity		7,582		10,848
Accumulated other comprehensive income		1,090		656
Total member’s equity		8,672		11,504
Total Liabilities and Member’s Equity	$	25,491	$	35,056

See Notes to Unaudited Consolidated Financial Statements

F-103

Duke Capital LLC

Consolidated Statements of Cash Flows

(Unaudited)

(In millions)

	Nine Months Ended September 30,
	2006			2005
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	989		$	247
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		458			611
Gains on sales of investments in commercial and multi-family real estate		(201	)		(117	)
Gains on sales of equity investments and other assets		(311	)		(1,276	)
Impairment charges		20			123
Deferred income taxes		165			(338	)
Minority Interest		50			508
Equity in earnings of unconsolidated affiliates		(551	)		(256	)
Contribution to company-sponsored pension plans		(35	)		(32	)
(Increase) decrease in
Net realized and unrealized mark-to-market and hedging transactions		63			927
Receivables		921			31
Inventory		61			(150	)
Other current assets		1,359			(1,244	)
Increase (decrease) in
Accounts payable		(1,138	)		(89	)
Taxes accrued		49			215
Other current liabilities		(750	)		813
Capital expenditures for residential real estate		(322	)		(276	)
Cost of residential real estate sold		143			159
Other, assets		(473	)		819
Other, liabilities		(128	)		—
Net cash provided by operating activities		369			675
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(684	)		(717	)
Investment expenditures		(80	)		(19	)
Acquisitions, net of cash acquired		(89	)		(293	)
Purchases of available-for-sale securities		(8,740	)		(24,156	)
Proceeds from sales and maturities of available-for-sale securities		8,886			23,368
Net proceeds from the sales of equity investments and other assets, and sales of and collections on notes receivable		2,040			2,364
Proceeds from the sales of commercial and multi-family real estate		254			185
Settlement of net investment hedges and other investing derivatives		(134	)		(244	)
Other		(31	)		(19	)
Net cash provided by investing activities		1,422			469
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the issuance of long-term debt		1,430			286
Payments for the redemption of:
Long-term debt		(705	)		(769	)
Preferred stock of a subsidiary		(1	)		—
Notes payable and commercial paper		(85	)		—
Distributions to minority interests		(268	)		(576	)
Contributions from minority interests		219			528
Proceeds from Duke Energy Income Fund		104			—
Advances (to) from parent		(86	)		104
Capital contributions from parent		—			269
Distributions to parent		(2,192	)		(1,150	)
Distribution of Bison cash to parent		(113	)		—
Other		(8	)		(4	)
Net cash used in financing activities		(1,705	)		(1,312	)
Changes in cash and cash equivalents included in assets held for sale		—			3
Net increase (decrease) in cash and cash equivalents		86			(165	)
Cash and cash equivalents at beginning of period		491			515
Cash and cash equivalents at end of period	$	577		$	350
Supplemental Disclosures
Significant non-cash transactions:
Transfer of Midwestern assets to CG&E	$	1,452		$	—
Forgiveness of advances to Duke Energy	$	571		$	—
Transfer of Bison to Duke Energy	$	60		$	—
Distributions from parent	$	37		$	—
Advances from parent converted to equity	$	—		$	761
AFUDC—equity component	$	8		$	3

See Notes to Unaudited Consolidated Financial Statements

F-104

Duke Capital LLC

Consolidated Statements of Member’s Equity and Comprehensive Income

(Unaudited)

(In millions)

				Accumulated Other Comprehensive Income
	Member’s Equity			Foreign Currency Adjustments		Net Gains (Losses) on Cash Flow Hedges			Minimum Pension Liability Adjustment			Other		Total
Balance December 31, 2004	$	11,223		$	534	$	536		$	(21	)	$	—	$	12,272
Net income		247			—		—			—			—		247
Other Comprehensive Income
Foreign currency translation adjustments		—			303		—			—			—		303
Net unrealized gains on cash flow hedges(a)		—			—		402			—			—		402
Reclassification into earnings from cash flow hedges(b)		—			—		(877	)		—			—		(877	)
Total comprehensive income															75
Advances from parent converted to equity		761			—		—			—			—		761
Capital contributions from parent		269			—		—			—			—		269
Distribution to parent		(1,150	)		—		—			—			—		(1,150	)
Other, net		25			—		—			—			—		25
Balance September 30, 2005	$	11,375		$	837	$	61		$	(21	)	$	—	$	12,252
Balance December 31, 2005	$	10,848		$	779	$	(79	)	$	(61	)	$	17	$	11,504
Net income		989													989
Other Comprehensive Income
Foreign currency translation adjustments		—			295		—			—			—		295
Net unrealized gains (losses) on cash flow hedges(a)		—			—		(1	)		—			—		(1	)
Reclassification into earnings from cash flow hedges(b)		—			—		26			—			—		26
Transfer of taxes on net investment hedge and other hedges from parent		—			62		7			—			—		69
Transfer of Midwestern assets to Duke Energy Ohio (c)		—			—		40			—			—		40
Other(d)					—		—			—			5		5
Total comprehensive income															1,423
Transfer of Midwestern assets to Duke Energy Ohio		(1,452	)		—		—			—			—		(1,452	)
Transfer of Bison to Duke Energy		(60	)		—		—			—			—		(60	)
Forgiveness of advances to Duke Energy		(571	)		—		—			—			—		(571	)
Distribution to parent		(553	)		—		—			—			—		(553	)
Distribution to parent associated with sale of Crescent		(1,602	)		—		—			—			—		(1,602	)
Other, net		(17	)		—		—			—			—		(17	)
Balance September 30, 2006	$	7,582		$	1,136	$	(7	)	$	(61	)	$	22	$	8,672

(a) Net unrealized gains (losses) on cash flow hedges, net of $7 tax benefit and $230 tax expense for the nine months ended September 30, 2006 and 2005, respectively.

(b) Reclassification into earnings from cash flow hedges, net of $20 tax expense and $502 tax benefit for the nine months ended September 30, 2006 and 2005, respectively.

(c) Net of $24 tax expense for the nine months ended September 30, 2006.

(d) Net of $3 tax expense for the nine months ended September 30, 2006.

See Notes to Unaudited Consolidated Financial Statements

F-105

Duke Capital LLC

Notes to Consolidated Financial Statements

(Unaudited)

1. Basis of Presentation

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 (New Duke Energy) and Old Duke Energy converted into a limited liability company named Duke Power Company LLC (subsequently renamed Duke Energy Carolinas, LLC (Duke Energy Carolinas) effective October 1, 2006). The term Duke Energy, as used in this report, refers to Old Duke Energy and New Duke Energy, as the context requires.

Duke Capital LLC (collectively with its subsidiaries, Duke Capital) is an energy company located in the Americas. On April 1, 2006, in connection with the above transactions, Old Duke Energy transferred the operations of Duke Energy Merchants, LLC and Duke Energy Merchant Finance, LLC (collectively DEM) to its wholly-owned subsidiary, Duke Capital LLC (collectively with its subsidiaries, “Duke Capital”). As a result of these transfers, prior period amounts have been retrospectively adjusted to include the results of operations, financial position and cash flows related to DEM as these transactions represent a transfer of assets under common control. The inclusion of DEM in the results of operations of Duke Capital for prior periods increased net income $6 million for the nine months ended September 30, 2005. The net of tax impact on other comprehensive income of the inclusion of DEM was immaterial for all prior periods. Additionally, on April 1, 2006, Duke Capital transferred the operations of its wholly-owned captive insurance subsidiary, Bison Insurance Company Limited (Bison), to Duke Energy. Due to continuing involvement between Bison and Duke Capital entities, the results of operations of Bison do not qualify for discontinued operations treatment. Accordingly, Bison’s operations are not included in Duke Capital’s results of operations, financial position or cash flows subsequent to its transfer to Duke Energy. On April 3, 2006, Duke Energy Carolinas transferred to its parent, New Duke Energy, all of its membership interests in Duke Capital.

Additionally, in April 2006, Duke Capital indirectly transferred to Duke Energy Ohio, Inc. (Duke Energy Ohio) (formerly The Cincinnati Gas & Electric Company (CG&E)), a subsidiary of Cinergy, its ownership interest in Duke Energy North America’s (DENA’s) Midwestern assets, representing a mix of combined cycle and peaking plants, with a combined capacity of approximately 3,600 megawatts (MWs). In connection with this transfer, Duke Capital transferred to Duke Energy Ohio approximately $1.6 billion of assets at their carrying value and approximately $0.1 billion of liabilities at their carrying value, for a net transfer of approximately $1.5 billion. This transfer has been accounted for as a capital contribution at historical cost. In connection with the transfer, Duke Capital and Duke Energy Ohio entered into an arrangement through April 2016, unless otherwise extended by the parties, whereby Duke Capital will reimburse Duke Energy Ohio in the event of certain cash shortfalls that may result from Duke Energy Ohio’s ownership of the Midwestern assets. The amounts that Duke Capital may be required to reimburse Duke Energy Ohio under this arrangement are not expected to be significant. The results of operations for DENA’s Midwestern assets have been reflected as discontinued operations in the accompanying Consolidated Statements of Operations.

As a result of Duke Energy’s merger with Cinergy, Duke Capital and its subsidiaries entered into a tax sharing agreement with Duke Energy, effective April 1, 2006, where the separate return method is used to allocate income taxes to the subsidiaries based on the results of their operations. The accounting for income taxes essentially represents the income taxes that Duke Capital would incur if Duke Capital were a separate company filing its own tax return as a C-Corporation. Prior to entering into this tax sharing agreement, Duke Capital and Duke Energy Americas (DEA), a subsidiary of Duke Capital, were pass-through entities for U.S. income tax

F-106

Duke Capital LLC

Notes to Consolidated Financial Statements—(Continued)

purposes. As a result, on April 1, 2006, all deferred taxes related to Duke Capital and DEA, which previously flowed through to Duke Capital’s parent, Duke Energy, were reinstated, resulting in an increase in Member’s Equity of approximately $37 million.

The Consolidated Financial Statements include, after eliminating intercompany transactions and balances, the accounts of Duke Capital and all majority-owned subsidiaries where Duke Capital has control, and those variable interest entities where Duke Capital is the primary beneficiary.

These Consolidated Financial Statements reflect all normal recurring adjustments that are, in the opinion of management, necessary to fairly present Duke Capital’s financial position and results of operations. Amounts reported in the interim Consolidated Statements of Operations are not necessarily indicative of amounts expected for the respective annual periods due to the effects of seasonal temperature variations on energy consumption, the timing of maintenance on electric generating units, changes in mark-to-market valuations, changing commodity prices and other factors. These Consolidated Financial Statements and other information included in this quarterly report should be read in conjunction with the Consolidated Financial Statements and Notes in Duke Capital’s Form 10-K/A for the year ended December 31, 2005.

On September 7, 2006, Duke Capital deconsolidated Crescent Resources, LLC (Crescent) due to a reduction in ownership and its inability to exercise control over Crescent (see Note 2). Crescent has been accounted for as an equity method investment since the date of deconsolidation.

Effective July 1, 2005, Duke Capital deconsolidated Duke Energy Field Services, LLC (DEFS) due to a reduction in ownership and its inability to exercise control over DEFS (see Note 2). DEFS has been accounted for as an equity method investment since July 1, 2005.

Use of Estimates. To conform with 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 To Consolidated Financial Statements. Although these estimates are based on management’s best available knowledge at the time, actual results could differ from those estimates.

Reclassifications. In 2005, Duke Capital recorded prior period reclassifications of management fees charged to an unconsolidated affiliate of Duke Capital (See Note 16).

Accounting For Sales of Stock by a Subsidiary. Duke Capital accounts for sales of stock by a subsidiary under Staff Accounting Bulletin (SAB) No. 51, “Accounting for Sales of Stock of a Subsidiary.” Under SAB 51, companies may elect, via an accounting policy decision, to record a gain on the sale of stock of a subsidiary equal to the amount of proceeds received in excess of the carrying value of the shares. Duke Capital has elected to treat such excesses as gains in earnings, which are reflected in Gain on Sale of Subsidiary Stock in the Consolidated Statements of Operations. During the nine months ended September 30, 2006, Duke Energy recognized a gain of approximately $15 million related to the sale of securities of the Duke Energy Income Fund (Income Fund) (see Note 16).

2. Acquisitions and Dispositions

Acquisitions. Duke Capital 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 purchase date. The purchase price minus the estimated fair value of the acquired assets and liabilities meeting the definition of a business as defined in Emerging Issues Task Force (EITF) Issue No. 98-3, “Determining Whether a Nonmonetary Transaction Involves

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Receipt of Productive Assets or of a Business” is recorded as goodwill. The allocation of the purchase price may be adjusted as 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.

During the first quarter of 2006, Duke Energy International (DEI) closed on two transactions which resulted in the acquisition of an additional 27% interest in the Aguaytia Integrated Energy Project (Aguaytia), located in Peru, for approximately $31 million (approximately $18 million net of cash acquired). The project’s scope includes the production and processing of natural gas, sale of liquefied petroleum gas (LPG) and natural gas liquids and the generation, transmission and sale of electricity from a 177 megawatt power plant. These acquisitions increased DEI’s ownership in Aguaytia to 66% and resulted in Duke Capital accounting for Aguaytia as a consolidated entity. Prior to the acquisition of this additional interest, Aguaytia was accounted for as an equity method investment.

During the first quarter of 2006, Duke Energy North America (DENA) acquired the remaining 33 ¹/3% interest in Bridgeport Energy LLC (Bridgeport) from United Bridgeport Energy LLC (UBE) for approximately $71 million. The assets and liabilities of Bridgeport were included as part of DENA’s power generation assets which were sold to a subsidiary of LS Power Equity Partners (LS Power) (see Note 10).

Dispositions. For the nine months ended September 30, 2006, the sale of other assets and businesses resulted in approximately $1.6 billion in proceeds and net pre-tax gains of $276 million recorded in Gains on Sales of Other Assets and Other, net on the Consolidated Statements of Operations. These sales exclude assets that were held for sale and reflected in discontinued operations, both of which are discussed in Note 10, and sales by Crescent prior to deconsolidation which are discussed separately below. Significant sales of other assets during the nine months ended September 30, 2006 are detailed as follows:

• On September 7, 2006, an indirect wholly owned subsidiary of Duke Capital closed an agreement to create a joint venture of Crescent (the Crescent JV) with Morgan Stanley Real Estate Fund V U.S., L.P. (MSREF) and other affiliated funds controlled by Morgan Stanley (collectively the MS Members). Under the agreement, the Duke Capital subsidiary contributed all of the membership interests in Crescent to a newly-formed joint venture, which was ascribed an enterprise value of approximately $2.1 billion as of December 31, 2005. In conjunction with the formation of the Crescent JV, the joint venture, Crescent and Crescent’s subsidiaries entered into a credit agreement with third party lenders under which Crescent borrowed approximately $1.23 billion, of which approximately $1.19 billion was immediately distributed to Duke Capital. Immediately following the debt transaction, the MS Members collectively acquired a 49% membership interest in the Crescent JV from Duke Capital for a purchase price of approximately $415 million. The MS Members 49% interest reflects a 2% interest in the Crescent JV issued by the joint venture to the President and Chief Executive Officer of Crescent which is subject to forfeiture if the executive voluntarily leaves the employment of the Crescent JV within a three year period. Additionally, this interest can be put back to the Crescent JV after three years or possibly earlier upon the occurrence of certain events at an amount equal to 2% of the fair value of the Crescent JV’s equity as of the put date. Therefore, the Crescent JV will accrue the obligation related to the put as a liability over the three year forfeiture period. Accordingly, Duke Capital has an effective 50% ownership in the equity of Crescent JV for financial reporting purposes.

In conjunction with this transaction, Duke Capital has recognized a pre-tax gain on the sale of approximately $250 million which has been classified as a component of Gains on Sales of Other Assets and Other, net in the accompanying Consolidated Statement of Operations for the nine months ended September 30, 2006. As a result of the Crescent transaction, Duke Capital no longer controls the Crescent JV and on September 7, 2006 deconsolidated its investment in Crescent and subsequently will account for its investment in the Crescent JV utilizing the equity method of accounting. Duke Capital’s

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Notes to Consolidated Financial Statements—(Continued)

equity investment in the Crescent JV is approximately $163 million as of September 30, 2006. The proceeds from the sale were recorded on the Consolidated Statements of Cash Flows as follows: approximately $1.2 billion in long-term debt proceeds, net of issuance costs, were classified as Proceeds from the issuance of long-term debt within Financing Activities, and approximately $380 million, which represents cash received from the MS Members net of cash held by Crescent as of the transaction date, were classified as Net proceeds from the sales of and distributions from equity investments and other assets, and sales of and collections on notes receivable within Investing Activities.

• Natural Gas Transmission’s sale of certain Stone Mountain natural gas gathering system assets resulted in proceeds of $18 million (which is reflected in Net proceeds from the sales of equity investments and other assets, and sales of and collections on notes receivable within Cash Flows from Investing Activities in the Consolidated Statements of Cash Flows), and pre-tax gain of $5 million which was recorded in Gains on Sales of Other Assets and Other, net in the accompanying Consolidated Statements of Operations for the nine months ended September 30, 2006. In addition, Natural Gas Transmission’s sale of stock, received as consideration for the settlement of a customers’ transportation contract, resulted in proceeds of approximately $24 million (which is reflected in Other, assets within Cash Flows from Operating Activities in the Consolidated Statements of Cash Flows) and a pre-tax gain of $24 million, of which approximately $23 million was recorded in Gains on Sales of Other Assets and Other, net and approximately $1 million was recorded in Other Income and Expenses, net in the accompanying Consolidated Statements of Operations for the nine months ended September 30, 2006 (see Note 7).

For the period from January 1, 2006 to September 7, 2006, Crescent commercial and multi-family real estate sales resulted in $254 million of proceeds and $201 million of net pre-tax gains recorded in Gains on Sales of Investments in Commercial and Multi-Family Real Estate on the Consolidated Statements of Operations. Sales primarily consisted of two office buildings at Potomac Yard in Washington, D.C. for a pre-tax gain of $81 million and land at Lake Keowee in northwestern South Carolina for a pre-tax gain of $52 million, as well as several other large land tract sales.

For the nine months ended September 30, 2005, the sale of other assets, businesses and equity investments resulted in approximately $2.2 billion in proceeds, net pre-tax gains of $588 million recorded in Gains on Sales of Other Assets and Other, net and pre-tax gains of $1.2 billion recorded in (Losses) Gains on Sales and Impairments of Equity Investments on the Consolidated Statements of Operations. These sales exclude assets held for sale as of September 30, 2005 and reflected in discontinued operations, both of which are discussed in Note 10, and sales by Crescent which are discussed separately below. Significant sales of other assets and equity investments during the nine months ended September 30, 2005 are detailed as follows:

• In February 2005, DEFS sold its wholly-owned subsidiary Texas Eastern Products Pipeline Company, LLC (TEPPCO GP), which is the general partner of TEPPCO Partners, LP (TEPPCO LP), for approximately $1.1 billion and Duke Capital 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, which have been classified as (Losses) Gains on Sales and Impairments of Equity Investments on the Consolidated Statement of Operations for the nine months ended September 30, 2005. Minority Interest Expense of $343 million was recorded in the Consolidated Statement of Operations for the nine months ended September 30, 2005 to reflect ConocoPhillips’ proportionate share in the pre-tax gain on sale of the TEPPCO GP.

Additionally, in July 2005, Duke Energy completed the agreement with ConocoPhillips, Duke Energy’s co-equity owner in DEFS, to reduce Duke Capital’s ownership interest in DEFS from 69.7% to 50% (the DEFS disposition transaction), which results in Duke Capital and ConocoPhillips becoming equal 50% owners in DEFS. Duke Capital has received, directly and indirectly through its ownership interest

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Duke Capital LLC

Notes to Consolidated Financial Statements—(Continued)

in DEFS, a total of approximately $1.1 billion from ConocoPhillips and DEFS, consisting of approximately $1.0 billion in cash and approximately $0.1 billion of assets. The DEFS disposition transaction resulted in a pre-tax gain of approximately $575 million, which was recorded in Gains on Sales of Other Assets and Other, net, on the accompanying Consolidated Statements of Operations. The DEFS disposition transaction includes the transfer to Duke Capital of DEFS’ Canadian natural gas gathering and processing facilities. Additionally, the DEFS disposition transaction included the acquisition of ConocoPhillips’ interest in the Empress System, which is a natural gas processing and NGL marketing business. Subsequent to the closing of the DEFS disposition transaction, effective on July 1, 2005, DEFS is no longer consolidated into Duke Capital’s consolidated financial statements and is accounted for by Duke Capital as an equity method investment. See Note 12 for the impacts of this transaction on certain cash flow hedges. The Canadian natural gas gathering and processing facilities and the Empress System are included in the Natural Gas Transmission segment.

• Additional asset and business sales during the nine months ended September 30, 2005 totaled approximately $24 million in proceeds. These sales resulted in net pre-tax gains of approximately $12 million which were recorded in Gains on Sales of Other Assets and Other, net in the Consolidated Statements of Operations.

For the nine months ended September 30, 2005, Crescent’s commercial and multi-family real estate sales resulted in $185 million of proceeds and $117 million of net pre-tax gains recorded in Gains on Sales of Investments in Commercial and Multi-Family Real Estate on the Consolidated Statements of Operations. Sales included a large land sale in Lancaster County, South Carolina during the three months ended September 30, 2005 that resulted in $41 million of pre-tax gains and several other “legacy” land sales. Additionally, in the third quarter of 2005, Crescent had a $45 million gain on sale of an interest in a portfolio of commercial office buildings which was recognized in Other Income and Expenses, net, on the Consolidated Statements of Operations.

3. Stock-Based Compensation

Duke Capital and its subsidiaries are allocated stock-based compensation expense from Duke Energy as certain of its employees participate in Duke Energy’s stock-based compensation programs. Effective January 1, 2006, Duke Energy 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 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. Duke Energy previously applied Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees,” and FIN 44, “Accounting for Certain Transactions Involving Stock Compensation (an Interpretation of APB Opinion 25)” and provided the required pro forma disclosures of SFAS No. 123, “Accounting for Stock-Based Compensation” (SFAS No. 123). Since the exercise price for all options granted under those plans was equal to the market value of the underlying common stock on the grant date, no compensation cost was recognized in the accompanying Consolidated Statements of Operations.

Compensation expense for awards with graded vesting provisions is recognized in accordance with FIN 28, “Accounting for Stock Appreciation Rights and Other Variable Stock Option or Award Plans.” Duke Energy elected to adopt the modified prospective application method as provided by SFAS No. 123(R), and accordingly, financial statement amounts from the prior periods presented in this Form 10-Q have not been restated. There were no modifications to outstanding stock options prior to the adoption of SFAS 123(R).

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Duke Capital LLC

Notes to Consolidated Financial Statements—(Continued)

Duke Capital recorded stock-based compensation expense for the nine months ended September 30, 2006 and 2005 as follows, the components of which are further described below:

	Nine Months Ended September 30
	2006		2005
	(in millions)
Stock Options	$	3	$	—
Stock Appreciation Rights		1		1
Phantom Stock		17		13
Performance Awards		17		16
Other Stock Awards		1		1
Total	$	39	$	31

The tax benefit at Duke Energy associated with the recorded expense for the nine months ended September 30, 2006 and 2005 was approximately $14 million and $11 million, respectively. There were no material differences in income from continuing operations, net income, or cash flows from the adoption of SFAS No. 123(R).

The following table shows what net income would have been for Duke Capital if Duke Energy had applied the fair value recognition provisions of SFAS No. 123 to all stock-based compensation awards during prior periods.

Pro Forma Stock-Based Compensation (in millions)

	Nine months ended September 30, 2005
Net (loss) income, as reported	$	247
Add: stock-based compensation expense included in reported net (loss) income, net of related tax effects		20
Deduct: total stock-based compensation expense determined under fair value-based method for all awards, net of related tax effects		(20	)
Pro forma net (loss) income, net of related tax effects	$	247

Duke Energy’s 1998 Long-term Incentive Plan, as amended (the 1998 Plan), reserved 60 million shares of common stock for awards to employees and outside directors. Under the 1998 Plan, the exercise price of each option granted cannot be less than the market price of Duke Energy’s common stock on the date of grant and the maximum option term is 10 years. The vesting periods range from immediate to five years. Duke Energy issues new shares upon exercising or vesting of share-based awards.

Upon the acquisition of Westcoast Energy, Inc (Westcoast), Duke Energy converted all stock options outstanding under the 1989 Westcoast Long-term Incentive Share Option Plan to Duke Energy stock options. Certain of these options also provide for share appreciation rights under which the holder of a stock option may, in lieu of exercising the option, exercise the share appreciation right. The exercise price of these options equals the market price on the date of grant and the maximum option term is 10 years. The vesting periods range from immediate to four years.

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Duke Capital LLC

Notes to Consolidated Financial Statements—(Continued)

Stock Option Activity

	Options (in thousands)		Weighted-Average Exercise Price		Weighted-Average Remaining Life (in years)	Aggregate Intrinsic Value (in millions)
Outstanding at December 31, 2005	19,493		$	29
Employee transfers into Duke Capital net of transfers out(a)	596			30
Exercised	(1,739	)		22
Forfeited or expired	(803	)		35
Outstanding at September 30, 2006	17,547			30	4.3	$	80
Exercisable at September 30, 2006	15,452		$	32	3.9	$	49

(a) Represents options associated with employees transferred into Duke Capital.

On December 31, 2005, Duke Capital employees had 16 million exercisable Duke Energy options with a $32 weighted-average exercise price. The total intrinsic value of options exercised during the nine months ended September 30, 2006 and 2005 was approximately $13 million and $13 million, respectively. Cash received by Duke Energy from options exercised during the nine months ended September 30, 2006 was approximately $39 million, with a related tax benefit to Duke Energy of approximately $5 million.

There were no options granted to Duke Capital employees during the nine months ended September 30, 2006 or during the year ended December 31, 2005.

The 1998 Plan allows for a maximum of twelve million shares of common stock to be issued under various stock-based awards. Payments for cash settled awards during the period were immaterial.

Performance Awards

Stock-based performance awards outstanding under the 1998 Plan generally vest over three years. Vesting for certain stock-based performance awards can occur in three years, at the earliest, if performance is met. Certain performance awards granted in 2006 contain market conditions based on the total shareholder return (TSR) of Duke Energy stock (relative 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 788,700 shares (fair value of approximately $14 million) to Duke Capital employees in the nine months ended September 30, 2006, and 1,005,100 shares (fair value of approximately $27 million, based on the market price of Duke Energy’s common stock at the grant date) in the nine months ended September 30, 2005.

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Duke Capital LLC

Notes to Consolidated Financial Statements—(Continued)

The following table summarizes information about stock-based performance awards outstanding at September 30, 2006:

	Shares		Weighted Average Grant Date Fair Value
Number of Stock-based Performance Awards:
Outstanding at December 31, 2005	2,351,972		$	25
Granted	788,700			18
Vested	(114,000	)		27
Forfeited	(134,648	)		26
Canceled	—			—
Outstanding at September 30, 2006	2,892,024		$	23

The total fair value of the shares vested during the nine months ended September 30, 2006 and 2005 was approximately $3 million in both periods. As of September 30, 2006, Duke Capital had approximately $23 million of future compensation cost which is expected to be recognized over a weighted-average period of 1.1 years.

Phantom Stock Awards

Phantom stock awards outstanding under the 1998 Plan generally vest over periods from immediate to five years. Duke Energy awarded 558,620 shares to Duke Capital employees (fair value of approximately $16 million) based on the market price of Duke Energy’s common stock at the grant dates in the nine months ended September 30, 2006, and 924,240 shares (fair value of approximately $25 million) in the nine months ended September 30, 2005.

The following table summarizes information about phantom stock awards outstanding at September 30, 2006:

	Shares		Weighted Average Grant Date Fair Value
Number of Phantom Stock Awards:
Outstanding at December 31, 2005	2,009,641		$	25
Granted	558,620			29
Vested	(618,410	)		25
Forfeited	(80,980	)		25
Canceled	—			—
Outstanding at September 30, 2006	1,868,871		$	27

The total fair value of the shares vested during the nine months ended September 30, 2006 and 2005 was approximately $15 million and $6 million, respectively. As of September 30, 2006, Duke Capital had approximately $20 million of future compensation cost which is expected to be recognized over a weighted-average period of 3.2 years.

Other Stock Awards

Other stock awards outstanding under the 1998 Plan generally vest over periods from three to five years. Duke Energy awarded 41,000 shares to Duke Capital employees (fair value of approximately $1 million) based on the market price of Duke Energy’s common stock at the grant dates in the nine months ended September 30, 2006, and 38,000 shares (fair value of approximately $1 million) in the nine months ended September 30, 2005.

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Duke Capital LLC

Notes to Consolidated Financial Statements—(Continued)

The following table summarizes information about other stock awards outstanding at September 30, 2006:

	Shares		Weighted Average Grant Date Fair Value
Number of Other Stock Awards:
Outstanding at December 31, 2005	122,937		$	25
Granted	41,000			29
Vested	(18,630	)		24
Forfeited	—			—
Canceled	—			—
Outstanding at September 30, 2006	145,307		$	27

The total fair value of the shares vested during the nine months ended September 30, 2006 and 2005 was less than $1 million in both periods. As of September 30, 2006, Duke Capital had approximately $2 million of future compensation cost which is expected to be recognized over a weighted-average period of 1.6 years.

4. Inventory

Inventory is recorded at the lower of cost or market value, primarily using the average cost method.

Inventory

	September 30, 2006		December 31, 2005
	(in millions)
Materials and supplies	$	142	$	130
Natural gas		321		269
Petroleum products		37		45
Total inventory	$	500	$	444

5. Debt and Credit Facilities

In September 2006, prior to the completion of the joint venture transaction of Crescent, as discussed in Note 2, the Crescent JV, Crescent and Crescent’s subsidiaries borrowed approximately $1.23 billion principal amount of debt. The net proceeds from the debt issuance of approximately $1.21 billion were recorded as a cash inflow within Financing Activities on the Consolidated Statements of Cash Flows and were distributed to Duke Capital. As a result of Duke Capital’s deconsolidation of Crescent effective September 7, 2006, Crescent’s outstanding debt balance of $1,298 million was removed from Duke Capital’s Consolidated Balance Sheets.

In September 2006, Union Gas Limited (Union Gas) entered into a fixed-rate financing agreement denominated in 165 million Canadian dollars (approximately $148 million in U.S. dollar equivalents as of the issuance date) due in 2036 with an interest rate of 5.46%.

Available Credit Facilities and Restrictive Debt Covenants. During the nine months ended September 30, 2006, Duke Capital’s consolidated credit capacity decreased by approximately $1,237 million, primarily due to the terminations of an $800 million syndicated credit facility and $460 million in bi-lateral credit facilities. The terminations of these credit facilities primarily reflect Duke Capital’s reduced liquidity needs as a result of

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Duke Capital LLC

Notes to Consolidated Financial Statements—(Continued)

exiting the DENA business (see Note 10). During October 2006, the $130 million bi-lateral credit facility at Duke Capital was cancelled. In addition, the remaining $120 million bi-lateral facility at Duke Capital was cancelled in November 2006 and reissued at Duke Energy for the same amount with the same terms and conditions.

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

Duke Capital’s 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 September 30, 2006, Duke Capital was in compliance with those covenants. In addition, credit agreements allow for acceleration of payments or termination of the agreements due to nonpayment, or in some cases, due to the acceleration of other significant indebtedness of the borrower or some of its subsidiaries. None of the debt or credit agreements contain material adverse change clauses.

Credit Facilities Summary as of September 30, 2006 (in millions)

	Expiration Date	Credit Facilities Capacity		Amounts Outstanding
				Commercial Paper		Letters of Credit		Total
Duke Capital LLC
$600 multi-year syndicated(a), (b), (d)	June 2010
$130 three-year bi-lateral(b)(h)	October 2007
$120 multi-year bi-lateral(b)(i)	July 2009
Total Duke Capital LLC		$	850	$	—	$	310	$	310
Westcoast Energy Inc.
$180 multi-year syndicated(c), (e)	June 2011		180		—		—		—
Union Gas Limited
$359 364-day syndicated(f)	June 2007		359		—		—		—
Total(g)		$	1,389	$	—	$	310	$	310

(a) Credit facility contains an option allowing borrowing up to the full amount of the facility on the day of initial expiration for up to one year.

(b) Credit facility contains a covenant requiring the debt-to-total capitalization ratio to not exceed 65%.

(c) In June 2006, credit facility expiration date was extended from June 2010 to June 2011.

(d) In June 2006, credit facility expiration date was extended from June 2009 to June 2010.

(e) Credit facility is denominated in Canadian dollars totaling 200 million Canadian dollars and contains a covenant that requires the debt-to-total capitalization ratio to not exceed 75%.

(f) In June 2006, credit facility was amended to increase the amount from 300 to 400 million Canadian dollars, in addition to extending the maturity from June 2006 to June 2007. It contains a covenant requiring the debt-to-total capitalization ratio to not exceed 75% and an option at maturity allowing for the conversion of all outstanding loans to a term loan repayable up to one year after maturity date but not exceeding 18 months from the date of draw.

(g) Various credit facilities that support ongoing or discontinued operations and miscellaneous transactions are not included in this credit facilities summary.

(h) In October 2006, credit facility was cancelled.

(i) In November 2006, credit facility was cancelled and reissued at Duke Energy for the same amount with the same terms and conditions.

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Duke Capital LLC

Notes to Consolidated Financial Statements—(Continued)

6. Employee Benefit Obligations

Duke Capital and its subsidiaries participate in Duke Energy’s non-contributory defined benefit retirement plan. Duke Capital’s net periodic pension benefit for its U.S. plan, as allocated by Duke Energy, was $11 million and $16 million for the nine months ended September 30, 2006 and 2005, respectively.

Duke Energy sponsors non-qualified pension plans (plans that do not meet the criteria for certain tax benefits) that cover officers, certain other key employees, and non-employee directors. Duke Capital and its subsidiaries participate in Duke Energy’s non-qualified pension plans. Duke Capital’s net periodic pension cost for its U.S. plan, as allocated by Duke Energy, was $3 million for both the nine months ended September 30, 2006 and 2005, respectively.

There have been no contributions made by Duke Capital to Duke Energy’s U.S. retirement plan during the nine months ended September 30, 2006.

The following tables show the components of the net periodic pension costs for the Westcoast Canadian retirement plans.

Components of Net Periodic Pension Costs for Westcoast: Qualified Pension Benefits (Income)

	Nine Months Ended September 30,
	2006			2005
	(in millions)
Service cost	$	10		$	6
Interest cost on projected benefit obligation		23			22
Expected return on plan assets		(24	)		(20	)
Amortization of prior service cost		1			1
Amortization of loss		7			3
Net periodic pension costs	$	17		$	12

Components of Net Periodic Pension Costs for Westcoast: Non-Qualified Pension Benefits

	Nine Months Ended September 30,
	2006		2005
	(in millions)
Service cost	$	1	$	1
Interest cost on projected benefit obligation		3		3
Amortization of loss		1		—
Net periodic pension costs	$	5	$	4

Westcoast’s policy is to fund its defined benefit (DB) retirement plans on an actuarial basis and in accordance with Canadian pension standards legislation, in order to accumulate assets sufficient to meet benefit payments. Contributions to the defined contribution (DC) retirement plans are determined in accordance with the terms of the plans. Duke Capital has contributed $32 million to the Westcoast DB plans for the nine months ended September 30, 2006. Duke Capital anticipates that it will make total contributions of approximately $45 million in 2006. Duke Capital has contributed $3 million to the Westcoast DC plans for the nine months ended September 30, 2006, and anticipates that it will make total contributions of approximately $4 million in 2006.

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Duke Capital LLC

Notes to Consolidated Financial Statements—(Continued)

Duke Capital and most of its subsidiaries, in conjunction with Duke Energy, provide some health care and life insurance benefits for retired employees on a contributory and non-contributory basis. Duke Capital’s net periodic post-retirement costs as allocated by Duke Energy $15 million and $14 million for the nine months ended September 30, 2006 and 2005, respectively.

The following table shows the components of the net periodic post-retirement benefit costs for the Westcoast other post-retirement benefit plans.

Components of Net Periodic Post-Retirement Benefit Costs (Income) for Westcoast

	Nine Months Ended September 30,
	2006			2005
	(in millions)
Service cost	$	3		$	2
Interest cost on accumulated post-retirement benefit obligation		5			4
Amortization of prior service credit		(1	)		(1	)
Amortization of loss		2			1
Net periodic post-retirement benefit costs	$	9		$	6

Duke Energy also sponsors, and Duke Capital participates in, an employee savings plan that covers substantially all U.S. employees. Duke Capital expensed plan contributions, including amounts allocated by Duke Energy, of $18 million and $16 million for the nine months ended September 30, 2006 and 2005, respectively.

7. Marketable Securities

During the nine months ended September 30, 2006, Duke Energy’s Natural Gas Transmission business unit received shares of stock as consideration for settlement of a customer’s transportation contract. The market value of the equity securities, determined by quoted market prices on the date of receipt, of approximately $23 million is reflected in Gains on Sales of Other Assets and Other, net in the Consolidated Statements of Operations for the nine months ended September 30, 2006. Subsequent to receipt, these securities were accounted for under SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities,” as trading securities. During the nine months ended September 30, 2006, these securities were sold and an additional gain of approximately $1 million was recognized in Other Income and Expenses, net in the Consolidated Statements of Operations for the nine months ended September 30, 2006.

As discussed in Note 1, on April 3, 2006, Duke Capital transferred the operations of Bison to Duke Energy. As a result of this transfer, Duke Capital’s long-term investments, which are classified in Other Investments and Other Assets on the Consolidated Balance Sheets, decreased approximately $200 million from the amounts reported in Duke Capital’s Annual Report on Form 10-K for the year ended December 31, 2005.

8. Severance

During the period from April 1, 2006 to September 30, 2006, Duke Capital accrued approximately $10 million related to voluntary and involuntary severance as a result of Duke Energy’s merger with Cinergy (see Note 1).

As discussed further in Note 10, during the third quarter of 2005, the Board of Directors of Duke Energy authorized and directed management to execute the sale or disposition of substantially all of DENA’s remaining assets and contracts outside the Midwestern United States and certain contractual positions related to the

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Duke Capital LLC

Notes to Consolidated Financial Statements—(Continued)

Midwestern assets. As a result of this exit plan, DENA terminated approximately 207 employees through the end of the third quarter of 2006. Management anticipates future severance costs related to this exit plan not included in the following table will be immaterial.

Severance Reserve

	Balance at January 1, 2006		Provision/ Adjustments		Cash Reductions			Balance at September 30, 2006
	(in millions)
Natural Gas Transmission	$	3	$	—	$	(1	)	$	2
Other(a)		28		2		(17	)		13
Total(b)	$	31	$	2	$	(18	)	$	15

(a) Amounts associated with DENA’s discontinued operations are included as part of Other (see Note 10). Included in the provisions/adjustments column is approximately $9 million of reversals of previously recorded reserves related to the DENA exit.

(b) Substantially all remaining severance payments are expected to be applied to the reserves within one year from the date that the provision was recorded.

9. Impairments and Other Charges

International Energy. In the second quarter of 2006, International Energy recorded a $55 million other-than-temporary impairment charge related to an investment in Compañía de Servicios de Compresión de Campeche, S.A. de C.V. (Campeche), a natural gas compression facility in the Cantarell oil field in the Gulf of Mexico. Campeche project revenues are generated from the gas compression services agreement (GCSA) with the Mexican National Oil Company (PEMEX). The current GCSA expired on October 26, 2006 and a nine month extension was executed on November 2, 2006. In the second quarter of 2006, based on ongoing discussions with PEMEX, it was determined that there was a limited future need for Campeche’s gas compression services. Management of International Energy determined that it is probable that the Campeche investment will ultimately be sold or the GCSA will be renewed for a significantly lower rate. An other-than-temporary impairment loss was recorded to reduce the carrying value to management’s best estimate of realizable value. The charges consist of a $17 million impairment of the carrying value of the equity method investment, which has been classified within (Losses) Gains on Sales and Impairments of Equity Investments in the Consolidated Statements of Operations for the nine months ended September 30, 2006, and a $38 million reserve against notes receivable from Campeche, which has been classified within Operations, Maintenance and Other in the Consolidated Statements of Operations for the nine months ended September 30, 2006. The facility ownership will transfer to PEMEX in August 2007. The carrying value of the note at September 30, 2006 was $17 million, which is management’s best estimate of the net realizable value of the note receivable from Campeche.

During the nine months ended September 30, 2005, International Energy recorded a $20 million other than temporary impairment charge related to the investment in Campeche which has been classified as a component of (Losses) Gains on Sales and Impairments of Equity Investments in the Consolidated Statements of Operations.

Field Services. During the nine months ended September 30, 2005, the Field Services business unit recorded a charge of approximately $120 million due to the reclassification into earnings of pre-tax unrealized losses from accumulated other comprehensive income (AOCI) as a result of the discontinuance of certain cash flow hedges entered into to hedge Field Services’ commodity price risk. See Note 12 for a discussion of the impacts of the DEFS disposition transaction on certain cash flow hedges.

F-118

Duke Capital LLC

Notes to Consolidated Financial Statements—(Continued)

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 impairment was recognized as a component of Impairments and Other Charges in the accompanying Consolidated Statements of Operations. 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.

10. Discontinued Operations and Assets Held for Sale

The following table summarizes the results classified as Income (Loss) From Discontinued Operations, net of tax, in the Consolidated Statements of Operations.

			Operating (Loss) Gain									Net Gain (Loss) on Dispositions
	Operating Revenues		Pre-tax Operating (Loss) Gain			Income Tax (Benefit) Expense			Operating (Loss) Gain, Net of Tax			Pre-tax Gain (Loss) on Dispositions			Income Tax Expense (Benefit)			Gain (Loss) on Dispositions, Net of Tax			Income (Loss) From Discontinued Operations, Net of Tax
	(in millions)
Nine Months Ended September 30, 2006
Other(a)	$	516	$	(74	)	$	(116	)	$	42		$	(175	)	$	(63	)	$	(112	)	$	(70	)
International Energy		—		(1	)		(1	)		—			(10	)		(3	)		(7	)		(7	)
Commercial Power		13		(13	)		—			(13	)		—			—			—			(13	)
Total consolidated	$	529	$	(88	)	$	(117	)	$	29		$	(185	)	$	(66	)	$	(119	)	$	(90	)
Nine Months Ended September 30, 2005
Other(a)	$	1,542	$	(879	)	$	(222	)	$	(657	)	$	(544	)	$	(27	)	$	(517	)	$	(1,174	)
International Energy		—		(6	)		(1	)		(5	)		—			—			—			(5	)
Commercial Power		19		(44	)		5			(49	)		—			—			—			(49	)
Crescent		2		1			1			—			2			1			1			1
Field Services		4		—			—			—			—			—			—			—
Total consolidated	$	1,567	$	(928	)	$	(217	)	$	(711	)	$	(542	)	$	(26	)	$	(516	)	$	(1,227	)

(a) Other includes the results for DENA’s discontinued operations, which were previously reported in the DENA segment

The following table presents the carrying values of the major classes of assets and associated liabilities held for sale in the Consolidated Balance Sheets as of September 30, 2006 and December 31, 2005.

F-119

Duke Capital LLC

Notes to Consolidated Financial Statements—(Continued)

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

	September 30, 2006		December 31, 2005
	(in millions)
Current assets	$	36	$	1,528
Investments and other assets		157		2,059
Property, plant and equipment, net		—		1,538
Total assets held for sale	$	193	$	5,125
Current liabilities	$	36	$	1,488
Long-term debt		—		61
Deferred credits and other liabilities		119		2,024
Total liabilities associated with assets held for sale	$	155	$	3,573

Other

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 DENA remaining assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets. The DENA assets to be divested include:

• Approximately 6,100 MW of power generation located primarily in the Western and Eastern United States, including all of the commodity contracts (primarily forward gas and power contracts) related to these facilities,

• All remaining commodity contracts related to DENA’s Southeastern generation operations, which were substantially disposed of in 2004, and certain commodity contracts related to DENA’s Midwestern power generation facilities, and

• Contracts related to DENA’s energy marketing and management activities, which include gas storage and transportation, structured power and other contracts.

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 (see Note 8). Approximately $700 million has been incurred from the announcement date through September 30, 2006, of which approximately $230 million was incurred during the nine months ended September 30, 2006, and was recognized in Income (Loss) From Discontinued Operations, net of tax.

In January 2006, a Duke Capital subsidiary signed an agreement to sell to LS Power DENA’s entire fleet of power generation assets outside the Midwest, representing approximately 6,100 MW of power generation located in the Western and Northeast United States. In May 2006, the transaction with LS Power closed and total proceeds from the sale were approximately $1.56 billion, including certain working capital adjustments. Additional proceeds of up to approximately $40 million were subject to LS Power obtaining certain state regulatory approvals. On July 20, 2006 the Public Utilities Commission of the State of California approved a toll arrangement related to the Moss Landing facility previously sold to LS Power. In August 2006, LS Power made an additional payment to DENA of approximately $40 million, which DENA recorded as an additional gain on the sale of assets.

F-120

Duke Capital LLC

Notes to Consolidated Financial Statements—(Continued)

As of September 30, 2006, the DENA exit activities are substantially complete. As of September 30, 2006 and December 31, 2005, DENA’s remaining assets and liabilities to be disposed of under the exit plan were classified as Assets Held for Sale in the Consolidated Balance Sheets. At September 30, 2006, contracts with a net fair value of approximately $6 million remain in Assets Held for Sale and represent contracts that have yet to be novated by Barclays Bank PLC (Barclays). Duke Capital has taken all steps necessary to novate these remaining contracts and is awaiting counterparty action. Barclays handles all administrative aspects of the remaining contracts and there are no cash flows to Duke Capital associated with the remaining contracts, nor does Duke Capital have any continuing involvement with the remaining contracts. In connection with the Barclays transaction, Duke Capital entered into a series of Total Return Swaps (TRS) with Barclays, which are accounted for as mark-to-market derivatives. The fair value of the TRS as of September 30, 2006 is a net liability of approximately $6 million, which offsets the net fair value of the underlying contracts. The TRS will be cancelled as the underlying transactions are transferred to Barclays.

In October 2006, DENA recognized an approximate $38 million pre-tax gain on the sale of available-for-sale securities that were included in Assets Held For Sale on the Consolidated Balance Sheets at September 30, 2006.

The results of operations of DENA’s Western and Eastern United States generation assets, including related commodity contracts, certain contracts related to DENA’s energy marketing and management activities and certain general and administrative costs, are required to be classified as discontinued operations for current and prior periods in the accompanying Consolidated Statements of Operations. GAAP requires an ongoing assessment of the continued qualification for discontinued operations presentation for the period up through one year following disposal. While this assessment requires judgment, management is not currently aware of any matters or events that are likely to occur that would impact the presentation of these operations as discontinued operations.

In the first quarter of 2005, DENA’s Grays Harbor facility was sold to an affiliate of Invenergy LLC, resulting in a pre-tax gain of approximately $21 million (excluding any potential contingent consideration).

Commercial Power

As discussed in Note 1, in April 2006, Duke Capital indirectly transferred its ownership interest in DENA’s Midwestern assets to Duke Energy Ohio. As a result, the results of operations for DENA’s Midwestern assets up through April 1, 2006 have been reflected as discontinued operations in the accompanying Consolidated Statements of Operations.

International Energy

International Energy held a receivable from Norsk Hydro ASA (Norsk) related to the 2003 sale of International Energy’s European business. In the first quarter of 2006, based on management’s best estimate of recoverability, International Energy recorded an allowance of approximately $19 million ($12 million after tax) against this receivable, which was recorded in Income (Loss) From Discontinued Operations, net of tax on the Consolidated Statements of Operations. This allowance reduced the carrying value of the receivable to approximately $24 million at March 31, 2006. During the second quarter of 2006, International Energy and Norsk signed a settlement agreement in which Norsk agreed to pay International Energy approximately $34 million in full settlement of International Energy’s receivable. In connection with this settlement, International Energy recorded an approximate $9 million write-up ($5 million after tax) of the receivable through a reduction in the valuation allowance, which was recorded in Income (Loss) From Discontinued Operations, net of tax on the Consolidated Statements of Operations during the nine months ended September 30, 2006. In July 2006, International Energy received the settlement proceeds.

F-121

Duke Capital LLC

Notes to Consolidated Financial Statements—(Continued)

Crescent

Crescent routinely develops real estate projects and operates those facilities until they are substantially leased and a sales agreement is finalized. If Crescent does not have significant continuing involvement after the sale, Crescent classifies the projects as “discontinued operations” as required by SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.”

In the third quarter of 2005, Crescent sold one commercial property resulting in sales proceeds of approximately $14 million. The after-tax gain on that sale was included in Income (Loss) From Discontinued Operations, net of tax, on the Consolidated Statements of Operations. Additionally, Crescent had two commercial properties, which were sold during the fourth quarter of 2005, for which the results of operations were included in Income (Loss) From Discontinued Operations, net of tax, on the Consolidated Statements of Operations.

11. Business Segments

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

• Natural Gas Transmission—segment is the same as former Duke Energy business segment

• Field Services—segment is the same as former Duke Energy business segment

• Commercial Power—DENA’s Midwestern operations up to April 2006, at which time the Midwestern assets were transferred to Duke Energy Ohio (pre-merger included in Other)

• International Energy—consists of Duke Energy International (DEI)

• Crescent—segment is the same as former Duke Energy business segment

Duke Capital’s chief operating decision maker regularly reviews financial information about each of these business units in deciding how to allocate resources and evaluate performance. All of the business units are considered reportable segments under SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information.” Prior to the September 2005 announcement of the exiting of the majority of DENA’s businesses, DENA’s operations were considered a separate reportable segment. There is no aggregation within Duke Capital’s defined business segments.

The remainder of Duke Capital’s operations is presented as “Other.” While it is not considered a business segment, Other primarily includes DENA’s discontinued operations, certain unallocated corporate costs, including certain costs to achieve related to the merger with Cinergy, certain discontinued hedges, DukeNet Communications, LLC, Duke Energy Merchants, LLC, Duke Energy Trading and Marketing (DETM), and Duke Capital’s 50% interest in Duke/Fluor Daniel (D/FD). As discussed in Note 1, Bison was transferred to Duke Energy on April 1, 2006. Accordingly, the results of operations of Bison are reflected in Other for all periods prior to the transfer.

On September 7, 2006, Duke Capital deconsolidated Crescent due to a reduction in ownership and its inability to exercise control over Crescent (see Note 2). Crescent has been accounted for as an equity method investment since the date of deconsolidation.

In February 2005, DEFS sold its wholly-owned subsidiary TEPPCO GP, which is the general partner of TEPPCO LP, and Duke Energy sold its limited partner interest in TEPPCO LP, in each case to Enterprise GP Holdings LP, an unrelated third party (see Note 2).

F-122

Duke Capital LLC

Notes to Consolidated Financial Statements—(Continued)

In July 2005, Duke Capital completed the agreement with ConocoPhillips to reduce Duke Capital’s ownership interest in DEFS from 69.7% to 50% (see Note 2). In connection with the DEFS disposition transaction, DEFS transferred its Canadian natural gas gathering and processing facilities to Duke Capital’s Natural Gas Transmission segment.

During the first quarter of 2005, Duke Capital discontinued hedge accounting for certain contracts related to Field Services’ commodity price risk and changes in the fair value of these contracts subsequent to hedge discontinuance have been classified in Other. See Note 12 for further discussion.

Duke Capital’s reportable segments offer different products and services and are managed separately as business units. Accounting policies for Duke Capital’s segments are the same as those described in the Notes to the Consolidated Financial Statements in Duke Capital’s Annual Report on Form 10-K/A for the year ended December 31, 2005. Management evaluates segment performance based on earnings before interest and taxes (EBIT) from continuing operations, after deducting minority interest expense related to those profits.

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 Capital, so the associated realized and unrealized gains and losses from foreign currency transactions and interest and dividend income on those balances are excluded from the segments’ EBIT.

Transactions between reportable segments are accounted for on the same basis as unaffiliated revenues and expenses in the accompanying Consolidated Financial Statements.

F-123

Duke Capital LLC

Notes to Consolidated Financial Statements—(Continued)

Business Segment Data^(a)

	Unaffiliated Revenues		Intersegment Revenues			Total Revenues			Segment EBIT / Consolidated Earnings from Continuing Operations before Income Taxes			Depreciation and Amortization
	(in millions)
Nine Months Ended September 30, 2006
Natural Gas Transmission	$	3,327	$	(3	)	$	3,324		$	1,102		$	361
Field Services(c)		—		—			—			450			—
International Energy		719		—			719			182			56
Crescent(d)		221		—			221			515			1
Total reportable segments		4,267		(3	)		4,264			2,249			418
Other		244		38			282			(55	)		18
Eliminations		—		(35	)		(35	)		—			—
Interest expense		—		—			—			(542	)		—
Interest income and other(b)		—		—			—			43			—
Total consolidated	$	4,511	$	—		$	4,511		$	1,695		$	436
Nine Months Ended September 30, 2005
Natural Gas Transmission	$	2,732	$	92		$	2,824		$	1,044		$	339
Field Services(c)		5,470		60			5,530			1,784			143
International Energy		536		—			536			217			48
Crescent(d)		281		—			281			210			1
Total reportable segments		9,019		152			9,171			3,255			531
Other		516		(85	)		431			(270	)		19
Eliminations		—		(67	)		(67	)		—			—
Interest expense		—		—			—			(596	)		—
Interest income and other(b)		—		—			—			35			—
Total consolidated	$	9,535	$	—		$	9,535		$	2,424		$	550

(a) Segment results exclude results of any discontinued operations.

(b) Other includes foreign currency transaction gains and losses, and additional minority interest expense not allocated to the segment results.

(c) In July 2005, Duke Energy caused a Duke Capital subsidiary to complete the agreement with ConocoPhillips to reduce Duke Capital’s ownership interest in DEFS from 69.7% to 50%. Field Services segment data includes DEFS as a consolidated entity for periods prior to July 1, 2005 and as an equity method investment for periods after June 30, 2005.

(d) In September 2006, Duke Energy caused a Duke Capital subsidiary to complete a joint venture transaction of Crescent (see Note 2). As a result, Crescent segment data includes Crescent as a consolidated entity for periods prior to September 7, 2006 and as an equity method investment for periods subsequent to September 7, 2006.

F-124

Duke Capital LLC

Notes to Consolidated Financial Statements—(Continued)

Segment assets in the following table exclude all intercompany assets.

Segment Assets

	September 30, 2006			December 31, 2005
	(in millions)
Natural Gas Transmission	$	19,219		$	18,823
Field Services		1,455			1,377
Commercial Power(a)		—			1,619
International Energy		3,151			2,962
Crescent(b)		163			1,507
Total reportable segments		23,988			26,288
Other(a)		1,528			8,533
Reclassifications(c)		(25	)		235
Total consolidated assets	$	25,491		$	35,056

(a) December 31, 2005 balance includes impacts of the reclassification of DENA’s Midwestern power generating assets from Other to Commercial Power

(b) Decrease in Crescent segment assets due to the joint venture transaction of Crescent completed in September 2006 and resulting deconsolidation of Crescent (see Note 2). Balance at September 30, 2006 represents Duke Capital’s effective 50% investment in Crescent as a result of the deconsolidation.

(c) Represents reclassification of federal tax balances in consolidation.

12. Risk Management Instruments

The following table shows the carrying value of Duke Capital’s derivative portfolio as of September 30, 2006, and December 31, 2005.

Derivative Portfolio Carrying Value

	September 30, 2006			December 31, 2005
	(in millions)
Hedging	$	8		$	(2	)
Trading		—			5
Undesignated		(41	)		(52	)
Total	$	(33	)	$	(49	)

The amounts in the table above represent the combination of assets and (liabilities) for unrealized gains and losses on mark-to-market and hedging transactions on Duke Capital’s Consolidated Balance Sheets, excluding approximately $153 million of derivative assets and $153 million of derivative liabilities presented as assets and liabilities held for sale at September 30, 2006.

The $11 million change in the undesignated derivative portfolio fair value is due primarily to realized losses on certain contracts held by Duke Capital related to Field Services’ commodity price risk, partially offset by realized mark-to-market (MTM) gains at DENA and mark-to-market movement due to change in crude oil prices. As a result of the transfer of 19.7% interest in DEFS to ConocoPhillips and the third quarter 2005 deconsolidation of its investment in DEFS, Duke Capital has discontinued hedge accounting for certain contracts held by Duke Capital related to Field Services’ commodity price risk, which were previously accounted for as

F-125

Duke Capital LLC

Notes to Consolidated Financial Statements—(Continued)

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. As a result, approximately $355 million of pre-tax losses were recognized in earnings by Duke Capital during the nine months ended September 30, 2005. These charges have been classified in the accompanying Consolidated Statements of Operations as follows: upon discontinuance of hedge accounting approximately $120 million of pre-tax losses were recognized as a component of Impairments and Other Charges, approximately $130 million of pre-tax losses prior to the deconsolidation of DEFS were recognized as a component of Non-Regulated Electric, Natural Gas, Natural Gas Liquids, and Other Revenues, and $105 million of pre-tax losses subsequent to the deconsolidation of DEFS were recognized as a component of Other Income and Expenses, net for the nine months ended September 30, 2005. Approximately $20 million and $25 million of realized and unrealized pre-tax gains and losses, respectively, related to these contracts were recognized in earnings by Duke Capital during the nine months ended September 30, 2006, as a component of Other Income and Expenses, net as of a result of Duke Capital’s investment in DEFS being accounted for using the equity method. Cash settlements on these contracts during the nine months ended September 30, 2006 of approximately $134 million are classified as a component of net cash used in investing activities in the accompanying Consolidated Statements of Cash Flows.

Included in Other Current Assets in the Consolidated Balance Sheets as of September 30, 2006 and December 31, 2005 are collateral assets of approximately $9 million and $1,279 million, respectively. Collateral assets represent cash collateral posted by Duke Capital with other third parties. Included in Other Current Liabilities and Other Deferred Credits and Other Liabilities in the Consolidated Balance Sheets as of September 30, 2006 and December 31, 2005 are collateral liabilities of approximately $109 million and $608 million, respectively. Collateral liabilities represent cash collateral posted by other third parties to Duke Capital. Subsequent to December 31, 2005, in connection with the sale to Barclays of contracts related to DENA’s energy marketing and management activities, which includes structured power and other contracts, Barclays provided DENA cash equal to the net collateral posted by DENA under the contracts. Net cash collateral received by Duke Capital in January 2006 was approximately $540 million based on current market prices of the contracts (see Note 10).

During the first quarter of 2005, Duke Capital settled certain hedges which were documented and designated as net investment hedges of the investment in Westcoast on their scheduled maturity and paid approximately $162 million. Losses recognized on this net investment hedge have been classified in AOCI as a component of foreign currency adjustments and will not be recognized in earnings unless the complete or substantially complete liquidation of Duke Capital’s investment in Westcoast occurs.

Commodity Cash Flow Hedges. Some Duke Capital subsidiaries are exposed to market fluctuations in the prices of various commodities related to their ongoing power generating and natural gas gathering, distribution, processing and marketing activities. Duke Capital closely monitors the potential impacts of commodity price changes and, where appropriate, enters into contracts to protect margins for a portion of future sales and generation revenues and fuel expenses. Duke Capital uses commodity instruments, such as swaps, futures, forwards and options as cash flow hedges for natural gas, electricity and natural gas liquid transactions. Duke Capital’s hedging exposures to the price variability of these commodities does not extend beyond one year.

As of September 30, 2006, $6 million of pre-tax deferred net losses on derivative instruments related to commodity cash flow hedges were accumulated on the Consolidated Balance Sheet in AOCI, and are expected to be recognized in earnings during the next 12 months as the hedged transactions occur. However, due to the volatility of the commodities markets, the corresponding value in AOCI will likely change prior to its reclassification into earnings.

F-126

Duke Capital LLC

Notes to Consolidated Financial Statements—(Continued)

The ineffective portion of commodity cash flow hedges resulted in the recognition of a pre-tax gain of approximately $2 million in the nine months ended September 30, 2006, as compared to a pre-tax loss of approximately $11 million in the nine months ended September 30, 2005. The amount recognized for transactions that no longer qualified as cash flow hedges was a pre-tax loss of approximately $67 million as of September 30, 2006 and is reported in Income (Loss) From Discontinued Operations, net of tax. The amount recognized for transactions that no longer qualify as cash flow hedges was a pre-tax gain of approximately $1.2 billion in the nine months ended September 30, 2005, and is reported in Income (Loss) From Discontinued Operations, net of tax in the Consolidated Statement of Operations. The disqualified cash flow hedges were primarily associated with DENA’s unrealized net gains on natural gas and power cash flow hedge positions.

Commodity Fair Value Hedges. Some Duke Capital subsidiaries are exposed to changes in the fair value of some unrecognized firm commitments to sell generated power or natural gas due to market fluctuations in the underlying commodity prices. Duke Capital actively evaluates changes in the fair value of such unrecognized firm commitments due to commodity price changes and, where appropriate, uses various instruments to hedge its market risk. These commodity instruments, such as swaps, futures and forwards, serve as fair value hedges for the firm commitments associated with generated power. The ineffective portion of commodity fair value hedges resulted in a pre-tax gain of $7 million in the nine months ended September 30, 2006, as compared to an immaterial amount in the nine months ended September 30, 2005.

Other Derivative Contracts. In connection with the Barclays transaction discussed in Note 10, Duke Capital entered into a series of TRS with Barclays, which are accounted for as mark-to-market derivatives. The TRS offsets the net fair value of the contracts being sold to Barclays. At September 30, 2006, contracts with a net fair value of approximately $6 million remain in Assets Held for Sale and represent contracts that have yet to be novated by Barclays. Duke Capital has taken all steps necessary to novate these remaining contracts and is awaiting counterparty action. Barclays handles all administrative aspects of the remaining contracts and there are no cash flows to Duke Capital associated with the remaining contracts, nor does Duke Capital have any continuing involvement with these contracts. The fair value of the TRS as of September 30, 2006 is a net liability of approximately $6 million, which offsets the net fair value of the underlying contracts. The TRS will be cancelled as the underlying transactions are transferred to Barclays.

Normal Purchases and Normal Sales. The amount recognized for transactions that no longer qualified as normal purchases/normal sales was a pretax net loss of approximately $1.9 billion in the nine months ended September 30, 2005, and is reported in Income (Loss) From Discontinued Operations, net of tax in the accompanying Consolidated Statement of Operations. The net loss recorded during the third quarter of 2005, which primarily included certain contracts that were being accounted for as normal purchases/normal sales, was recognized due to management’s plan for the sale or disposition of substantially all of DENA’s physical and commercial assets outside the midwestern United States and certain contractual positions related to the Midwestern assets.

13. Regulatory Matters

Natural Gas Transmission. Rate Related Information. In November 2005, The British Columbia Pipeline System (BC Pipeline) filed an application with the National Energy Board (NEB) for interim and final tolls for 2006. In December 2005, the NEB approved the 2006 interim tolls as filed and BC Pipeline started negotiations with its shippers to reach a settlement on final tolls for years 2006 and 2007. BC Pipeline reached a toll settlement agreement in principle with its customers for the 2006 and 2007 fiscal years on March 30, 2006. The toll settlement agreement was filed with the NEB on June 21, 2006 and on July 11, 2006 pursuant to the NEB’s Revised Guidelines for Negotiated Settlements, the NEB has asked for comments from interested parties due July 26, 2006. NEB approval was received on August 17, 2006.

F-127

Duke Capital LLC

Notes to Consolidated Financial Statements—(Continued)

Union Gas has rates that are approved by the Ontario Energy Board (OEB). Effective January 1, 2006, Union Gas implemented new rates approved by the OEB in December 2005, reflecting items previously approved. Union Gas’ earnings for 2006 continue to be subject to the earnings sharing mechanism implemented by the OEB in 2005.

In December 2005, Union Gas filed an application with the OEB for new rates effective January 1, 2007. In May 2006, Union Gas reached a comprehensive agreement with intervenors on all financial issues, except storage regulation and Demand Side Management (DSM), and on most non-financial issues. Storage regulation and DSM are being addressed through separate proceedings initiated by the OEB. The OEB accepted this agreement on May 23, 2006. The agreement includes an increase in the common equity component of Union Gas’ capital structure, from 35% to 36%. A decision on the remaining non-financial issues was issued by the OEB on June 29, 2006. As a result of the comprehensive agreement reached in May 2006, the DSM decision, and the decrease in return on equity, 2007 rates are expected to increase by approximately 1.7%, excluding the impact of the pending decision on storage rates.

Rates for the sale of gas are adjusted quarterly to reflect updated commodity price forecasts. The difference between the approved and the actual cost of gas incurred in the current period is deferred for future recover from or return to customers, subject to approval by the OEB. These differences are directly flowed through to customers and, therefore, no rate of return is earned on the related deferred balances. The OEB’s review and approval of these gas purchase costs primarily considers the prudence of the cost incurred.

Effective January 1, 2005, new rates (interim rates) for Maritimes & Northeast Pipeline L.L.C. (M&N) took effect, subject to refund, as a result of a rate case filed by M&N in 2004. In June 2005, a settlement agreement to resolve the proceeding was reached with customers that would provide for a rate increase over rates charged prior to January 1, 2005. On May 15, 2006 the FERC issued an order approving the settlement agreement. In June 2006, M&N refunded the difference between the settlement rates and the interim rates, plus interest, to each shipper due a refund.

Management believes that the effects of these matters will have no material adverse effect on Duke Capital’s future consolidated results of operations, cash flows or financial position.

14. Commitments and Contingencies

Environmental

Duke Capital is subject to international, federal, state and local regulations regarding air and water quality, hazardous and solid waste disposal and other environmental matters.

Remediation activities. Like others in the energy industry, Duke Capital and its affiliates are responsible for environmental remediation at various contaminated sites. These include some properties that are part of ongoing Duke Capital operations, sites formerly owned or used by Duke Capital 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 Capital or its affiliates could potentially be held responsible for contamination caused by other parties. In some instances, Duke Capital may share liability associated with contamination with other potentially responsible parties, and may also benefit from insurance policies or contractual indemnities that cover some or all cleanup costs. All of these sites generally are managed in the normal course of business or affiliate operations. Management believes that completion or resolution of these matters will have no material adverse effect on Duke Capital’s consolidated results of operations, cash flows or financial position.

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Extended Environmental Activities, Accruals. Included in Other Current Liabilities and Other Deferred Credits and Other Liabilities on the Consolidated Balance Sheets were total accruals related to extended environmental-related activities of approximately $46 million and $50 million as of September 30, 2006 and December 31, 2005, respectively. These accruals represent Duke Capital’s provisions for costs associated with remediation activities at some of its current and former sites, as well as other relevant environmental contingent liabilities. Management believes that completion or resolution of these matters will have no material adverse effect on Duke Capital’s consolidated results of operations, cash flows or financial position.

Litigation

Western Energy and Natural Gas Litigation and Regulatory Matters. Duke Capital and several of its affiliates, as well as other energy companies, are parties to 34 lawsuits filed by or on behalf of electricity and/or natural gas purchasers in several Western states. Many of the suits seek class-action certification. The plaintiffs allege that the defendants conspired to manipulate the electricity and/or natural gas markets in violation of state and/or federal antitrust, unfair business practices and other laws. Plaintiffs in some of the cases further allege that such activities, including engaging in “round trip” trades, providing false information to natural gas trade publications and unlawfully exchanging information, resulted in artificially high energy prices. Plaintiffs seek aggregate damages or restitution of billions of dollars from the defendants. Six of these cases were dismissed on filed rate and/or federal preemption grounds, and the plaintiffs in each of these dismissed cases have appealed their respective rulings to the U.S. Ninth Circuit Court of Appeals. In September 2006, Duke Capital reached an agreement in principle to settle the 12 class action cases pending in California. Such agreement is subject to execution of mutually acceptable agreements and approval by the class members and the court. Duke Capital does not expect that the proposed settlement will have a material adverse effect on its consolidated results of operations, cash flows or financial position. With respect to the remaining cases, it is not possible to predict with certainty whether Duke Capital will incur any liability or to estimate the damages, if any, that Duke Capital might incur in connection with these lawsuits, but Duke Capital does not presently believe the outcome of these matters will have a material adverse effect on Duke Capital’s results of operations, cash flows or financial position.

In 2002, Southern California Edison Company initiated arbitration proceedings regarding disputes with DETM relating to amounts owed in connection with the termination of bi-lateral power contracts between the parties in early 2001. This matter proceeded to hearing in November 2005. In January 2006, the parties reached an agreement in principle to resolve the matters at issue in the arbitration. The parties entered into a Settlement Agreement and Mutual Release dated as of March 10, 2006, and on March 24, 2006, DETM paid the settlement amount, including interest, into escrow. The agreement received final regulatory approval in October 2006. The resolution of this matter did not have a material adverse effect on Duke Capital’s consolidated results of operations, cash flows or financial position.

Trading Related Litigation. Commencing August 2003, plaintiffs filed three class-action lawsuits in the U.S. District Court for the Southern District of New York on behalf of entities who bought and sold natural gas futures and options contracts on the New York Mercantile Exchange during the years 2000 through 2002. DETM, along with numerous other entities, were named as defendants. The plaintiffs claim that the defendants violated the Commodity Exchange Act by reporting false and misleading trading information to trade publications, resulting in monetary losses to the plaintiffs. Plaintiffs seek class action certification, unspecified damages and other relief. On September 24, 2004, the court denied a motion to dismiss the plaintiffs’ claims filed on behalf of DETM and other defendants, and on September 30, 2005, the court certified the class. Duke Capital has reached an agreement with the plaintiffs in these consolidated cases to resolve all issues and on February 8, 2006, the court granted preliminary approval of this settlement. The Final Judgment and Order of Dismissal were entered in May 2006. The resolution of this matter did not have a material adverse effect on Duke Capital’s consolidated results of operations, cash flows or financial position.

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On January 28, 2005, four plaintiffs filed suit in Tennessee Chancery Court against Duke Capital affiliates and other energy companies seeking class action certification on behalf of indirect purchasers of natural gas. On August 8, 2005, a plaintiff filed a lawsuit in state court in Kansas against Duke Capital and DETM, as well as other energy companies. On September 26, 2005, a petition was filed in state court in Kansas and on May 19, 2006 another petition was filed in Colorado state court. In October 2006, the Missouri Public Service Commission filed a lawsuit in state court in Missouri. These cases were also filed against Duke Capital and DETM, as well as other energy companies. Each of these five cases contains similar claims, that the respective plaintiffs, and the classes they claim to represent, were harmed by the defendants’ alleged manipulation of the natural gas markets by various means, including providing false information to natural gas trade publications and entering into unlawful arrangements and agreements in violation of the antitrust laws of the respective states. Plaintiffs seek damages in unspecified amounts. Duke Capital is unable to express an opinion regarding the probable outcome or estimate damages, if any, related to these matters at this time.

Trading Related Investigations. Beginning in February 2004, Duke Capital has received requests for information from the U.S. Attorney’s office in Houston focused on the natural gas price reporting activities of certain individuals involved in DETM trading operations. Duke Capital has cooperated with the government in this investigation and is unable to express an opinion regarding the probable outcome or estimated damages, if any, related to this matter at this time.

Sonatrach/Sonatrading Arbitration. Duke Energy LNG Sales Inc. (Duke LNG) claims in an arbitration commenced in January 2001 in London that Sonatrach, the Algerian state-owned energy company, together with its subsidiary, Sonatrading Amsterdam B.V. (Sonatrading), breached their shipping obligations under a liquefied natural gas (LNG) purchase agreement and related transportation agreements (the LNG Agreements) relating to Duke LNG’s purchase of LNG from Algeria and its transportation by LNG tanker to Lake Charles, Louisiana. Duke LNG seeks damages of approximately $27 million. Sonatrading and Sonatrach, on the other hand, claim that Duke LNG repudiated the LNG Agreements by allegedly failing to diligently perform LNG marketing obligations. Sonatrading and Sonatrach seek damages in the amount of approximately $250 million. In 2003, an arbitration tribunal issued a Partial Award on liability issues, finding that Sonatrach and Sonatrading breached their obligations to provide shipping. The tribunal also found that Duke LNG breached the LNG Purchase Agreement by failing to perform marketing obligations. The final hearing on damages was concluded in March 2006 and the parties are awaiting a ruling from the tribunal.

Citrus Trading Corporation (Citrus) Litigation. In conjunction with the Sonatrach LNG Agreements, Duke LNG entered into a natural gas purchase contract (the Citrus Agreement) with Citrus. Citrus filed a lawsuit in March 2003 in the U.S. District Court for the Southern District of Texas against Duke LNG and PanEnergy Corp alleging that Duke LNG breached the Citrus Agreement by failing to provide sufficient volumes of gas to Citrus. Duke LNG contends that Sonatrach caused Duke LNG to experience a loss of LNG supply that affected Duke LNG’s obligations and termination rights under the Citrus Agreement. Citrus seeks monetary damages and a judicial determination that Duke LNG did not experience such a loss. After Citrus filed its lawsuit, Duke LNG terminated the Citrus Agreement and filed a counterclaim asserting that Citrus had breached the agreement by, among other things, failing to provide sufficient security under a letter of credit for the gas transactions. Citrus denies that Duke LNG had the right to terminate the agreement and contends that Duke LNG’s termination of the agreement was itself a breach, entitling Citrus to terminate the agreement and recover damages in the amount of approximately $190 million (excluding interest). The Court has made preliminary rulings regarding the issues of fact and law that remain for trial. A jury trial is scheduled to commence on December 5, 2006. It is not possible to predict with certainty whether Duke Capital will incur any liability or to estimate the damages, if any, that Duke Capital might incur in connection with the Sonatrach and Citrus matters.

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Exxon Mobil Disputes. In April 2004, Mobil Natural Gas, Inc. (MNGI) and 3946231 Canada, Inc. (3946231, and collectively with MNGI, Exxon Mobil) filed a Demand for Arbitration against Duke Capital, DETMI Management Inc. (DETMI), DTMSI Management Ltd. (DTMSI) and other affiliates of Duke Capital. MNGI and DETMI are the sole members of DETM. DTMSI and 3946231 are the sole beneficial owners of Duke Energy Marketing Limited Partnership (DEMLP, and with DETM, the Ventures). Among other allegations, Exxon Mobil alleges that DETMI and DTMSI engaged in wrongful actions relating to affiliate trading, payment of service fees, expense allocations and distribution of earnings in breach of agreements and fiduciary duties relating to the Ventures. Exxon Mobil seeks to recover actual damages, plus attorneys’ fees and exemplary damages; aggregate damages were specified at the arbitration hearing and totaled approximately $125 million (excluding interest). Duke Capital denies these allegations, and has filed counterclaims asserting that Exxon Mobil breached its Venture obligations and other contractual obligations. By order dated May 2, 2005, the arbitrators granted Duke Capital’s Motion for Partial Summary Judgment, effectively eliminating a significant portion of Exxon Mobil’s claims. Exxon Mobil filed a motion for reconsideration of the ruling as well as for an extension of the date for the arbitration hearing. Exxon Mobil also filed a motion to dismiss certain of Duke Capital’s counterclaims. Following a hearing in December 2005 on the motion for reconsideration, the arbitrators issued their ruling on January 26, 2006, generally reaffirming the original order, with a limited exception with respect to affiliate trades that is not expected to have a significant impact on the case. The panel also dismissed one of Duke Capital’s counterclaims. The parties agreed that the damages due to Duke Capital on its counterclaim will be determined in the upcoming hearing scheduled in the Canadian arbitration proceedings. The arbitration hearing in the U.S. arbitration was held in October 2006 in Houston, Texas. In August 2004, DEMLP initiated arbitration proceedings in Canada against certain Exxon Mobil entities asserting that those entities wrongfully terminated two gas supply agreements with the DEMLP and wrongfully failed to assume certain related gas supply agreements with other parties. A hearing in the Canadian arbitration was held in March 2006. The arbitrators issued their award in June, 2006 finding that (1) the two gas supply agreements were improperly terminated by ExxonMobil; but (2) ExxonMobil was not required to take assignment of the related third party gas supply agreements. A hearing to determine the damages to be paid as the result of the first ruling, as well as the damages to be paid to Duke Capital as the result of the termination of the U.S. gas supply agreement, was held on November 9 and 10, 2006, before the same panel of arbitrators. At this time Duke Capital is unable to estimate the amount of any damage award to be received in resolution of this matter. The gas supply agreements with other parties, under which DEMLP continues to remain obligated, are currently estimated to result in losses of between $100 million and $150 million through 2011. However, these losses are subject to change in the future in the event of changes in market conditions and underlying assumptions.

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

Duke Capital has exposure to certain legal matters that are described herein. As of September 30, 2006 and December 31, 2005, Duke Capital has recorded reserves of approximately $79 million and $150 million, respectively, for these proceedings and exposures. Duke Capital 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, “Accounting for Contingencies.”

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

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Other Commitments and Contingencies

Other. As part of its normal business, Duke Capital is a party to various financial guarantees, performance guarantees and other contractual commitments to extend guarantees of credit and other assistance to various subsidiaries, investees and other third parties. To varying degrees, these guarantees involve elements of performance and credit risk, which are not included on the Consolidated Balance Sheets. The possibility of Duke Capital having to honor its contingencies is largely dependent upon future operations of various subsidiaries, investees and other third parties, or the occurrence of certain future events. (For further information see Note 15.)

In addition, Duke Capital enters into various fixed-price, non-cancelable commitments to purchase or sell power (tolling arrangements or power purchase contracts), take-or-pay arrangements, transportation or throughput agreements and other contracts that may or may not be recognized on the Consolidated Balance Sheets. Some of these arrangements may be recognized at market value on the Consolidated Balance Sheets as trading contracts or qualifying hedge positions included in Unrealized Gains or Losses on Mark-to-Market and Hedging Transactions. (See Note 15 for discussion of Calpine guarantee obligation.)

15. Guarantees and Indemnifications

Duke Capital and its subsidiaries have various financial and performance guarantees and indemnifications which are issued in the normal course of business. As discussed below, these contracts include performance guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications. Duke Capital and its subsidiaries enter into these arrangements to facilitate a commercial transaction with a third party by enhancing the value of the transaction to the third party.

Duke Capital has issued performance guarantees to customers and other third parties that guarantee the payment and performance of other parties, including certain non-wholly-owned entities. The maximum potential amount of future payments Duke Capital could have been required to make under these performance guarantees as of September 30, 2006 was approximately $558 million. Of this amount, approximately $318 million relates to guarantees of the payment and performance of less than wholly-owned consolidated entities. Approximately $352 million of the performance guarantees expire between 2006 and 2007, with the remaining performance guarantees expiring after 2007 or having no contractual expiration. Additionally, Duke Capital has issued joint and several guarantees to some of the D/FD project owners, guaranteeing the performance of D/FD under its engineering, procurement and construction contracts and other contractual commitments. These guarantees have no contractual expiration and no stated maximum amount of future payments that Duke Capital could be required to make. Additionally, Fluor Enterprises Inc., as 50% owner in D/FD, has issued similar joint and several guarantees to the same D/FD project owners. In accordance with the D/FD partnership agreement, each of the partners is responsible for 50% of any payments to be made under those guarantees.

Duke Capital has issued guarantees to customers or other third parties related to the payment or performance obligations of certain entities that were previously wholly-owned by Duke Capital but which have been sold to third parties, such as DukeSolutions, Inc. (DukeSolutions) and Duke Engineering & Services, Inc. (DE&S). These guarantees are primarily related to payment of lease obligations, debt obligations, and performance guarantees related to provision of goods and services. Duke Capital has received back-to-back indemnification from the buyer of DE&S indemnifying Duke Capital for any amounts paid by Duke Capital related to the DE&S guarantees. Duke Capital also received indemnification from the buyer of DukeSolutions for the first $2.5 million paid by Duke Capital related to the DukeSolutions guarantees. Further, Duke Capital granted indemnification to the buyer of DukeSolutions with respect to losses arising under some energy services agreements retained by DukeSolutions after the sale, provided that the buyer agreed to bear 100% of the performance risk and 50% of any other risk up to an aggregate maximum of $2.5 million (less any amounts paid

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by the buyer under the indemnity discussed above). Additionally, for certain performance guarantees, Duke Capital has recourse to subcontractors involved in providing services to a customer. These guarantees have various terms ranging from 2006 to 2021, with others having no specific term. Duke Capital is unable to estimate the total maximum potential amount of future payments under these guarantees, since some of the underlying agreements have no limits on potential liability.

Westcoast has issued performance guarantees to third parties guaranteeing the performance of unconsolidated entities, such as equity method investments, and of entities previously sold by Westcoast to third parties. Those guarantees require Westcoast to make payment to the guaranteed third party upon the failure of such unconsolidated or sold entity to make payment under some of its contractual obligations, such as debt, purchase contracts and leases. The maximum potential amount of future payments Westcoast could have been required to make under those performance guarantees as of September 30, 2006 was approximately $15 million. Of those guarantees, approximately $10 million expire in 2006, with the remainder having no contractual expiration.

Duke Capital uses bank-issued stand-by letters of credit to secure the performance of non-wholly-owned entities to a third party or customer. Under these arrangements, Duke Capital has payment obligations to the issuing bank which are triggered by a draw by the third party or customer due to the failure of the non-wholly-owned entity to perform according to the terms of its underlying contract. The maximum potential amount of future payments Duke Capital could have been required to make under these letters of credit as of September 30, 2006 was approximately $50 million. Substantially all of these letters of credit were issued on behalf of less than wholly-owned consolidated entities and expire in 2006 or 2007.

In connection with Duke Capital’s sale of the Murray merchant generation facility to KGen Partners LLC (KGEN), in August 2004, Duke Capital guaranteed in favor of a bank the repayment of any draws under a $120 million letter of credit issued by the bank to Georgia Power Company. The letter of credit, which expires in 2006, is related to the obligation of a KGen subsidiary under a seven-year power sales agreement, commencing in May 2005. Duke Capital will be required to ensure reissuance of this letter of credit or issue similar credit support until the power sales agreement expires in 2012. Duke Capital will operate the sold Murray facility under an operation and maintenance agreement with the KGen subsidiary. As a result, the guarantee has an immaterial fair value. Further, KGen has agreed to indemnify Duke Capital for any payments Duke Capital makes with respect to the $120 million letter of credit.

Duke Capital has guaranteed certain issuers of surety bonds, obligating itself to make payment upon the failure of a non-wholly-owned entity to honor its obligations to a third party. As of September 30, 2006, Duke Capital had guaranteed approximately $200 million of outstanding surety bonds related to obligations of non-wholly-owned entities. The majority of these bonds expire in various amounts in 2007.

In 1999, the Industrial Development Corp of the City of Edinburg, Texas (IDC) issued approximately $100 million in bonds to purchase equipment for lease to Duke Hidalgo (Hidalgo), a subsidiary of Duke Capital. Duke Capital unconditionally and irrevocably guaranteed the lease payments of Hidalgo to IDC through 2028. In 2000, Hidalgo was sold to Calpine Corporation and Duke Capital remained obligated under the lease guaranty. In January 2006, Hidalgo and its subsidiaries filed for bankruptcy protection in connection with the previous bankruptcy filing by its parent, Calpine Corporation in December 2005. Gross, undiscounted exposure under the guarantee obligation as of September 30, 2006 is approximately $200 million, which includes principal and interest. Duke Capital does not believe a loss under the guarantee obligation is probable as of September 30, 2006, but continues to evaluate the situation. Therefore, no reserves have been recorded for any contingent loss as of September 30, 2006. No demands for payment of principal or interest have been made under the guarantee. If future losses are incurred under the guarantee, Duke Capital has certain rights which should allow it to mitigate such loss.

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Natural Gas Transmission and International Energy have issued guarantees of debt and performance guarantees associated with non-consolidated entities and less than wholly-owned consolidated entities. If such entities were to default on payments or performance, Natural Gas Transmission or International Energy would be required under the guarantees to make payment on the obligation of the less than wholly-owned entity. As of September 30, 2006, Natural Gas Transmission was the guarantor of approximately $18 million of debt at Westcoast associated with less than wholly-owned entities, which expire in 2019. International Energy was the guarantor of approximately $13 million of performance guarantees associated with less than wholly-owned entities. Substantially all of these guarantees expire between 2006 and 2008.

Duke Capital has entered into various indemnification agreements related to purchase and sale agreements and other types of contractual agreements with vendors and other third parties. These agreements typically cover environmental, tax, litigation and other matters, as well as breaches of representations, warranties and covenants. Typically, claims may be made by third parties for various periods of time, depending on the nature of the claim. Duke Capital’s potential exposure under these indemnification agreements can range from a specified amount, such as the purchase price, to an unlimited dollar amount, depending on the nature of the claim and the particular transaction. Duke Capital is unable to estimate the total potential amount of future payments under these indemnification agreements due to several factors, such as the unlimited exposure under certain guarantees.

As discussed in Note 1, in connection with the transfer of DENA’s Midwestern assets to Duke Energy Ohio, Duke Capital and Duke Energy Ohio entered into an arrangement through April 2016, unless otherwise extended by the parties, whereby Duke Capital will reimburse Duke Energy Ohio in the event of certain cash shortfalls that may result from Duke Energy Ohio’s ownership of the Midwestern assets. Duke Capital is unable to estimate total maximum potential amount of future payments under this financial performance guarantee, however payments made under this agreement have not been and are not expected to be significant.

As of September 30, 2006, the amounts recorded for the guarantees and indemnifications mentioned above are immaterial, both individually and in the aggregate.

In June 2006, the Board of Directors of Duke Energy authorized management to pursue a plan to create two separate publicly traded companies by spinning off Duke Energy’s natural gas businesses to Duke Energy shareholders. The new gas company, which would be named Spectra Energy, would consist of Duke Capital’s Natural Gas Transmission businesses segment, which would include Union Gas, and would also include Duke Capital’s 50-percent ownership interest in DEFS. While the actual timing of the spin-off, if it occurs, is dependent upon the resolution of certain regulatory and other matters, Duke Energy is currently targeting a January 1, 2007 effective date for the transaction. As a result of the spin-off, Duke Capital is expected to indemnify Duke Energy for any amounts paid under existing guarantees of wholly-owned subsidiaries that will become guarantees of third party performance upon the separation of the gas and power businesses.

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16. Member’s Equity and Related Party Transactions

As discussed in Note 2, in September 2006, Duke Capital deconsolidated its investment in Crescent JV as a result of a reduction in ownership and subsequently has accounted for the investment using the equity method of accounting. Duke Capital’s investment in Crescent JV as of September 30, 2006 was approximately $163 million. Equity earnings for the period from the date of deconsolidated (September 7, 2006) through September 30, 2006 were immaterial. Summary balance sheet information for Crescent, which is accounted for under the equity method, as of September 30, 2006 is as follows:

	September 30, 2006
	(in millions)
Current assets	$	215
Non-current assets	$	1,587
Current liabilities	$	169
Non-current liabilities	$	1,344
Minority interest	$	30

During the nine months ended September 30, 2006, Duke Capital advanced approximately $86 million to its parent, Duke Energy, and forgave advances to Duke Energy of approximately $571 million. The advance is presented as Advances to Parent within financing activities in the Consolidated Statements of Cash Flows for the nine months ended September 30, 2006. The advances forgiveness has been presented as a non-cash financing activity within the Consolidated Statement of Cash Flows for the nine months ended September 30, 2006.

During the nine months ended September 30, 2006, Duke Capital distributed approximately $2,192 million to Duke Energy to provide funding support for Duke Energy’s dividend payments and share repurchase plan. The distribution was principally obtained from the proceeds received on Duke Capital’s sale of 50% of Crescent to the MS Members (see Note 2). During the nine months ended September 30, 2005, Duke Capital distributed $1,150 million to Duke Energy to provide funding for the execution of Duke Energy’s accelerated share acquisition plan. The distribution was principally obtained from Duke Capital’s portion of the cash proceeds realized from the sale by DEFS of TEPPCO GP and Duke Capital’s sale of its limited partner interest in TEPPCO, noted above.

During 2004, $267 million of cash advances were received by Duke Capital from Duke Energy as a partial return of the income tax benefit associated with the transfer of deferred tax assets to Duke Energy in 2004. During the first quarter of 2005, Duke Energy forgave these advances of $267 million and Duke Capital classified the $267 million as an addition to Member’s Equity. Additionally, during the third quarter of 2005, Duke Energy forgave additional advances of $494 million and classified the $494 million as an addition to Member’s Equity. These forgivenesses have been presented as a non-cash financing activity in the Consolidated Statements of Cash Flows for the nine months ended September 30, 2005.

During the nine months ended September 30, 2005, Duke Capital received capital contributions of $269 million from Duke Energy, which Duke Capital classified as an addition to Member’s Equity. Additionally, during the nine months ended September 30, 2005, Duke Capital received $104 million in advances from Duke Energy. These transactions are presented as a component of net cash used in financing activities in the Consolidated Statements of Cash Flows for the nine months ended September 30, 2005.

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Balances due to or due from Duke Energy or other affiliates included in the Consolidated Balance Sheets as of September 30, 2006 and December 31, 2005 are as follows:

Assets/(Liabilities)	September 30, 2006			December 31, 2005
	(in millions)
Advances receivable/(payable)(b)	$	392		$	(30	)
Taxes receivable/(payable)(a)	$	(38	)	$	187
Other noncurrent assets(d)	$	20		$	—
Other current liabilities(c)	$	—		$	(2	)

(a) Taxes receivable are classified as Other Current Assets on the Consolidated Balance Sheets. Taxes payable are classified as Taxes Accrued on the Consolidated Balance Sheets.

(b) Advances receivable are included in Other within Investments and Other Assets on the Consolidated Balance Sheets. Advances payable are included in Other within Deferred Credits and Other Liabilities on the Consolidated Balance Sheets. The advances do not bear interest, are carried as open accounts and are not segregated between current and non-current amounts.

(c) The balance is classified as Other Current Liabilities on the Consolidated Balance Sheets.

(d) The balance is classified in Other within Investments and Other Assets on the Consolidated Balance Sheets.

For the nine months ended September 30, 2006 and 2005, Duke Capital recorded income in the amount of approximately $62 million and $66 million, respectively, related to management fees charged to an unconsolidated affiliate of Duke Capital. These amounts are recorded in Other Income and Expenses, net on the Consolidated Statements of Operations. Previously, these amounts were recorded as a reduction of Operation, Maintenance and Other within Operating Expenses on the Consolidated Statements of Operations. Prior period amounts have been reclassified to Other Income and Expenses, net to conform to the 2006 presentation. For the nine months ended September 30, 2006 and 2005, Duke Capital recognized recoveries of expenses in the amount of $557 million and $332 million, respectively. These amounts represent recoveries of direct and allocated corporate governance and shared service costs charged to unconsolidated affiliates and are reflected as an offset within Operation, Maintenance, and Other and Depreciation and Amortization within Operating Expenses on the Consolidated Statements of Operations. Also included in Operations, Maintenance and Other within Operating Expenses in the Consolidated Statements of Operations for the nine months ended September 30, 2006 is approximately $21 million of allocated costs charged to Duke Capital by an affiliate of Cinergy.

For the nine months ended September 30, 2006 and 2005, net revenues of approximately $42 million and net revenues of $1 million, respectively, are included in the Consolidated Statements of Operations and primarily consist of settlements to Duke Energy for NGL’s, gas hedges and insurance premiums.

Additionally, as discussed in Note 2, in February 2005, DEFS sold its wholly-owned subsidiary TEPPCO GP, the general partner of TEPPCO Partners, L.P. (TEPPCO), for approximately $1.1 billion and Duke Energy sold its limited partner interest in TEPPCO for approximately $100 million. Prior to the completion of these sale transactions, Duke Energy accounted for its investment in TEPPCO under the equity method of accounting. For the three months ended March 31, 2005, TEPPCO had 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.

In July 2005, Duke Energy caused a Duke Capital subsidiary to complete the transfer of a 19.7% interest in DEFS to ConocoPhillips, Duke Capital’s co-equity owner in DEFS, which reduced Duke Energy’s ownership interest in DEFS from 69.7% to 50% and resulted in Duke Energy and ConocoPhillips becoming equal 50% owners of DEFS. As a result of this transaction, Duke Capital deconsolidated its investment in DEFS and

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subsequently has accounted for the investment using the equity method of accounting (see Note 2). Duke Capital’s 50% of equity in earnings of DEFS for the nine months ended September 30, 2006 was approximately

$454 million and Duke Capital’s investment in DEFS as of September 30, 2006 was $1,351 million, which is included in Investments in Unconsolidated Affiliates in the accompanying Consolidated Balance Sheets. During the nine months ended September 30, 2006, Duke Capital had gas sales to, purchases from, and other operating expenses from affiliates of DEFS of approximately $110 million, $36 million and $24 million, respectively. As of September 30, 2006, Duke Capital had payables to affiliates of DEFS of approximately $58 million. Additionally, Duke Capital received approximately $385 million in distributions of earnings from DEFS in the nine months ended September 30, 2006, which are included in Other, assets within Cash Flows from Operating Activities in the accompanying Consolidated Statements of Cash Flows. Duke Capital has recognized an approximate $98 million receivable as of September 30, 2006 due to its share of a distribution declared by DEFS in September 2006 but paid in October 2006. Summary financial information for DEFS, which is accounted for under the equity method, as of and for the nine months ended September 30, 2006 is as follows:

	Nine months Ended September 30, 2006
	(in millions)
Operating revenues	$	9,501
Operating expenses	$	8,492
Operating income	$	1,009
Net income	$	908

	September 30, 2006
	(in millions)
Current assets	$	2,524
Non-current assets	$	4,759
Current liabilities	$	2,515
Non-current liabilities	$	2,028
Minority interest	$	102

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

In December 2005, Duke Capital completed a 140 million Canadian dollar 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. Proceeds of approximately 14 million Canadian dollars are included in Proceeds from Duke Energy Income Fund within Cash Flows from Financing Activities in the Consolidated Statements of Cash Flows. Subsequent to the January 2006 sale of additional Trust Units, Duke Capital held an approximate 58% ownership interest in the Income Fund. In September 2006, the Income Fund sold approximately 9 million previously unissued Trust Units at a price of 12.15 Canadian dollars per Trust Unit for total proceeds of 104 million Canadian dollars, net of commissions and expenses of issuance, which is included in Proceeds from Duke Energy Income Fund within Cash Flows from Financing Activities in the Consolidated Statements of Cash Flows. The sale of approximately 9 million Trust Units reduced Duke Capital’s ownership interest in the Income Fund to approximately 46% at

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September 30, 2006. As a result of the sale of additional Trust Units, Duke Capital recognized an approximate $15 million U.S. dollar pre-tax SAB No. 51 gain on the sale of subsidiary stock, which is classified in Gain on Sale of Subsidiary Stock on the Consolidated Statements of Operations. The proceeds from the offering plus the draw down of approximately 39 million Canadian dollars on an available credit facility were used by the Income Fund to acquire a 100% interest in Westcoast Gas Services, Inc. There were no deferred taxes recorded as a result of this transaction.

Also see Notes 1, 2, 3, 6, 9, 11 and 15 for additional related party information.

17. New Accounting Standards

The following new accounting standards were adopted by Duke Capital subsequent to September 30, 2005 and the impact of such adoption, if applicable, has been presented in the accompanying Consolidated Financial Statements:

SFAS No. 123(R) “Share-Based Payment” (SFAS No. 123(R)). In December 2004, the Financial Accounting Standards Board (FASB) issued SFAS No. 123(R), which replaces SFAS No. 123, “Accounting for Stock-Based Compensation,” and supersedes APB Opinion No. 25, “Accounting for Stock Issued to Employees.” SFAS No. 123(R) requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values. For Duke Energy, 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 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 implemented SFAS No. 123(R) using the modified prospective transition method, which required Duke Capital to record compensation expense for all unvested awards beginning January 1, 2006.

Duke Capital 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 Capital is required to recognize compensation cost for new awards granted to employees over the requisite service period, which generally begins on the date the award is granted through the earlier of the date the award vests or the date the employee becomes retirement eligible. Awards, including stock options, granted to employees that are already retirement eligible are deemed to have vested immediately upon issuance, and therefore, compensation cost for those awards is recognized on the date such awards are granted.

The adoption of SFAS No. 123(R) did not have a material impact on Duke Energy’s 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 Capital 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 3.)

SFAS No. 153, “Exchanges of Nonmonetary Assets—an amendment of APB Opinion No. 29” (SFAS No. 153). In December 2004, the FASB issued SFAS No. 153 which amends APB Opinion No. 29, “Accounting for Nonmonetary Transactions,” by eliminating the exception to the fair-value principle for exchanges of similar productive assets, which were accounted for under APB Opinion No. 29 based on the book value of the asset surrendered with no gain or loss recognition. SFAS No. 153 also eliminates APB Opinion No. 29’s concept of culmination of an earnings process. The amendment requires that an exchange of nonmonetary assets be accounted for at fair value if the exchange has commercial substance and fair value is determinable within reasonable limits. Commercial substance is assessed by comparing the entity’s expected cash flows immediately before and after the exchange. If the difference is significant, the transaction is considered to have commercial

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substance and should be recognized at fair value. SFAS No. 153 is effective for nonmonetary transactions occurring on or after July 1, 2005. The adoption of SFAS No. 153 did not have a material impact on Duke Capital’s consolidated results of operations, cash flows or financial position.

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

FASB Interpretation (FIN) No. 47 “Accounting for Conditional Asset Retirement Obligations” (FIN No. 47). In March 2005, the FASB issued FIN No. 47, which clarifies the accounting for conditional asset retirement obligations as used in SFAS No. 143, “Accounting for Asset Retirement Obligations,” (SFAS No. 143). A conditional asset retirement obligation is an unconditional legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. Therefore, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation under SFAS No. 143 if the fair value of the liability can be reasonably estimated. The provisions of FIN No. 47 were effective for Duke Capital as of December 31, 2005. The provisions of FIN No. 47 were effective for Duke Capital as of December 31, 2005 and resulted in an increase in assets of $7 million, an increase in liabilities of $11 million and a net-of-tax cumulative effect adjustment to earnings of $4 million.

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

FSP No. FAS 123(R)-4, “Classification of Options and Similar Instruments Issued as Employee Compensation That Allow for Cash Settlement upon the Occurrence of a Contingent Event” (FSP No. FAS 123(R)-4). In February 2006, the FASB staff issued FSP FAS No. 123(R)-4 to address the classification of options and similar instruments issued as employee compensation that allow for cash settlement upon the occurrence of a contingent event. The guidance amends SFAS No. 123(R). FSP No. FAS 123(R)-4 provides that cash settlement features that can be exercised only upon the occurrence of a contingent event that is outside the employee’s control does not require classifying the option or similar instrument as a liability until it becomes probable that the event will occur. FSP No. FAS 123(R)-4 applies only to options or similar instruments issued as part of employee compensation arrangements. The guidance in FSP No. FAS 123(R)-4 was effective for Duke Capital as of April 1, 2006. Duke Capital adopted SFAS No. 123(R) as of January 1, 2006 (see Note 3). The

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Notes to Consolidated Financial Statements—(Continued)

adoption of FSP No. FAS 123(R)-4 did not have a material impact on Duke Capital’s consolidated statement of operations, cash flows or financial position.

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

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

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

The following new accounting standards have been issued, but have not yet been adopted by Duke Capital as of September 30, 2006:

SFAS No. 155, “Accounting for Certain Hybrid Financial Instruments—an amendment of FASB Statements No. 133 and 140” (SFAS No. 155). In February 2006, the FASB issued SFAS No. 155, which amends SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” and SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities.” SFAS No. 155 allows financial instruments that have embedded derivatives to be accounted for at fair value at acquisition, at issuance, or when a previously recognized financial instrument is subject to a remeasurement (new basis) event, on an instrument-by-instrument basis, in cases in which a derivative would otherwise have to be bifurcated. SFAS No. 155 is effective for Duke Capital for all financial instruments acquired, issued, or subject to remeasurement after January 1, 2007, and for certain hybrid financial instruments that have been bifurcated prior to the effective date, for which the effect is to be reported as a cumulative-effect adjustment to beginning retained earnings.

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Notes to Consolidated Financial Statements—(Continued)

Duke Capital does not anticipate the adoption of SFAS No. 155 will have any material impact on its consolidated results of operations, cash flows or financial position.

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

SFAS No. 158, “Employer’s Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment to FASB Statements No. 87, 88, 106, and 132(R)” (SFAS No. 158). In October 2006, the FASB issued SFAS No. 158, which changes the recognition and disclosure provisions and measurement date requirements for an employer’s accounting for defined benefit pension and other postretirement plans. The recognition and disclosure provisions require an employer to (1) recognize the funded status of a benefit plan—measured as the difference between plan assets at fair value and the benefit obligation—in its statement of financial position, (2) recognize as a component of OCI, net of tax, the gains or losses and prior service costs or credits that arise during the period but are not recognized as components of net periodic benefit cost, and (3) disclose in the notes to financial statements certain additional information. SFAS No. 158 does not change the amounts recognized in the income statement as net periodic benefit cost. Duke Capital is required to initially recognize the funded status of its defined benefit pension and other postretirement plans and to provide the required additional disclosures as of December 31, 2006. Retrospective application is not permitted. Duke Capital anticipates that adoption of SFAS No. 158 recognition and disclosure provisions will result in an increase in total assets of approximately $34 million, an increase in total liabilities of approximately $111 million and a decrease in accumulated other comprehensive income, net of tax, of approximately $77 million as of December 31, 2006 related to the Westcoast plans. Duke Capital does not anticipate the adoption of SFAS No. 158 will have any material impact on its consolidated results of operations or cash flows.

Under the measurement date requirements of SFAS No. 158, an employer is required to measure defined benefit plan assets and obligations as of the date of the employer’s fiscal year-end statement of financial position (with limited exceptions). Historically, Duke Capital has measured its plan assets and obligations up to three months prior to the fiscal year-end, as allowed under the authoritative accounting literature. The measurement date requirement is effective for the year ending December 31, 2008, and early application is encouraged. Duke Capital intends to adopt the change in measurement date effective January 1, 2007 by remeasuring plan assets and benefit obligations as of that date, pursuant to the transition requirements of SFAS No. 158. Net periodic benefit cost for the three-month period between September 30, 2006 and December 31, 2006 will be recognized, net of tax, as a separate adjustment of retained earnings as of January 1, 2007, except for any gain or loss arising from curtailments or settlement, if any, during that three-month period, which would be recognized in earnings in 2006. Additionally, changes in plan assets and plan obligations between September 30, 2006 and December 31, 2006 not related to net periodic benefit cost will be recognized, net of tax, as an adjustment to OCI.

SAB No. 108, “Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in Current Year Financial Statements” (SAB No. 108). In September 2006 the SEC issued SAB No. 108, which provides interpretive guidance on how the effects of the carryover or reversal of prior year misstatements should be considered in quantifying a current year misstatement. Traditionally, there have been two widely-recognized approaches for quantifying the effects of financial statement misstatements. The income statement approach

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Duke Capital LLC

Notes to Consolidated Financial Statements—(Continued)

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 is effective for Duke Capital’s 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 Capital currently uses a dual approach for quantifying identified financial statement misstatements. Therefore, Duke Capital does not anticipate the adoption of SAB No. 108 will have any material impact on its 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 No. 48). On July 13, 2006, the FASB issued FIN No. 48, which interprets SFAS No. 109, “Accounting for Income Taxes.” FIN No. 48 provides guidance for the recognition, measurement, classification and disclosure of the financial statement effects of a position taken or expected to be taken in a tax return (“tax position”). The financial statement effects of a tax position must be recognized when there is a likelihood of more than 50 percent that based on the technical merits, the position will be sustained upon examination and resolution of the related appeals or litigation processes, if any. A tax position that meets the recognition threshold must be measured initially and subsequently as the largest amount of tax benefit that is greater than 50 percent likely of being realized upon ultimate settlement with a taxing authority. The Interpretation is effective for Duke Capital as of January 1, 2007. Duke Capital is currently evaluating the impact of adopting FIN No. 48, and cannot currently estimate the impact of FIN No. 48 on its consolidated results of operations, cash flows or financial position.

FSP No. FAS 123(R)-5, “Amendment of FASB Staff Position FAS 123(R)-1” (FSP No. FAS 123(R)-5). In October 2006, the FASB staff issued FSP No. FAS 123(R)-5 to address whether a modification of an instrument in connection with an equity restructuring should be considered a modification for purposes of applying FSP No. FAS 123(R)-1, “Classification and Measurement of Freestanding Financial Instruments Originally Issued in Exchange for Employee Services under FASB Statement No. 123(R) (FSP No. FAS 123(R)-1).” In August 2005, the FASB staff issued FSP FAS 123(R)-1 to defer indefinitely the effective date of paragraphs A230–A232 of SFAS No. 123(R), and thereby require entities to apply the recognition and measurement provisions of SFAS No. 123(R) throughout the life of an instrument, unless the instrument is modified when the holder is no longer an employee. The recognition and measurement of an instrument that is modified when the holder is no longer an employee should be determined by other applicable generally accepted accounting principles. FSP No. FAS 123(R)-5 addresses modifications of stock-based awards made in connection with an equity restructuring and clarifies that for instruments that were originally issued as employee compensation and then modified, and that modification is made to the terms of the instrument solely to reflect an equity restructuring that occurs when the holders are no longer employees, no change in the recognition or the measurement (due to a change in classification) of those instruments will result if certain conditions are met. This FSP is effective for Duke Capital as of January 1, 2007. Duke Capital is currently evaluating the impact of adopting FSP No. FAS 123(R)-5 and cannot currently estimate the impact of adopting FAS 123(R)-5 on its consolidated results of operations, cash flows or financial position.

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Duke Capital LLC

Notes to Consolidated Financial Statements—(Continued)

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

EITF Issue No. 06-3, “How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (That Is, Gross versus Net Presentation)” (EITF No. 06-3). In June 2006, the EITF reached a consensus on EITF No. 06-3 to address any tax assessed by a governmental authority that is directly imposed on a revenue-producing transaction between a seller and a customer and may include, but are not limited to, sales, use, value added, and some excise taxes. For taxes within the issue’s scope, the consensus requires that entities present such taxes on either a gross (i.e. included in revenues and costs) or net (i.e. exclude from revenues) basis according to their accounting policies, which should be disclosed. If such taxes are reported gross and are significant, entities should disclose the amounts of those taxes. Disclosures may be made on an aggregate basis. The consensus is effective for Duke Capital beginning January 1, 2007. Duke Capital does not anticipate the adoption of EITF No. 06-3 will have any material impact on its consolidated results of operations, cash flows or financial position.

EITF Issue No. 06-5, “Accounting for Purchases of Life Insurance—Determining the Amount That Could Be Realized in Accordance with FASB Technical Bulletin No. 85-4” (EITF No. 06-5). In June 2006, the EITF reached a consensus on the accounting for corporate-owned and bank-owned life insurance policies. EITF No. 06-5 requires that a policyholder consider the cash surrender value and any additional amounts to be received under the contractual terms of the policy in determining the amount that could be realized under the insurance contract. Amounts that are recoverable by the policyholder at the discretion of the insurance company must be excluded from the amount that could be realized. Fixed amounts that are recoverable by the policyholder in future periods in excess of one year from the surrender of the policy must be recognized at their present value. EITF No. 06-5 is effective for Duke Capital as of January 1, 2007 and must be applied as a change in accounting principle through a cumulative-effect adjustment to retained earnings or other components of equity as of January 1, 2007. Duke Capital is currently evaluating the impact of adopting EITF No. 06-5, and cannot currently estimate the impact of EITF No. 06-5 on its consolidated results of operations, cash flows or financial position.

18. Income Tax Expense

Although the outcome of tax audits is uncertain, management believes that adequate provisions for income and other taxes, such as sales and use, franchise, and property, have been made for potential liabilities resulting from such matters. As of September 30, 2006 and December 31, 2005, Duke Capital had total provisions of approximately $125 million for uncertain tax positions, including interest. Management is not aware of any issues for open tax years that upon final resolution are expected to have a material adverse effect on Duke Capital’s consolidated results of operations, cash flows or financial position.

The effective tax rate for the nine months ended September 30, 2006 was approximately 36.3% as compared to 39.2% for the same period in 2005. The decrease in the effective tax rate for income from continuing operations for the nine months ended September 30, 2006 as compared to the same period in the prior year primarily relates to the reduction in the unitary state tax rate in 2006 as a result of Duke Energy’s merger with

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Notes to Consolidated Financial Statements—(Continued)

Cinergy, partially offset by non-deductible costs associated with the proposed spin-off of the natural gas businesses. Additionally, the effective tax rate for income from continuing operations was impacted by tax expenses of approximately $36 million associated with the 2005 repatriation of foreign earnings under the American Jobs Creation Act of 2004 and the flow through of certain tax losses to Duke Energy up through April 1, 2006.

As of September 30, 2006 and December 31, 2005, approximately $232 million and $168 million, respectively, of current deferred tax assets were included in Other within Current Assets on the Consolidated Balance Sheets. At September 30, 2006, these balances exceeded 5% of total current assets.

19. Subsequent Events

For information on subsequent events related to debt and credit facilities, discontinued operations and assets held for sale, commitments and contingencies, and member’s equity and related party transactions, see Notes 5, 10, 14 and 16, respectively.

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DUKE ENERGY FIELD SERVICES, LLC

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	Page
Consolidated Financial Statements:
Report of Independent Auditors	F-146
Consolidated Statement of Operations and Comprehensive Income for the year ended December 31, 2005	F-147
Consolidated Balance Sheet as of December 31, 2005	F-148
Consolidated Statement of Cash Flows for the year ended December 31, 2005	F-149
Consolidated Statements of Members’ Equity for the year ended December 31, 2005	F-150
Notes to Consolidated Financial Statements	F-151

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INDEPENDENT AUDITORS’ REPORT

To the Board of Directors and Members of

Duke Energy Field Services, LLC

Denver, Colorado

We have audited the accompanying consolidated balance sheet of Duke Energy Field Services, LLC and subsidiaries as of December 31, 2005, and the related consolidated statements of operations and comprehensive income, members’ equity, and cash flows for the year then ended. Our audit 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 these financial statements and financial statement schedule based on our audit.

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

/s/ DELOITTE & TOUCHE LLP

Denver, Colorado

March 10, 2006

(March 31, 2006 as to the financial statement schedule listed in the Index at Item 15)

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DUKE ENERGY FIELD SERVICES, LLC

CONSOLIDATED STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME

Year Ended December 31, 2005

(millions)

Operating revenues:
Sales of natural gas and petroleum products	$	10,011
Sales of natural gas and petroleum products to affiliates		2,785
Transportation, storage and processing		253
Trading and marketing losses		(15	)
Total operating revenues		13,034
Operating costs and expenses:
Purchases of natural gas and petroleum products		10,133
Purchases of natural gas and petroleum products from affiliates		830
Operating and maintenance		447
Depreciation and amortization		287
General and administrative		195
Gain on sale of assets		(2	)
Total operating costs and expenses		11,890
Operating income		1,144
Gain on sale of general partner interest in TEPPCO		1,137
Equity in earnings of unconsolidated affiliates		22
Minority interest income		1
Interest income		26
Interest expense		(154	)
Income from continuing operations before income taxes		2,176
Income tax expense		(9	)
Income from continuing operations		2,167
Income from discontinued operations, net of income taxes		3
Net income		2,170
Other comprehensive loss:
Foreign currency translation adjustment		(8	)
Canadian business distributed to Duke Energy		(70	)
Reclassification of cash flow hedges into earnings		1
Total other comprehensive loss		(77	)
Total comprehensive income	$	2,093

See Notes to Consolidated Financial Statements.

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DUKE ENERGY FIELD SERVICES, LLC

CONSOLIDATED BALANCE SHEET

As of December 31, 2005

(millions)

ASSETS
Current assets:
Cash and cash equivalents	$	59
Short-term investments		627
Accounts receivable:
Customers, net of allowance for doubtful accounts of $4 million		1,237
Affiliates		340
Other		59
Inventories		110
Unrealized gains on mark-to-market and hedging transactions		252
Other		22
Total current assets		2,706
Property, plant and equipment, net		3,836
Restricted investments		364
Investments in unconsolidated affiliates		169
Intangible assets:
Commodity sales and purchases contracts, net		66
Goodwill		421
Total intangible assets		487
Unrealized gains on mark-to-market and hedging transactions		60
Deferred income taxes		3
Other non-current assets		86
Total assets	$	7,711
LIABILITIES AND MEMBERS’ EQUITY
Current liabilities:
Accounts payable:
Trade	$	2,035
Affiliates		42
Other		42
Current maturities of long-term debt		300
Unrealized losses on mark-to-market and hedging transactions		244
Distributions payable to members		185
Accrued interest payable		45
Accrued taxes		46
Other		129
Total current liabilities		3,068
Long-term debt		1,760
Unrealized losses on mark-to-market and hedging transactions		54
Other long-term liabilities		224
Minority interests		95
Commitments and contingent liabilities
Members’ equity:
Members’ interest		2,107
Retained earnings		411
Accumulated other comprehensive loss		(8	)
Total members’ equity		2,510
Total liabilities and members’ equity	$	7,711

See Notes to Consolidated Financial Statements.

F-148

DUKE ENERGY FIELD SERVICES, LLC

CONSOLIDATED STATEMENT OF CASH FLOWS

Year Ended December 31, 2005

(millions)

Cash flows from operating activities:
Net income	$	2,170
Adjustments to reconcile net income to net cash provided by operating activities:
Income from discontinued operations		(3	)
Gain from sale of equity investment in TEPPCO		(1,137	)
Depreciation, amortization and impairment charges		287
Distributions received in excess of earnings from unconsolidated affiliates		15
Deferred income tax benefit		(2	)
Other, net		(1	)
Change in operating assets and liabilities (net of effects of acquisitions) Which (used) provided cash:
Accounts receivable		(432	)
Inventories		(37	)
Net unrealized losses (gains) on mark-to-market and hedging transactions		9
Accounts payable		910
Accrued interest payable		(14	)
Other		(12	)
Net cash provided by continuing operations		1,753
Net cash provided by discontinued operations		11
Net cash provided by operating activities		1,764
Cash flows from investing activities:
Capital and acquisition expenditures		(212	)
Purchase of investment in unconsolidated affiliate		(13	)
Investment expenditures, net of cash acquired		(11	)
Purchases of available-for-sale securities		(17,986	)
Proceeds from sales of available-for-sale securities		17,260
Proceeds from sales of discontinued operations		30
Proceeds from sales of assets and general partner interest in TEPPCO		1,123
Other		9
Net cash provided by continuing operations		200
Net cash used in discontinued operations		(13	)
Net cash provided by investing activities		187
Cash flows from financing activities:
Payment of dividends and distributions to members		(2,313	)
Proceeds from issuance of equity securities of a subsidiary, net of offering costs		206
Contribution received from ConocoPhillips		398
Payment of debt		(607	)
Proceeds from issuing debt		408
Loans made to Duke Capital LLC and ConocoPhillips		(1,100	)
Repayment of loans by Duke Capital LLC and ConocoPhillips		1,100
Cash received from minority interests		3
Other		(2	)
Net cash used in continuing operations		(1,907	)
Net cash used in discontinued operations		(44	)
Net cash used in financing activities		(1,951	)
Net change in cash and cash equivalents		—
Cash and cash equivalents, beginning of year		59
Cash and cash equivalents, end of year	$	59
Supplementary cash flow information:
Cash paid for interest (net of amounts capitalized)	$	163

See Notes to Consolidated Financial Statements.

F-149

DUKE ENERGY FIELD SERVICES, LLC

CONSOLIDATED STATEMENT OF MEMBERS’ EQUITY

Year Ended December 31, 2005

(millions)

	Members’ Interest		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
Balance, January 1, 2005	$	1,709	$	909		$	69		$	2,687
Distributions		—		(2,414	)		—			(2,414	)
Distribution of Canadian business		—		(254	)		(70	)		(324	)
Contributions		398		—			—			398
Net income		—		2,170			—			2,170
Foreign currency translation adjustment		—		—			(8	)		(8	)
Reclassification of cash flow hedges into earnings		—		—			1			1
Balance, December 31, 2005	$	2,107	$	411		$	(8	)	$	2,510

See Notes to Consolidated Financial Statements.

F-150

DUKE ENERGY FIELD SERVICES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Year Ended December 31, 2005

1. General and Summary of Significant Accounting Policies

Basis of Presentation—Duke Energy Field Services, LLC (with its consolidated subsidiaries, “us”, “we”, “our”, or the “Company”) operates in the midstream natural gas industry. Our primary operations consist of natural gas gathering, processing, transportation and storage and natural gas liquid, or NGL, fractionation, transportation, compression, gathering, treating, processing and storage, as well as marketing, from which we generate revenues primarily by trading and marketing natural gas and NGLs. Our limited liability company agreement (“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 recently formed DCP Midstream Partners, LP, a master limited partnership (“DCP Midstream Partners”) of which our subsidiary, DCP Midstream GP LP, acts as general partner. In September 2005, DCP Midstream Partners filed a Registration Statement on Form S-1 with the Securities and Exchange Commission (“SEC”) to register the initial public offering of its limited partnership units to the public. The initial public offering closed in December 2005. As a result of DCP Midstream Partners’ initial public offering, we own approximately 40% of the limited partnership interests in DCP Midstream Partners and a 2% general partnership interest. As the general partner of DCP Midstream Partners, we have responsibility for its operations. DCP Midstream Partners is accounted for as a consolidated subsidiary.

In July 2005, Duke Energy Corporation (“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% (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 are designated for the acquisition or improvement of property, plant and equipment. At December 31, 2005, the remaining balance related to this contribution of approximately $264 million was included in the consolidated balance sheet as restricted investments.

We are governed by a five member Board of Directors, consisting of two voting members from each parent and a single non-voting member who is our Chief Executive Officer and President. 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 Duke Energy 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 Duke Energy and ConocoPhillips.

On January 31, 2005, we filed a Form 15 with the SEC to suspend our reporting obligations under the Securities Exchange Act of 1934. We are eligible to suspend our reporting obligations under the 1934 Act because we have fewer than 300 holders of record of any class of our securities. DCP Midstream Partners is a public registrant and reports under the Securities Exchange Act of 1934.

Consolidation—The consolidated financial statements include the accounts of the Company and all majority-owned subsidiaries where we have the ability to exercise control, our general partner interest in a limited partnership where the limited partners do not have substantive kick-out or participating rights, variable interest entities where we are the primary beneficiary, and undivided interests in jointly owned assets, after eliminating intercompany transactions and balances. Investments in 20% to 50% owned affiliates, and investments in less than 20% owned affiliates where we have the ability to exercise significant influence, are accounted for using the equity method (see Note 10).

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DUKE ENERGY FIELD SERVICES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Year Ended December 31, 2005

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.

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 (“SFAS”) No. 115 (“SFAS 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 sheet as accumulated other comprehensive income (loss) (“AOCI”). No gains or losses were deferred in AOCI at December 31, 2005.

As of December 31, 2005 we had short-term investments of $627 million which were available for general corporate purposes.

In July 2005, ConocoPhillips contributed cash of $398 million to our Company. This cash is invested in financial instruments as described above, however, under the terms of the amended and restated LLC Agreement, proceeds from this contribution are designated for the acquisition or improvement of property, plant and equipment. As this cash is to be used to acquire non-current assets, it has been classified as a long-term asset in the consolidated balance sheet. At December 31, 2005, we had restricted investments related to this contribution of $264 million. At December 31, 2005, we also had restricted investments of $100 million consisting of collateral for DCP Midstream Partners’ term loan (see Note 12).

Inventories—Inventories consist primarily of natural gas and NGLs held in storage for transmission and processing and sales commitments. Inventories are recorded at the lower of cost or market value using the average cost method (see Note 6).

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 (“SFAS 133”), “Accounting for Derivative Instruments and Hedging Activities,” as amended, is recorded on a gross basis in the consolidated balance sheet at its fair value as unrealized gains or unrealized losses on mark-to-market and hedging transactions. Derivative assets and liabilities remain classified in the consolidated balance sheet as unrealized gains or unrealized losses on mark-to-market and hedging transactions at fair value until the contractual delivery period occurs.

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

F-152

DUKE ENERGY FIELD SERVICES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Year Ended December 31, 2005

non-trading mark-to-market derivatives. For each of our derivatives, the accounting method and presentation in the consolidated statement of operations are as follows:

Classification of Contract	Accounting Method	Presentation of Gains & Losses or Revenue & Expense
Trading Derivatives	Mark-to-marketa	Net basis in trading and marketing losses and gains
Non-Trading Derivatives:
Cash Flow Hedge	Hedge methodb	Gross basis in the same statement of operations category as the related hedged item
Fair Value Hedge	Hedge methodb	Gross basis in the same statement of operations category as the related hedged item
Normal Purchase or Normal Sale	Accrual methodc	Gross basis upon settlement in the corresponding statement of operations category based on purchase or sale
Non-Trading Derivative Activity	Mark-to-marketa	Net basis in trading and marketing losses and gains

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

^b Hedge method—An accounting method whereby the effective portion of the change in the fair value of the asset or liability is recorded in the consolidated balance sheet and there is no recognition in the consolidated statement of operations for the effective portion until the service is provided or the associated delivery period occurs.

^c Accrual method—An accounting method whereby there is no recognition in the consolidated balance sheet or consolidated statement of operations for changes in fair value of a contract until the service is provided or the associated delivery period occurs.

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 sheet as unrealized gains or unrealized losses on mark-to-market and hedging transactions. The effective portion of the change in fair value of a derivative designated as a cash flow hedge is recorded in the consolidated balance sheet as AOCI and the ineffective portion is recorded in the consolidated statement of operations. During the period in which the hedged transaction occurs, amounts in AOCI associated with the hedged transaction are reclassified to the consolidated statement of operations 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 no longer probable that the hedged transaction will occur. When hedge accounting is discontinued because the derivative no longer qualifies as an effective hedge, the derivative is subject to the mark-to-market accounting method prospectively. The derivative continues to be carried on the consolidated balance sheet at its fair value; however, subsequent changes in its fair value are recognized in current period earnings. Gains and

F-153

DUKE ENERGY FIELD SERVICES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Year Ended December 31, 2005

losses related to discontinued hedges that were previously accumulated in AOCI will remain in AOCI until the hedged transaction occurs, unless it is no longer probable that the hedged transaction will occur, in which case, the gains and losses that were previously deferred in AOCI will be immediately recognized in current period earnings. We exclude the time value of the options when assessing hedge effectiveness.

For derivatives designated as fair value hedges, the Company recognizes 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 statement of operations.

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.

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 (see Note 9).

Impairment testing of goodwill consists of a two-step process. The first step involves a comparison of 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 a comparison of 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. Additional impairment tests are performed between the annual reviews if events or changes in circumstances make it more likely than not that the fair value of a reporting unit is below its carrying amount (see Note 9).

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 (see Note 7). 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 Long-Lived Assets, Assets Held for Sale and Discontinued Operations—We evaluate whether the carrying value of long-lived assets, excluding goodwill, have been impaired when circumstances

F-154

DUKE ENERGY FIELD SERVICES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Year Ended December 31, 2005

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:

• A significant adverse change in legal factors or in the business climate;

• A current-period operating or cash flow loss combined with a history of operating or cash flow losses or a projection or forecast that demonstrates continuing losses associated with the use of a long-lived asset;

• An accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of a long-lived asset;

• Significant adverse changes in the extent or manner in which an asset is used or in its physical condition;

• A significant change in the market value of an asset; and

• A current expectation that, more likely than not, an asset will be sold or otherwise disposed of before the end of its estimated useful life.

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 re-assess the cash flows related to the long-lived assets.

We use the criteria in SFAS No. 144 (“SFAS 144”), “Accounting for the Impairment or Disposal of Long-Lived Assets,” 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 sheet.

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 (loss) from discontinued operations in the consolidated statement of operations. 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 statement of operations.

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 an 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.

F-155

DUKE ENERGY FIELD SERVICES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Year Ended December 31, 2005

Revenue Recognition—Our primary types of sales and service activities reported as operating revenue include:

• Sales of natural gas and petroleum products;

• Natural gas gathering, processing, transportation and storage, and trading and marketing from which we generate revenues primarily by providing services such as compression, gathering, treating, processing, transportation of residue gas, storage and trading and marketing (the “Natural Gas Services”); and

• NGL fractionation, transportation, and trading and marketing from which we generate revenues primarily by providing services such as transportation, market center fractionation and the trading and marketing of NGLs (the “NGL Services”).

Revenues associated with sales of natural gas and petroleum products are recognized when title passes to the customer, which is when the risk of ownership passes to the purchaser and physical delivery occurs. Revenues for Natural Gas Services and NGL Services are recognized when the service is provided. We defer revenue recognition on all sales and service activities until the price is fixed or determinable and collectability is reasonably assured.

For gathering services, we receive fees from the producers to transport the natural gas from the wellhead to the processing plant. For processing services, we either receive fees or commodities as payment for these services, depending on the type of contract. Commodities received are in turn sold and recognized as revenue in accordance with the criteria outlined above. Under the percentage-of-proceeds contract type, we are paid for our services by keeping a percentage of the NGLs produced and the residue gas resulting from processing the natural gas. Under a keep-whole contract, we keep a portion of the NGLs produced, but return the equivalent energy content of the gas back to the producer. We also receive fees for further fractionation of the NGLs produced, and for transportation and for storage of NGLs and residue gas. Under a wellhead purchase contract, we purchase raw natural gas from the producer at the wellhead or defined receipt point for processing and then market the resulting NGLs and residue gas at market prices.

We recognize revenues for our NGL and residue gas derivative trading activities net in the consolidated statement of operations as trading and marketing losses and gains, in accordance with Emerging Issues Task Force (“EITF”) Issue No. 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities.” These activities include mark-to-market gains and losses on energy trading contracts and the financial or physical settlement of energy trading contracts.

We generally report revenues gross in the consolidated statement of operations, in accordance with EITF Issue No. 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent.” Except for fee-based agreements, we act as the principal in these transactions, take title to the product, and incur the risks and rewards of ownership.

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. 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, 2005.

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DUKE ENERGY FIELD SERVICES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Year Ended December 31, 2005

Significant Customers—ConocoPhillips, an affiliated company, was a significant customer in 2005. Sales to ConocoPhillips, including its affiliate, ChevronPhillips Chemical Company LLC (“CP Chem”), totaled approximately $2,513 million during 2005.

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 sheet as an offset to long-term debt. These expenses are recorded on the consolidated balance sheet as other non-current assets.

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, 2005 included in the consolidated balance sheet totaled $6 million recorded as other current liabilities and $7 million recorded as other long-term liabilities.

Gas and NGL Imbalance Accounting—Quantities of natural gas or NGL over-delivered or under-delivered related to imbalance agreements with customers, producers or pipelines are recorded monthly as other receivables or other payables using then 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 sheet as accounts receivable—other as of December 31, 2005 were imbalances totaling $59 million. Included in the consolidated balance sheet as accounts payable—other, as of December 31, 2005 were imbalances totaling $42 million.

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 statement 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, 2005.

Income Taxes—We are structured as a limited liability company which is a pass-through entity for U.S. income tax purposes. We own corporations who file their own respective federal, foreign and state corporate income tax returns. The income tax expense related to these corporations is included in our income tax expense, along with other miscellaneous state, local and franchise taxes of the limited liability company and other subsidiaries. In addition, until July 1, 2005, we had Canadian subsidiaries which 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 (see Note 11).

Distributions—Under the terms of our LLC Agreement, we are required to make quarterly distributions to Duke Energy and ConocoPhillips based on allocated taxable income. The LLC Agreement, as amended, 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

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DUKE ENERGY FIELD SERVICES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Year Ended December 31, 2005

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 Duke Energy and ConocoPhillips. Prior to July 1, 2005, the capital accounts were maintained at 69.7% for Duke Energy and 30.3% for ConocoPhillips. During the year ended December 31, 2005, we paid distributions of $389 million 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 considers the payment of a quarterly dividend to Duke Energy and ConocoPhillips. The Board of Directors may consider net income, cash flow or any other criteria deemed appropriate for determining the amount of the quarterly dividend to be paid. During the year ended December 31, 2005, we paid total dividends of $1,925 million, 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. Our LLC Agreement restricts payment of dividends except with the approval of both members.

DCP Midstream Partners intends to distribute to the holders of its common units and subordinated units on a quarterly basis at least DCP Midstream Partners’ minimum quarterly distribution of $0.35 per unit, or $1.40 per year, to the extent DCP Midstream 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. However, there is no guarantee that DCP Midstream Partners will pay the minimum quarterly distribution on the units in any quarter. DCP Midstream Partners will be prohibited from making any distributions to unitholders if it would cause an event of default, or an event of default its existing, under its credit agreement. Our 40% limited partner interest in DCP Midstream Partners primarily consists of subordinated units. The subordinated units are entitled to receive the minimum quarterly distribution only after DCP Midstream 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.

Stock-Based Compensation—Under its 1998 Long-Term Incentive Plan (“1998 Plan”), Duke Energy granted certain of our key employees stock options, restricted stock, phantom stock awards and stock-based performance awards to be settled in shares of Duke Energy’s common stock. Through July 1, 2005, we accounted for stock-based compensation in accordance with the intrinsic value recognition and measurement principles of Accounting Principles Board (“APB”) Opinion No. 25(“APB 25”), “Accounting for Stock Issued to Employees,” and FASB Interpretation No. 44 (“FIN 44”), “Accounting for Certain Transactions Involving Stock Compensation—an Interpretation of APB Opinion No. 25.” Under that method, compensation expense is 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 statement of operations. Compensation expense for restricted stock grants and phantom stock awards is 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 is recorded over the required vesting period, and is adjusted for increases and decreases in market value at each reporting date up to the measurement dates.

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DUKE ENERGY FIELD SERVICES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Year Ended December 31, 2005

Upon execution of the 50-50 Transaction in July 2005, certain employees of Duke Energy Field Services 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 options were required to be re-measured as of July 2005 under EITF Issue No. 96-18 (“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 (“SFAS 123”), “Accounting for Stock-Based Compensation.” 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 the stock options at each reporting date.

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 six month period ended June 30, 2005 (millions):

Net income, as reported	$	1,582
Add: stock-based compensation expense included in reported net income		3
Deduct: total stock-based compensation expense determined under fair value based method for all awards		(3	)
Pro forma net income	$	1,582

Accounting for Sales of Units by a Subsidiary—In December 2005, we formed DCP Midstream 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 Midstream 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 (“SAB”) No. 51 (“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 the gain on sale of common units in DCP Midstream Partners in the amount of approximately $149 million as other long-term liabilities in the consolidated balance sheet. We will recognize this gain in earnings upon conversion of our subordinated units in DCP Midstream Partners to common units.

New Accounting Standards—SFAS No. 154 (“SFAS 154”), “Accounting Changes and Error Corrections.” In June 2005, the FASB issued SFAS 154, a replacement of APB Opinion No. 20, “Accounting Changes” and FASB Statement 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 on the new accounting principle, unless it is impracticable to do so. SFAS 154 also provides that (1) a change in method of depreciating or amortizing 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) correction of errors in previously issued financial statements should be termed a “restatement.” The new standard is effective for accounting changes and correction of errors made in fiscal years beginning after December 15, 2005. The impact of SFAS 154 depends on the nature and extent of any changes in accounting principles after the effective date, but we do not currently expect SFAS 154 to have a material impact on our consolidated results of operations, cash flows or financial position.

Emerging Issues Task Force Issue No. 04-13 (“EITF 04-13”), “Accounting for Purchases and Sales of Inventory with the Same Counterparty.” In September 2005, the EITF reached consensus on EITF 04-13. In

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general, an entity would be required under the consensus 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 (“APB 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. If the consensus is ratified by the FASB, an affected entity should apply the consensus to new arrangements that it enters into in reporting periods beginning after March 15, 2006. We do not currently expect EITF 04-13 to have a material impact on our consolidated results of operations, cash flows or financial position.

EITF Issue No. 04-5 (“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.” In June 2005, the FASB ratified the EITF’s consensus on Issue 04-5 regarding control of a limited partnership. There is a presumption that the general partner in a limited partnership or similar entity has control unless the limited partners have substantive kick-out rights or participating rights. For general partners of all new limited partnerships formed and for existing limited partnerships for which the partnership agreements are modified, EITF 04-5 is effective after June 29, 2005. For general partners in all other limited partnerships, the guidance is effective no later than the beginning of the first reporting period in fiscal years beginning after December 15, 2005. DCP Midstream Partners was formed in the third quarter of 2005 and is accounted for as a consolidated subsidiary in accordance with EITF 04-5.

Financial Accounting Standards Board Interpretation No. 47 (“FIN 47”), “Accounting for Conditional Asset Retirement Obligations.” In March 2005, the FASB issued FIN 47, which clarifies the accounting for conditional asset retirement obligations as used in SFAS 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 143 if the fair value of the liability can be reasonably estimated. FIN 47 permits, but does not require, restatement of interim financial information. The provisions of FIN 47 are effective for reporting periods ending after December 15, 2005. The adoption of FIN 47 did not have a material impact on our consolidated results of operations, cash flows or financial position.

SFAS No. 123 (Revised 2004) (“SFAS 123R”), “Share-Based Payment.” In December 2004, the FASB issued SFAS 123R, which replaces SFAS 123 and supersedes APB 25. SFAS 123R 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 beginning with the first annual period after June 15, 2005. The pro forma disclosures previously permitted under SFAS 123 no longer will be an alternative to financial statement recognition. We do not currently expect SFAS 123R to have a material impact on our consolidated results of operations, cash flows or financial position.

SFAS No. 153 (“SFAS 153”), “Exchanges of Nonmonetary Assets—an amendment of APB Opinion No. 29.” In December 2004, the FASB issued SFAS 153, which amends APB 29 by eliminating the exception to the fair-value principle for exchanges of similar productive assets, which were accounted for under APB 29 based on the book value of the asset surrendered with no gain or loss recognition. SFAS 153 also eliminates APB 29’s concept of culmination of an earnings process. The amendment requires that an exchange of nonmonetary assets be accounted for at fair value if the exchange has commercial substance and fair value is determinable within reasonable limits. Commercial substance is assessed by comparing the entity’s expected cash flows immediately before and after the exchange. If the difference is significant, the transaction is considered to have

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commercial substance and should be recognized at fair value. SFAS 153 is effective for nonmonetary transactions occurring in fiscal periods beginning after June 15, 2005. The adoption of SFAS 153 did not have a material impact on our consolidated results of operations, cash flows or financial position.

EITF Issue No. 03-13 (“EITF 03-13”), “Applying the Conditions in Paragraph 42 of FASB Statement No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, in Determining Whether to Report Discontinued Operations.” In November 2004, the EITF reached a consensus with respect to evaluating whether the criteria in SFAS 144 have been met for classifying as a discontinued operation a component of an entity that either has been disposed of or is classified as held for sale. To qualify as a discontinued operation, SFAS 144 requires that the cash flows of the disposed component be eliminated from the operations of the ongoing entity and that the ongoing entity not have any significant continuing involvement in the operations of the disposed component after the disposal transaction. The consensus in EITF 03-13 clarifies that the cash flows of the eliminated component are not considered to be eliminated if the continuing cash flows represent “direct” cash flows, as defined in the consensus. The consensus also requires that the assessment of whether significant continuing involvement exists be made from the perspective of the disposed component. The assessment should consider whether (a) the continuing entity retains an interest in the disposed component sufficient to enable it to exert significant influence over the disposed component’s operating and financial policies or (b) the entity and the disposed component are parties to a contract or agreement that gives rise to significant continuing involvement by the ongoing entity. The consensus is to be applied prospectively to a component of an entity that is either disposed or classified as held for sale in fiscal periods beginning after December 15, 2004. The adoption of EITF 03-13 did not have a material impact on our consolidated results of operations, cash flows or financial position.

2. Impairment of Goodwill

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 included the use of an appropriate discount rate, estimated future cash flows and an estimated run rate of general and administrative costs. In estimating cash flows, 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, 2005. 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. There were no impairments of goodwill for the year ended December 31, 2005.

3. Acquisitions and Dispositions

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, the purchase price less the estimated fair value of the acquired assets and liabilities is recorded as goodwill.

Acquisition of Various Gathering, Transmission and Processing Assets—In March 2005, we purchased pipeline, compressor station and metering station assets in East Texas for a total purchase price of approximately

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$4 million in cash, the estimated fair value of the assets. As the acquired assets were not considered businesses under the guidance in EITF Issue No. 98-3, “Determining Whether a Nonmonetary Transaction Involves Receipt of Productive Assets or of a Business” (“EITF 98-3”), no goodwill was recognized in connection with this transaction.

Acquisition of Additional Equity Interests—In December 2005, we purchased an additional 6.67% interest in Discovery Producer Services, LLC (“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.

Dispositions

Disposition of Various Gathering, Transmission and Processing Assets—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 March 2005, we sold certain vehicles and personal property in Colorado for a sales price of approximately $3 million and recognized a $2 million gain.

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.

Assets Held for Sale and Discontinued Operations

Assets Held for Sale—In December 2005, based upon management’s assessment of the probable disposition of certain plant, gathering and transmission assets, we classified 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. These transactions are expected to close in the first half of 2006.

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Year Ended December 31, 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 classified as discontinued operations for the period presented. The following is a summary of the net assets distributed to Duke Energy on the closing date of July 1, 2005 (millions):

Assets:
Cash	$	44
Accounts receivable		18
Other assets		1
Property, plant and equipment, net		291
Goodwill		18
Total Assets:	$	372
Liabilities:
Accounts payable	$	11
Other current liabilities		4
Current and long-term debt		1
Deferred income taxes		20
Other long-term liabilities		12
Total Liabilities:		48
Net assets of Canadian business distributed to Duke Energy	$	324

Disposition of Various Gathering, Transmission and Processing Assets—In December 2004, based upon management’s assessment of the probable disposition of certain processing plant assets in Wyoming, we classified certain assets as held for sale. The results of operations and cash flows related to these assets have been classified as discontinued operations for the period presented. In February 2005, we exchanged these assets for certain gathering assets and related gathering contracts in Oklahoma of equivalent fair value.

In September 2004, based upon management’s assessment of the probable disposition of certain gathering, compression, fractionation, processing plant and transportation assets in Wyoming, we classified these assets as held for sale. The results of operations and cash flows related to these assets have been classified as discontinued operations for the period presented. In February 2005, we sold these assets for approximately $28 million.

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 classified as discontinued operations for the period presented.

The following table sets forth selected financial information associated with assets accounted for as discontinued operations for the year ended December 31, 2005 (millions):

Operating revenues	$	35
Pre-tax operating income	$	4
Income tax expense		(1	)
Operating income, net of tax		3
Income from discontinued operations	$	3

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Year Ended December 31, 2005

4. Agreements and Transactions with Affiliates

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.

The following table represents the unrealized gains and unrealized losses on mark-to-market and hedging transactions with affiliates as of December 31, 2005 (millions):

Unrealized gains on mark-to-market and hedging transactions—current	$	27
Unrealized gains on mark-to-market and hedging transactions—non-current	$	19
Unrealized losses on mark-to-market and hedging transactions—current	$	(24	)
Unrealized losses on mark-to-market and hedging transactions—non-current	$	(20	)

The following table summarizes the transactions with Duke Energy, ConocoPhillips, and other unconsolidated affiliates as described below for the year ended December 31, 2005 (millions):

Duke Energy:
Sales of natural gas and petroleum products to affiliates	$	109
Transportation, storage and processing	$	2
Purchases of natural gas and petroleum products from affiliates	$	130
Operating and general and administrative expenses	$	44
Interest income	$	8
Operating lease expense	$	4
ConocoPhillips:
Sales of natural gas and petroleum products to affiliates	$	2,513
Transportation, storage and processing	$	11
Purchases of natural gas and petroleum products from affiliates	$	556
Unconsolidated affiliates:
Sales of natural gas and petroleum products to affiliates	$	163
Transportation, storage and processing	$	20
Purchases of natural gas and petroleum products from affiliates	$	144

Duke Energy

Services Agreements—Under a services agreement that is negotiated and renewed on an annual basis, Duke Energy and certain of its subsidiaries provide us with various staff and support services, including information technology products and services, payroll, employee benefits, insurance, cash management, media relations, printing, records management and legal functions. These services are priced on the basis of a monthly charge. Additionally, we may use other Duke Energy services subject to hourly rates, including legal, insurance, internal audit, tax planning, human resources and security departments.

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Year Ended December 31, 2005

Included in accounts receivable—affiliates in the consolidated balance sheet are insurance recovery receivables of $39 million at December 31, 2005 from an insurance provider that is a subsidiary of Duke Energy. There were no prepaid insurance premiums as of December 31, 2005. During 2005 we recorded business interruption insurance recoveries related to Hurricanes Ivan and Katrina of $3 million, included in the consolidated statement of operations as sales of natural gas and petroleum products.

License Agreement—Duke Energy has licensed to us a non-exclusive right to use the phrase “Duke Energy” and its logo and certain other trademarks in identifying our businesses. This right may be terminated by Duke Energy at its sole option with one year prior written notice to us or upon the sale of Duke Energy’s interest in us.

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 its subsidiaries. Management anticipates continuing to purchase and sell these commodities and provide these services to Duke Energy in the ordinary course of business.

ConocoPhillips

Long-term NGLs Purchases Contract and Transactions—We sell a portion of our residue gas and NGLs to ConocoPhillips and CP Chem (see Note 1). In addition, we purchase raw natural gas from ConocoPhillips. Under the NGL Output Purchase and Sale Agreement (the “ConocoPhillips NGL Agreement”) between us and ConocoPhillips, a wholly-owned subsidiary of ConocoPhillips 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 ConocoPhillips NGL Agreement also grants ConocoPhillips, and subsequently 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.

Transactions with other unconsolidated affiliates

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.

Estimates related to affiliates

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, 2005.

5. Marketable Securities

Short-term and restricted investments—At December 31, 2005 we had $627 million of short-term investments and $364 million of restricted investments consisting primarily of highly liquid tax-exempt debt

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securities. 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.

6. Inventories

A summary of inventories as of December 31, 2005 by category follows (millions):

Natural gas held for resale	$	43
NGLs		67
Total inventories	$	110

7. Property, Plant and Equipment

A summary of property, plant and equipment as of December 31, 2005 by classification follows (millions):

	Depreciable Life
Gathering	15 - 30 years	$	2,503
Processing	25 - 30 years		1,840
Transmission	25 - 30 years		1,223
Underground storage	20 - 50 years		103
General plant	3 - 5 years		138
Construction work in progress			108
			5,915
Accumulated depreciation			(2,079	)
Property, plant and equipment, net		$	3,836

Depreciation expense for the year ended December 31, 2005 was $278 million. Interest capitalized on construction projects in 2005 was approximately $2 million. At December 31, 2005 we had non-cancelable purchase obligations of approximately $16 million for capital projects expected to be completed in 2006. In addition, property, plant and equipment includes $13 million of non-cash additions for the year ended December 31, 2005.

8. Asset Retirement Obligations

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, which do not trigger a 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 only be recorded if and when a future retirement obligation with a determinable life is identified.

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Year Ended December 31, 2005

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 sheet, for the year ended December 31, 2005 (millions):

Balance as of January 1	$	57
Accretion expense		3
Liabilities incurred		1
Distribution of Canadian business to Duke Energy		(10	)
Other		(1	)
Balance as of December 31	$	50

9. Goodwill and Other Intangibles

The changes in the carrying amount of goodwill are as follows for the year ended December 31, 2005 (millions):

Goodwill as of January 1	$	452
Purchase price adjustments		(11	)
Foreign currency translation adjustments		(2	)
Distribution of Canadian business to Duke Energy		(18	)
Goodwill as of December 31	$	421

During 2005, the Company 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 taxes 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, 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 year ended December 31, 2005 (millions):

Commodity sales and purchases contracts	$	130
Accumulated amortization		(64	)
Commodity sales and purchases contracts, net	$	66

During the year ended December 31, 2005, we recorded amortization expense associated with commodity sales and purchases contracts of $9 million. The remaining amortization periods for these contracts range from 1 to 21 years with a weighted average remaining period of approximately 8 years.

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Year Ended December 31, 2005

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

2006	$	8
2007		8
2008		8
2009		8
2010		8
Thereafter		26
Total	$	66

10. Investments in Unconsolidated Affiliates

We have investments in the following unconsolidated affiliates accounted for using the equity method as of December 31, 2005 (millions):

	Ownership
Discovery Producer Services LLC	40.00	%	$	102
Sycamore Gas System General Partnership	48.45	%		13
Mont Belvieu I	20.00	%		12
Tri-States NGL Pipeline, LLC	16.67	%		9
Main Pass Oil Gathering Company	33.33	%		13
Fox Plant, LLC	50.00	%		7
Black Lake Pipe Line Company	50.00	%		6
Other unconsolidated affiliates	Various			7
Total investments in unconsolidated affiliates			$	169

Discovery Producer Services LLC—Discovery Producer Services LLC (“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 $53 million at December 31, 2005 is associated with, and is being depreciated over the life of, the underlying long-lived assets of Discovery.

Sycamore Gas System General Partnership—Sycamore Gas System General Partnership (“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 $10 million at December 31, 2005 is associated with, and is being depreciated over the life of, the underlying long-lived assets of Sycamore.

Mont Belvieu I—Mont Belvieu I operates a 200 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 $12 million at December 31, 2005 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 (“Tri-States”) owns 169 miles of NGL pipeline, extending from a point near Mobile Bay, Alabama to a point near Kenner, Louisiana. The deficit

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between the carrying amount of the investment and the underlying equity of Tri-States of $3 million at December 31, 2005 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.”

Main Pass Oil Gathering Company—Main Pass Oil Gathering Company is 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.

Fox Plant, LLC—Fox Plant, LLC is a limited liability company formed for the purpose of constructing, owning and operating a gathering facility and gas processing plant in Carter County, Oklahoma.

Black Lake Pipe Line Company—Black Lake Pipe Line Company (“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 $8 million at December 31, 2005 is associated with, and is being depreciated over the life of, the underlying long-lived assets of Black Lake.

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. During 2005, total cash distributions to the general partner of TEPPCO were approximately $17 million.

Equity in earnings of unconsolidated affiliates amounted to the following for the year ended December 31, 2005 (millions):

TEPPCO Partners, L.P.	$	8
Discovery Producer Services LLC		11
Sycamore Gas System General Partnership		(1	)
Mont Belvieu I		(1	)
Tri-States NGL Pipeline, LLC		1
Main Pass Oil Gathering Company		3
Other unconsolidated affiliates		1
Total equity in earnings of unconsolidated affiliates	$	22

Distributions received in excess of earnings were $15 million in 2005.

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Year Ended December 31, 2005

The following summarizes combined financial information of unconsolidated affiliates for the year ended and as of December 31, 2005 (millions):

Income statement:
Operating revenues	$	328
Operating expenses	$	312
Net income	$	18
Balance sheet:
Current assets	$	133
Non-current assets		740
Current liabilities		81
Non-current liabilities		6
Net assets	$	786

11. Income Taxes

We are a limited liability company which is a pass-through entity for U.S. income tax purposes. We own corporations who file their own respective federal and state corporate income tax returns. The income tax expense related to these corporations is included in the income tax expense of the Company, along with other miscellaneous state, local and franchise taxes of the limited liability company and other subsidiaries.

Income tax as presented in the consolidated statement of operations is summarized as follows for the year ended December 31, 2005 (millions):

Current:
Federal	$	9
State		2
Total current		11
Deferred:
State		(2	)
Total deferred		(2	)
Total income tax expense	$	9

Our temporary differences primarily relate to depreciation on property, plant and equipment. Cash paid for income taxes was $13 million for the year ended December 31, 2005.

12. Financing

Debt Securities—In October 2005, we issued $200 million principal amount of 5.375% Senior Notes Due 2015 (“5.375% Notes”), for proceeds of $197 million (net of related offering costs). The 5.375% Notes mature on October 15, 2015. We will 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 our Term Loan Facility (see 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 Term Loan Facility (see below).

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Year Ended December 31, 2005

Credit Facilities with Financial Institutions—On December 7, 2005, DCP Midstream Partners entered into a 5-year credit agreement (the “DCP Credit Agreement”) that consists of a $250 million revolving credit facility and a $100 million term loan facility. The DCP Credit Agreement matures on December 7, 2010. At December 31, 2005, there was $110 million 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. There were no letters of credit outstanding on the DCP Credit Agreement as of December 31, 2005. The DCP Credit Agreement requires DCP Midstream Partners to maintain at all times (commencing with the quarter ending March 31, 2006) a leverage ratio (the ratio of DCP Midstream Partners’ consolidated indebtedness to its consolidated EBITDA, in each case as is defined by the DCP 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 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, 2005, 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.

In August 2005, we entered into a credit agreement (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 April 29, 2005, we entered into a credit facility (the “Facility”). The Facility replaced the One-Year Facility that was scheduled to mature on May 10, 2005 (see below). The Facility is used to support our commercial paper program and for working capital and other general corporate purposes. On December 6, 2005, we amended the Facility to extend the maturity for a period of one additional year to April 29, 2011, amend the definition of consolidated capitalization to include minority interest and amend the pricing. 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%; 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 Facility, for the four most recent quarters to interest expense for the same period) of at least 2.5 to 1 (adjusted EBITDA is defined by the Facility to be earnings before interest, taxes and depreciation and amortization and other non-cash adjustments). 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, 2005, there were no borrowings or commercial paper outstanding, and there were no letters of credit drawn against the Facility.

On March 26, 2004, we entered into a credit facility (the “One-Year Facility”). The One-Year Facility replaced the credit facility that matured on March 26, 2004. The One-Year Facility was a $250 million revolving credit facility used to support our commercial paper program and for working capital and other general corporate

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Year Ended December 31, 2005

purposes. In December 2004, the One-Year Facility was amended to extend the maturity date to May 10, 2005. On April 29, 2005, the One-Year Facility was terminated.

In October 2001, we entered into an interest rate swap to convert the fixed interest rate of $250 million of debt securities that 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 August 2005, the date at which this swap and the underlying debt matured. In August 2003, we entered into two interest rate swaps to convert the fixed interest rate of $100 million of debt securities issued on August 16, 2000 to floating rate debt. These interest rate fair value hedges bear a floating rate based on six-month LIBOR, which is re-priced semiannually through 2030.

Long-term debt at December 31, 2005 was as follows (millions):

	Principal/ Discount			Due Date	Interest Rate
Debt securities	$	300		November 15, 2006	5.750	%
		800		August 16, 2010	7.875	%
		250		February 1, 2011	6.875	%
		200		October 15, 2015	5.375	%
		300		August 16, 2030	8.125	%
DCP credit facility		210		December 7, 2010	Varies
Interest rate swap		7
Unamortized discount		(7	)
Current portion of long-term debt		(300	)
Long-term debt	$	1,760

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. DCP Midstream Partners has $100 million held in restricted investments as collateral for the term loan portion of the debt held under its credit agreement. Approximate future maturities of long-term debt in the year indicated are as follows at December 31, 2005 (millions):

2006	$	300
2007		—
2008		—
2009		—
2010		1,010
Thereafter		757
		2,067
Short-term debt		(300	)
Unamortized discount		(7	)
Long-term debt	$	1,760

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

Commodity price risk—Our principal operations of gathering, processing, transportation and storage of natural gas, and the accompanying operations of fractionation, transportation, trading and marketing of NGLs

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Year Ended December 31, 2005

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 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 are exposed to market risks related to changes in interest rates. We periodically use interest rate swaps to hedge interest rate risk associated with debt issuances. 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. Our corporate credit policy prescribes the use of 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, the Company’s standard gas and NGL sales contracts contain adequate assurance provisions which allow the Company to suspend deliveries, cancel agreements or continue deliveries to the buyer after the buyer provides security for payment in a form satisfactory to the Company.

As of December 31, 2005, we held cash or letters of credit of $99 million to secure future performance of financial or physical contracts, and had deposited with counterparties $15 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Year Ended December 31, 2005

Hedging strategies—Historically, we have used 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 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 Midstream Partners’ operations. Some of the assets operated by DCP Midstream 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 Midstream 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 Midstream Partners, we do not currently anticipate using cash flow hedges in 2006 because management believes cash flows will be sufficient to fund our business.

Commodity cash flow hedges—During September 2005, we executed a series of derivative financial instruments effective January 1, 2006, which have been designated as cash flow hedges of the price risk through 2010, associated with forecasted sales of natural gas, NGLs and condensate related to assets of DCP Midstream 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. Historically we have used natural gas, crude oil and NGL swaps to hedge the impact of market fluctuations in the price of NGLs, natural gas and other energy-related products. For the year ended December 31, 2005, amounts recognized in the consolidated statement of operations for changes in the fair value of these hedge instruments and for the effects of any ineffectiveness were not significant. No derivative gains or losses were reclassified from AOCI to current period earnings as a result of the discontinuance of cash flow hedges related to any forecasted transactions that are not probable of occurring. At December 31, 2005, amounts deferred in AOCI related to commodity cash flow hedges were not significant. As of December 31, 2005, $2 million of deferred net losses on derivative instruments in AOCI are expected to be reclassified into earnings during the next 12 months as the hedged transactions occur; 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 year ended December 31, 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—Prior to issuing fixed rate debt in August 2000, the Company 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 deferred balance was $8 million at December 31, 2005. 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 that were issued in August 2000 to floating rate debt. The interest rate fair

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Year Ended December 31, 2005

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, 2005, the fair value of the interest rate swaps was an $8 million asset, which is included in the consolidated balance sheet as unrealized gains or unrealized losses on mark-to-market and hedging transactions 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.

14. Estimated Fair Value of Financial Instruments

We have determined the following fair value amounts using available market information and appropriate valuation methodologies. However, considerable judgment is required 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 carrying amount and estimated fair value of our financial instruments are as follows at December 31, 2005 (millions):

	Carrying Amount			Estimated Fair Value
Short-term investments	$	627		$	627
Restricted investments		364			364
Accounts receivable		1,636			1,636
Accounts payable		(2,119	)		(2,119	)
Unrealized gains on mark-to-market and hedging transactions		14			14
Current maturities of long-term debt		(300	)		(302	)
Long-term debt		(1,760	)		(1,942	)

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.

The estimated fair value of the natural gas, NGLs and crude oil derivative contracts is determined by multiplying the difference between the quoted termination prices for natural gas, NGLs and crude oil and the derivative contract prices by the quantities under contract. The estimated fair value of options is determined by the Black-Scholes option valuation model.

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DUKE ENERGY FIELD SERVICES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Year Ended December 31, 2005

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

15. Commitments and Contingent Liabilities

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. However, these class actions can be costly and time consuming to defend. Management believes that, based on currently known information, these proceedings will not have a material adverse effect on our consolidated results of operations, financial position or cash flows.

General Insurance—We carry insurance coverage, with an affiliate of Duke Energy, that management believes is consistent with companies engaged in similar commercial operations with similar type properties. 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. 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 comparable to those carried by other energy companies of similar size. The cost of our general insurance coverages continued to fluctuate over the past year reflecting the changing conditions of the insurance markets.

During the third quarter 2004, certain assets, located in the Gulf Coast, were damaged as a result of Hurricane Ivan. Management believes that the resulting losses will be covered by insurance, subject to applicable deductibles for property and business interruption. Included in accounts receivable—affiliate on the consolidated balance sheet are insurance recovery receivables related to Hurricane Ivan of $29 million at December 31, 2005 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. Substantially all of our facilities have resumed operations, but some facilities are not yet operating at the same levels of capacity utilization as they operated before the hurricanes. Several of our assets sustained property damage including some of our operating equipment on a platform in the Gulf of Mexico. We expect that a portion of the resulting lost revenues and property damage will be covered by our insurance, subject to applicable deductibles. We expect that the financial impact of recent hurricanes may increase market rates for insurance coverage in the future, however, we do not expect these increases to have a material adverse effect on our consolidated results of operations, financial position or cash flows. Included in accounts receivable—affiliate on the consolidated balance sheet are insurance recovery receivables related to Hurricane Katrina of $5 million at December 31, 2005 from an insurance provider that is a subsidiary of Duke Energy. Insurance recovery receivables related to Hurricane Rita are insignificant.

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DUKE ENERGY FIELD SERVICES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Year Ended December 31, 2005

During the year ended December 31, 2005, we recorded business interruption insurance recoveries related to these hurricanes of $3 million in the consolidated statement of operations 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.

Other Commitments and Contingencies—We utilize assets under operating leases in several areas of operations. Rental expense, including leases with no continuing commitment, amounted to $36 million in 2005. 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, 2005 (millions):

2006	$	22
2007		19
2008		17
2009		13
2010		13
Thereafter		51
Total gross payments		135
Sublease receipts		(4	)
Total net payments	$	131

16. Stock-Based Compensation

Under Duke Energy’s 1998 Plan, stock options for Duke Energy’s common stock were granted to certain of our key employees. 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 five years with a maximum option term of 10 years.

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DUKE ENERGY FIELD SERVICES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Year Ended December 31, 2005

The following tables show information regarding options to purchase Duke Energy’s common stock granted to our employees.

	Stock Option Activity
	Options (thousands)		Weighted-Average Exercise Price
Outstanding at January 1, 2005	2,956			29
Exercised	(302	)		20
Forfeited	(61	)		31
Outstanding at December 31, 2005	2,593		$	29

	Stock Options at December 31, 2005
	Outstanding				Exercisable
Range of Exercise Prices	Number (thousands)	Weighted- Average Remaining Life (years)	Weighted- Average Exercise Price		Number (thousands)	Weighted- Average Exercise Price
$11 to $16	587	7.1	$	14	235	$	14
$17 to $22	28	6.1		18	28		18
$23 to $28	747	3.4		26	747		26
$29 to $34	97	3.5		30	97		30
$35 to $40	647	6.0		38	641		38
> $40	487	5.0		43	487		43
Total	2,593	5.2	$	29	2,235	$	32

There were no options granted in 2005.

Upon execution of the 50-50 Transaction in July 2005, the employees referred to above incurred a change in status from Duke Energy employees to non-employees. As a result, we ceased using the intrinsic value method under APB 25 and FIN 44 to account for all outstanding unvested options. 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 occurs. Compensation expense for outstanding unvested options was not significant for the year ended December 31, 2005.

Duke Energy granted stock-based performance awards of Duke Energy common stock to certain of our key employees under the 1998 Plan. Stock-based performance awards under the 1998 Plan vest over periods ranging from three to seven years. Vesting can occur in three years, at the earliest, if certain performance objectives are met. Duke Energy awarded 160,910 stock-based performance awards (fair value of approximately $4 million at grant dates) in 2005. Compensation expense for stock-based performance awards is recognized over the required vesting period and amounted to approximately $3 million in 2005.

Duke Energy granted phantom shares of Duke Energy common stock to certain of our employees under the 1998 Plan. Phantom stock awards under the 1998 Plan vest over periods ranging from one to five years. Duke Energy awarded 128,850 phantom awards (fair value of approximately $3 million at grant dates) in 2005. Compensation expense for phantom awards is recognized over the required vesting period and amounted to approximately $2 million in 2005.

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DUKE ENERGY FIELD SERVICES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Year Ended December 31, 2005

Duke Energy granted restricted shares of Duke Energy common stock to certain of our employees under the 1998 Plan. Restricted shares under the 1998 Plan vest over periods from one to five years. Duke Energy awarded 3,000 restricted shares (fair value of less than $1 million at grant date) in 2005. Compensation expense for restricted shares is recognized over the required vesting period and amounted to less than $1 million in 2005.

In February 2006, we adopted a long-term incentive plan (see Note 19). On a prospective basis, we will not participate in Duke Energy’s 1998 Plan.

17. Benefits

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 in which we contribute 4% of each eligible employee’s qualified earnings. Additionally, we match employees’ contributions in the plan up to 6% of qualified earnings. During 2005 we expensed plan contributions of $15 million.

We offer certain eligible executives the opportunity to participate in the Duke Energy Field Services’ LP 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. Additionally, certain of our executives participate in restricted stock and other compensatory plans. Total expense for all of our executive compensatory plans was $5 million in 2005.

18. Guarantees and Indemnifications

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 $22 million of construction obligations. This guaranty will be reduced by construction payments and 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 December 31, 2005, we had a liability of approximately $1 million recorded for known liabilities related to outstanding indemnification provisions.

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DUKE ENERGY FIELD SERVICES, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Year Ended December 31, 2005

19. Subsequent Events

On January 25, 2006, DCP Midstream Partners announced the declaration of a cash distribution of $0.095 per unit, payable on February 13, 2006 to unitholders of record on February 3, 2006. That distribution represents the pro rata portion of their minimum quarterly cash distribution of $0.35 per unit for the period December 7, 2005 through December 31, 2005.

In February 2006, we adopted a long-term incentive plan (the “2006 LTI Plan”). Under the 2006 LTI Plan, the Board of Directors may award phantom units, including dividend/distribution rights, equal to the weighted average fair value of a common share of ConocoPhillips, Duke Energy and DCP Midstream Partners. The phantom units may be settled in cash or equity securities at the discretion of the Board of Directors. The weighted percentage for each such unit is 45%, 45% and 10%, respectively. The Board of Directors has the discretion to determine the vesting period for phantom units granted under the 2006 LTI Plan, however these units will generally vest over three to eight years, contingent upon the grantee continuing to be an employee of the Company.

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DUKE ENERGY FIELD SERVICES, LLC

SCHEDULE II—CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

	Balance at Beginning of Period		Increases					Deductions (c)			Balance at End of Period
			Charged to Expense		Charged to Other Accounts (b)
	($ in millions)
December 31, 2005
Allowance for doubtful accounts	$	4	$	1	$	—		$	(1	)	$	4
Environmental		17		5		—			(9	)		13
Litigation		8		1		2			(6	)		5
Other (a)		8		11		(2	)		(11	)		6
	$	37	$	18	$	—		$	(27	)	$	28

(a) Principally consists of other contingency liabilities which are included in other current liabilities.

(b) Consists of other contingency reserves reclassified to litigation reserve accounts.

(c) Principally consists of cash payments, collections, reserve reversals and liabilities settled, and liabilities transferred upon sale of assets.

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TEPPCO PARTNERS, L.P.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	Page
Consolidated Financial Statements:
Report of Independent Registered Public Accounting Firm	F-183
Consolidated Balance Sheets as of December 31, 2005 and 2004 (as restated)	F-184
Consolidated Statements of Income for the years ended December 31, 2005, 2004 (as restated) and 2003 (as restated)	F-185
Consolidated Statements of Cash Flows for the years ended December 31, 2005, 2004 (as restated) and 2003 (as restated)	F-186
Consolidated Statements of Partners’ Capital for the years ended December 31, 2005, 2004 (as restated) and 2003 (as restated)	F-187
Consolidated Statements of Comprehensive Income for the years ended December 31, 2005, 2004 (as restated) and 2003 (as restated)	F-188
Notes to Consolidated Financial Statements	F-189

F-182

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners of

TEPPCO Partners, L.P.:

We have audited the accompanying consolidated balance sheets of TEPPCO Partners, L.P. 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.

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. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes 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, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of TEPPCO Partners, L.P. 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.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of TEPPCO Partners, L.P.’s internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 28, 2006, expressed an unqualified opinion on management’s assessment of, and the effective operation of, internal control over financial reporting.

KPMG LLP

Houston, Texas

February 28, 2006, except for the effects of discontinued operations, as discussed in Note 5, which is as of June 1, 2006

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TEPPCO PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

(in thousands)

	December 31,
	2005			2004
				(as restated)
ASSETS
Current assets:
Cash and cash equivalents	$	119		$	16,422
Accounts receivable, trade (net of allowance for doubtful accounts of $250 and $112)		803,373			553,628
Accounts receivable, related parties		5,207			11,845
Inventories		29,069			19,521
Other		61,361			42,138
Total current assets		899,129			643,554
Property, plant and equipment, at cost (net of accumulated depreciation and amortization of $474,332 and $407,670)		1,960,068			1,703,702
Equity investments		359,656			363,307
Intangible assets		376,908			407,358
Goodwill		16,944			16,944
Other assets		67,833			51,419
Total assets	$	3,680,538		$	3,186,284
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable and accrued liabilities	$	800,033		$	564,464
Accounts payable, related parties		11,836			24,654
Accrued interest		32,840			32,292
Other accrued taxes		16,532			13,309
Other		75,970			46,593
Total current liabilities		937,211			681,312
Senior Notes		1,119,121			1,127,226
Other long-term debt		405,900			353,000
Other liabilities and deferred credits		16,936			13,643
Commitments and contingencies
Partners’ capital:
Accumulated other comprehensive income		11			—
General partner’s interest		(61,487	)		(35,881	)
Limited partners’ interests		1,262,846			1,046,984
Total partners’ capital		1,201,370			1,011,103
Total liabilities and partners’ capital	$	3,680,538		$	3,186,284

See accompanying Notes to Consolidated Financial Statements.

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TEPPCO PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF INCOME

(in thousands, except per Unit amounts )

	Years Ended December 31,
	2005			2004			2003
				(as restated)			(as restated)
Operating revenues:
Sales of petroleum products	$	8,061,808		$	5,426,832		$	3,766,651
Transportation—Refined products		144,552			148,166			138,926
Transportation—LPGs		96,297			87,050			91,787
Transportation—Crude oil		37,614			37,177			29,057
Transportation—NGLs		43,915			41,204			39,837
Gathering—Natural gas		152,797			140,122			135,144
Other		68,051			67,539			54,430
Total operating revenues		8,605,034			5,948,090			4,255,832
Costs and expenses:
Purchases of petroleum products		7,986,438			5,367,027			3,711,207
Operating, general and administrative		218,920			219,909			198,478
Operating fuel and power		48,972			48,139			41,362
Depreciation and amortization		110,729			112,284			100,728
Taxes—other than income taxes		20,610			17,340			15,597
Gains on sales of assets		(668	)		(1,053	)		(3,948	)
Total costs and expenses		8,385,001			5,763,646			4,063,424
Operating income		220,033			184,444			192,408
Interest expense—net		(81,861	)		(72,053	)		(84,250	)
Equity earnings		20,094			22,148			12,874
Other income—net		1,135			1,320			748
Income from continuing operations		159,401			135,859			121,780
Discontinued operations		3,150			2,689			—
Net income	$	162,551		$	138,548		$	121,780
Net Income Allocation:
Limited Partner Unitholders income from continuing operations	$	112,744		$	96,667		$	86,357
Limited Partner Unitholders income from discontinued operations		2,228			1,913			—
Total Limited Partner Unitholders net income allocation		114,972			98,580			86,357
Class B Unitholder net income allocation		—			—			1,754
General Partner income from continuing operations		46,657			39,192			33,669
General Partner income from discontinued operations		922			776			—
Total General Partner net income allocation		47,579			39,968			33,669
Total net income allocated	$	162,551		$	138,548		$	121,780
Basic and diluted net income per Limited Partner and Class B Unit:
Continuing operations	$	1.67		$	1.53		$	1.47
Discontinued operations		0.04			0.03			—
Basic and diluted net income per Limited Partner and Class B Unit	$	1.71		$	1.56		$	1.47
Weighted average Limited Partner and Class B Units outstanding		67,397			62,999			59,765

See accompanying Notes to Consolidated Financial Statements.

F-185

TEPPCO PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

	Years Ended December 31,
	2005			2004			2003
				(as restated)			(as restated)
Cash flows from operating activities:
Net income	$	162,551		$	138,548		$	121,780
Adjustments to reconcile net income to cash provided by continuing operating activities:
Income from discontinued operations		(3,150	)		(2,689	)		—
Depreciation and amortization		110,729			112,284			100,728
Earnings in equity investments, net of distributions		16,991			25,065			15,129
Gains on sales of assets		(668	)		(1,053	)		(3,948	)
Non-cash portion of interest expense		1,624			(391	)		4,793
Increase in accounts receivable		(249,745	)		(181,690	)		(100,085	)
Decrease (increase) in accounts receivable, related parties		6,638			(14,693	)		8,788
Increase in inventories		(970	)		(3,433	)		(956	)
Increase in other current assets		(19,088	)		(9,926	)		(953	)
Increase in accounts payable and accrued expenses		254,251			186,942			95,540
Increase (decrease) in accounts payable, related parties		(12,817	)		4,360			7,381
Other		(15,623	)		10,572			(5,773	)
Net cash provided by continuing operating activities		250,723			263,896			242,424
Net cash provided by discontinued operations		3,782			3,271			—
Net cash provided by operating activities		254,505			267,167			242,424
Cash flows from continuing investing activities:
Proceeds from sales of assets		510			1,226			8,531
Proceeds from cash investments		—			—			750
Purchase of assets		(112,231	)		(3,421	)		(27,469	)
Investment in Mont Belvieu Storage Partners, L.P.		(4,233	)		(21,358	)		(2,533	)
Investment in Centennial Pipeline LLC		—			(1,500	)		(4,000	)
Purchase of additional interest in Centennial Pipeline LLC		—			—			(20,000	)
Cash paid for linefill on assets owned		(14,408	)		(957	)		(3,070	)
Capital expenditures		(220,553	)		(156,749	)		(126,707	)
Net cash used in continuing investing activities		(350,915	)		(182,759	)		(174,498	)
Net cash used in discontinued investing activities		—			(7,398	)		(13,810	)
Net cash used in investing activities		(350,915	)		(190,157	)		(188,308	)
Cash flows from financing activities:
Proceeds from revolving credit facility		657,757			324,200			382,000
Issuance of Limited Partner Units, net		278,806			—			287,506
Issuance of Senior Notes		—			—			198,570
Repayments on revolving credit facility		(604,857	)		(181,200	)		(604,000	)
Repurchase and retirement of Class B Units		—			—			(113,814	)
Debt issuance costs		(498	)		—			(3,381	)
General Partner’s contributions		—			—			2
Distributions paid		(251,101	)		(233,057	)		(202,498	)
Net cash provided by (used in) financing activities		80,107			(90,057	)		(55,615	)
Net decrease in cash and cash equivalents		(16,303	)		(13,047	)		(1,499	)
Cash and cash equivalents at beginning of period		16,422			29,469			30,968
Cash and cash equivalents at end of period	$	119		$	16,422		$	29,469
Non-cash investing activities:
Net assets transferred to Mont Belvieu Storage Partners, L.P.	$	1,429		$	—		$	61,042
Supplemental disclosure of cash flows:
Cash paid for interest (net of amounts capitalized)	$	82,315		$	77,510		$	79,930

See accompanying Notes to Consolidated Financial Statements.

F-186

TEPPCO PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

(in thousands, except Unit amounts)

	Outstanding Limited Partner Units	General Partner’s Interest			Limited Partners’ Interests			Accumulated Other Comprehensive (Loss) Income			Total
Partners’ capital at December 31, 2002 (as restated)	53,809,597	$	12,104		$	897,400		$	(20,055	)	$	889,449
Issuance of Limited Partner Units, net	9,101,650		—			285,461			—			285,461
Retirement of Class B units	—		—			(11,175	)		—			(11,175	)
Net income on cash flow hedge	—		—			—			16,164			16,164
Reclassification due to discontinued portion of cash flow hedge	—		—			—			989			989
2003 net income allocation	—		33,669			86,357			—			120,026
2003 cash distributions	—		(54,725	)		(145,427	)		—			(200,152	)
Issuance of Limited Partner Units upon exercise of options	87,307		2			2,045			—			2,047
Partners’ capital at December 31, 2003 (as restated)	62,998,554		(8,950	)		1,114,661			(2,902	)		1,102,809
Adjustments to issuance of Limited Partner Units, net	—		—			(99	)		—			(99	)
Net income on cash flow hedge	—		—			—			2,902			2,902
2004 net income allocation	—		39,968			98,580			—			138,548
2004 cash distributions	—		(66,899	)		(166,158	)		—			(233,057	)
Partners’ capital at December 31, 2004 (as restated)	62,998,554		(35,881	)		1,046,984			—			1,011,103
Issuance of Limited Partner Units, net	6,965,000		—			278,806			—			278,806
Changes in fair values of crude oil hedges	—		—			—			11			11
2005 net income allocation	—		47,579			114,972			—			162,551
2005 cash distributions	—		(73,185	)		(177,916	)		—			(251,101	)
Partners’ capital at December 31, 2005	69,963,554	$	(61,487	)	$	1,262,846		$	11		$	1,201,370

See accompanying Notes to Consolidated Financial Statements.

F-187

TEPPCO PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in thousands)

	Years Ended December 31,
	2005		2004		2003
			(as restated)		(as restated)
Net income	$	162,551	$	138,548	$	121,780
Net income on cash flow hedges		11		—		16,164
Comprehensive income	$	162,562	$	138,548	$	137,944

See accompanying Notes to Consolidated Financial Statements.

F-188

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. PARTNERSHIP ORGANIZATION

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”.

F-189

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(CONTINUED)

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.

NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

F-190

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(CONTINUED)

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):

	Years Ended December 31,
	2005			2004			2003
Balance at beginning of period	$	112		$	4,700		$	4,608
Charges to expense		829			536			793
Deductions and other		(691	)		(5,124	)		(701	)
Balance at end of period	$	250		$	112		$	4,700

F-191

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(CONTINUED)

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.

F-192

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(CONTINUED)

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.

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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):

	Years Ended December 31,
	2005			2004			2003
Balance at beginning of period	$	5,037		$	7,639		$	7,693
Charges to expense		2,530			5,178			6,824
Deductions and other		(5,120	)		(7,780	)		(6,878	)
Balance at end of period	$	2,447		$	5,037		$	7,639

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(CONTINUED)

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

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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

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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

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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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(CONTINUED)

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.

NOTE 3. GOODWILL AND OTHER INTANGIBLE ASSETS

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):

	Downstream Segment		Midstream Segment		Upstream Segment		Segments Total
Goodwill	$	—	$	2,777	$	14,167	$	16,944

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(CONTINUED)

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):

	December 31, 2005					December 31, 2004
	Gross Carrying Amount		Accumulated Amortization			Gross Carrying Amount		Accumulated Amortization
Intangible assets:
Gathering and transportation agreements	$	464,337	$	(118,921	)	$	464,337	$	(91,262	)
Fractionation agreement		38,000		(14,725	)		38,000		(12,825	)
Other		10,226		(2,009	)		12,262		(3,154	)
Subtotal	$	512,563	$	(135,655	)	$	514,599	$	(107,241	)
Excess investments:
Centennial Pipeline LLC	$	33,400	$	(12,947	)	$	33,400	$	(8,875	)
Seaway Crude Pipeline Company		27,100		(3,764	)		27,100		(3,072	)
Subtotal	$	60,500	$	(16,711	)	$	60,500	$	(11,947	)
Total intangible assets	$	573,063	$	(152,366	)	$	575,099	$	(119,188	)

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).

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(CONTINUED)

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):

	Intangible Assets		Excess Investments
2006	$	32,561	$	4,691
2007		33,395		5,113
2008		32,967		5,438
2009		30,719		6,878
2010		27,338		7,042

NOTE 4. INTEREST RATE SWAPS

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(CONTINUED)

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.

NOTE 5. ACQUISITIONS, DISPOSITIONS AND DISCONTINUED OPERATIONS

Rancho Pipeline

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.

Genesis Pipeline

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):

Property, plant and equipment	$	12,811
Intangible assets		8,742
Other		144
Total assets		21,697
Total liabilities assumed		(687	)
Net assets acquired	$	21,010

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(CONTINUED)

Mexia Pipeline

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.

Crude Oil Storage and Terminaling Assets

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.

Refined Products Terminal and Truck Rack

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.

Genco Assets

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 origin 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.

Pioneer Plant

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

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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):

	Years Ended December 31,
	2005		2004
Sales of petroleum products	$	10,479	$	7,295
Other		2,975		2,807
Total operating revenues		13,454		10,102
Purchases of petroleum products		8,870		5,944
Operating, general and administrative		692		738
Depreciation and amortization		612		610
Taxes—other than income taxes		130		121
Total costs and expenses		10,304		7,413
Income from discontinued operations	$	3,150	$	2,689

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

	December 31,
	2005		2004
Inventories	$	7	$	28
Property, plant and equipment, net		19,812		20,598
Assets of discontinued operations	$	19,819	$	20,626

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

	Years Ended December 31,
	2005		2004			2003
Cash flows from discontinued operating activities:
Net income	$	3,150	$	2,689		$	—
Depreciation and amortization		612		610			—
(Increase) decrease in inventories		20		(28	)		—
Net cash flows provided by discontinued operating activities		3,782		3,271			—
Cash flows from discontinued investing activities:
Capital expenditures		—		(7,398	)		(13,810	)
Net cash flows used in discontinued investing activities		—		(7,398	)		(13,810	)
Net cash flows from discontinued operations	$	3,782	$	(4,127	)	$	(13,810	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(CONTINUED)

NOTE 6. EQUITY INVESTMENTS

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

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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):

	Years Ended December 31,
	2005		2004
Revenues	$	164,494	$	149,843
Net income		52,623		52,059

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

	December 31,
	2005		2004
Current assets	$	60,082	$	59,314
Noncurrent assets		630,212		633,222
Current liabilities		42,242		41,209
Long-term debt		140,000		140,000
Noncurrent liabilities		13,626		20,440
Partners’ capital		494,426		490,887

NOTE 7. RELATED PARTY TRANSACTIONS

EPCO and Affiliates and Duke Energy, DEFS and Affiliates

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).

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

	Years Ended December 31,
	2005		2004		2003
Revenues from EPCO and affiliates(1)
Transportation—NGLs(2)	$	7.4	$	—	$	—
Transportation—LPGs(3)		4.3		—		—
Other operating revenues(4)		0.3		—		—
Costs and Expenses from EPCO and affiliates(1)
Payroll and administrative(5)		68.2		—		—
Purchases of petroleum products(6)		3.4		—		—
Revenues from DEFS and affiliates(7)
Sales of petroleum products(8)		4.3		23.2		15.2
Transportation—NGLs(9)		2.8		16.7		17.2
Gathering—Natural gas—Jonah(10)		0.5		3.3		2.0
Transportation—LPGs(11)		0.7		2.6		2.8
Other operating revenues(12)		2.4		14.0		10.8
Costs and Expenses from DEFS and affiliates(7)(13)(14)
Payroll and administrative(5)		16.2		95.9		88.8
Purchases of petroleum products—TCO(15)		37.7		141.3		110.7
Purchases of petroleum products—Jonah(16)		0.8		5.1		—

(1) Operating revenues earned and expenses incurred from activities with EPCO and its affiliates are considered related party transactions from February 24, 2005, through December 31, 2005, as a result of the change in ownership of the General Partner (see Note 1).

(2) Includes revenues from NGL transportation on the Chaparral and Panola NGL pipelines.

(3) Includes revenues from LPG transportation on the TE Products pipeline.

(4) Includes other operating revenues on TE Products.

(5) Substantially all of these costs were related to payroll, payroll related expenses and administrative expenses incurred in managing us and our subsidiaries.

(6) Includes TCO purchases of condensate and expenses related to LSI’s use of an affiliate of EPCO as a transporter.

(7) Operating revenues earned and expenses incurred from activities with DEFS and its affiliates are considered related party transactions for all periods through February 23, 2005, as a result of the change in ownership of the General Partner (see Note 1).

(8) Includes LSI sales of lubrication oils and specialty chemicals and Jonah NGL sales in connection with Jonah’s Pioneer processing plant operations, which was constructed during the Phase III expansion and began operating in 2004. Amounts related to the Pioneer plant are classified as discontinued operations in the consolidated statements of income.

(9) Includes revenues from NGL transportation on the Chaparral, Panola, Dean and Wilcox NGL pipelines.

(10) Includes gas gathering revenues on the Jonah system.

(11) Effective May 2001, we entered into an agreement with an affiliate of DEFS to commit to it sole utilization of our Providence, Rhode Island, terminal. We operate the terminal and provide propane loading services to an affiliate of DEFS. We recognized revenue from an affiliate of DEFS pursuant to this agreement.

(12) Includes fractionation revenues and other revenues. Effective with the purchase of the fractionation facilities on March 31, 1998, TEPPCO Colorado and DEFS entered into a 20-year Fractionation Agreement, under which TEPPCO Colorado receives a variable fee for all fractionated volumes delivered to DEFS. Other

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operating revenues also include other operating revenues on TE Products and processing and other revenues on the Jonah system. Amounts related to the Pioneer plant are classified as discontinued operations in the consolidated statements of income.

(13) Includes operating costs and expenses related to DEFS managing and operating the Jonah and Val Verde systems and the Chaparral NGL pipeline on our behalf under a contractual agreement established at the time of acquisition of each asset. In connection with the change in ownership of our General Partner, we have assumed these activities.

(14) Effective with the purchase of the fractionation facilities on March 31, 1998, TEPPCO Colorado and DEFS entered into an Operation and Maintenance Agreement, whereby DEFS operates and maintains the fractionation facilities for TEPPCO Colorado. For these services, TEPPCO Colorado pays DEFS a set volumetric rate for all fractionated volumes delivered to DEFS.

(15) Includes TCO purchases of condensate.

(16) Includes Jonah purchases of natural gas in connection with Jonah’s Pioneer processing plant operations.

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).

Seaway

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

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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.

Centennial

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.

MB Storage

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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(CONTINUED)

NOTE 8. INVENTORIES

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):

	December 31,
	2005		2004
Crude oil	$	3,021	$	3,690
Refined products		4,461		5,665
LPGs		7,403		—
Lubrication oils and specialty chemicals		5,740		4,002
Materials and supplies		8,203		6,135
Other		241		29
Total	$	29,069	$	19,521

NOTE 9. PROPERTY, PLANT AND EQUIPMENT

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

	December 31,
	2005		2004
Land and right of way	$	147,064	$	135,984
Line pipe and fittings		1,434,392		1,344,193
Storage tanks		189,054		140,690
Buildings and improvements		51,596		41,205
Machinery and equipment		370,439		333,363
Construction work in progress		241,855		115,937
Total property, plant and equipment	$	2,434,400	$	2,111,372
Less accumulated depreciation and amortization		474,332		407,670
Net property, plant and equipment	$	1,960,068	$	1,703,702

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

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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.

NOTE 10. DEBT

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:

Year	Redemption Price
2008	103.755	%
2009	103.380	%
2010	103.004	%
2011	102.629	%
2012	102.253	%
2013	101.878	%
2014	101.502	%
2015	101.127	%
2016	100.751	%
2017	100.376	%

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

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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):

			Fair Value
	Face Value		December 31,
			2005		2004
6.45% TE Products Senior Notes, due January 2008	$	180.0	$	183.7	$	187.1
7.625% Senior Notes, due February 2012		500.0		552.0		569.6
6.125% Senior Notes, due February 2013		200.0		205.6		210.2
7.51% TE Products Senior Notes, due January 2028		210.0		224.1		225.6

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

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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:

• Total bank commitments increased from $600.0 million to $700.0 million. The amendment also provided that the commitments under the credit facility may be increased up to a maximum of $850.0 million upon our request, subject to lender approval and the satisfaction of certain other conditions.

• The facility fee and the borrowing rate currently in effect were reduced by 0.275%.

• The maturity date of the credit facility was extended from October 21, 2009, to December 13, 2010. Also under the terms of the amendment, we may request up to two, one-year extensions of the maturity date. These extensions, if requested, will become effective subject to lender approval and satisfaction of certain other conditions.

• The amendment also removed the $100.0 million limit on the total amount of standby letters of credit that can be outstanding under the credit facility.

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):

	December 31,
	2005		2004
Credit Facilities:
Revolving Credit Facility, due December 2010	$	405,900	$	353,000
6.45% TE Products Senior Notes, due January 2008		179,937		179,906
7.625% Senior Notes, due February 2012		498,659		498,438
6.125% Senior Notes, due February 2013		198,988		198,845
7.51% TE Products Senior Notes, due January 2028		210,000		210,000
Total borrowings		1,493,484		1,440,189
Adjustment to carrying value associated with hedges of fair value		31,537		40,037
Total Credit Facilities	$	1,525,021	$	1,480,226

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(CONTINUED)

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.

NOTE 11. PARTNERS’ CAPITAL AND DISTRIBUTIONS

Equity Offerings

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. We received approximately $0.7 million in proceeds from the offering in excess of the amount needed to repurchase and retire the Class B Units.

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.

Quarterly Distributions of Available Cash

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:

	Unitholders		General Partner
Quarterly Cash Distribution per Unit:
Up to Minimum Quarterly Distribution ($0.275 per Unit)	98	%	2	%
First Target—$0.276 per Unit up to $0.325 per Unit	85	%	15	%
Second Target—$0.326 per Unit up to $0.45 per Unit	75	%	25	%
Over Second Target—Cash distributions greater than $0.45 per Unit	50	%	50	%

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(CONTINUED)

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):

	Years Ended December 31,
	2005		2004		2003
Limited Partner Units	$	177,917	$	166,158	$	145,427
General Partner Ownership Interest		3,630		3,391		3,016
General Partner Incentive		69,554		63,508		51,709
Total Partners’ Capital Cash Distributions Paid		251,101		233,057		200,152
Class B Units		—		—		2,346
Total Cash Distributions Paid	$	251,101	$	233,057	$	202,498
Total Cash Distributions Paid Per Unit	$	2.68	$	2.64	$	2.50

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.

General Partner Interest

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(CONTINUED)

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.

NOTE 12. CONCENTRATIONS OF CREDIT RISK

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.

NOTE 13. UNIT-BASED COMPENSATION

1994 Long Term Incentive Plan

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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(CONTINUED)

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:

	Options Outstanding		Options Exercisable		Exercise Range
Unit Options:
Outstanding at December 31, 2002	90,091		90,091		$	13.81 – $25.69
Exercised	(90,091	)	(90,091	)	$	13.81 – $25.69
Outstanding at December 31, 2003	—		—

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.

1999 and 2002 Phantom Unit Plans

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.

2000 Long Term Incentive Plan

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(CONTINUED)

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.

2005 Phantom Unit Plan

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(CONTINUED)

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.

NOTE 14. OPERATING LEASES

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):

2006	$	19,536
2007		17,391
2008		10,863
2009		7,682
2010		6,645
Thereafter		21,544
	$	83,661

NOTE 15. EMPLOYEE BENEFITS

Retirement Plans

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.

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TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(CONTINUED)

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):

	Year Ended December 31,
	2005			2004			2003
Service cost benefit earned during the year	$	4,393		$	3,653		$	3,179
Interest cost on projected benefit obligation		934			719			504
Expected return on plan assets		(671	)		(878	)		(604	)
Amortization of prior service cost		5			7			7
Recognized net actuarial loss		129			57			24
SFAS 88 curtailment charge		50			—			—
SFAS 88 settlement charge		194			—			—
Net pension benefits costs	$	5,034		$	3,558		$	3,110

Other Postretirement Benefits

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.

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TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(CONTINUED)

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):

	Year Ended December 31,
	2005			2004		2003
Service cost benefit earned during the year	$	81		$	165	$	137
Interest cost on accumulated postretirement benefit obligation		69			153		137
Amortization of prior service cost		53			126		126
Recognized net actuarial loss		4			1		—
Curtailment credit		(1,676	)		—		—
Settlement credit		(4	)		—		—
Net postretirement benefits costs	$	(1,473	)	$	445	$	400

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:

	Pension Benefits				Other Postretirement Benefits
	2005		2004		2005		2004
Discount rate	4.59	%	5.75	%	5.75	%	5.75	%
Increase in compensation levels	—		5.00	%	—		—

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:

	Pension Benefits				Other Postretirement Benefits
	2005		2004		2005		2004
Discount rate(1)	5.75%/5.00	%	6.25	%	5.75%/5.00	%	6.25	%
Increase in compensation levels	5.00	%	5.00	%	—		—
Expected long-term rate of return on plan assets(2)	8.00%/2.00	%	8.00	%	—		—

(1) Expense was remeasured on May 31, 2005, as a result of TEPPCO RCBP and TEPPCO SBP amendments. The discount rate was decreased from 5.75% to 5% effective June 1, 2005, to reflect rates of returns on bonds currently available to settle the liability.

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(2) As a result of TEPPCO RCBP and TEPPCO SBP amendments, the expected return on assets was changed from 8% to 2% due to the movement of plan funds from equity investments into short-term money market funds, effective June 1, 2005.

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):

	Pension Benefits						Other Postretirement Benefits
	2005			2004			2005			2004
Change in benefit obligation
Benefit obligation at beginning of year	$	15,940		$	11,256		$	2,964		$	2,467
Service cost		4,393			3,653			81			165
Interest cost		934			719			70			153
Actuarial loss		2,740			572			76			205
Retiree contributions		—			—			64			60
Benefits paid		(910	)		(260	)		(80	)		(86	)
Impact of curtailment		(986	)		—			(3,575	)		—
Settlement		—			—			400			—
Benefit obligation at end of year	$	22,111		$	15,940		$	—		$	2,964
Change in plan assets
Fair value of plan assets at beginning of year	$	14,969		$	10,921		$	—		$	—
Actual return on plan assets		20			808			—			—
Retiree contributions		—			—			64			60
Employer contributions		9,025			3,500			16			26
Benefits paid		(910	)		(260	)		(80	)		(86	)
Fair value of plan assets at end of year	$	23,104		$	14,969		$	—		$	—
Reconciliation of funded status
Funded status	$	994		$	(971	)	$	—		$	(2,964	)
Unrecognized prior service cost		—			33			—			1,003
Unrecognized actuarial loss		4,067			2,006			—			472
Net amount recognized	$	5,061		$	1,068		$	—		$	(1,489	)

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

	Pension Benefits		Other Postretirement Benefits
2006	$	22,360	$	—

Plan Assets

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

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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):

	December 31,
Asset Category	2005		2004
Equity securities	—		63	%
Debt securities	—		35	%
Other (money market and cash)	100	%	2	%
Total	100	%	100	%

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

Other Plans

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.

NOTE 16. COMMITMENTS AND CONTINGENCIES

Litigation

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

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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.

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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.

Regulatory Matters

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

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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

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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 PPIIndex 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.

Other

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

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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).

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NOTE 17. SEGMENT INFORMATION

We have three reporting segments:

• Our Downstream Segment, which is engaged in the transportation and storage of refined products, LPGs and petrochemicals;

• Our Upstream Segment, which is engaged in the gathering, transportation, marketing and storage of crude oil and distribution of lubrication oils and specialty chemicals; and

• Our Midstream Segment, which is engaged in the gathering of natural gas, fractionation of NGLs and transportation of NGLs.

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.

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

	Year Ended December 31, 2005
	Downstream Segment			Upstream Segment			Midstream Segment			Segments Total			Partnership and Other			Consolidated
Sales of petroleum products	$	—		$	8,062,131		$	—		$	8,062,131		$	(323	)	$	8,061,808
Operating revenues		287,191			48,108			211,171			546,470			(3,244	)		543,226
Purchases of petroleum products		—			7,989,682			—			7,989,682			(3,244	)		7,986,438
Operating expenses, including power		159,784			70,340			58,701			288,825			(323	)		288,502
Depreciation and amortization expense		39,403			17,161			54,165			110,729			—			110,729
Gains on sales of assets		(139	)		(118	)		(411	)		(668	)		—			(668	)
Operating income		88,143			33,174			98,716			220,033			—			220,033
Equity earnings (losses)		(2,984	)		23,078			—			20,094			—			20,094
Other income, net		755			156			224			1,135			—			1,135
Earnings before interest from continuing operations		85,914			56,408			98,940			241,262			—			241,262
Discontinued operations		—			—			3,150			3,150			—			3,150
Earnings before interest	$	85,914		$	56,408		$	102,090		$	244,412		$	—		$	244,412

	Year Ended December 31, 2004
	Downstream Segment			Upstream Segment			Midstream Segment		Segments Total			Partnership and Other			Consolidated
	(as restated)			(as restated)					(as restated)						(as restated)
Sales of petroleum products	$	—		$	5,426,832		$	—	$	5,426,832		$	—		$	5,426,832
Operating revenues		279,400			49,163			195,902		524,465			(3,207	)		521,258
Purchases of petroleum products		—			5,370,234			—		5,370,234			(3,207	)		5,367,027
Operating expenses, including power		165,528			60,893			58,967		285,388			—			285,388
Depreciation and amortization expense		43,135			13,130			56,019		112,284			—			112,284
Gains on sales of assets		(526	)		(527	)		—		(1,053	)		—			(1,053	)
Operating income		71,263			32,265			80,916		184,444			—			184,444
Equity earnings (losses)		(6,544	)		28,692			—		22,148			—			22,148
Other income, net		787			406			127		1,320			—			1,320
Earnings before interest from continuing operations		65,506			61,363			81,043		207,912			—			207,912
Discontinued operations		—			—			2,689		2,689			—			2,689
Earnings before interest	$	65,506		$	61,363		$	83,732	$	210,601		$	—		$	210,601

F-230

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(CONTINUED)

	Year Ended December 31, 2003
	Downstream Segment			Upstream Segment			Midstream Segment		Segments Total			Partnership and Other			Consolidated
	(as restated)			(as restated)					(as restated)						(as restated)
Sales of petroleum products	$	—		$	3,766,651		$	—	$	3,766,651		$	—		$	3,766,651
Operating revenues		266,427			39,564			185,105		491,096			(1,915	)		489,181
Purchases of petroleum products		—			3,713,122			—		3,713,122			(1,915	)		3,711,207
Operating expenses, including power		151,103			57,314			47,020		255,437			—			255,437
Depreciation and amortization expense		31,620			11,311			57,797		100,728			—			100,728
Gain on sale of assets		—			(3,948	)		—		(3,948	)		—			(3,948	)
Operating income		83,704			28,416			80,288		192,408			—			192,408
Equity earnings (losses)		(7,384	)		20,258			—		12,874			—			12,874
Other income, net		226			306			289		821			(73	)		748
Earnings before interest	$	76,546		$	48,980		$	80,577	$	206,103		$	(73	)	$	206,030

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):

	Downstream Segment		Upstream Segment		Midstream Segment		Segments Total		Partnership and Other			Consolidated
December 31, 2005:
Total assets	$	1,056,217	$	1,353,492	$	1,280,548	$	3,690,257	$	(9,719	)	$	3,680,538
Capital expenditures		58,609		40,954		119,837		219,400		1,153			220,553
Non-cash investing activities		1,429		—		—		1,429		—			1,429
December 31, 2004 (as restated):
Total assets	$	959,042	$	1,069,007	$	1,184,184	$	3,212,233	$	(25,949	)	$	3,186,284
Capital expenditures		80,930		37,448		37,677		156,055		694			156,749
Capital expenditures for discontinued operations		—		—		7,398		7,398		—			7,398
December 31, 2003 (as restated):
Total assets	$	911,184	$	833,723	$	1,194,844	$	2,939,751	$	(5,271	)	$	2,934,480
Capital expenditures		59,061		13,427		54,072		126,560		147			126,707
Capital expenditures for discontinued operations		—		—		13,810		13,810		—			13,810
Non-cash investing activities		61,042		—		—		61,042		—			61,042

F-231

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(CONTINUED)

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):

	Years Ended December 31,
	2005			2004			2003
				(as restated)			(as restated)
Earnings before interest	$	244,412		$	210,601		$	206,030
Interest expense—net		(81,861	)		(72,053	)		(84,250	)
Net income	$	162,551		$	138,548		$	121,780

NOTE 18. COMPREHENSIVE INCOME

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):

Balance at December 31, 2002 (as restated)	$	(20,055	)
Reclassification due to discontinued portion of cash flow hedge		989
Transferred to earnings		14,417
Change in fair value of cash flow hedge		1,747
Balance at December 31, 2003 (as restated)	$	(2,902	)
Transferred to earnings		2,939
Change in fair value of cash flow hedge		(37	)
Balance at December 31, 2004 (as restated)	$	—
Changes in fair values of crude oil cash flow hedges		11
Balance at December 31, 2005	$	11

NOTE 19. SUPPLEMENTAL CONDENSED CONSOLIDATING FINANCIAL INFORMATION

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.”

F-232

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(CONTINUED)

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.

	December 31, 2005
	TEPPCO Partners, L.P.		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Consolidating Adjustments			TEPPCO Partners, L.P. Consolidated
	(in thousands)
Assets
Current assets	$	40,977	$	107,692	$	789,486	$	(39,026	)	$	899,129
Property, plant and equipment—net		—		1,335,724		624,344		—			1,960,068
Equity investments		1,201,388		461,741		202,343		(1,505,816	)		359,656
Intercompany notes receivable		1,134,093		—		—		(1,134,093	)		—
Intangible assets		—		345,005		31,903		—			376,908
Other assets		5,532		22,170		57,075		—			84,777
Total assets	$	2,381,990	$	2,272,332	$	1,705,151	$	(2,678,935	)	$	3,680,538
Liabilities and partners’ capital
Current liabilities	$	43,236	$	140,743	$	793,683	$	(40,451	)	$	937,211
Long-term debt		1,135,973		389,048		—		—			1,525,021
Intercompany notes payable		—		635,263		498,832		(1,134,095	)		—
Other long term liabilities		1,422		14,564		950		—			16,936
Total partners’ capital		1,201,359		1,092,714		411,686		(1,504,389	)		1,201,370
Total liabilities and partners’ capital	$	2,381,990	$	2,272,332	$	1,705,151	$	(2,678,935	)	$	3,680,538
	December 31, 2004 (as restated)
	TEPPCO Partners, L.P.		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Consolidating Adjustments			TEPPCO Partners, L.P. Consolidated
	(in thousands)
Assets
Current assets	$	44,125	$	85,992	$	576,365	$	(62,928	)	$	643,554
Property, plant and equipment—net		—		1,211,312		492,390		—			1,703,702
Equity investments		1,011,131		420,343		202,326		(1,270,493	)		363,307
Intercompany notes receivable		1,084,034		—		—		(1,084,034	)		—
Intangible assets		—		372,621		34,737		—			407,358
Other assets		5,980		22,183		40,200		—			68,363
Total assets	$	2,145,270	$	2,112,451	$	1,346,018	$	(2,417,455	)	$	3,186,284
Liabilities and partners’ capital
Current liabilities	$	45,255	$	142,513	$	556,474	$	(62,930	)	$	681,312
Long-term debt		1,086,909		393,317		—		—			1,480,226
Intercompany notes payable		—		676,993		407,040		(1,084,033	)		—
Other long term liabilities		2,003		9,980		1,660		—			13,643
Total partners’ capital		1,011,103		889,648		380,844		(1,270,492	)		1,011,103
Total liabilities and partners’ capital	$	2,145,270	$	2,112,451	$	1,346,018	$	(2,417,455	)	$	3,186,284

F-233

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(CONTINUED)

	Year Ended December 31, 2005
	TEPPCO Partners, L.P.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			TEPPCO Partners, L.P. Consolidated
	(in thousands)
Operating revenues	$	—	$	439,944		$	8,168,657		$	(3,567	)	$	8,605,034
Costs and expenses		—		285,072			8,104,164			(3,567	)		8,385,669
Gains on sales of assets		—		(551	)		(117	)		—			(668	)
Operating income		—		155,423			64,610			—			220,033
Interest expense—net		—		(54,011	)		(27,850	)		—			(81,861	)
Equity earnings		162,551		57,088			23,078			(222,623	)		20,094
Other income—net		—		901			234			—			1,135
Income from continuing operations		162,551		159,401			60,072			(222,623	)		159,401
Discontinued operations		—		3,150			—			—			3,150
Net income	$	162,551	$	162,551		$	60,072		$	(222,623	)	$	162,551
	Year Ended December 31, 2004 (as restated)
	TEPPCO Partners, L.P.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			TEPPCO Partners, L.P. Consolidated
	(in thousands)
Operating revenues	$	—	$	420,060		$	5,531,237		$	(3,207	)	$	5,948,090
Costs and expenses		—		294,155			5,473,751			(3,207	)		5,764,699
Gains on sales of assets		—		(526	)		(527	)		—			(1,053	)
Operating income		—		126,431			58,013			—			184,444
Interest expense—net		—		(48,902	)		(23,151	)		—			(72,053	)
Equity earnings		138,548		57,454			28,692			(202,546	)		22,148
Other income—net		—		876			444			—			1,320
Income from continuing operations		138,548		135,859			63,998			(202,546	)		135,859
Discontinued operations		—		2,689			—			—			2,689
Net income	$	138,548	$	138,548		$	63,998		$	(202,546	)	$	138,548
	Year Ended December 31, 2003 (as restated)
	TEPPCO Partners, L.P.		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			TEPPCO Partners, L.P. Consolidated
	(in thousands)
Operating revenues	$	—	$	399,504		$	3,858,243		$	(1,915	)	$	4,255,832
Costs and expenses		—		262,971			3,806,316			(1,915	)		4,067,372
Gain on sale of assets		—		—			(3,948	)		—			(3,948	)
Operating income		—		136,533			55,875			—			192,408
Interest expense—net		—		(52,903	)		(31,420	)		73			(84,250	)
Equity earnings		121,780		37,689			20,258			(166,853	)		12,874
Other income—net		—		461			360			(73	)		748
Net income	$	121,780	$	121,780		$	45,073		$	(166,853	)	$	121,780

F-234

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(CONTINUED)

	Year Ended December 31, 2005
	TEPPCO Partners, L.P.			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			TEPPCO Partners, L.P. Consolidated
	(in thousands)
Cash flows from continuing operating activities
Net income	$	162,551		$	162,551		$	60,072		$	(222,623	)	$	162,551
Adjustments to reconcile net income to net cash provided by continuing operating activities:
Income from discontinued operations		—			(3,150	)		—			—			(3,150	)
Depreciation and amortization		—			82,536			28,193			—			110,729
Earnings in equity investments, net of distributions		88,550			14,598			1,576			(87,733	)		16,991
Gains on sales of assets		—			(551	)		(117	)		—			(668	)
Changes in assets and liabilities and other		(54,540	)		(57,645	)		22,884			53,571			(35,730	)
Net cash provided by continuing operating activities		196,561			198,339			112,608			(256,785	)		250,723
Cash flows from discontinued operations		—			3,782			—			—			3,782
Net cash provided by operating activities		196,561			202,121			112,608			(256,785	)		254,505
Cash flows from investing activities		(278,806	)		(31,529	)		(180,486	)		139,906			(350,915	)
Cash flows from financing activities		80,107			(184,126	)		65,097			119,029			80,107
Net increase in cash and cash equivalents		(2,138	)		(13,534	)		(2,781	)		2,150			(16,303	)
Cash and cash equivalents at beginning of period		4,116			13,596			2,826			(4,116	)		16,422
Cash and cash equivalents at end of period	$	1,978		$	62		$	45		$	(1,966	)	$	119

F-235

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(CONTINUED)

	Year Ended December 31, 2004 (as restated)
	TEPPCO Partners, L.P.			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			TEPPCO Partners, L.P. Consolidated
	(in thousands)
Cash flows from continuing operating activities
Net income	$	138,548		$	138,548		$	63,998		$	(202,546	)	$	138,548
Adjustments to reconcile net income to net cash provided by continuing operating activities:
Income from discontinued operations		—			(2,689	)		—			—			(2,689	)
Depreciation and amortization		—			89,438			22,846			—			112,284
Earnings in equity investments, net of distributions		94,509			(130	)		8,208			(77,522	)		25,065
Gains on sales of assets		—			(526	)		(527	)		—			(1,053	)
Changes in assets and liabilities and other		(158,726	)		29,707			(30,930	)		151,690			(8,259	)
Net cash provided by continuing operating activities		74,331			254,348			63,595			(128,378	)		263,896
Cash flows from discontinued operations		—			3,271			—			—			3,271
Net cash provided by operating activities		74,331			257,619			63,595			(128,378	)		267,167
Cash flows from continuing investing activities		98			(26,662	)		(40,864	)		(115,331	)		(182,759	)
Cash flows from discontinued investing activities		—			(7,398	)		—			—			(7,398	)
Cash flows from investing activities		98			(34,060	)		(40,864	)		(115,331	)		(190,157	)
Cash flows from financing activities		(90,057	)		(229,206	)		(25,575	)		254,781			(90,057	)
Net decrease in cash and cash equivalents		(15,628	)		(5,647	)		(2,844	)		11,072			(13,047	)
Cash and cash equivalents at beginning of period		19,744			19,243			5,670			(15,188	)		29,469
Cash and cash equivalents at end of period	$	4,116		$	13,596		$	2,826		$	(4,116	)	$	16,422

F-236

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(CONTINUED)

	Year Ended December 31, 2003 (as restated)
	TEPPCO Partners, L.P.			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			TEPPCO Partners, L.P. Consolidated
	(in thousands)
Cash flows from operating activities
Net income	$	121,780		$	121,780		$	45,073		$	(166,853	)	$	121,780
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		—			80,114			20,614			—			100,728
Earnings in equity investments, net of distributions		80,718			7,548			2,482			(75,619	)		15,129
Gain on sale of assets		—			—			(3,948	)		—			(3,948	)
Changes in assets and liabilities and other		48,432			5,576			1,075			(46,348	)		8,735
Net cash provided by operating activities		250,930			215,018			65,296			(288,820	)		242,424
Cash flows from continuing investing activities		(175,568	)		(164,872	)		(37,589	)		203,531			(174,498	)
Cash flows from investing activities		—			(13,810	)		—			—			(13,810	)
Cash flows from discontinued investing activities		(175,568	)		(178,682	)		(37,589	)		203,531			(188,308	)
Cash flows from financing activities		(55,618	)		(25,340	)		(44,758	)		70,101			(55,615	)
Net increase (decrease) in cash and cash equivalents		19,744			10,996			(17,051	)		(15,188	)		(1,499	)
Cash and cash equivalents at beginning of period		—			8,247			22,721			—			30,968
Cash and cash equivalents at end of period	$	19,744		$	19,243		$	5,670		$	(15,188	)	$	29,469

NOTE 20. RESTATEMENT OF CONSOLIDATED FINANCIAL STATEMENTS

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

F-237

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(CONTINUED)

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):

Balance Sheet Amounts;

	December 31, 2004
	As Previously Reported			Adjustment			As Restated
Equity investments	$	373,652		$	(10,345	)	$	363,307
Total assets	$	3,196,629		$	(10,345	)	$	3,186,284
Capital:
General partner’s interest	$	(33,006	)	$	(2,875	)	$	(35,881	)
Limited partners’ interest		1,054,454			(7,470	)		1,046,984
Total partners’ capital		1,021,448			(10,345	)		1,011,103
Total liabilities and partners’ capital	$	3,196,629		$	(10,345	)	$	3,186,284

F-238

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(CONTINUED)

Income Statement Amounts:

	Years Ended December 31,
	2004			2003
Equity earnings as previously reported	$	25,981		$	16,863
Adjustment for amortization of excess investments		(3,833	)		(3,989	)
Equity earnings as restated	$	22,148		$	12,874
Net income as previously reported	$	142,381		$	125,769
Adjustment for amortization of excess investments		(3,833	)		(3,989	)
Net income as restated	$	138,548		$	121,780
Net Income Allocation as previously reported:
Limited Partner Unitholders	$	101,307		$	89,191
Class B Unitholder		—			1,806
General Partner		41,074			34,772
Total net income allocated	$	142,381		$	125,769
Basic and diluted net income per Limited Partner and Class B Unit as previously reported	$	1.61		$	1.52
Net Income Allocation as restated:
Limited Partner Unitholders	$	98,580		$	86,357
Class B Unitholder		—			1,754
General Partner		39,968			33,669
Total net income allocated as restated	$	138,548		$	121,780
Basic and diluted net income per Limited Partner and Class B Unit as restated	$	1.56		$	1.47

Cash Flow Amounts;

	Year Ended December 31, 2004
	As Previously Reported		Adjustment			As Restated
Cash flows from operating activities:
Net income	$	142,381	$	(3,833	)	$	138,548
Earnings in equity investments, net of distributions		21,232		3,833			25,065

	Year Ended December 31, 2003
	As Previously Reported		Adjustment			As Restated
Cash flows from operating activities:
Net income	$	125,769	$	(3,989	)	$	121,780
Earnings in equity investments, net of distributions		11,140		3,989			15,129

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TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(CONTINUED)

Partners’ Capital Amounts:

	Outstanding Limited Partner Units	General Partner’s Interest			Limited Partners’ Interests			Accumulated Other Comprehensive Loss			Total
2002:
Partners’ capital at December 31, 2002 as previously reported	53,809,597	$	12,770		$	899,127		$	(20,055	)	$	891,842
Restatement adjustment	—		(666	)		(1,727	)		—			(2,393	)
Partners’ capital at December 31, 2002 as restated (unaudited)	53,809,597	$	12,104		$	897,400		$	(20,055	)	$	889,449
2003:
Partners’ capital at December 31, 2003 as previously reported	62,998,554	$	(7,181	)	$	1,119,404		$	(2,902	)	$	1,109,321
Restatement adjustment	—		(1,769	)		(4,743	)		—			(6,512	)
Partners’ capital at December 31, 2003 as restated	62,998,554	$	(8,950	)	$	1,114,661		$	(2,902	)	$	1,102,809
2004:
Partners’ capital at December 31, 2004 as previously reported	62,998,554	$	(33,006	)	$	1,054,454		$	—		$	1,021,448
Restatement adjustment	—		(2,875	)		(7,470	)		—			(10,345	)
Partners’ capital at December 31, 2004 as restated	62,998,554	$	(35,881	)	$	1,046,984		$	—		$	1,011,103

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TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(CONTINUED)

NOTE 21. QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
	(as restated)			(as restated)			(as restated)			(as restated)
	(in thousands, except per Unit amounts)
2005:(1)
Operating revenues	$	1,523,791		$	2,087,385		$	2,500,127		$	2,493,731
Operating income		61,232			53,817			43,378			61,606
Income from continuing operations:
As previously reported	$	47,457		$	41,387		$	30,231		$	44,137
Restatement adjustment		(1,152	)		(1,311	)		(1,348	)		—
As restated	$	46,305		$	40,076		$	28,883		$	44,137
Income from discontinued operations	$	1,124		$	846		$	692		$	488
Net income:
As previously reported	$	48,581		$	42,233		$	30,923		$	44,625
Restatement adjustment		(1,152	)		(1,311	)		(1,348	)		—
As restated	$	47,429		$	40,922		$	29,575		$	44,625
Basic and diluted net income per Limited Partner Unit from continuing operations:(2)(3)
As previously reported	$	0.54		$	0.44		$	0.30		$	0.45
Restatement adjustment		(0.01	)		(0.02	)		(0.01	)		—
As restated	$	0.53		$	0.42		$	0.29		$	0.45
Basic and diluted net income per Limited Partner Unit from discontinued operations(3)	$	0.01		$	0.01		$	0.01		$	—
Basic and diluted net income per Limited Partner Unit:(2)(3)
As previously reported	$	0.55		$	0.45		$	0.31		$	0.45
Restatement adjustment		(0.01	)		(0.02	)		(0.01	)		—
As restated	$	0.54		$	0.43		$	0.30		$	0.45

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TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(CONTINUED)

	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
	(as restated)			(as restated)			(as restated)			(as restated)
	(in thousands, except per Unit amounts)
2004:(1)
Operating revenues	$	1,315,942		$	1,352,107		$	1,487,556		$	1,792,485
Operating income		53,457			41,990			36,361			52,636
Income from continuing operations:
As previously reported	$	39,989		$	37,348		$	25,135		$	37,220
Restatement adjustment		(713	)		(1,129	)		(1,085	)		(906	)
As restated	$	39,276		$	36,219		$	24,050		$	36,314
Income from discontinued operations	$	444		$	411		$	720		$	1,114
Net income:
As previously reported	$	40,433		$	37,759		$	25,855		$	38,334
Restatement adjustment		(713	)		(1,129	)		(1,085	)		(906	)
As restated	$	39,720		$	36,630		$	24,770		$	37,428
Basic and diluted net income per Limited Partner Unit from continuing operations:
As previously reported	$	0.45		$	0.43		$	0.28		$	0.42
Restatement adjustment		(0.01	)		(0.02	)		(0.01	)		(0.01	)
As restated	$	0.44		$	0.41		$	0.27		$	0.41
Basic and diluted net income per Limited Partner Unit from discontinued operations	$	0.01		$	—		$	0.01		$	0.01
Basic and diluted net income per Limited Partner Unit:
As previously reported	$	0.46		$	0.43		$	0.29		$	0.43
Restatement adjustment		(0.01	)		(0.02	)		(0.01	)		(0.01	)
As restated	$	0.45		$	0.41		$	0.28		$	0.42

(1) The quarterly financial information for 2004 and the first three quarters of 2005 reflect the impact of the restatement.

(2) The sum of the four quarters does not equal the total year due to rounding.

(3) Per Unit calculation includes 6,965,000 Units issued in May and June 2005.

F-242

TEPPCO PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(CONTINUED)

NOTE 22. SUBSEQUENT EVENTS

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.

F-243