Duke Energy (DUK) 8-K Gains on sales of investments in commercial and multi-family real estate

PART II

Exhibit 99.1

Item 6. Selected Financial Data.^(a)

	2006		2005			2004			2003(c)			2002
	(in millions, except per-share amounts)
Statement of Operations
Operating revenues	$	10,678	$	6,906		$	6,357		$	6,006		$	6,507
Operating expenses		9,314		5,586			5,074			6,550			5,250
Gains on sales of investments in commercial and multi-family real estate		201		191			192			84			106
Gains (losses) on sales of other assets and other, net		229		(55	)		(435	)		(202	)		32
Operating income (loss)		1,794		1,456			1,040			(662	)		1,395
Other income and expenses, net		356		217			180			326			126
Interest expense		633		381			425			431			402
Minority interest expense (benefit)		13		24			(15	)		(79	)		(4	)
Earnings (loss) from continuing operations before income taxes		1,504		1,268			810			(688	)		1,123
Income tax expense (benefit) from continuing operations		421		375			192			(288	)		390
Income (loss) from continuing operations		1,083		893			618			(400	)		733
Income (loss) from discontinued operations, net of tax		780		935			872			(761	)		301
Income (loss) before cumulative effect of change in accounting principle		1,863		1,828			1,490			(1,161	)		1,034
Cumulative effect of change in accounting principle, net of tax and minority interest		—		(4	)		—			(162	)		—
Net income (loss)		1,863		1,824			1,490			(1,323	)		1,034
Dividends and premiums on redemption of preferred and preference stock		—		12			9			15			13
Earnings (loss) available for common stockholders	$	1,863	$	1,812		$	1,481		$	(1,338	)	$	1,021
Ratio of Earnings to Fixed Charges		2.6		2.4			1.6			—	(b)		1.7
Common Stock Data
Shares of common stock outstanding(d)
Year-end		1,257		928			957			911			895
Weighted average—basic		1,170		934			931			903			836
Weighted average—diluted		1,188		970			966			904			838
Earnings (loss) per share (from continuing operations)
Basic	$	0.93	$	0.94		$	0.65		$	(0.44	)	$	0.87
Diluted		0.91		0.92			0.64			(0.46	)		0.87
Earnings (loss) per share (from discontinued operations)
Basic	$	0.66	$	1.00		$	0.94		$	(0.86	)	$	0.35
Diluted		0.66		0.96			0.90			(0.84	)		0.35
Earnings (loss) per share (before cumulative effect of change in accounting principle)
Basic	$	1.59	$	1.94		$	1.59		$	(1.30	)	$	1.22
Diluted		1.57		1.88			1.54			(1.30	)		1.22
Earnings (loss) per share
Basic	$	1.59	$	1.94		$	1.59		$	(1.48	)	$	1.22
Diluted		1.57		1.88			1.54			(1.48	)		1.22
Dividends per share		1.26		1.17			1.10			1.10			1.10
Balance Sheet
Total assets	$	68,700	$	54,723		$	55,770		$	57,485		$	60,122
Long-term debt including capital leases, less current maturities	$	18,118	$	14,547		$	16,932		$	20,622		$	20,221

(a) Significant transactions reflected in the results above include: 2007 spin-off of the natural gas businesses (see Note 1 to the Consolidated Financial Statements, “Summary of Significant Accounting Policies”), 2006 merger with Cinergy (see Note 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions”), 2006 Crescent joint venture transaction and subsequent deconsolidation effective September 7, 2006 (see Note 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions”), 2005 DENA disposition (see Note 13 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale”), 2005 deconsolidation of DEFS effective July 1, 2005 (see Note 13 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale”), 2005 DEFS sale of TEPPCO (see Note 13 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale”) and 2004 DENA sale of the Southeast plants (see Note 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions”).

(b) Earnings were inadequate to cover fixed charges by $924 million for the year ended December 31, 2003.

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(c) As of January 1, 2003, Duke Energy 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 Energy 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.)

(d) 2006 increase primarily attributable to issuance of approximately 313 million shares in connection with Duke Energy’s merger with Cinergy (see Note 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions”).

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

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

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

• State, federal and foreign legislative and regulatory initiatives, including costs of compliance with existing and future environmental requirements;

• State, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery or have an impact on rate structures;

• Costs and effects of legal and administrative proceedings, settlements, investigations and claims;

• Industrial, commercial and residential growth in Duke Energy Corporation’s (Duke Energy) service territories;

• Additional competition in electric markets and continued industry consolidation;

• Political and regulatory uncertainty in other countries in which Duke Energy conducts business;

• The influence of weather and other natural phenomena on Duke Energy operations, including the economic, operational and other effects of hurricanes, ice storms and tornados;

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

• Unscheduled generation outages, unusual maintenance or repairs and electric transmission system constraints;

• The results of financing efforts, including Duke Energy’s ability to obtain financing on favorable terms, which can be affected by various factors, including Duke Energy’s credit ratings and general economic conditions;

• Declines in the market prices of equity securities and resultant cash funding requirements for Duke Energy’s defined benefit pension plans;

• The level of credit worthiness of counterparties to Duke Energy’s transactions;

• Employee workforce factors, including the potential inability to attract and retain key personnel;

• Growth in opportunities for Duke Energy’s business units, including the timing and success of efforts to develop domestic and international power and other projects;

• The performance of electric generation and of projects undertaken by Duke Energy’s non-regulated businesses;

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

• The ability to successfully complete merger, acquisition or divestiture plans.

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

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INTRODUCTION

Management’s Discussion and Analysis should be read in conjunction with the Consolidated Financial Statements and Notes for the years ended December 31, 2006, 2005 and 2004.

On January 2, 2007, Duke Energy completed the spin-off of its natural gas business to shareholders, as discussed below. Accordingly, the results of operations of Duke Energy’s Natural Gas Transmission business segment and Duke Energy’s 50% ownership interest in DEFS have been reclassified to discontinued operations for all periods presented. Additionally, in February 2007, International Energy completed the disposition of its assets in Bolivia. The results of operations related to Bolivia have been reflected as a component of discontinued operations for all periods presented.

EXECUTIVE OVERVIEW

2006 Objectives. Duke Energy’s objectives for 2006, as outlined in the 2006 Charter, consisted of the following:

• Establish an industry-leading electric power platform through successful execution of the merger with Cinergy Corp. (Cinergy);

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

• Complete the exit of the former Duke Energy North America (DENA) business 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.

During 2006, management executed on its objectives primarily through strategically completed and pending acquisitions, as well as dispositions of certain businesses with higher risk profiles, such as the former DENA operations outside the Midwest and the Cinergy commercial marketing and trading businesses. During 2006, Duke Energy created a business model that would give both Duke Energy’s electric and gas businesses stand-alone strength and additional scope and scale along with steady and stable earnings growth.

On April 3, 2006, Duke Energy and Cinergy consummated the previously announced merger, which combined the Duke Energy and Cinergy regulated franchises as well as deregulated generation in the Midwestern United States. The merger with Cinergy increased the size and scope of Duke Energy’s electric utility operations. Duke Energy management expects to achieve numerous synergies, both immediately and over time, in all regions impacted by the merger.

As a result of the additional size and scope of the electric utility operations discussed above, 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, which was completed on January 2, 2007. The new natural gas company, Spectra Energy, consists of Duke Energy’s Natural Gas Transmission business segment, including Union Gas Limited (Union Gas), as well as Duke Energy’s 50-percent ownership interest in DEFS. The spin off of the natural gas business is expected to deliver long-term value to shareholders as the two stand-alone companies are expected to be able to more easily participate in growth opportunities in their own industries as well as the gas and power industry consolidations. Duke Energy’s results for periods prior to the spin off have been retrospectively adjusted to reflect the operations transferred as Spectra Energy as discontinued operations.

In connection with the effort to reduce the risk profile of Duke Energy and to focus on businesses that can be expected to contribute steady, stable earnings growth, during 2006 Duke Energy finalized the sale of the former DENA power generation fleet outside of the Midwest to LS Power and the sale of the Cinergy commercial marketing and trading business to Fortis, a Benelux-based financial services group (Fortis).

Additionally, the Board of Directors of Duke Energy authorized management to explore the potential value of bringing in a joint venture partner at Crescent Resources, LLC to expand the business and create a platform for increased growth. On September 7, 2006, an indirect wholly owned subsidiary of Duke Energy 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). As a result of the Crescent JV transaction, Duke Energy no longer controls the Crescent JV and on September 7, 2006 deconsolidated its investment in Crescent and subsequently accounts for its investment in the Crescent JV utilizing the equity method of accounting.

After completion of the spin-off of the natural gas businesses, the primary businesses remaining in Duke Energy in 2007 are the U.S. Franchised Electric and Gas business segment, the Commercial Power business segment, the International Energy business segment and Duke Energy’s effective 50% interest in the Crescent JV (Crescent), which management currently expects to continue to be a reportable business segment.

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Duke Energy announced an agreement with Southern Company to evaluate the potential construction of a new nuclear power plant at a site jointly owned in Cherokee County, South Carolina. In May 2007, Duke Energy announced its intent to purchase Southern Company’s 500-megawatt interest in the proposed William States Lee III nuclear power project, making the plant’s total output available to electric customers in the Carolinas. Additionally, Duke Energy continues to evaluate other opportunities to re-invest in the electric utility operations, by modernizing older coal-fired plants in the Carolinas and exploring the replacement of an aging coal plant in Indiana with a coal gasification plant. Also, during the fourth quarter of 2006, Duke Energy closed on a transaction to acquire from Dynegy a 825 megawatt power plant located in Rockingham County, North Carolina. This peaking plant, which will primarily be used during times of high electricity demand, generally in the winter and summer months, will provide customers with competitively priced peaking capacity and helps to ensure Duke Energy can meet growing customer demands for electricity in the foreseeable future. Additionally, in December 2006 Duke Energy entered into an agreement to increase its ownership interest in the Catawba Nuclear Station for a purchase price of approximately $158 million. The purchase is subject to regulatory approvals and other conditions precedent and is expected to close prior to September 30, 2008.

Effective with the third quarter 2006, the Board of Directors of Duke Energy approved a quarterly dividend increase of $0.01 per share, increasing the annual dividend to $1.28 per share. Additionally, during 2006 Duke Energy repurchased approximately 17.5 million shares of its common stock for approximately $500 million. In connection with the above mentioned plan to spin off Duke Energy’s natural gas businesses to Duke Energy shareholders, the share repurchase program was suspended. In October 2006, Duke Energy’s Board of Directors authorized the reactivation of the share repurchase plan for Duke Energy of up to $500 million of share repurchases subsequent to the spin-off of the natural gas businesses on January 2, 2007.

2006 Financial Results. For the year-ended December 31, 2006, Duke Energy reported earnings available for common stockholders of $1,863 million and basic and diluted earnings per share (EPS) of $1.59 and $1.57, respectively, as compared to reported earnings available for common stockholders of $1,812 million and basic and diluted EPS of $1.94 and $1.88, respectively, for the year-ended December 31, 2005. Earnings available for common stockholders for 2006 as compared to 2005 were fairly flat; however, basic and diluted EPS were negatively impacted by the issuance of approximately 313 million shares in April 2006 in connection with the Cinergy merger. The highlights for 2006 include the following:

• U.S. Franchised Electric and Gas experienced higher earnings in 2006 primarily as a result of the addition of the former Cinergy regulated utility operations in the Midwest. These higher results were partially offset by milder weather, the impact of rate reductions related to Cinergy merger approvals, and lower bulk power marketing results in the Carolinas.

• Commercial Power experienced higher earnings in 2006 primarily as a result of the addition of the former Cinergy non-regulated generation operations in the Midwest, partially offset by the impacts of unfavorable purchase accounting charges as a result of recognizing the Cinergy assets and liabilities at their estimated fair values as of the date of merger.

• International Energy experienced lower earnings in 2006 primarily as a result of 2006 non-cash charges related to a settlement related to the Citrus litigation and an impairment charge related to the investment in Compania de Servicios de Compression de Campeche, S.A. (Campeche).

• Crescent experienced higher earnings in 2006 primarily as a result of the gain recognized on the joint venture transaction in September 2006, which resulted in the deconsolidation of Duke Energy’s investment in the Crescent JV.

• Other experienced higher losses in 2006 primarily as a result of 2006 charges related to contract settlement negotiations and costs to achieve the Cinergy merger.

• Income tax expense from continuing operations was higher in 2006 as a result of an increase in earnings from continuing operations before income taxes, partially offset by a reduction in the effective tax rate. The reduction in the effective tax rate was primarily a result of favorable tax settlements on research and development costs and nuclear decommissioning costs, tax benefits related to the impairment of the investment in Bolivia, and tax credits recognized on synthetic fuel operations.

• During 2006, Duke Energy recognized net of tax income of $780 million in discontinued operations, as compared to net of tax income of $935 million in 2005. As a result of the spin-off of the natural gas businesses to shareholders, income from discontinued operations includes approximately $953 million and $1,623 million related to the natural gas businesses for 2006 and 2005, respectively. The decrease in income for the natural gas businesses in 2006 compared to 2005 primarily relates to the 2005 gains on the sale of the TEPPCO investments and the transfer of a 19.7 percent interest in DEFS to ConocoPhillips in July 2005. Partially offsetting the income related to the natural gas businesses was the recognition of additional losses as a result of sales of certain contracts at former DENA. During 2006, Duke Energy completed the exit of the former DENA operations outside the Midwest region. Additionally, during 2006, Duke Energy exited the Cinergy commercial marketing and trading business.

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2007 Objectives.As a result of the initiatives accomplished during 2006 and the spin-off of the natural gas businesses on January 2, 2007, Duke Energy is positioned as a lower-risk business with steady earnings growth potential. For 2007, management of Duke Energy is focused on the following objectives, as outlined in the 2007 Charter:

• Establish the identity and culture of the new Duke Energy, unifying its people, values, strategy, processes and systems;

• Optimize its operations by focusing on safety, simplicity, accountability, inclusion, customer satisfaction, cost management and employee development;

• Achieve public policy, regulatory and legislative outcomes that balance customers’ needs for reliable energy at competitive prices with shareholders’ expectation of superior returns;

• Invest in energy infrastructure that meets rising customer demands for reliable energy in an energy efficient and environmentally sound manner; and

• Achieve 2007 financial objectives and position Duke Energy to meet future growth targets.

Duke Energy’s consolidated earnings during 2007 are anticipated to be reduced principally as a result of the spin-off of the natural gas businesses on January 2, 2007. Excluding the impacts of the spin-off of the natural gas businesses, earnings are anticipated to be favorably affected by the following factors: a full year of earnings from the Midwest operations acquired from Cinergy, realization of cost savings as the regulatory rate reductions shared with ratepayers will phase-out in 2007, customer sales growth, capital reinvestments and regulatory initiatives.

The majority of expected earnings in 2007 are anticipated to be contributed from U.S. Franchised Electric and Gas, which consists of Duke Energy’s regulated businesses operating a net capacity of approximately 28,000 megawatts of generation. The regulated generation portfolio consists of a mix of coal, nuclear, natural gas and hydroelectric generation, with substantially all of the sales of electricity coming from coal and nuclear generation facilities. Commercial Power has net capacity of approximately 8,100 megawatts of unregulated generation, of which approximately 4,100 megawatts serves retail customers under the Rate Stabilization Plan (RSP) in Ohio. Approximately 75% of International Energy’s net capacity of approximately 4,000 megawatts of installed generation capacity in Latin America consists of baseload hydroelectric capacity that carries a low level of dispatch risk; in addition, for 2007 over 90% of International Energy’s contractible capacity in Latin America is either currently contracted or receives a system capacity payment.

Duke Energy’s total dividends and dividends per share in 2007 will be lower than in 2006 as a result of the spin-off of the natural gas businesses on January 2, 2007. Future dividends are expected to grow in connection with any earnings growth.

During the three-year period from 2007 to 2009, Duke Energy anticipates total capital expenditures of approximately $14 billion, consisting of annual capital expenditures of approximately $4 billion in 2007 and approximately $5 billion in both 2008 and 2009. These expenditures are principally related to expansion plans, environmental spending related to Clean Air requirements, nuclear fuel, as well as maintenance costs. Current estimates are that Duke Energy’s regulated generation capacity will need to increase by approximately 6,400 megawatts over the next ten years, with the majority being in North and South Carolina and the remainder being in Indiana. Duke Energy is committed to adding base load capacity at a reasonable price while modernizing the current generation facilities by replacing older, less efficient plants with cleaner, more efficient plants. Significant expansion projects may include a new integrated gasification combined cycle (IGCC) plant in Indiana, a new coal unit at Duke Energy’s existing Cliffside facility in North Carolina, new gas-fired generation units and costs related to the evaluation of the potential construction of a new nuclear power plant in Cherokee County, South Carolina as well as normal additions due to system growth. Costs related to environmental spending are expected to decrease over the three-year period as the upgrades to comply with the new environmental regulations are completed. Duke Energy does not anticipate any additional capital investment related to its investment in the Crescent JV. Duke Energy does not currently anticipate funding 2007 capital expenditures with the issuance of common equity, but rather through the use of available cash and cash equivalents as well as the issuance of incremental debt.

As the majority of Duke Energy’s anticipated future capital expenditures are related to its regulated operations, a significant risk to Duke Energy is the ability to recover in a timely manner costs related to such expansion. In Indiana, Duke Energy has been given approval to recover its development costs for the new IGCC plant. In North and South Carolina, Duke Energy will pursue legislation to provide for construction work in progress recovery for the additional unit at the Cliffside facility as well as the proposed nuclear power plant. Additionally, Duke Energy is attempting to obtain assurance of recovery of development costs related to the proposed nuclear power plant. Duke Energy does not anticipate beginning construction of the proposed nuclear power plant without adequate assurance of cost recovery from the state legislators or regulators. In November 2006, Duke Energy received approval for nearly $260 million of future federal tax credits related to costs to be incurred for the modernization of the Cliffside facility as well as the IGCC plant in Indiana.

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In an effort to respond to concerns over climate change, the U.S. Congress recently discussed various proposals to reduce or cap carbon dioxide and other greenhouse gas emissions. Any legislation enacted as a result of these efforts could involve a market based cap and trade program. Duke Energy is also focusing on energy efficiency initiatives in an effort to reduce emissions.

Duke Energy’s current regulatory initiatives primarily include obtaining the timely recovery of invested capital and pursuing a regulatory extension of the RSP in Ohio through 2010 as well as being a proponent of cost-effective energy efficiency initiatives. In June 2007, Duke Energy filed an application with the North Carolina Utilities Commission (NCUC) seeking authority to increase its rates and charges for electric service in North Carolina effective January 1, 2008 (see Note 4, “Regulatory Matters,” to the Consolidated Financial Statements). During 2006, Duke Energy filed for an increase in its base electric rates in Kentucky. In December 2006, the Kentucky Public Service Commission approved an annual rate increase of $49 million to be effective January 1, 2007.

New energy legislation has been introduced in the current South Carolina legislative session which includes expansion of the annual fuel clause mechanism to include recovery of costs of reagents (ammonia, limestone, etc.) that are consumed in the operation of Duke Energy Carolinas, LLC’s (Duke Energy Carolinas) SO₂ and NOx control technologies. The legislation also includes provisions to provide cost recovery assurance for upfront development costs associated with nuclear baseload generation, cost recovery assurance for construction costs associated with nuclear or coal baseload generation, and the ability to recover financing costs for new nuclear or coal baseload generation through annual riders. Similar legislation is being discussed in North Carolina and may be introduced in the 2007 legislative session.

In summary, Duke Energy is coordinating its future capital expenditure requirements with regulatory initiatives in order to ensure adequate and timely cost recovery while continuing to provide low cost energy to its customers.

Economic Factors for Duke Energy’s Business. Duke Energy’s business model provides diversification between stable, less cyclical businesses like U.S. Franchised Electric and Gas, and the traditionally higher-growth and more cyclical energy businesses like Commercial Power and International Energy. Additionally, Crescent’s portfolio strategy is diversified between residential, commercial and multi-family development. All of Duke Energy’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 Energy’s control, and could impair Duke Energy’s ability to meet its goals for 2007 and beyond.

Declines in demand for electricity as a result of economic downturns would reduce overall electricity sales and lessen Duke Energy’s cash flows, especially as industrial customers reduce production and, thus, consumption of electricity. A portion of U.S. Franchised Electric and Gas’ business risk is mitigated by its regulated allowable rates of return and recovery of fuel costs under fuel adjustment clauses.

If negative market conditions should persist over time and estimated cash flows over the lives of Duke Energy’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 Energy’s 2007 goals can also be substantially at risk due to the regulation of its businesses. Duke Energy’s businesses in the United States are subject to regulations on the federal and state level. Regulations, applicable to the electric power 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 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.

Duke Energy’s earnings are impacted by fluctuations in commodity prices. Exposure to commodity prices generates higher earnings volatility in the unregulated businesses as there are timing differences as to when such costs are recovered in rates. To mitigate these risks, Duke Energy enters into derivative instruments to effectively hedge known exposures. With the 2006 sales of former DENA’s assets outside the Midwestern United States, including substantially all the derivative portfolio, and Cinergy’s marketing and trading operation, Duke Energy expects a less volatile earnings pattern going forward.

Additionally, Duke Energy’s investments and projects located outside of the United States expose Duke Energy 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 Energy’s future results.

Duke Energy 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 Energy’s ability to implement its strategy. Market disruptions or a downgrade of Duke Energy’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 Energy’s risk factors, see Item 1A. “Risk Factors.”

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PART II

RESULTS OF OPERATIONS

Consolidated Operating Revenues

Year Ended December 31, 2006 as Compared to December 31, 2005. Consolidated operating revenues for 2006 increased $3,772 million, compared to 2005. This change was driven by:

• An approximate $3,891 million increase due to the merger with Cinergy, and

• A $216 million increase at International Energy due primarily to higher revenues in Peru from increased ownership and resulting consolidation of Aguaytia (approximately $118 million), higher energy prices in El Salvador (approximately $40 million), favorable results in Brazil, primarily foreign exchange rate impacts (approximately $31 million) and higher electricity volumes and prices in Argentina (approximately $27 million).

Partially offsetting these increases in revenues were:

• A $274 million decrease at Crescent due primarily to the deconsolidation of Crescent, effective September 7, 2006 and softening in the residential real estate market, and

• A $69 million decrease in Other due primarily to the sale of Duke Project Services Group, Inc. (DPSG) in February 2006 (approximately $43 million) and a prior year mark-to-market gain related to former DENA’s hedge discontinuance in the Southeast (approximately $21 million).

Year Ended December 31, 2005 as Compared to December 31, 2004. Consolidated operating revenues for 2005 increased $549 million, compared to 2004. This change was driven by:

• A $363 million increase at U.S. Franchised Electric and Gas due primarily to increased sales to retail and wholesale customers as a result of warmer weather, more efficient performance of the generation fleet, and customer growth, coupled with an increase in fuel rates primarily as a result of higher coal costs in 2005 and increased market prices for wholesale power

• A $122 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.

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

Consolidated Operating Expenses

Year Ended December 31, 2006 as Compared to December 31, 2005. Consolidated operating expenses for 2006 increased $3,728 million, compared to 2005. The change was primarily driven by:

• An approximate $3,430 million increase due to the merger with Cinergy

• A $312 million increase at International Energy due primarily to higher costs in Peru (approximately $109 million), driven primarily by increased ownership and resulting consolidation of Aguaytia, a reserve related to a settlement made in conjunction with the Citrus litigation (approximately $100 million), higher fuel prices and increased consumption in El Salvador (approximately $38 million), unfavorable exchange rates, increased regulatory fees and higher purchased power costs in Brazil (approximately $34 million) and an increase in Mexico due to an impairment of a note receivable from Campeche (approximately $33 million)

• A $132 million increase in Other due primarily to costs to achieve the Cinergy merger (approximately $128 million), a reserve charge related to contract settlement negotiations (approximately $65 million), partially offset by decreases due to the continued wind-down of the former DENA businesses (approximately $47 million), and

• An approximate $115 million increase at Duke Energy Carolinas driven primarily by increased fuel expenses, due primarily to higher coal costs ($188 million) and increased purchase power expense resulting primarily from less generation availability during 2006 as a result of outages at base load stations ($42 million), partially offset by lower regulatory amortization, due primarily to reduced amortization of compliance costs related to clean air legislation ($86 million), and decreased operating and maintenance expense, due primarily to a December 2005 ice storm.

Partially offsetting these increases in expenses was:

• A $239 million decrease at Crescent due primarily to the deconsolidation of Crescent, effective September 7, 2006 and softening in the residential real estate market.

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Year Ended December 31, 2005 as Compared to December 31, 2004. Consolidated operating expenses for 2005 increased $512 million, compared to 2004. The change was primarily driven by:

• A $346 million increase in operating expenses at U.S. Franchised Electric and Gas due primarily to increased fuel expenses, driven by higher coal costs and increased generation to meet customer demand, and increased operating and maintenance expenses due primarily to increased planned outage and maintenance at generating plants, planned maintenance to improve reliability of distribution and transmission equipment, and higher storm charges in 2005, driven primarily by an ice storm in December 2005

• A $158 million increase in Other, primarily related to a $75 million charge to increase liabilities associated with mutual insurance companies in 2005 and a $64 million increase as a result of the 2004 correction of an immaterial accounting error in prior periods related to reserves at Bison Insurance Company Limited (Bison), Duke Energy’s wholly owned, captive insurance subsidiary, and

• A $73 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.

Partially offsetting these increases in expenses was:

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

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 $201 million in 2006, $191 million in 2005, and $192 million in 2004. The gain in 2006 was driven primarily by pre-tax gains from the sale of two office buildings at Potomac Yard in Washington, D.C. and a gain on a land sale at Lake Keowee in northwestern South Carolina. 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.

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

Consolidated gains (losses) on sales of other assets and other, net was a gain of $229 million for 2006, a loss of $55 million for 2005, and a loss of $435 million for 2004. The gain in 2006 was due primarily to the pre-tax gains resulting from the sale of an effective 50% interest in Crescent, creating a joint venture between Duke Energy and MSREF (approximately $250 million), partially offset by Commercial Power’s losses on sales of emission allowances (approximately $29 million). The loss in 2005 was due primarily to net pre-tax losses at Commercial Power, principally the termination of DENA structured power contracts in the Southeast region (approximately $75 million). 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 Duke Energy Trading and Marketing, LLC (DETM) contracts ($65 million) in Other.

Consolidated Operating Income

Year Ended December 31, 2006 as Compared to December 31, 2005. For 2006, consolidated operating income increased $338 million, compared to 2005. Increased operating income was primarily related to approximately $461 million of operating income generated by legacy Cinergy in 2006 as a result of the merger and an approximate $250 million gain in 2006 on the sale of an effective 50% interest in Crescent, partially offset by approximately $128 million of cost in 2006 to achieve the Cinergy merger and approximately $165 million of charges in 2006 related to settlements and contract negotiations.

Year Ended December 31, 2005 as Compared to December 31, 2004. For 2005, consolidated operating income increased $416 million, compared to 2004. Increased operating income was due primarily to the charge in 2004 associated with the sale of the Southeast Plants in 2005, partially offset by 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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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, 2006 as Compared to December 31, 2005. For 2006, consolidated other income and expenses increased $139 million, compared to 2005. The increase was due primarily to an increase of approximately $126 million of interest income resulting primarily from favorable income tax settlements in 2006.

Year Ended December 31, 2005 as Compared to December 31, 2004. For 2005, consolidated other income and expenses increased $37 million, compared to 2004. The increase was due primarily to increased equity earnings, partially offset by a $20 million impairment charge at International Energy during 2005.

Consolidated Interest Expense

Year Ended December 31, 2006 as Compared to December 31, 2005. For 2006, consolidated interest expense increased $252 million, compared to 2005. This increase is primarily attributable to the increase in long-term debt as a result of the merger with Cinergy (an approximate $228 million impact).

Year Ended December 31, 2005 as Compared to December 31, 2004. For 2005, consolidated interest expense decreased $44 million, compared to 2004. This decrease was due primarily to Duke Energy’s debt reduction efforts in 2004.

Consolidated Minority Interest Expense (Benefit)

Year Ended December 31, 2006 as Compared to December 31, 2005. For 2006, consolidated minority interest expense (benefit) decreased $11 million, compared to 2005.

Year Ended December 31, 2005 as Compared to December 31, 2004. For 2005, consolidated minority interest expense (benefit) increased $39 million, compared to 2004. This increase was due primarily to increased earnings from Crescent’s LandMar affiliate and the continued wind-down of DETM.

Consolidated Income Tax Expense from Continuing Operations

Year Ended December 31, 2006 as Compared to December 31, 2005. For 2006, consolidated income tax expense from continuing operations increased $46 million, compared to 2005. This increase primarily resulted from higher pre-tax earnings, partially offset by favorable tax settlements on research and development costs and nuclear decommissioning costs, tax benefits related to the impairment of an investment in Bolivia, and reserves and tax credits recognized on synthetic fuel operations.

Year Ended December 31, 2005 as Compared to December 31, 2004. For 2005, consolidated income tax expense from continuing operations increased $183 million, compared to 2004. The increase in income tax expense from continuing operations is primarily a result of higher pre-tax earnings. Other than the increase from higher pre-tax earnings, the increase in income tax expense from continuing operations is due to an increase in the effective tax rate, which was approximately 30% in 2005, as compared to approximately 24% in 2004. The increase in the effective tax rate was due primarily to the release of approximately $53 million of income tax reserves, resulting from the resolution of various outstanding income tax issues and changes in estimates in 2004 and a $20 million tax benefit in 2004 recognized in connection with the prior year formation of Duke Energy Americas, LLC, partially offset by the $45 million taxes recorded in 2004 on the repatriation of foreign earnings that was expected to occur in 2005 associated with the American Jobs Creation Act of 2004.

Consolidated Income from Discontinued Operations, net of tax

Consolidated income from discontinued operations was $780 million for 2006, $935 million for 2005, and $872 million for 2004. These amounts include the after-tax earnings of Duke Energy’s natural gas businesses that were spun off to shareholders on January 2, 2007. These amounts also include results of operations and gains (losses) on dispositions related primarily to former DENA’s assets and contracts outside the Midwestern and Southeastern United States, which are included in Other, and Cinergy commercial marketing and trading operations, which are included in Commercial Power, (see Note 13 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale”). The 2006 amount is primarily comprised of after-tax earnings of approximately $953 million related to the natural gas businesses, approximately $140 million of after-tax losses associated with certain contract terminations or sales at former DENA, as a result of the 2005 decision to exit substantially all of former DENA’s remaining assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets, and the recognition of approximately $17 million of after-tax losses associated with exiting the Cinergy commercial marketing and trading operations.

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The 2005 amount is primarily comprised of after-tax earnings of approximately $1,623 million related to the natural gas businesses, which includes $1,245 million of pre-tax gains on sales of equity investments, primarily associated with the sale of TEPPCO GP and Duke Energy’s limited partner interest in TEPPCO LP and an approximate $575 million gain resulting from the DEFS disposition transaction, an approximate $550 million non-cash, after-tax charge (approximately $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 as a result of the decision to exit substantially all of former DENA’s remaining assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets. Additionally, during 2005, Duke Energy recognized after-tax losses of approximately $250 million (approximately $400 million pre-tax) as the result of selling certain gas transportation and structured contracts related to the former DENA operations. These charges were offset by the recognition of after-tax gains of approximately $125 million (approximately $200 million pre-tax) related to the recognition of deferred gains in Accumulated Other Comprehensive Income (AOCI) related to discontinued cash flow hedges related to the former DENA operations.

The 2004 amount is primarily comprised of after-tax earnings of approximately $518 million related to the natural gas businesses, a $273 million after-tax gain resulting from the sale of International Energy’s Asia-Pacific Business, an approximate $117 million after-tax gain on the sale of two partially constructed merchant power plants in the western United States offset by operating losses at the western and northeast merchant power plants.

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

During 2005, Duke Energy 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 Energy.

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 Energy, 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 Energy’s ownership interest in operations without regard to financing methods or capital structures.

See Note 3 to the Consolidated Financial Statements, “Business Segments,” for a discussion of Duke Energy’s new segment structure.

As discussed in Note 13 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale” 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 former 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, the continuing operations of the former DENA segment (which primarily include the operations of the Midwestern generation assets, former DENA’s remaining Southeastern operations related to assets which were disposed of in 2004, the remaining operations of DETM, and certain general and administrative costs) have been reclassified to Commercial Power, except for DETM, which is in Other. Previously, the continuing operations of the former DENA segment were included as a component of Other in 2005 and as a component of the former DENA segment in prior periods.

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Duke 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, and detailed discussions follow.

EBIT by Business Segment

	Years Ended December 31,
	2006			2005			Variance 2006 vs 2005			2004			Variance 2005 vs 2004
	(in millions)
U.S. Franchised Electric and Gas	$	1,811		$	1,495		$	316		$	1,467		$	28
Commercial Power(a)		21			(118	)		139			(479	)		361
International Energy		163			309			(146	)		219			90
Crescent(b)		532			314			218			240			74
Total reportable segment EBIT		2,527			2,000			527			1,447			553
Other(a)		(537	)		(347	)		(190	)		(225	)		(122	)
Total reportable segment and other EBIT		1,990			1,653			337			1,222			431
Interest expense		(633	)		(381	)		(252	)		(425	)		44
Interest income and other(c)		147			(4	)		151			13			(17	)
Consolidated earnings from continuing operations before income taxes	$	1,504		$	1,268		$	236		$	810		$	458

(a) Amounts associated with former DENA’s operations are included in Other for all periods presented, except for the Midwestern generation and Southeast operations, which are reflected in Commercial Power.

(b) In September 2006, Duke Energy completed a joint venture transaction of Crescent. 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.

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

Minority interest expense as shown and discussed below includes only minority interest expense related to EBIT of Duke Energy’s joint ventures. It does not include minority interest expense related to interest and taxes of the joint ventures.

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

U.S. Franchised Electric and Gas

	Years Ended December 31,
	2006		2005		Variance 2006 vs. 2005			2004		Variance 2005 vs. 2004
	(in millions, except where noted)
Operating revenues	$	8,098	$	5,432	$	2,666		$	5,069	$	363
Operating expenses		6,319		3,959		2,360			3,613		346
Gains (losses) on sales of other assets and other, net		—		7		(7	)		3		4
Operating income		1,779		1,480		299			1,459		21
Other income and expenses, net		32		15		17			8		7
EBIT	$	1,811	$	1,495	$	316		$	1,467	$	28
Duke Energy Carolinas GWh sales(a)		82,652		85,277		(2,625	)		82,708		2,569
Duke Energy Midwest GWh sales(a) (b)		46,069				46,069

(a) Gigawatt-hours (GWh)

(b) Relates to operations of former Cinergy from the date of acquisition and thereafter

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The following table shows the percentage changes in GWh sales and average number of customers for Duke Energy Carolinas. The table below excludes amounts related to legacy Cinergy since results of operations of Cinergy are only included from the date of acquisition and thereafter.

Increase (decrease) over prior year	2006		2005		2004
Residential sales	(1.2	)%	3.7	%	5.1	%
General service sales	1.4	%	1.9	%	3.5	%
Industrial sales	(3.8	)%	1.1	%	1.8	%
Wholesale sales	(38.7	)%	38.0	%	(26.1	)%
Total Duke Energy Carolinas salesa	(3.1	)%	3.1	%	(0.1	)%
Average number of customers	2.0	%	2.0	%	1.7	%

(a) Consists of all components of Duke Energy Carolinas’ sales, including retail sales and wholesale sales to incorporated municipalities and to public and private utilities and power marketers.

Year Ended December 31, 2006 as Compared to December 31, 2005

Operating Revenues.The increase was driven primarily by:

• A $2,651 million increase in regulated revenues due to the acquisition of Cinergy

• A $203 million increase in fuel revenues driven by increased fuel rates for retail customers due primarily to increased coal costs. The delivered cost of coal in 2006 is approximately $11 per ton higher than the same period in 2005, representing an approximately 20% increase, and

• A $27 million increase related to demand from retail customers, due primarily to continued growth in the number of residential and general service customers in Duke Energy Carolinas’ service territory. The number of customers in 2006 increased by approximately 45,000 compared to 2005.

Partially offsetting these increases were:

• A $91 million decrease in wholesale power sales, net of the impact of sharing of profits from wholesale power sales with industrial customers in North Carolina ($40 million). Sales volumes decreased by approximately 39% primarily due to production constraints caused by generation outages and pricing

• A $77 million decrease related to the sharing of anticipated merger savings by way of a rate decrement rider with regulated customers in North Carolina and South Carolina. As a requirement of the merger, Duke Energy Carolinas is required to share anticipated merger savings of approximately $118 million with North Carolina customers and approximately $40 million with South Carolina customers over a one year period, and

• A $32 million decrease in GWh sales to retail customers due to unfavorable weather conditions compared to the same period in 2005. Weather statistics in 2006 for heating degree days were approximately 9% below normal as compared to 2% above normal in 2005. Overall weather statistics for both heating and cooling periods in 2006 were unfavorable compared to the same periods in 2005.

Operating Expenses.The increase was driven primarily by:

• A $2,245 million increase in regulated operating expenses due to the acquisition of Cinergy

• A $188 million increase in fuel expenses, due primarily to higher coal costs. Fossil generation fueled by coal accounted for slightly more than 50% of total generation for year to date December 31, 2006 and 2005 and the delivered cost of coal in 2006 is approximately $11 per ton higher than the same period in 2005

• A $42 million increase in purchased power expense, due primarily to less generation availability during 2006 as a result of outages at base load stations, and

• A $24 million increase in depreciation expense, due to additional capital spending.

Partially offsetting these increases were:

• An $86 million decrease in regulatory amortization, due to reduced amortization of compliance costs related to clean air legislation during 2006 as compared to the same period in 2005. Regulatory amortization expenses were approximately $225 million for the year ended December 31, 2006 as compared to approximately $311 million during the same period in 2005

• A $39 million decrease in operating and maintenance expenses, due primarily to a December 2005 ice storm, and

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• A $15 million decrease in donations related to sharing of profits from wholesale power sales with charitable, educational and economic development programs in North Carolina and South Carolina. For the year ended December 31, 2006, donations totaled $13 million, while for the same period in 2005, donations totaled $28 million.

Other income and expenses.The increase in Other income and expenses resulted primarily from an increase in allowance for funds used during construction (AFUDC) due mainly to the acquisition of the regulated operations of Cinergy.

EBIT. The increase in EBIT resulted primarily from the acquisition of the regulated operations of Cinergy, lower regulatory amortization in North Carolina, increased demand from retail customers due to continued growth in the number of residential and general service customers and decreased operating and maintenance expense in the Carolinas. These changes were partially offset by lower wholesale power sales, net of sharing, rate reductions due to the merger, unfavorable weather conditions and increased purchased power expense in the Carolinas.

Matters Impacting Future U.S. Franchised Electric and Gas Results

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

Various regulatory activities will continue in 2007, including a North Carolina rate review (see Note 4, “Regulatory Matters,” to the Consolidated Financial Statements) and filings for certification for new generation and approval of various costs to be recovered in trackers. The outcomes of these matters will impact future earnings and cash flows for U.S. Franchised Electric and Gas. As a result of additional costs and synergies that are expected from the merger with Cinergy as well as the uncertainty related to the regulatory activities mentioned above, U.S. Franchised Electric and Gas is unable to estimate reported segment EBIT for 2007 and beyond. However, segment EBIT for 2007 is expected to be higher than in 2006 primarily due to a full-year of contributions from Cinergy’s regulated operations and the expectation for more normalized weather in U.S. Franchised Electric and Gas’ service territories.

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

Operating Revenues.The increase was driven primarily by:

• A $137 million increase in fuel revenues, due primarily to increased GWh sales to retail and wholesale customers and increased fuel rates for retail customers due primarily to increased coal costs. Sales to retail customers increased by approximately 2%, while sales to wholesale customers increased by approximately 40% resulting in significantly more fuel revenue collections from those customers. The delivered cost of coal in 2005 is approximately $7 per ton higher than in 2004

• A $109 million increase in wholesale power revenues, net of the impact of sharing of profits from wholesale power sales with industrial customers in North Carolina ($37 million), due primarily to increased sales volumes and higher market prices, approximately $42 million and $104 million, respectively. Wholesale GWh sales increased by approximately 40% due to strong demand driven by favorable weather, more efficient performance by the generation fleet in 2005 and alleviation of coal constraints that limited wholesale sales opportunities in 2004. Gross margin increased by $11,000 per GWh, an 80% increase, due to higher average market rates for power resulting primarily from energy supply disruptions and record natural gas prices in 2005

• A $55 million increase in GWh sales to retail customers due to favorable weather conditions during the latter half of the year. Weather statistics in 2005 for cooling degree days were approximately 7% better than normal as compared to 1% below normal in 2004, and

• A $27 million increase related to demand from retail customers, due primarily to continued growth in the number of residential and general service customers in Franchised Electric’s service territory. The number of customers in 2005 increased by approximately 43,000 compared to 2004.

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Operating Expenses.The increase was driven primarily by:

• A $176 million increase in fuel expenses, due primarily to higher coal costs and increased generation to meet the strong demand of retail and wholesale customers. Total generation increased by 4% compared to 2004 and generation fueled by coal accounted for more than 50 percent of total generation during both periods. The delivered cost of coal in 2005 is approximately $7 per ton higher than the same period in 2004

• A $134 million increase in operating and maintenance expenses, due primarily to increased planned outage and maintenance at generating plants, planned maintenance to improve the reliability of distribution and transmission equipment and employee wages and benefits

• A $29 million increase due to higher storm charges in 2005. The increase is primarily due to a December 2005 ice storm ($46 million), which resulted in outages for approximately 700,000 customers. This is partially offset by charges for Hurricane Ivan in September 2004 ($11 million) and a wind storm in March 2004 ($7 million), and

• A $14 million increase in donations related to sharing of profits from wholesale power sales with charitable, educational and economic development programs in North Carolina and South Carolina. For the year ended December 31, 2005, donations totaled $28 million, while for the same period in 2004, donations totaled $14 million.

EBIT. The increase in EBIT resulted primarily from increased sales to wholesale customers, net of sharing, increased sales to retail customers due to favorable weather in 2005, and continued growth in the number of residential and general service customers in 2005. These changes were partially offset by increased operating and maintenance expenses, including storm costs.

Commercial Power

	Years Ended December 31,
	2006			2005			Variance 2006 vs 2005		2004			Variance 2005 vs 2004
	(in millions, except where noted)
Operating revenues	$	1,402		$	148		$	1,254	$	179		$	(31	)
Operating expenses		1,395			200			1,195		302			(102	)
Gains (losses) on sales of other assets and other, net		(23	)		(70	)		47		(359	)		289
Operating income		(16	)		(122	)		106		(482	)		360
Other income and expenses, net		37			4			33		3			1
EBIT	$	21		$	(118	)	$	139	$	(479	)	$	361
Actual plant production, GWh(a)		17,640			1,759			15,881		3,343			(1,584	)
Net proportional megawatt capacity in operation		8,100			3,600			4,500		3,600			—

(a) Excludes discontinued operations

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 former 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, Commercial Power includes the operations of former DENA’s Midwestern generation assets and remaining Southeastern operations related to the assets which were disposed of in 2004. The results of former DENA’s discontinued operations, which are comprised of assets sold to LS Power, are presented in Income From Discontinued Operations, net of tax, on the Consolidated Statements of Operations, and are discussed in consolidated Results of Operations section titled “Consolidated Income from Discontinued Operations, net of tax.”

Year Ended December 31, 2006 as compared to December 31, 2005

Operating Revenues.The increase was primarily driven by the acquisition of Cinergy non-regulated generation assets for which results, including the impacts of purchase accounting, are reflected from the date of acquisition and thereafter, but are not included in the same period in 2005 (approximately $1,240 million). Operating revenues associated with the former DENA Midwest plants were approximately $14 million higher in 2006 compared to 2005 due primarily to higher average prices and slightly higher volumes.

Operating Expenses.The increase was primarily driven by the acquisition of Cinergy non-regulated generation assets for which results, including the impacts of purchase accounting, are reflected from the date of acquisition and thereafter, but are not included in the same period in 2005 (approximately $1,185 million).

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Gain (losses) on Sales of Other Assets and Other, net.The increase was driven primarily by an approximate $75 million pre-tax charge in 2005 related to the termination of structured power contracts in the Southeastern Region and an approximate $6 million gain on the sale of the Pine Mountain synthetic fuel facility in 2006, partially offset by net losses of approximately $29 million on sales of emission allowances in 2006.

Other Income and Expenses, net. The increase is driven primarily by equity earnings of unconsolidated affiliates related to investments acquired in connection with the Cinergy merger in 2006.

EBIT.The increase was due primarily to the approximate $75 million pre-tax charge in 2005 related to the termination of structured power contracts in the Southeastern Region and the acquisition of Cinergy assets (approximately $69 million).

Matters Impacting Future Commercial Power Results

Commercial Power’s current strategy is focused on maximizing the returns and cash flows from its current portfolio. Results for Commercial Power are sensitive to changes in power supply, power demand and fuel prices.

Segment EBIT for 2007 is expected to be higher than in 2006 primarily due to the impacts of a full year of contributions from Cinergy’s Midwestern non-regulated generation portfolio, impacts of purchase accounting from the Cinergy merger, and the recovery of under-collected fuel costs in 2006. Future results for Commercial Power are subject to volatility due to the over or under-collection of fuel costs since Commercial Power is not subject to regulatory accounting pursuant to SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” In addition, the outcome of the remand hearing by the Ohio Supreme Court in regard to the RSP with the Public Utilities Commission of Ohio could affect the current tariff structure of the RSP.

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

Operating Revenues.The decrease was driven primarily by the sale of the Southeast plants in 2004, including losses in 2005 associated with structured power contracts in the Southeast.

Operating Expenses. The decrease was driven primarily by the sale of the Southeast plants in 2004 and lower operating expenses in the Midwest, including:

• $61 million decrease in operations and maintenance costs, including general and administrative expenses, and depreciation expenses, and

• $38 million decrease in fuel costs.

Gains (losses) on sales of other assets and other, net. The 2005 loss was due primarily to an approximate $75 million pre-tax charge related to the termination of structured power contracts in the Southeastern Region. The 2004 results include pre-tax losses of approximately $360 million associated with the sale of the Southeast Plants.

EBIT. EBIT loss decreased driven by the loss recognized in 2004 on the sale of the Southeast Plants and decreased operating costs and lower general and administrative expense, as outlined above.

International Energy

	Years Ended December 31,
	2006			2005		Variance 2006 vs 2005			2004			Variance 2005 vs 2004
	(in millions, except where noted)
Operating revenues	$	943		$	727	$	216		$	605		$	122
Operating expenses		838			526		312			453			73
Gains (losses) on sales of other assets and other, net		(1	)		—		(1	)		(3	)		3
Operating income		104			201		(97	)		149			52
Other income and expenses, net		76			116		(40	)		78			38
Minority interest expense (benefit)		17			8		9			8			—
EBIT	$	163		$	309	$	(146	)	$	219		$	90
Sales, GWh		19,613			17,587		2,026			16,961			626
Net proportional megawatt capacity in operation(a)		3,922			3,863		59			4,067			(204	)

(a) Excludes discontinued operations

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Year Ended December 31, 2006 as Compared to December 31, 2005

Operating Revenues.The increase was driven primarily by:

• A $118 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 Egenor due to higher sales volumes, offset by lower prices

• A $40 million increase in El Salvador due to higher energy prices

• A $31 million increase in Brazil due to the strengthening of the Brazilian Real against the U.S. dollar and higher average energy prices, offset by lower volumes, and

• A $27 million increase in Argentina primarily due to higher electricity generation, prices and increased gas marketing sales.

Operating Expenses.The increase was driven primarily by:

• A $109 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 $100 million increase due to a reserve established as a result of a settlement made in conjunction with the Citrus litigation (see Note 17 to the Consolidated Financial Statements, “Commitments and Contingencies”)

• A $38 million increase in El Salvador primarily due to higher fuel prices and increased fuel consumption

• A $34 million increase in Brazil due to the strengthening of the Brazilian Real against the U.S. dollar, increased regulatory fees, and purchased power costs, and

• A $33 million increase in Mexico due to an impairment of a note receivable from Campeche.

Other Income and expenses, net. The decrease was primarily driven by a $26 million decrease in National Methanol Company (NMC) due to lower methyl tertiary butyl ether (MTBE) margins and unplanned outages and a $12 million decrease as a result of consolidation of Aguaytia in 2006 (See Note 2 in the Consolidated Financial Statements, “Acquisitions and Dispositions”).

EBIT. The decrease in EBIT was primarily due to a litigation provision, an impairment in Mexico, lower margins at NMC, higher purchased power costs in Egenor, offset by favorable hydrology and pricing in Argentina.

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. Results for International Energy are sensitive to changes in hydrology, power supply, power demand and fuel prices. Regulatory matters can also impact International Energy 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.

International Energy’s Argentine operations are participating in a government sponsored project to construct and operate additional gas-fired generation capacity in Argentina. International Energy’s future results of operations may be impacted by the Argentine government’s ability to successfully carry out this project and provide an adequate return to entities participating in the project.

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

• 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

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• 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, and

• A $14 million increase in Argentina due to higher power purchase volumes and prices.

Partially offsetting these increases were:

• 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 and Expenses, net. 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.

Crescent^(a)

	Years Ended December 31,
	2006		2005		Variance 2006 vs 2005			2004			Variance 2005 vs 2004
	(in millions)
Operating revenues	$	221	$	495	$	(274	)	$	437		$	58
Operating expenses		160		399		(239	)		393			6
Gains on sales of investments in commercial and multi-family real estate		201		191		10			192			(1	)
Gains (losses) on sales of other assets and other, net		246		—		246			—			—
Operating income		508		287		221			236			51
Equity in earnings of unconsolidated affiliates		15		—		15			—			—
Other income and expenses, net		14		44		(30	)		3			41
Minority interest expense (benefit)		5		17		(12	)		(1	)		18
EBIT	$	532	$	314	$	218		$	240		$	74

(a) In September 2006, Duke Energy completed 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.

Year Ended December 31, 2006 as Compared to December 31, 2005

Operating Revenues. The decrease was driven primarily by the deconsolidation of Crescent effective September 7, 2006, as well as a $272 million decrease in residential developed lot sales, primarily due to decreased sales at the LandMar division in Florida.

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Operating Expenses.The decrease was driven primarily the deconsolidation of Crescent effective September 7, 2006, as well as a $187 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, D.C. 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, a $15 million gain on a land sale in Charlotte, North Carolina in 2005 and a $19 million gain on a project sale in Jacksonville, Florida in 2005.

Gains (Losses) on Sales of Other Assets and Other, net. The increase was due to an approximate $246 million pre-tax gain resulting from the sale of an effective 50% interest in Crescent (see Note 2 in the Consolidated Financial Statements, “Acquisitions and Dispositions”).

Other Income and Expenses, net. The decrease is 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.

EBIT. The increase was primarily due to the gain on sale of an ownership interest in Crescent, as noted above, as well as the sale of the Potomac Yard office buildings, partially offset by land and project sales in 2005 as discussed above.

Matters Impacting Future Crescent Results

In September 2006, Duke Energy 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 $1.21 billion, net of transaction costs, of which $1.19 billion was immediately distributed to Duke Energy. Subsequent to the sale, Duke Energy deconsolidated its investment in the Crescent JV and has accounted for the investment under the equity method of accounting. The combination of Duke Energy’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 Energy’s future equity earnings, will likely significantly impact the amount of equity earnings of the Crescent JV that Duke Energy 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 Energy’s equity earnings will be recognized as projects are sold by the Crescent JV.

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.

Gains on Sales of Investments in Commercial and Multi-Family Real Estate. The decrease was driven primarily 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.

Partially offsetting these decreases were:

• 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 in 2005, and

• 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 in 2005.

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Other Income and Expenses, net. 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 Expense (Benefit). The increase in minority interest expense (benefit) 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.

Supplemental Data

Below is supplemental information for Crescent operating results subsequent to deconsolidation on September 7, 2006:

	September 7 through December 31, 2006
	(in millions)
Operating revenues	$	179
Operating expenses	$	152
Operating income	$	27
Net income	$	30

Other

	Years Ended December 31,
	2006			2005			Variance 2006 vs 2005			2004			Variance 2005 vs 2004
	(in millions)
Operating revenues	$	140		$	209		$	(69	)	$	202		$	7
Operating expenses		707			575			132			417			158
Gains (losses) on sales of other assets and other, net		8			8			—			(76	)		84
Operating income		(559	)		(358	)		(201	)		(291	)		(67	)
Other income and expenses, net		13			14			(1	)		41			(27	)
Minority interest expense (benefit)		(9	)		3			(12	)		(25	)		28
EBIT	$	(537	)	$	(347	)	$	(190	)	$	(225	)	$	(122	)

Year Ended December 31, 2006 as Compared to December 31, 2005

Operating Revenues. The decrease was driven primarily by:

• A $43 million decrease due to the sale of DPSG in February 2006, and

• A $21 million decrease due to a prior year mark-to-market gain related to former DENA’s hedge discontinuance in the Southeast.

Operating Expenses. The increase was driven primarily by:

• A $128 million increase due to costs-to-achieve in 2006 related to the Cinergy merger

• A $65 million increase due to a charge in 2006 related to contract settlement negotiations, and

• A $14 million increase in corporate governance and other costs due primarily to the merger with Cinergy in April 2006.

Partially offsetting these increases were:

• A $47 million decrease due to the continued wind-down of the former DENA businesses, and

• A $45 million decrease due to the sale of DPSG.

EBIT.The decrease was due primarily to the increase in charges in 2006 associated with Cinergy merger and a charge for contract settlement negotiations.

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Matters Impacting Future Other Results

Future Other results may be subject to volatility as a result of losses insured by Bison and changes in liabilities associated with mutual insurance companies. Costs associated with achieving the Cinergy merger, and the wind-down of DETM could also impact future earnings for Other.

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

Operating Revenues. Operating revenues were relatively flat for the year ended December 31, 2005 compared to the same period in 2004.

Operating Expenses. The increase was driven primarily by:

• An approximate $75 million charge to increase liabilities associated with mutual insurance companies in 2005

• A $64 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 Energy subsidiaries, and

• A $26 million increase in corporate governance costs in 2005.

Partially offsetting these increases was:

• A $35 million decrease primarily associated with the continued wind-down of DETM.

Gains (losses) on sales of other assets and other, net. The 2004 loss was due primarily to approximately $65 million ($39 million net of minority interest expense) of pre-tax losses associated with the sale and terminations of DETM contracts.

Other Income and Expenses, net.The decrease was due primarily to lower equity earnings in affiliates and lower foreign currency gains at DETM.

Minority Interest Expense (Benefit).The change was due primarily to the continued wind-down of DETM.

EBIT.The decrease was due primarily to the reversal of insurance reserves at Bison in 2004 and the increase in liabilities associated with mutual insurance companies in 2005.

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CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The application of accounting policies and estimates is an important process that continues to evolve as Duke Energy’s operations change and accounting guidance evolves. Duke Energy 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 passes and more information about Duke Energy’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 Energy discusses its critical accounting policies and estimates and other significant accounting policies with senior members of management and the audit committee, as appropriate. Duke Energy’s critical accounting policies and estimates are discussed below.

Regulatory Accounting

Duke Energy accounts for certain of its regulated operations (primarily U.S. Franchised Electric and Gas and Natural Gas Transmission) under the provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” As a result, Duke Energy records assets and liabilities that result from the regulated ratemaking process that would not be recorded under generally accepted accounting principles (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. Additionally, the regulatory agencies can provide flexibility in the manner and timing of the depreciation of property, plant and equipment, nuclear decommissioning costs and amortization of regulatory assets. Total regulatory assets were $4,072 million as of December 31, 2006 and $2,319 million as of December 31, 2005. Total regulatory liabilities were $3,058 million as of December 31, 2006 and $2,338 million as of December 31, 2005. (See Note 4 to the Consolidated Financial Statements, “Regulatory Matters.”)

Long-Lived Asset Impairments and Assets Held For Sale

Duke Energy 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 Energy 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 or natural gas 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 Energy’s plans regarding, or probability assessments of, holding or selling an asset could have a significant impact on the estimated future cash flows. Duke Energy 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;

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• 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.

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 2006 and 2005, Duke Energy recorded impairments on several of its long-lived assets. (For discussion of these impairments, see Note 12 to the Consolidated Financial Statements, “Impairments, Severance and Other Charges.”)

Duke Energy may dispose of certain other assets in addition to the assets classified as held for sale at December 31, 2006. Accordingly, based in part on current market conditions in the merchant energy industry, it is reasonably possible that Duke Energy’s current estimate of fair value of its long-lived assets being considered for sale at December 31, 2006 and its other long-lived assets, could change and that change may impact the consolidated results of operations. In addition, Duke Energy could decide to dispose of additional assets in future periods, at prices that could be less than the book value of the assets.

Duke Energy 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 Energy that are being disposed of or are classified as held for sale are required to be reported as discontinued operations in the Consolidated Statements of Operations. To qualify as a discontinued operation under SFAS No. 144, the component being disposed of must have clearly distinguishable operations and cash flows. Additionally, pursuant to EITF 03-13, Duke Energy must not have significant continuing involvement in the operations after the disposal (i.e. Duke Energy 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 Energy’s ongoing operations (i.e. Duke Energy 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 and gains or losses on sales, are reflected as Income From Discontinued Operations, net of tax, in the Consolidated Statements of Operations. If an asset held for sale does not meet the requirements for discontinued operations classification, any impairments and gains or losses on sales are recorded in continuing operations as Gains (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 Impairments and other charges in the Consolidated Statements of Operations.

Impairment of Goodwill

At December 31, 2006 and 2005, Duke Energy had goodwill balances of $8,175 million and $3,775 million, respectively. Duke Energy evaluates the impairment of goodwill under SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS No. 142). The majority of Duke Energy’s goodwill at December 31, 2006 relates to the acquisition of Cinergy in April 2006, whose assets are primarily included in the U.S. Franchised Electric and Gas and Commercial Power segments, and the acquisition of Westcoast Energy, Inc. (Westcoast) in March 2002, whose assets are primarily included within the Natural Gas Transmission segment. The remainder relates to International Energy’s Latin American operations. As of the acquisition date, Duke Energy allocates goodwill to a reporting unit, which Duke Energy defines as an operating segment or one level below an operating segment. As required by SFAS No. 142, Duke Energy 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 Energy 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 2006 impairment test required by SFAS No. 142, Duke Energy did not record any impairment on its goodwill.

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 electricity, primarily at U.S. Franchised Electric and Gas, are recognized when the service is provided. Unbilled revenues are estimated by applying an average revenue/kilowatt hour for all customer classes to the number of estimated kilowatt hours delivered but not billed. Differences between actual and estimated unbilled revenues are immaterial and are a result of customer mix.

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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 actual and estimated unbilled revenues 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 of accounting (Accrual Model) or mark-to-market model of accounting (MTM Model) is applied. While the MTM Model is the default method of accounting for all derivatives, SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” (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 Energy 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” below. 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”.)

Risk Management Accounting

Duke Energy 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, 2006, 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.

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 former DENA was the primary business segment that used this accounting model, the U.S. Franchised Electric and Gas, Commercial Power and Field Services segments, as well as Other, have historically had certain transactions subject to this model. For the years ended December 31, 2006, 2005 and 2004, Duke Energy 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 risk-free based interest rate [i.e.- London Interbank Offered Rate (LIBOR) or US Treasury 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. 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. While Duke Energy uses common industry practices to develop its valuation techniques, changes in Duke Energy’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 Energy’s deal origination 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.

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For certain derivative instruments, Duke Energy applies either hedge accounting or the normal purchase and normal sales exemption in accordance with SFAS No. 133. 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 may be used when Duke Energy 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 may be used when Duke Energy 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 Energy’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 Issue C15, “Scope Exceptions: Normal Purchases and Normal Sales Exception for Option-Type Contracts and Forward Contracts in Electricity,” (DIG Issue No. C15) and amended by SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities,” (SFAS No. 149) indicates that no recognition of the contract’s fair value in the Consolidated Financial Statements is required until settlement of the contract (in Duke Energy’s case, the delivery of power). On a limited basis, Duke Energy applies the normal purchase and normal sales exception to certain contracts. 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.

As a result of the September 2005 decision to pursue the sale or other disposition of substantially all of former DENA’s remaining assets and contracts outside the Midwestern United States, Duke Energy 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.

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.

Pension and Other Post-Retirement Benefits

Duke Energy accounts for its defined benefit pension plans using SFAS No. 87, “Employers’ Accounting for Pensions,” (SFAS No. 87) and SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans.” Under SFAS No. 87, pension income/expense is recognized on an accrual basis over employees’ approximate service periods. Other post-retirement benefits are accounted for using SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions,” (SFAS No. 106). (See Note 22 to the Consolidated Financial Statements, “Employee Benefit Plans.”)

Funding requirements for defined benefit plans are determined by government regulations, not SFAS No. 87. Duke Energy made voluntary contributions of $124 million in 2006, zero in 2005 and $250 million in 2004 to its U.S. plan. Duke Energy anticipates making a contribution of approximately $150 million to the U.S. plan in 2007. Duke Energy made contributions to the Westcoast DB plans of approximately $44 million in 2006, $42 million in 2005 and $26 million in 2004. As a result of the spin-off of the natural gas businesses, Duke Energy has no future obligations to make contributions to the Westcoast DB plans. Duke Energy made contributions to the Westcoast DC plans of approximately $4 million in 2006, $3 million in 2005 and $3 million in 2004. As a result of the spin-off of the natural gas businesses, Duke Energy has no future obligations to make contributions to the Westcoast DC plans.

The calculation of pension expense, other post-retirement expense and Duke Energy’s pension and other post-retirement liabilities require the use of assumptions. Changes in these assumptions can result in different expense and reported liability amounts, and future actual experience can differ from the assumptions. Duke Energy believes that the most critical assumptions for pension and other post-retirement benefits are the expected long-term rate of return on plan assets and the assumed discount rate. Additionally, medical and prescription drug cost trend rate assumptions are critical for other post-retirement benefits. The prescription drug trend rate assumption resulted from the effect of the Medicare Prescription Drug Improvement and Modernization Act (Modernization Act).

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Duke Energy U.S. Plans

Duke Energy and its subsidiaries (including legacy Cinergy businesses) maintain non-contributory defined benefit retirement plans (U.S. Plans). The U.S. Plans cover most U.S. employees using a cash balance formula. Under a cash balance formula, a plan participant accumulates a retirement benefit consisting of pay credits that are based upon a percentage (which may vary with age and years of service) of current eligible earnings and current interest credits. Certain legacy Cinergy U.S. employees are covered under plans that use a final average earnings formula. Under a final average earnings formula, a plan participant accumulates a retirement benefit equal to a percentage of their highest 3-year average earnings, plus a percentage of their highest 3-year average earnings in excess of covered compensation per year of participation (maximum of 35 years), plus a percentage of their highest 3-year average earnings times years of participation in excess of 35 years. Duke Energy also maintains non-qualified, non-contributory defined benefit retirement plans which cover certain U.S. executives.

Duke Energy and most of its subsidiaries also 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.

Duke Energy’s U.S. Plans recognized pre-tax pension cost of $80 million, pre-tax non-qualified pension cost of $11 million and pre-tax other post-retirement benefits cost of $76 million in 2006. In 2007, Duke Energy’s U.S. pension cost is expected to be approximately $5 million lower, non-qualified pension cost is expected to be $1 million lower and other post-retirement benefits cost is expected to be $16 million lower primarily as a result of the spin-off of the natural gas businesses.

For both pension and other post-retirement plans, Duke Energy assumed that its U.S. plan’s assets would generate a long-term rate of return of 8.5% as of September 30, 2006. The assets for Duke Energy’s U.S. pension and other post-retirement 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 plan participants. The asset allocation target was set after considering the investment objective and the risk profile with respect to the trust. U.S. equities are held for their high expected return. Non-U.S. equities, debt securities, and real estate are held for diversification. Investments within asset classes are to be diversified to achieve broad market participation and reduce the impact of individual managers or investments. Duke Energy regularly reviews its actual asset allocation and periodically rebalances its investments to its targeted allocation when considered appropriate.

The expected long-term rate of return of 8.5% for the Duke Energy U.S. assets was developed using a weighted average calculation of expected returns based primarily on future expected returns across asset classes considering the use of active asset managers. The weighted average returns expected by asset classes were 4.2% for U.S. equities, 1.8% for Non U.S. equities, 2.2% for fixed income securities, and 0.3% for real estate.

If Duke Energy had used a long-term rate of 8.25% in 2006, pre-tax pension expense would have been higher by approximately $8 million and pre-tax other post-retirement expense would have been higher by approximately $1 million. If Duke Energy had used a long-term rate of 8.75% pre-tax pension expense would have been lower by approximately $8 million and pre-tax other post-retirement expense would have been lower by approximately $1 million.

Duke Energy discounted its future U.S. pension and other post-retirement obligations using a rate of 5.75% as of September 30, 2006. Duke Energy discounted its future U.S. pension and other post-retirement obligations using rates of 5.50% as of September 30, 2005 for its non-legacy Cinergy business pension plans and 6.00% as of April 1, 2006 for its legacy Cinergy business pension plans. For legacy Cinergy plans, the discount rate reflects remeasurement as of April 1, 2006 due to the merger between Duke Energy and Cinergy. Duke Energy determines the appropriate discount based on a AA bond yield curve. The yield is selected based on bonds with cash flows that match the timing and amount of the expected benefit payments under the plan. Lowering the discount rates by 0.25% would have decreased Duke Energy’s 2006 pre-tax pension expense by approximately $2 million. Increasing the discount rates by 0.25% would have increased Duke Energy’s 2006 pre-tax pension expense by approximately $2 million. Lowering the discount rates by 0.25% would have increased Duke Energy’s 2006 pre-tax other post-retirement expense by approximately $1 million. Increasing the discount rate by 0.25% would have decreased Duke Energy’s 2006 pre-tax other post-retirement expense by approximately $1 million.

Duke Energy’s U.S. post-retirement plan uses a medical care trend rate which reflects the near and long-term expectation of increases in medical health care costs. Duke Energy’s U.S. post-retirement plan uses a prescription drug trend rate which reflects the near and long-term expectation of increases in prescription drug health care costs. As of September 30, 2006, the medical care trend rates were 8.50%, which grades to 4.75% by 2013. As of September 30, 2006, the prescription drug trend rate was 13.00%, which grades to 4.75% by 2022. If Duke Energy had used health care trend rates one percentage point higher, pre-tax other post-retirement expense would have been higher by $6 million. If Duke Energy had used health care trend rates one percentage point lower, pre-tax other post-retirement expense would have been lower by $5 million.

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Future changes in plan asset returns, assumed discount rates and various other factors related to the participants in Duke Energy’s pension and post-retirement plans will impact Duke Energy’s future pension expense and liabilities. Management cannot predict with certainty what these factors will be in the future.

Westcoast 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 also 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 applied to 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.

Westcoast recognized pre-tax pension cost of $22 million, pre-tax non-qualified pension cost of $6 million and pre-tax other post-retirement benefits cost of $12 million in 2006. In 2007, as a result of the spin-off of the natural gas businesses, Duke Energy will not incur any future pension costs associated with the Westcoast plan.

The expected long-term rate of return for the Westcoast plans assets was 7.25% as of September 30, 2006. The Westcoast plans 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 plan participants. The asset allocation target was set after 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 expected long-term rate of return of 7.25% and 7.50% as of September 30, 2006 and 2005, respectively, for the Westcoast assets was developed using a weighted average calculation of expected returns based primarily on future expected returns across asset classes considering the use of active asset managers. The weighted average returns expected by asset classes were 2.5% for Canadian equities, 1.3% for U.S. equities, 1.4% for Europe, Australasia and Far East equities, and 2.0% for fixed income securities. For 2006, the expected long-term rate of return used to calculate pension expense was 7.5%. Lowering the expected rate of return on assets by 0.25% (from 7.50% to 7.25%) would have increased Westcoast’s 2006 pre-tax pension expense by approximately $1 million. Increasing the expected rate of return by 0.25% (from 7.50% to 7.75%) would have decreased Westcoast’s 2006 pre-tax pension expense by approximately $1 million. The Westcoast other post-retirement plan does not hold any assets.

Westcoast discounted its future pension and other post-retirement obligations using a rate of 5.00% as of September 30, 2006 and 2005. For Westcoast, the discount rate used to determine the pension and other post-retirement obligations 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. For 2006, the discount rate used to calculate pension expense was 5.00%. Lowering the discount rate by 0.25% (from 5.00% to 4.75%) would have increased Duke Energy’s 2006 pre-tax pension expense by approximately $2 million. Increasing the discount rate by 0.25% (from 5.00% to 5.25%) would have decreased Duke Energy’s 2006 pre-tax pension expense by approximately $2 million. Lowering the discount rate by 0.25% (from 5.00% to 4.75%) would have increased Duke Energy’s 2006 pre-tax other post-retirement expense by approximately $1 million. Increasing the discount rate by 0.25% (from 5.00% to 5.25%) would have decreased Duke Energy’s 2006 pre-tax other post-retirement expense by approximately $1 million.

The Westcoast post-retirement plans use a medical care trend rate which reflects the near and long-term expectation of increases in medical costs. As of September 30, 2006, the health care trend rates were 8.00%, which grades to 5.00% by 2009. If Westcoast had used a health care trend rate one percentage point higher, pre-tax other post-retirement expense would have been higher by $2 million. If Westcoast had used a health care trend rate one percentage point lower, pre-tax other post-retirement expense would have been lower by less than $1 million.

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LIQUIDITY AND CAPITAL RESOURCES

Known Trends and Uncertainties

Duke Energy will rely primarily upon cash flows from operations, as well as its cash, cash equivalents and short-term investments to fund its liquidity and capital requirements for 2007. The current cash, cash equivalents and short-term investments and future cash generated from operations may be used by Duke Energy to continue with its February 2005 announced plan to periodically repurchase up to an aggregate of $2.5 billion of common stock over a three year period. In June 2006, the share repurchase plan was suspended. At the time of the suspension of the repurchase plan, Duke Energy had repurchased approximately 50 million shares of common stock for approximately $1.4 billion since inception of the repurchase plan. In October 2006, Duke Energy’s Board of Directors authorized the reactivation of the share repurchase plan for Duke Energy of up to $500 million of share repurchases after the spin-off of the natural gas businesses. In addition, Duke Energy’s future cash flows will be negatively impacted by the spin-off of the natural gas businesses effective January 2, 2007. For the year ended December 31, 2006, operating, investing and financing cash flows provided/(used) by the natural gas businesses, including distributions from Duke Energy’s 50% investment in DEFS, were approximately $1.7 billion, $(0.6) billion and $(0.2) billion, respectively.

A material adverse change in operations or available financing may impact Duke Energy’s ability to fund its current liquidity and capital resource requirements.

Duke Energy currently anticipates net cash provided by operating activities in 2007 to be lower than in 2006, primarily as a result of the following:

• Lower operating cash flows as a result of the spin-off of the natural gas businesses, as discussed above; and,

• Lower operating cash flows due to the sale of an effective 50% interest in the Crescent JV in September 2006.

These lower operating cash flows are expected to be partially offset by the following:

• Lower costs incurred related to the merger with Cinergy; and,

• Higher operating results of legacy Cinergy businesses as a result of ownership for the entire year 2007.

Additionally, Duke Energy anticipates funding its defined benefit pension plans with approximately $150 million of cash during 2007, as compared to $172 million during 2006.

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 Energy projects 2007 capital and investment expenditures of approximately $3.8 billion, primarily consisting of approximately:

• $3.0 billion at U.S. Franchised Electric and Gas, including $0.5 billion of North Carolina Clean Air Expenditures

• $0.5 billion at Commercial Power

• $0.3 billion combined at International Energy and Other

Duke Energy 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. Based on this goal, approximately 80 percent of total projected 2007 capital expenditures are allocated to the U.S. Franchised Electric and Gas segment. Total U.S. Franchised Electric and Gas projected 2007 capital and investment expenditures include approximately $1.5 billion for maintenance and upgrades of existing plants and infrastructure to serve load growth, approximately $0.7 billion of environmental expenditures, and approximately $0.8 billion of expansion capital. Duke Energy’s U.S. Franchised Electric and Gas business segment is evaluating the construction of several large, new electric generating plants in North Carolina, South Carolina, and Indiana. During this evaluation process, Duke Energy has begun to see significant increases in the estimated costs of these projects driven by strong domestic and international demand for the material, equipment, and labor necessary to construct these facilities. In October 2006, Duke Energy made a filing with the NCUC related to the Duke Energy Carolinas’ request for a Certificate of Public Convenience and Necessity (CPCN) for the Cliffside project. In this filing, Duke Energy stated that due to the rising costs described above, the cost of building two Cliffside units could be approximately $3 billion, excluding AFUDC. The costs described above are expected to continue to increase causing the overall cost of the Cliffside project to increase, until such time as the NCUC issues a CPCN and Duke Energy is able to enter into definitive agreements with necessary material and service providers. On February 28, 2007, the NCUC issued a notice of decision approving the construction of one unit at the Cliffside Steam Station. The NCUC stated that it will issue a full order in the near future. Duke Energy will review the NCUC’s order, once issued, and determine whether to proceed with the Cliffside Project or consider other alternatives, including additional gas fired generation. On May 30, 2007, Duke Energy Carolinas filed an updated cost estimate for the approved new Cliffside Unit 6. The current capital cost

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estimate is $1.8 billion, which excludes AFUDC of $600 million. Duke Energy is attempting to obtain approval for the upfront recovery of development costs related to a proposed nuclear power plant. Duke Energy does not anticipate beginning construction of the proposed nuclear power plant without adequate assurance of cost recovery from the state regulators. In November 2006, Duke Energy received approval for nearly $260 million of future federal tax credits related to costs to be incurred for the modernization of the Cliffside facility as well as the IGCC plant in Indiana.

Duke Energy Indiana, Inc.’s (Duke Energy Indiana’s) estimated costs associated with the potential construction of an IGCC plant in Indiana have also increased. Duke Energy Indiana’s publicly filed testimony with the Indiana Utility Regulatory Commission indicates that industry (Electric Power Research Institute) total capital requirement estimates for a facility of this type and size are now in the range of $1.6 billion to $2.1 billion (including escalation to 2011 and owner’s specific site costs).

Duke Energy anticipates its debt to total capitalization ratio to be approximately 38% by the end of 2007, as compared to 43% at the end of 2006. This reduction is primarily due to the impacts of the spin-off the natural gas businesses in 2007. Duke Energy does not expect its total debt balance (including outstanding commercial paper balances) to change significantly in 2007, excluding the impacts of approximately $8.6 billion of debt transferred to Spectra Energy as a result of the spin-off of the natural gas businesses.

Excluding the debt which was transferred in connection with the spin-off of the natural gas businesses on January 2, 2007, Duke Energy has expected debt maturities of approximately $1.1 billion in 2007. Duke Energy expects to refinance approximately $0.5 billion of these maturities. Based upon anticipated 2007 cash flows from operations and capital expenditure and dividend payment plans, Duke Energy expects to increase outstanding commercial paper balances by approximately $0.6 billion during 2007. Current total available capacity under Duke Energy’s commercial paper facilities is sufficient to meet these additional requirements.

Duke Energy 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 Energy also maintains an active dialogue with the credit rating agencies, and believes that the current credit ratings are positioned for potential improvement evidenced by positive outlooks at Duke Energy and most of its subsidiaries.

Operating Cash Flows

Net cash provided by operating activities was $3,748 million in 2006 compared to $2,818 million in 2005, an increase of $930 million. The increase in cash provided by operating activities was due primarily to the following:

• The impacts of the merger with Cinergy, effective April 3, 2006,

• Collateral received by Duke Energy (approximately $540 million) in 2006 from Barclays, partially offset by

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

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

Net cash provided by operating activities was $2,818 million in 2005 compared to $4,168 million in 2004, a decrease of $1,350 million. The decrease in cash provided by operating activities was due primarily to the following:

• Approximately $750 million of additional net cash collateral posted by Duke Energy during 2005 attributable to 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.

These decreases were offset by an increase in cash provided due to an approximate $234 million decrease in contributions to company-sponsored pension plans in 2005.

Investing Cash Flows

Net cash used in investing activities was $1,328 million in 2006 compared to $126 million in 2005, an increase in cash used of $1,202 million. Net cash used in investing activities was $126 million in 2005 compared to $793 million in 2004, a decrease in cash used of $667 million.

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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,
	2006		2005		2004
	(in millions)
U.S. Franchised Electric and Gas(a)	$	2,381	$	1,350	$	1,126
Natural Gas Transmission		790		930		544
Field Services(b)		—		86		202
Commercial Power		209		2		7
International Energy		58		23		28
Crescent(c)(d)		507		599		568
Other		131		29		54
Total consolidated	$	4,076	$	3,019	$	2,529

(a) Amounts include capital expenditures associated with North Carolina clean-air legislation of $403 million in 2006, $310 million in 2005 and $106 million in 2004 which are included in Capital Expenditures within Cash Flows from Investing Activities on the accompanying Consolidated Statements of Cash Flows.

(b) 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.

(c) Amounts include capital expenditures associated with residential real estate of $322 million for the period from January 1, 2006 through the date of deconsolidation (September 7, 2006), $355 million in 2005, and $322 million in 2004 which are included in Capital Expenditures for Residential Real Estate within Cash Flows from Operating Activities on the accompanying Consolidated Statements of Cash Flows.

(d) As a result of the deconsolidation of Crescent, effective September 7, 2006, Crescent amounts for 2006 only include Crescent capital and investment expenditures for periods prior to September 7, 2006.

The increase in cash used in investing activities in 2006 as compared to 2005 is primarily due to the following:

• Increased capital and investment expenditures of $1,090 million, excluding Crescent’s residential real estate investment, primarily as a result of capital expenditures at U.S. Franchised Electric and Gas, primarily due to the acquisition of Cinergy in April 2006, the acquisition of the Rockingham facility in 2006 and increased expenditures associated with North Carolina clean-air legislation; and,

• Increased purchases of short-term investments of approximately $900 million in 2006 as compared to 2005, due primarily to the proceeds from the Crescent debt financing.

These increases were partially offset by the following:

• An increase in proceeds received from asset sales in 2006 as compared to 2005. Asset sales activity in 2006 of approximately $2.9 billion primarily involved the disposal of the former DENA operations outside of the Midwestern United States, Cinergy’s commercial marketing and trading business operations, as well as the Crescent JV transaction. Asset sales activity in 2005 of approximately $2.4 billion primarily involved the disposition of the investments in TEPPCO as well as the DEFS disposition transaction.

The decrease in cash used in investing activities in 2005 as compared to 2004 is primarily due to the following:

• An increase in proceeds from the sale of assets in 2005 as compared to 2004. Asset sales activity in 2005 of approximately $2.4 billion primarily involved the disposition of the investments in TEPPCO as well as the DEFS disposition transaction. Asset sales activity in 2004 of approximately $1.6 billion primarily involved the sales of the Asia-Pacific Business, Southeast Plants and Moapa and Luna partially completed facilities; and,

• Decreased amounts of cash invested in short-term investments in 2005 as compared to 2004.

These decreases were partially offset by the following:

• Increased capital and investment expenditures, excluding Crescent’s residential real estate investments, of $460 million primarily as a result of the approximate $230 million acquisition of the Empress System at Natural Gas Transmission and an increase in expenditures associated with North Carolina clean-air legislation.

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Financing Cash Flows and Liquidity

Duke Energy’s consolidated capital structure as of December 31, 2006, including short-term debt, was 43% debt, 55% common equity and 2% minority interests. The fixed charges coverage ratio, calculated using SEC guidelines, was 2.6 times for 2006, which includes a pre-tax gain of approximately $250 million on the sale of an effective 50% interest in Crescent, 2.4 times for 2005 and 1.6 times for 2004.

Net cash used in financing activities was $1,961 million in 2006 compared to $2,717 million in 2005, a decrease of $756 million. The change was due primarily to the following:

• An approximate $1.1 billion increase in proceeds from the issuance of long-term debt in 2006, net of redemptions, due primarily to the approximate $1.2 billion of debt proceeds from the Crescent JV transaction, and

• An approximate $400 million decrease in share repurchases under Duke Energy’s share repurchase plan.

These increases were partially offset by:

• An approximate $400 million increase in dividends paid due to the increase in the quarterly dividend paid per share combined with a larger number of shares outstanding, primarily attributable to the 313 million shares issued in connection with the Cinergy merger, and

• The repayment of approximately $400 million of notes payable and commercial paper in 2006 due primarily to proceeds received from asset sales.

Net cash used in financing activities was $2,717 million in 2005 compared to $3,278 million in 2004, a decrease of $561 million. The change was due primarily to the following:

• Approximately $3.0 billion of lower redemptions, net of paydowns, of long-term debt, commercial paper, notes payable, preferred and preference stock, and preferred stock of a subsidiary during 2005 as compared to 2004 as a result of an effort to reduce debt balances in 2004.

This decrease was partially offset by:

• Approximately $2.6 billion of lower proceeds from common stock transactions during 2005, primarily driven by the settlement of the forward purchase contract component of Duke Energy’s Equity Units in May and November 2004 for total proceeds of $1.7 billion and the repurchase of 32.6 million shares of common stock for $933 million in 2005.

With cash, cash equivalents and short-term investments on hand at December 31, 2006 of approximately $2.5 billion and a more stable portfolio of businesses, Duke Energy has financial flexibility to buy back common stock, invest incrementally or pay down additional debt. Duke Energy is evaluating these options and will determine the best economic decision to meet the needs of shareholders and the long-term financial strength of Duke Energy.

Significant Financing Activities — Year Ended 2006. During the year ended December 31, 2006, Duke Energy’s consolidated credit capacity increased by approximately $842 million, primarily due to the merger with Cinergy. This increase was net of other reductions in credit capacity due to the terminations of an $800 million syndicated credit facility and $590 million of other bi-lateral credit facilities. The terminations of these credit facilities primarily reflect Duke Energy’s reduced liquidity needs as a result of exiting the former DENA business.

During the year ended December 31, 2006, Duke Energy increased the portion of outstanding commercial paper and pollution control bond balances classified as long-term from $472 million to $929 million. This non-current classification is due to the existence of long-term credit facilities which back-stop these balances along with Duke Energy’s intent to refinance such balances on a long-term basis.

During 2006, Duke Energy has repurchased approximately 17.5 million shares of its common stock for approximately $500 million.

In November 2006, Union Gas issued 4.85% fixed-rate debenture bonds denominated in 125 million Canadian dollars (approximately $108 million U.S. dollar equivalents as of the closing date) due in 2022.

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

During October 2006, the $130 million bi-lateral credit facility at Spectra Energy 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.

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In September 2006, prior to the completion of the partial sale of Crescent to the MS Members as discussed in Note 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions,” 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 Energy’s deconsolidation of Crescent effective September 7, 2006, Crescent’s outstanding debt balance of $1,298 million was removed from Duke Energy’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%.

In September 2006, the Spectra Energy Income Fund (Income Fund), formerly Duke Energy 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 other expenses of issuance. The sale of approximately 9 million Trust Units reduced Duke Energy’s ownership interest in the Income Fund to approximately 46% at December 31, 2006. As a result of the sale of additional Trust Units, Duke Energy recognized an approximate $15 million U.S. Dollar pre-tax SAB No. 51 gain on the sale of subsidiary stock. 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. Subsequent to this transaction, Duke Energy had an approximate 46% ownership interest in the Income Fund.

In August 2006, Duke Energy Kentucky, Inc. (Duke Energy Kentucky) issued approximately $77 million principal amount of floating rate tax-exempt notes due August 1, 2027. Proceeds from the issuance were used to refund a like amount of debt on September 1, 2006 then outstanding at Duke Energy Ohio, Inc. (Duke Energy Ohio). Approximately $27 million of the floating rate debt was swapped to a fixed rate concurrent with closing.

In June 2006, Duke Energy Indiana issued $325 million principal amount of 6.05% senior unsecured notes due June 15, 2016. Proceeds from the issuance were used to repay $325 million of 6.65% First Mortgage Bonds that matured on June 15, 2006.

During the second, third and fourth quarters of 2006, Duke Energy’s $742 million of convertible debt became convertible into approximately 31.7 million shares of Duke Energy common stock due to the market price of Duke Energy common stock achieving a specified threshold during each respective quarter. Holders of the convertible debt were able to exercise their right to convert on or prior to each quarter end. During the second and third quarters, approximately $632 million of debt was converted into approximately 26.7 million shares of Duke Energy Common Stock. At December 31, 2006, the balance of the convertible debt is approximately $110 million.

Significant Financing Activities — Year Ended 2005. In connection with the up to $2.5 billion share repurchase program announced in February 2005, Duke Energy entered into an accelerated share repurchase transaction. Duke Energy repurchased and retired 30 million shares of its common stock from an investment bank at the March 18, 2005 closing price of $27.46 per share (total of approximately $834 million, including approximately $10 million in commissions and other fees). The final settlement with the investment bank occurred on September 22, 2005 for approximately $25 million in cash. The final settlement price was the difference between the initial settlement price of $27.46 per share and the volume weighted average price per share of actual shares purchased by the investment bank of $28.42 per share. Duke Energy also entered into a separate open-market purchase plan with the investment bank on March 18, 2005 to repurchase up to an additional 20 million shares of its common stock through December 27, 2005. As of May 9, 2005 (the date Duke and Cinergy announced a merger agreement), Duke Energy had already repurchased 2.6 million shares of its common stock through the separate open-market purchase plan at a weighted average price of $28.97 per share. In May 2005, in connection with the anticipated merger with Cinergy, Duke Energy suspended additional repurchases under the open market purchase plan. For the year ended December 31, 2005 a total of 32.6 million shares of common stock were repurchased under both share repurchase programs for approximately $933 million.

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.

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.

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%.

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In August 2005, Duke Energy International, LLC 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.

During the first quarter of 2005, Duke Energy increased the portion of outstanding commercial paper balances classified as long-term debt from $150 million to $300 million. This non-current classification is due to the existence of long-term credit facilities which back-stop these commercial paper balances along with Duke Energy’s intent to refinance such balances on a long-term basis.

In December 2004, Duke Energy 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 Energy 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 Energy in January 2005.

Preferred and Preference Stock of Duke Energy.In December 2005, Duke Energy redeemed all Preferred and Preference stock without Sinking Fund Requirements for approximately $137 million and recognized an immaterial loss on the redemption.

Available Credit Facilities and Restrictive Debt Covenants.Duke Energy’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, 2006, Duke Energy 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 Energy’s credit facilities as of December 31, 2006, see Note 15 to the Consolidated Financial Statements, “Debt and Credit Facilities.”)

Credit Ratings.Duke Energy and certain subsidiaries each hold credit ratings by Standard & Poor’s (S&P) and Moody’s Investors Service (Moody’s). In addition, certain subsidiaries transferred to Spectra Energy hold credit ratings by DBRS (formerly Dominion Bond Rating Service). Actions taken by ratings agencies subsequent to January 2, 2007 related to businesses transferred to Spectra Energy are not reflected herein since such actions have no impact on the ongoing operations of Duke Energy post spin-off.

In May 2006, S&P changed the outlook of Duke Energy and all of its subsidiaries (with the exception of Maritimes & Northeast Pipeline, LLC and Maritimes & Northeast Pipeline, LP (collectively M&N Pipeline) and DETM from stable to positive reflecting Duke Energy’s announcement to sell Cinergy’s commercial trading and marketing operations.

In April 2006, following the completion of Duke Energy’s merger with Cinergy, S&P removed Cinergy and its subsidiaries from credit-watch negative where they had been placed in May 2005 following the Cinergy merger announcement. S&P lowered Cinergy’s Corporate Credit Rating (CCR) consistent with Duke Energy’s CCR as disclosed in the table below. As a result of Cinergy’s lower CCR, S&P lowered the senior unsecured credit rating of Cinergy Corp. reflecting the structural subordination of its debt. In addition, S&P reassessed its view of the structural subordination for the debt outstanding at Spectra Energy Capital, Duke Energy Ohio, Duke Energy Indiana, and Duke Energy Kentucky and assigned the senior unsecured credit ratings at these entities equal to Duke Energy’s CCR. This resulted in the senior unsecured credit rating of Spectra Energy Capital being raised one ratings level to BBB and no changes to the senior unsecured ratings of Duke Energy Ohio, Duke Energy Indiana, and Duke Energy Kentucky as disclosed in the table below. At the same time, S&P assigned a senior unsecured credit rating to Duke Energy Carolinas equal to Duke Energy’s CCR and left the credit ratings of the Spectra Energy Capital subsidiaries (Texas Eastern Transmission, LP, Westcoast, Union Gas and M&N Pipeline) and DETM unchanged. At the completion of S&P’s April action, all the credit ratings were on stable outlook. S&P last affirmed its credit ratings for M&N Pipeline in July 2006 where they have remained unchanged with a stable outlook for the last several years.

In April 2006, upon Duke Energy’s completion of the merger with Cinergy, Moody’s upgraded the credit ratings of Duke Energy Carolinas (formerly rated as Duke Energy by Moody’s prior to the merger), Spectra Energy Capital and Texas Eastern Transmission, LP one ratings level each and assigned an issuer rating to New Duke Energy. The credit ratings resulting from the April action are as disclosed in the table below, except for businesses transferred to Spectra Energy entities as discussed above. The credit ratings of Spectra Energy Capital and Texas Eastern Transmission, LP were Baa2 and Baa1 respectively following Moody’s April action. Moody’s concluded their April action placing New Duke Energy and Duke Energy Carolinas on positive outlook and Spectra Energy Capital and Texas Eastern Transmission, LP on stable outlook. Moody’s also confirmed all of Cinergy and its subsidiaries credit ratings and changed the outlook to positive with the exception of Duke Energy Indiana, which was left on stable outlook. Moody’s noted in their April action the substantial

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reduction in business and operating risk of Duke Energy Carolinas from the distribution of its ownership in Spectra Energy Capital to a new holding company (New Duke Energy) and the substantial reduction in business and operating risk of Spectra Energy Capital through the restructuring of its ownership in DEFS and the divestiture of the former DENA merchant generation assets and trading book. Moody’s also noted the upgrade at Texas Eastern Transmission, LP in parallel to its parent Spectra Energy Capital.

In August 2005, Moody’s concluded a review of M&N Pipeline and downgraded the credit ratings one ratings level to A2 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 Westcoast, Union Gas and M&N Pipeline following Duke Energy’s announcement of the separation of the electric and gas businesses. Each of the credit ratings assigned by DBRS to these entities has remained unchanged for the last several years with a stable trend.

The following table summarizes the February 1, 2007 credit ratings from the agencies retained by Duke Energy, its principal funding subsidiaries and Duke Energy’s trading and marketing subsidiary DETM.

Credit Ratings Summary as of February 1, 2007

	Standard and Poor’s	Moody’s Investor Service
Duke Energy(a)	BBB	Baa2
Duke Energy Carolinas, LLC(b)	BBB	A3
Cinergy(b)	BBB-	Baa2
Duke Energy Ohio, Inc.(b)	BBB	Baa1
Duke Energy Indiana, Inc.(b)	BBB	Baa1
Duke Energy Kentucky, Inc.(b)	BBB	Baa1
Duke Energy Trading and Marketing, LLC(c)	BBB-	Not applicable

(a) Represents corporate credit rating and issuer rating for S&P and Moody’s respectively

(b) Represents senior unsecured 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. 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.

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 former DENA’s remaining assets and contracts outside the Midwestern United States. On November 18, 2005, Duke Energy announced it signed an agreement to transfer substantially all of the former DENA portfolio of derivatives contracts to Barclays. Under the agreement, Barclays acquired substantially all of former DENA’s outstanding gas and power derivatives contracts which essentially eliminated Duke Energy’s credit, collateral, market and legal risk associated with former DENA’s derivative trading positions effective on the date of signing. Substantially all of the underlying contracts have been transferred to Barclays.

Duke Energy operated a commercial marketing and trading business that was acquired as part of the merger with Cinergy in April 2006. In June 2006, Duke Energy announced it had reached an agreement to sell Cinergy’s commercial marketing and trading business, as well as associated contracts. The sale closed in October 2006 and, upon closing, the buyer assumed the credit, collateral, market and legal risk associated with the trading positions acquired.

A reduction in the credit rating of Duke Energy to below investment grade as of December 31, 2006 would have resulted in Duke Energy posting additional collateral of up to approximately $377 million, including impacts of Cinergy and excluding any collateral requirements associated with the spin-off of the natural gas businesses in January 2007. The majority of this collateral is related to outstanding surety bonds.

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Duke Energy 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 Energy 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.

Clauses. Duke Energy may be required to repay certain debt should the credit ratings of Duke Energy Carolinas fall to a certain level at S&P or Moody’s. As of December 31, 2006, Duke Energy had $13 million of senior unsecured notes which mature serially through 2012 that may be required to be repaid if Duke Energy Carolinas’ senior unsecured debt ratings fall below BBB- at S&P or Baa3 at Moody’s, and $23 million of senior unsecured notes which mature serially through 2016 that may be required to be repaid if Duke Energy Carolinas’ senior unsecured debt ratings fall below BBB at S&P or Baa2 at Moody’s.

Other Financing Matters. As of December 31, 2006, Duke Energy and its subsidiaries had effective SEC shelf registrations for up to $2,467 million in gross proceeds from debt and other securities, which include approximately $925 million of effective registrations at legacy Cinergy. Additionally, as of December 31, 2006, Duke Energy had 935 million Canadian dollars (approximately U.S. $807 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. Amounts available under U.S. and Canadian shelf registrations of approximately $592 million and 935 million Canadian dollars, respectively, relate to businesses included in the spin-off of the natural gas businesses on January 2, 2007 and, accordingly, are not available to Duke Energy subsequent to the consummation of the spin-off.

Duke Energy expects to continue its policy of paying regular cash dividends. There is no assurance as to the amount of future dividends because they depend on future earnings, capital requirements, and financial condition. Duke Energy has paid quarterly cash dividends for 81 consecutive years. Dividends on common and preferred stocks in 2007 are expected to be paid on March 15, June 18, September 17 and December 17, subject to the discretion of the Board of Directors.

Prior to June 2004, Duke Energy’s Investor Direct Choice Plan allowed investors to reinvest dividends in common stock and to purchase common stock directly from Duke Energy. In June 2004, Duke Energy changed the method of dividend reinvestment to open market purchases. There were no issuances of common stock under the plan in either 2006 or 2005. Issuances of common stock under the plan were $36 million in 2004.

Duke Energy also sponsors an employee savings plan that covers substantially all U.S. employees. In April 2004, Duke Energy stopped issuing shares under the plan and the plan began making open market purchases with cash provided by Duke Energy. There were no issuances of common stock under the plan in 2006 or 2005. Issuances of common stock under the plan were $51 million in 2004. Duke Energy also issues shares of its common stock to meet other employee benefit requirements. Issuances of common stock to meet other employee benefit requirements were approximately $126 million in 2006, approximately $39 million for 2005 and approximately $12 million for 2004.

Off-Balance Sheet Arrangements

Duke Energy 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 performance guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications. These arrangements are largely entered into by Duke Energy, Spectra Energy Capital and Cinergy. (See Note 18 to the Consolidated Financial Statements, “Guarantees and Indemnifications,” for further details of the guarantee arrangements.)

Most of the guarantee arrangements entered into by Duke Energy 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 Energy, Spectra Energy Capital or Cinergy 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 Energy’s operations. Thus, if Duke Energy discontinued issuing these guarantee arrangements, there would not be a material impact to the consolidated results of operations, cash flows or financial position.

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In contemplation of the spin-off of the natural gas businesses on January 2, 2007, certain guarantees that were previously issued by Spectra Energy Capital were transferred to Duke Energy prior to the consummation of the spin-off. This resulted in Duke Energy recording an immaterial liability for certain guarantees that were previously grandfathered under the provisions of FIN 45 and, therefore, were not recognized in the Consolidated Balance Sheets. Guarantees issued by Spectra Energy Capital or Natural Gas Transmission on or prior to December 31, 2006 remained with Spectra Energy Capital subsequent to the spin-off, except for certain guarantees that are in the process of being assigned to Duke Energy. During this assignment period, Duke Energy has indemnified Spectra Energy Capital against any losses incurred under these guarantee obligations.

Duke Energy Ohio, Duke Energy Indiana and Duke Energy Kentucky have an agreement to sell certain of their accounts receivable and related collections. Cinergy formed Cinergy Receivables to purchase, on a revolving basis, nearly all of the retail accounts receivable and related collections of Duke Energy Ohio, Duke Energy Indiana and Duke Energy Kentucky. Cinergy does not consolidate Cinergy Receivables since it meets the requirements to be accounted for as a qualifying special purpose entity (SPE). Duke Energy Ohio, Duke Energy Indiana and Duke Energy Kentucky each retain an interest in the receivables transferred to Cinergy Receivables. The transfers of receivables are accounted for as sales, pursuant to SFAS No. 140,“Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities.”For a more detailed discussion of our sales of accounts receivable, see Note 23 to the Consolidated Financial Statements, “Variable Interest Entities.”

Cinergy holds interests in variable interest entities (VIEs), consolidated and unconsolidated, as defined by FASB Interpretation No. 46, “Consolidation of Variable Interest Entities.” For further information, see Note 1 to the Consolidated Financial Statements, “Summary of Significant Accounting Policies”.

Duke Energy does not have any other 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 17 to the Consolidated Financial Statements, “Commitments and Contingencies” and Note 18 to the Consolidated Financial Statements, “Guarantees and Indemnifications.”)

Contractual Obligations

Duke Energy 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 Energy’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, as well as future obligations of businesses included in the spin-off of Spectra Energy on January 2, 2007. It is expected that the majority of current liabilities on the Consolidated Balance Sheets will be paid in cash in 2007.

Contractual Obligations as of December 31, 2006

	Payments Due By Period
	Total		Less than 1 year (2007)		2-3 Years (2008 & 2009)		4-5 Years (2010 & 2011)		More than 5 Years (Beyond 2012)
	(in millions)
Long-term debt(a)	$	17,879	$	1,695	$	3,504	$	1,749	$	10,931
Capital leases(a)		113		15		36		25		37
Operating leases(b)		522		86		150		101		185
Purchase Obligations:(g)
Firm capacity payments(c)		51		18		18		15		—
Energy commodity contracts(d)		5,189		1,872		1,901		918		498
Other purchase obligations(e)		2,065		912		778		39		336
Other long-term liabilities on the Consolidated Balance Sheets(f)		4,724		425		816		908		2,575
Total contractual cash obligations	$	30,543	$	5,023	$	7,203	$	3,755	$	14,562

(a) See Note 15 to the Consolidated Financial Statements, “Debt and Credit Facilities”. Amount includes interest payments over life of debt or capital lease.

(b) See Note 17 to the Consolidated Financial Statements, “Commitments and Contingencies”.

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(c) Includes firm capacity payments that provide Duke Energy with uninterrupted firm access to electricity transmission capacity, refining capacity and the option to convert natural gas to electricity at third-party owned facilities (tolling arrangements) in some power locations throughout North America. Also includes firm capacity payments under electric power agreements entered into to meet U.S. Franchised Electric and Gas’ native load requirements.

(d) Includes contractual obligations to purchase physical quantities of electricity, coal and nuclear fuel. 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, 2006. For certain of these amounts, Duke Energy may settle on a net cash basis since Duke Energy has entered into payment netting agreements with counterparties that permit Duke Energy to offset receivables and payables with such counterparties.

(e) Includes U.S. Franchised Electric and Gas’ obligation to purchase an additional ownership interest in the Catawba Nuclear Station (see Note 5 to the Consolidated Financial Statements, “Joint Ownership of Generating and Transmission Facilities”), as well as contracts for software, telephone, data and consulting or advisory services. Amount also includes contractual obligations for engineering, procurement and construction costs for nuclear plant refurbishments, environmental projects on fossil facilities, 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 2007 (see Note 22 to the Consolidated Financial Statements, “Employee Benefit Plans”), certain estimated executive benefits, and contributions to the Nuclear Decommissioning Trust Funds (NDTF) (see Note 7 to the Consolidated Financial Statements, “Asset Retirement Obligations”). The amount of cash flows to be paid to settle the asset retirement obligations is not known with certainty as Duke Energy 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 $2,301 million and the fair value of the NDTF, which will be used to help fund these obligations, is $1,775 million at December 31, 2006. Amount excludes reserves for litigation, environmental remediation, asbestos-related injuries and damages claims and self-insurance claims (see Note 17 to the Consolidated Financial Statements, “Commitments and Contingencies”) because Duke Energy 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, including nuclear insurance (see Note 17 to the Consolidated Financial Statements, “Commitments and Contingencies”), funding of other post-employment benefits (see Note 22 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 13 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale”) are also excluded as Duke Energy 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.

Quantitative and Qualitative Disclosures About Market Risk

Risk and Accounting Policies

Duke Energy 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. The Finance and Risk Management Committee of the Board receives periodic updates from the Treasurer and other members of management, on market risk positions, corporate exposures, credit exposures and overall risk management activities. The Treasurer 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.

Disclosures about market risks related to businesses transferred to Spectra Energy in January 2007 are not reflected herein since such exposures have no impact on the ongoing operations of Duke Energy post spin-off.

Commodity Price Risk

Duke Energy is exposed to the impact of market fluctuations in the prices of electricity, coal, natural gas and other energy-related products marketed and purchased as a result of its ownership of energy related assets. Price risk represents the potential risk of loss from adverse changes in the market price of electricity or other energy commodities. Duke Energy employs established policies and procedures to manage its risks associated with these market fluctuations using various commodity derivatives, including swaps, futures, forwards and options. (See Note 1 to the Consolidated Financial Statements, “Summary of Significant Accounting Policies” and Note 8 to the Consolidated Financial Statements, “Risk Management and Hedging Activities, Credit Risk, and Financial Instruments.”)

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

Hedging Strategies. Duke Energy closely monitors the risks associated with these commodity price changes on its future operations and, where appropriate, uses various commodity instruments such as electricity, coal and natural gas forward contracts to mitigate the effect of such fluctuations on operations. Duke Energy’s primary use of energy commodity derivatives is to hedge the output and production of assets.

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,

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including the use of contracts with different commodities or unmatched terms and counterparty credit risk. Hedge effectiveness is monitored regularly and measured each month. (See Note 1 to the Consolidated Financial Statements, “Summary of Significant Accounting Policies” and Note 8 to the Consolidated Financial Statements, “Risk Management and Hedging Activities, Credit Risk, and Financial Instruments.”)

In addition to the hedge contracts described above and recorded on the Consolidated Balance Sheets, Duke Energy enters into other contracts that qualify for the normal purchases and sales exception described in paragraph 10 of SFAS No. 133, DIG Issue No. C15 and SFAS No. 149. 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. On a limited basis, U.S. Franchised Electric and Gas and Commercial Power apply the normal purchase and normal sales exception to certain contracts. Recognition for the contracts in the Consolidated Statements of Operations will be the same regardless of whether the contracts are accounted for as cash flow hedges or as normal purchases and sales, unless designated as the hedged item in a fair value hedge, assuming no hedge ineffectiveness.

Income recognition and realization related to normal purchases and normal sales contracts generally coincide with the physical delivery of power. However, Duke Energy’s decisions in 2004 to sell former DENA Southeast Plants, reduce former DENA’s interest in partially completed plants and sale or disposition of substantially all of former 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.

Generation Portfolio Risks. Duke Energy is primarily exposed to market price fluctuations of wholesale power and natural gas prices in the U.S. Franchised Electric and Gas and Commercial Power segments. Duke Energy optimizes the value of its bulk power marketing and non-regulated generation portfolios. The portfolios include generation assets (power and capacity), fuel, and emission allowances. Modeled forecasts of future generation output, fuel requirements, and emission allowance requirements are based on forward power, fuel and emission allowance markets. The component pieces of the portfolio are bought and sold based on this model in order to manage the economic value of the portfolio, where such market transparency exists. The generation portfolio not utilized to serve native load or committed load is subject to commodity price fluctuations. Based on a sensitivity analysis as of December 31, 2006 and 2005, it was estimated that a ten percent price change per mega-watt hour in wholesale power prices would have a corresponding effect on Duke Energy’s pre-tax income of approximately $30 million in 2007 and $20 million in 2006, respectively. Based on a sensitivity analysis as of December 31, 2006, it was estimated that a ten percent price change per million British thermal units (MMBtu) in natural gas prices would have a corresponding effect on Duke Energy’s pre-tax income of approximately $15 million in 2007.

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 former 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 13 to the Consolidated Financial Statements, “Discontinued Operations and Assets Held for Sale”). As a result of this decision, Duke Energy 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. Duke Energy has retained the Midwestern generation assets in the Commercial Power segment, representing approximately 3,600 megawatts of power generation (see Note 2 to the Consolidated Financial Statements, “Acquisitions and Dispositions” for further details on the completed Cinergy merger).

Trading and Undesignated Contracts. The risk in the trading portfolio is measured and monitored on a daily basis utilizing a Value-at-Risk (VaR) model to determine the potential one-day favorable or unfavorable VaR calculation. Duke Energy’s VaR amounts for commodity derivatives recorded using the MTM Model are not material as a result of management decisions to dispose of certain businesses with higher risk profiles, including the former DENA operations outside the Midwestern United States and the Cinergy commercial marketing and trading businesses. In connection with the effort to reduce the risk profile, during 2006 Duke Energy finalized the sale of the former DENA power generation fleet outside of the Midwest to LS Power and sold the Cinergy commercial marketing and trading business to Fortis. Subsequent to the sales of both trading businesses, Duke Energy no longer uses VaR as a trading portfolio measure.

Other Commodity Risks. Duke Energy, through Commercial Power, owns coal-based synthetic fuel production facilities which convert coal feedstock into synthetic fuel for sale to third parties. The synthetic fuel produced at these facilities qualifies for tax credits (through 2007) in accordance with Internal Revenue Code Section 29/45K if certain requirements are satisfied. The Internal Revenue Code

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provides for a phase-out of synthetic fuel tax credits if the average annual wellhead oil prices increase above certain levels. If Commercial Power were to operate its synthetic fuel facilities based on December 31, 2006 prices throughout the entire forthcoming year, yet crude oil prices were to rise such that the tax credit is completely phased-out, projected net income in 2007 would be negatively impacted by approximately $100 million. Duke Energy is unlikely to experience a loss of this magnitude because the exposure to synthetic fuel tax credit phase-out is monitored and Duke Energy may choose to reduce or cease synthetic fuel production depending on the expectation of any potential tax credit phase-out. Duke Energy may also reduce its exposure to crude prices through the execution of derivative transactions. The objective of these activities is to reduce potential losses incurred if the reference price in a year exceeds a level triggering a phase-out of synthetic fuel tax credits.

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

Duke Energy’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.

Credit Risk

Credit risk represents the loss that Duke Energy would incur if a counterparty fails to perform under its contractual obligations. To reduce credit exposure, Duke Energy seeks to enter into netting agreements with counterparties that permit Duke Energy to offset receivables and payables with such counterparties. Duke Energy attempts to further reduce credit risk with certain counterparties by entering into agreements that enable Duke Energy 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 Energy may, at times, use credit derivatives or other structures and techniques to provide for third-party credit enhancement of Duke Energy’s counterparties’ obligations.

Duke Energy’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 Energy 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 Energy’s overall credit risk in that risk factors can negatively impact the credit quality of the entire sector. Where exposed to credit risk, Duke Energy 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 Energy’s distribution of unsecured credit exposures at December 31, 2006, including Spectra Energy businesses. 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 Enterprise Credit Exposures as of December 31, 2006

	% of Total
Investment Grade—Externally Rated	75	%
Non-Investment Grade—Externally Rated	7
Investment Grade—Internally Rated	8
Non-Investment Grade—Internally Rated	10
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 Energy 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 59% of the gross fair value of Duke Energy’s Receivables and Unrealized Gains on Mark-to-Market and Hedging Transactions on the Consolidated Balance Sheets at December 31, 2006.

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Duke Energy had no net exposure to any one customer that represented greater than 10% of the gross fair value of trade accounts receivable and unrealized gains on mark-to-market and hedging transactions at December 31, 2006. Excluding the businesses transferred to Spectra Energy in January 2007, the split between investment grade and non-investment grade would have been approximately 70% and 30%, respectively. Based on Duke Energy’s policies for managing credit risk, its exposures and its credit and other reserves, Duke Energy does not anticipate a materially adverse effect on its consolidated financial position or results of operations as a result of non-performance by any counterparty.

During 2006, Duke Energy finalized the sale of the former DENA portfolio of derivative contracts to Barclays and sold the Cinergy commercial marketing and trading business to Fortis, which eliminated Duke Energy’s credit, collateral, market and legal risk associated with these related trading positions.

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 Spectra Energy Capital. Spectra Energy Capital unconditionally and irrevocably guaranteed the lease payments of Hidalgo to IDC through 2028. In 2000, Hidalgo was sold to Calpine Corporation and Spectra Energy 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 December 31, 2006 is approximately $200 million, including principal and interest payments. Duke Energy does not believe a loss under the guarantee obligation is probable as of December 31, 2006, but continues to evaluate the situation. Therefore, no reserves have been recorded for any contingent loss as of December 31, 2006. No demands for payment have been made under the guarantee. If losses are incurred under the guarantee, Spectra Energy Capital has certain rights which should allow it to mitigate such loss. Subsequent to the spin-off the natural gas businesses, this guarantee remained with Spectra Energy Capital. However, Duke Energy indemnified Spectra Energy Capital against any future losses that could arise from payments required under this guarantee.

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

Duke Energy 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 normal purchases and normal sales, hedging contracts, and optimization contracts outstanding. Duke Energy may be required to return certain held collateral and post additional collateral should price movements adversely impact the value of open contracts or positions. In many cases, Duke Energy’s and its counterparties’ publicly disclosed credit ratings impact the amounts of additional collateral to be posted. If Duke Energy or its affiliates have a credit rating downgrade, it could result in reductions in Duke Energy’s unsecured thresholds granted by counterparties. Likewise, downgrades in credit ratings of counterparties could require counterparties to post additional collateral to Duke Energy and its affiliates. (See “Liquidity and Capital Resources—Financing Cash Flows and Liquidity” for additional discussion of downgrades.)

Interest Rate Risk

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

Based on a sensitivity analysis as of December 31, 2006, it was estimated that if market interest rates average 1% higher (lower) in 2007 than in 2006, interest expense, net of offsetting impacts in interest income, would increase (decrease) by approximately $3 million, excluding interest rate risk related to businesses transferred to Spectra Energy in January 2007. Comparatively, based on a sensitivity analysis as of December 31, 2005, had interest rates averaged 1% higher (lower) in 2006 than in 2005, it was estimated that interest expense, net of offsetting impacts in interest income, would have increased (decreased) by approximately $9 million. These amounts

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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, 2006 and 2005. The decrease in interest rate sensitivity was primarily due to the exclusion of interest rate risk, principally subsidiary debt and swaps, related to businesses transferred to Spectra Energy. If interest rates changed significantly, management would likely take actions to manage its exposure to the change. However, due to the uncertainty of the specific actions that would be taken and their possible effects, the sensitivity analysis assumes no changes in Duke Energy’s financial structure.

Equity Price Risk

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

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

Foreign Currency Risk

Duke Energy 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 naturally hedged through debt denominated or issued in the foreign currency. Duke Energy 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 Energy uses sensitivity analysis, which measures the impact of devaluation of the foreign currencies to which it has exposure.

In 2007, Duke Energy’s primary foreign currency rate exposures are expected to be the Brazilian Real and the Peruvian New Sol. A 10% devaluation in the currency exchange rates as of December 31, 2006 in all of Duke Energy’s exposure currencies would result in an estimated net pre-tax loss on the translation of local currency earnings of approximately $7 million to Duke Energy’s Consolidated Statements of Operations in 2007. The Consolidated Balance Sheet would be negatively impacted by approximately $120 million currency translation through the cumulative translation adjustment in AOCI as of December 31, 2006 as a result of a 10% devaluation in the currency exchange rates.

OTHER ISSUES

Spin-off of the Natural Gas 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 spin-off was effective January 2, 2007. The new natural gas company, which is named Spectra Energy, principally consists of Duke Energy’s Natural Gas Transmission business segment, which includes Union Gas, and also includes Duke Energy’s 50% ownership interest in DEFS. Approximately $20 billion of assets, $13 billion of liabilities (which includes approximately $8.6 billion of debt issued by Spectra Energy Capital and its consolidated subsidiaries) and $7 billion of common stockholders’ equity were distributed from Duke Energy as of the date of the spin-off. Assets and liabilities of entities included in the spin-off of Spectra Energy were transferred from Duke Energy on a historical cost basis on the date of the spin-off transaction. As a result of the spin-off transaction, on January 2, 2007, in lieu of adjusting the conversion ratio of the convertible debt, Duke Energy issued approximately 2.4 million shares of Spectra Energy common stock to holders of Duke Energy’s convertible senior notes due 2023, consistent with the terms of the debt agreements. The issuance of Spectra Energy shares to the convertible debt holders is expected to result in a pretax charge in the range of $20 million to $30 million in Duke Energy’s 2007 consolidated statement of operations. Duke Energy’s historical financial statements have been recast

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to reflect the results of the natural gas businesses as discontinued operations for all periods presented. The primary businesses remaining in Duke Energy post-spin are the U.S. Franchised Electric and Gas business segment, the Commercial Power business segment, the International Energy business segment and Duke Energy’s effective 50% interest in the Crescent JV. The decision to spin off the natural gas business is expected to deliver long-term value to shareholders.

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 Public Utility Holding Company Act of 1935, directs the Federal Energy Regulatory Commission (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. FERC’s enhanced merger authority will not apply to transactions pending with the FERC as of August 8, 2005, such as the 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 Energy 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 greenhouse gas policy of the United States currently favors voluntary actions to reduce emissions and continued research and technology development over near-term mandatory greenhouse gas emission reduction requirements. Although several bills have been introduced in Congress that would mandate greenhouse gas emission reductions, none have advanced through the legislature and presently there are no federal mandatory greenhouse gas reduction requirements. While it is possible that Congress will adopt some form of mandatory greenhouse gas emission reduction legislation in the future, the timing and specific requirements of any such legislation are highly uncertain. Several Northeastern states and California are in the process of developing their own mandatory greenhouse gas emission reduction programs; none of which will impact Duke Energy’s operations.

Duke Energy supports the enactment of U.S. federal legislation that would require a gradual transition to a lower carbon-intensive economy. Legislation preferably would be in the form of a federal-level carbon tax or cap-and-trade based program. Duke Energy, 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 Energy’s proactive role in climate change policy debates in the United States does not change the uncertainty around such policy. Due to the speculative outlook regarding U.S. federal policy, Duke Energy cannot estimate the potential effect of future U.S. greenhouse gas policy on its future consolidated results of operations, cash flows or financial position. Duke Energy will assess and respond to the potential implications of U.S. greenhouse gas policy for its business operations if policy becomes sufficiently developed and certain to support a meaningful assessment.

This disclosure related to the global climate change excludes developments in Canada due to the spin-off of Duke Energy’s natural gas businesses on January 2, 2007.

(For additional information on other issues related to Duke Energy, see Note 4 to the Consolidated Financial Statements, “Regulatory Matters” and Note 17 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 Energy as of December 31, 2006:

SFAS No. 155, “Accounting for Certain Hybrid Financial Instruments — an amendment of FASB Statements No. 133 and 140” (SFAS No. 155).In February 2006, the FASB issued SFAS No. 155, which amendsSFAS No. 133,“Accounting for Derivative Instruments and Hedging Activities”andSFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities” (SFAS No. 140). SFAS No. 155 allows financial instruments that have embedded derivatives to be accounted for at fair value at acquisition, at issuance, or when a previously recognized financial instrument is subject to a remeasurement (new basis) event, on an instrument-by-instrument basis, in cases in which a derivative would otherwise have to be bifurcated. SFAS No. 155 is effective for Duke Energy for all financial instruments acquired, issued, or subject to remeasurement after January 1, 2007, and for certain hybrid financial instruments that have been bifurcated prior to the effective date, for which the effect is to be reported as a cumulative-effect adjustment to beginning retained earnings. Duke Energy 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.

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SFAS No. 156, “Accounting for Servicing of Financial Assets — an amendment of FASB Statement No. 140” (SFAS No. 156).In March 2006, the FASB issued SFAS No. 156, which amends SFAS No. 140. SFAS No. 156 requires recognition of a servicing asset or liability when an entity enters into arrangements to service financial instruments in certain situations. Such servicing assets or servicing liabilities are required to be initially measured at fair value, if practicable. SFAS No. 156 also allows an entity to subsequently measure its servicing assets or servicing liabilities using either an amortization method or a fair value method. SFAS No. 156 is effective for Duke Energy as of January 1, 2007, and must be applied prospectively, except that where an entity elects to remeasure separately recognized existing arrangements and reclassify certain available-for-sale securities to trading securities, any effects must be reported as a cumulative-effect adjustment to retained earnings. Duke Energy does not anticipate the adoption of SFAS No. 156 will have any material impact on its consolidated results of operations, cash flows or financial position.

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

SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (SFAS No. 159).In February 2007, the FASB issued SFAS No. 159, which permits entities to choose to measure many financial instruments and certain other items at fair value. For Duke Energy, SFAS No. 159 is effective as of January 1, 2008 and will have no impact on amounts presented for periods prior to the effective date. Duke Energy cannot currently estimate the impact of SFAS No. 159 on its consolidated results of operations, cash flows or financial position and has not yet determined whether or not it will choose to measure items subject to SFAS No. 159 at fair value.

FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109” (FIN 48). In July 2006, the FASB issued FIN 48, which provides guidance on accounting for income tax positions about which Duke Energy has concluded there is a level of uncertainty with respect to the recognition in Duke Energy’s financial statements. FIN 48 prescribes a minimum recognition threshold a tax position is required to meet. Tax positions are defined very broadly and include not only tax deductions and credits but also decisions not to file in a particular jurisdiction, as well as the taxability of transactions. Duke Energy will implement FIN 48 effective January 1, 2007. The implementation is expected to result in a cumulative effect adjustment to beginning Retained Earnings on the Consolidated Statement of Common Stockholders’ Equity and Comprehensive Income (Loss) in the first quarter 2007 in the range of $15 million to $30 million. Corresponding entries will impact a variety of balance sheet line items, including Deferred Income Taxes, Taxes Accrued, Other Liabilities, and Goodwill. Upon implementation of FIN 48, Duke Energy will reflect interest expense related to taxes as Interest Expense, in the Consolidated Statement of Operations. In addition, subsequent accounting for FIN 48 (after January 1, 2007) will involve an evaluation to determine if any changes have occurred that would impact the existing uncertain tax positions as well as determining whether any new tax positions are uncertain. Any impacts resulting from the evaluation of existing uncertain tax positions or from the recognition of new uncertain tax positions would impact income tax expense and interest expense in the Consolidated Statement of Operations, with offsetting impacts to the balance sheet line items described above. Because of the spin-off of Spectra Energy in the first quarter of 2007, certain liabilities and deferred tax assets related to uncertain tax positions filed on Spectra Energy tax returns will be removed from Duke Energy’s balance sheet. Uncertain tax positions on consolidated or combined tax returns filed by Duke Energy which are indemnified by Spectra Energy will be recorded as receivables from Spectra Energy.

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 applyingFSP 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

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conditions are met. This FSP is effective for Duke Energy as of January 1, 2007. The impact to Duke Energy of applying FSP No. FAS 123(R)-5 in subsequent periods will be dependent upon the nature of any modifications to Duke Energy’s share-based compensation awards.

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

EITF Issue No. 06-3, “How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (That Is, Gross versus Net Presentation)” (EITF No. 06-3). In June 2006, the EITF reached a consensus on EITF No. 06-3 to address any tax assessed by a governmental authority that is directly imposed on a revenue-producing transaction between a seller and a customer and may include, but are not limited to, sales, use, value added, and some excise taxes. For taxes within the issue’s scope, the consensus requires that entities present such taxes on either a gross (i.e. included in revenues and costs) or net (i.e. exclude from revenues) basis according to their accounting policies, which should be disclosed. If such taxes are reported gross and are significant, entities should disclose the amounts of those taxes. Disclosures may be made on an aggregate basis. The consensus is effective for Duke Energy beginning January 1, 2007. Duke Energy 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 Energy 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 Energy does not anticipate the adoption of EITF No. 06-5 will have any material impact on its consolidated results of operations, cash flows or financial position.

EITF Issue No. 06-6, “Debtor’s Accounting for a Modification (or Exchange) of Convertible Debt Instruments” (EITF No. 06-6). In November 2006, the EITF reached a consensus on EITF No. 06-6. EITF No. 06-6 addresses how a modification of a debt instrument (or an exchange of debt instruments) that affects the terms of an embedded conversion option should be considered in the issuer’s analysis of whether debt extinguishment accounting should be applied, and further addresses the accounting for a modification of a debt instrument (or an exchange of debt instruments) that affects the terms of an embedded conversion option when extinguishment accounting is not applied. EITF No. 06-6 applies to modifications (or exchanges) occurring in interim or annual reporting periods beginning after November 29, 2006, regardless of when the instrument was originally issued. Early application is permitted for modifications (or exchanges) occurring in periods for which financial statements have not been issued. There were no modifications to, or exchanges of, any of Duke Energy’s debt instruments within the scope of EITF No. 06-6 in 2006. EITF No. 06-6 is effective for Duke Energy beginning January 1, 2007. The impact to Duke Energy of applying EITF No. 06-6 in subsequent periods will be dependent upon the nature of any modifications to, or exchanges of, any debt instruments within the scope of EITF No. 06-6. Refer to Note 15, “Debt and Credit Facilities.”

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

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

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Item 8. Financial Statements and Supplementary Data.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of Duke Energy Corporation

Charlotte, North Carolina

We have audited the accompanying consolidated balance sheets of Duke Energy Corporation and subsidiaries (the “Company”) as of December 31, 2006 and 2005, and the related consolidated statements of operations, stockholders’ equity and comprehensive income, and cash flows, and the related financial statement schedule for each of the three years in the period ended December 31, 2006. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. 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, such consolidated financial statements present fairly, in all material respects, the financial position of Duke Energy Corporation and subsidiaries as of December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

As discussed in Note 1 to the consolidated financial statements, in 2006 the Company changed its method of accounting for defined benefit pension and other postretirement plans as a result of adopting Statement of Financial Accounting Standard No. 158,Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans.

As discussed in Notes 1 and 25 to the consolidated financial statements, the Company’s spin-off of the natural gas businesses was completed on January 2, 2007.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006, based on the criteria established inInternal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 1, 2007 expressed an unqualified opinion on management’s assessment of the effectiveness of the Company’s internal control over financial reporting and an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/    DELOITTE & TOUCHE LLP

Charlotte, North Carolina

March 1, 2007

(October 1, 2007 as to the impacts described in the “Recasting of Previously Issued Financial Statements” section of Note 1 and the updates to the William States Lee III nuclear power project, the Cliffside Steam Station, and the Company’s 2007 application to increase rates in North Carolina in the “US Franchised and Electric and Gas” section of Note 4)

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DUKE ENERGY CORPORATION

Consolidated Statements of Operations

(In millions, except per-share amounts)

	Years Ended December 31,
	2006			2005			2004
Operating Revenues
Regulated electric	$	7,678		$	5,406		$	5,041
Non-regulated electric, natural gas, natural gas liquids, and other		2,613			1,500			1,316
Regulated natural gas and natural gas liquids		387			—			—
Total operating revenues		10,678			6,906			6,357
Operating Expenses
Operation, maintenance and other		3,433			2,533			2,147
Fuel used in electric generation and purchased power		3,372			1,579			1,552
Natural gas and petroleum products purchased		410			9			4
Depreciation and amortization		1,565			1,123			1,030
Property and other taxes		534			327			299
Impairments and other charges		—			15			42
Total operating expenses		9,314			5,586			5,074
Gains on Sales of Investments in Commercial and Multi-Family Real Estate		201			191			192
Gains (Losses) on Sales of Other Assets and Other, net		229			(55	)		(435	)
Operating Income		1,794			1,456			1,040
Other Income and Expenses
Equity in earnings of unconsolidated affiliates		123			124			73
(Losses) Gains on sales and impairments of equity investments		(20	)		(20	)		3
Other income and expenses, net		253			113			104
Total other income and expenses		356			217			180
Interest Expense		633			381			425
Minority Interest Expense (Benefit)		13			24			(15	)
Earnings From Continuing Operations Before Income Taxes		1,504			1,268			810
Income Tax Expense from Continuing Operations		421			375			192
Income From Continuing Operations		1,083			893			618
Income From Discontinued Operations, net of tax		780			935			872
Income Before Cumulative Effect of Change in Accounting Principle		1,863			1,828			1,490
Cumulative Effect of Change in Accounting Principle, net of tax and minority interest		—			(4	)		—
Net Income		1,863			1,824			1,490
Dividends and Premiums on Redemption of Preferred and Preference Stock		—			12			9
Earnings Available For Common Stockholders	$	1,863		$	1,812		$	1,481
Common Stock Data
Weighted-average shares outstanding
Basic		1,170			934			931
Diluted		1,188			970			966
Earnings per share (from continuing operations)
Basic	$	0.93		$	0.94		$	0.65
Diluted	$	0.91		$	0.92		$	0.64
Earnings per share (from discontinued operations)
Basic	$	0.66		$	1.00		$	0.94
Diluted	$	0.66		$	0.96		$	0.90
Earnings per share
Basic	$	1.59		$	1.94		$	1.59
Diluted	$	1.57		$	1.88		$	1.54
Dividends per share	$	1.26		$	1.17		$	1.10

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DUKE ENERGY CORPORATION

Consolidated Balance Sheets

(In millions)

	December 31, 2006		December 31, 2005
ASSETS
Current Assets
Cash and cash equivalents	$	948	$	511
Short-term investments		1,514		632
Receivables (net of allowance for doubtful accounts of $94 at December 31, 2006 and $127 at December 31, 2005)		2,256		2,580
Inventory		1,358		863
Assets held for sale		28		1,528
Unrealized gains on mark-to-market and hedging transactions		107		87
Other		729		1,756
Total current assets		6,940		7,957
Investments and Other Assets
Investments in unconsolidated affiliates		2,305		1,933
Nuclear decommissioning trust funds		1,775		1,504
Goodwill		8,175		3,775
Intangibles, net		905		65
Notes receivable		224		138
Unrealized gains on mark-to-market and hedging transactions		248		62
Assets held for sale		134		3,597
Investments in residential, commercial and multi-family real estate (net of accumulated depreciation of $17 at December 31, 2005)		—		1,281
Other		2,304		2,678
Total investments and other assets		16,070		15,033
Property, Plant and Equipment
Cost		58,330		40,823
Less accumulated depreciation and amortization		16,883		11,623
Net property, plant and equipment		41,447		29,200
Regulatory Assets and Deferred Debits
Deferred debt expense		320		269
Regulatory assets related to income taxes		1,361		1,338
Other		2,562		926
Total regulatory assets and deferred debits		4,243		2,533
Total Assets	$	68,700	$	54,723

See Notes to Consolidated Financial Statements

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DUKE ENERGY CORPORATION

Consolidated Balance Sheets—(Continued)

(In millions, except per-share amounts)

	December 31, 2006		December 31, 2005
LIABILITIES AND COMMON STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	1,686	$	2,431
Notes payable and commercial paper		450		83
Taxes accrued		434		327
Interest accrued		302		230
Liabilities associated with assets held for sale		26		1,488
Current maturities of long-term debt		1,605		1,400
Unrealized losses on mark-to-market and hedging transactions		134		204
Other		1,976		2,255
Total current liabilities		6,613		8,418
Long-term Debt		18,118		14,547
Deferred Credits and Other Liabilities
Deferred income taxes		7,003		5,253
Investment tax credit		175		144
Unrealized losses on mark-to-market and hedging transactions		238		10
Liabilities associated with assets held for sale		18		2,085
Asset retirement obligations		2,301		2,058
Other		7,327		5,020
Total deferred credits and other liabilities		17,062		14,570
Commitments and Contingencies
Minority Interests		805		749
Common Stockholders’ Equity
Common stock, $0.001 par value, 2 billion shares authorized; 1,257 million and zero shares outstanding at December 31, 2006 and December 31, 2005, respectively		1		—
Common stock, no par, 2 billion shares authorized; zero and 928 million shares outstanding at December 31, 2006 and December 31, 2005, respectively		—		10,446
Additional paid-in capital		19,854		—
Retained earnings		5,652		5,277
Accumulated other comprehensive income		595		716
Total common stockholders’ equity		26,102		16,439
Total Liabilities and Common Stockholders’ Equity	$	68,700	$	54,723

See Notes to Consolidated Financial Statements

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DUKE ENERGY CORPORATION

Consolidated Statements of Cash Flows

(In millions)

	Years Ended December 31,
	2006			2005			2004
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	1,863		$	1,824		$	1,490
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization (including amortization of nuclear fuel)		2,215			1,884			2,037
Cumulative effect of change in accounting principle		—			4			—
Gains on sales of investments in commercial and multi-family real estate		(201	)		(191	)		(201	)
Gains on sales of equity investments and other assets		(365	)		(1,771	)		(193	)
Impairment charges		48			159			194
Deferred income taxes		250			282			867
Minority Interest		61			538			195
Equity in earnings of unconsolidated affiliates		(732	)		(479	)		(161	)
Purchased capacity levelization		(14	)		(14	)		92
Contributions to company-sponsored pension plans		(172	)		(45	)		(279	)
(Increase) decrease in
Net realized and unrealized mark-to-market and hedging transactions		(134	)		443			216
Receivables		844			(249	)		(231	)
Inventory		(24	)		(80	)		(48	)
Other current assets		1,276			(944	)		(33	)
Increase (decrease) in
Accounts payable		(1,524	)		117			(5	)
Taxes accrued		(69	)		53			188
Other current liabilities		(594	)		622			91
Capital expenditures for residential real estate		(322	)		(355	)		(322	)
Cost of residential real estate sold		143			294			268
Other, assets		1,005			193			(155	)
Other, liabilities		194			533			158
Net cash provided by operating activities		3,748			2,818			4,168
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(3,381	)		(2,327	)		(2,161	)
Investment expenditures		(89	)		(43	)		(46	)
Acquisitions, net of cash acquired		(284	)		(294	)		—
Cash acquired from acquisition of Cinergy		147			—			—
Purchases of available-for-sale securities		(33,436	)		(40,317	)		(65,929	)
Proceeds from sales and maturities of available-for-sale securities		32,596			40,131			65,098
Net proceeds from the sales of equity investments and other assets, and sales of and collections on notes receivable		2,861			2,375			1,619
Proceeds from the sales of commercial and multi-family real estate		254			372			606
Settlement of net investment hedges and other investing derivatives		(163	)		(296	)		—
Distributions from equity investments		152			383			—
Purchases of emission allowances		(228	)		(18	)		—
Sales of emission allowances		194			—			—
Other		49			(92	)		20
Net cash used in investing activities		(1,328	)		(126	)		(793	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from the:
Issuance of long-term debt		2,369			543			153
Issuance of common stock and common stock related to employee benefit plans		127			41			1,704
Payments for the redemption of:
Long-term debt		(2,098	)		(1,346	)		(3,646	)
Preferred stock of a subsidiary		(12	)		(134	)		(176	)
Decrease in cash overdrafts		(2	)		—			—
Notes payable and commercial paper		(412	)		165			(67	)
Distributions to minority interests		(304	)		(861	)		(1,477	)
Contributions from minority interests		247			779			1,277
Dividends paid		(1,488	)		(1,105	)		(1,065	)
Repurchase of common shares		(500	)		(933	)		—
Proceeds from Duke Energy Income Fund		104			110			—
Other		8			24			19
Net cash used in financing activities		(1,961	)		(2,717	)		(3,278	)
Changes in cash and cash equivalents included in assets held for sale		(22	)		3			39
Net increase (decrease) in cash and cash equivalents		437			(22	)		136
Cash and cash equivalents at beginning of period		511			533			397
Cash and cash equivalents at end of period	$	948		$	511		$	533
Supplemental Disclosures:
Cash paid for interest, net of amount capitalized	$	1,154		$	1,089		$	1,323
Cash paid (refunded) for income taxes	$	460		$	546		$	(339	)
Acquisition of Cinergy Corp.
Fair value of assets acquired	$	17,304		$	—		$	—
Liabilities assumed	$	12,709		$	—		$	—
Issuance of common stock	$	8,993		$	—		$	—
Significant non-cash transactions:
Conversion of convertible notes to stock	$	632		$	28		$	—
AFUDC—equity component	$	58		$	30		$	25
Transfer of DEFS Canadian Facilities	$	—		$	97		$	—
Debt retired in connection with disposition of business	$	—		$	—		$	840
Note receivable from sale of southeastern plants	$	—		$	—		$	48
Remarketing of senior notes	$	—		$	—		$	1,625

See Notes to Consolidated Financial Statements

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DUKE ENERGY CORPORATION

Consolidated Statements of Common Stockholders’ Equity and Comprehensive Income

(In millions)

											Accumulated Other Comprehensive Income (Loss)
	Common Stock Shares		Common Stock			Additional Paid-in Capital		Retained Earnings			Foreign Currency Adjustments			Net Gains (Losses) on Cash Flow Hedges			Minimum Pension Liability Adjustment			SFAS No. 158 Adjustment	Other	Total
Balance December 31, 2003	911		$	9,513		$	—	$	4,066		$	315		$	298		$	(444	)			$	13,748
Net income	—			—			—		1,490			—			—			—		—	—		1,490
Other Comprehensive Income																							—
Foreign currency translation adjustments	—			—			—		—			279			—			—		—	—		279
Foreign currency translation adjustments reclassified																							—
into earnings as a result of the sale of Asia-Pacific Business	—			—			—		—			(54	)		—			—		—	—		(54	)
Net unrealized gains on cash flow hedges(b)	—			—			—		—			—			311			—		—	—		311
Reclassification into earnings from cash flow hedges(c)	—			—			—		—			—			(83	)		—		—	—		(83	)
Minimum pension liability adjustment(d)	—			—			—		—			—			—			28		—	—		28
Total comprehensive income																							1,971
Dividend reinvestment and employee benefits	5			128			—		—			—			—			—		—	—		128
Equity offering	41			1,625			—		—			—			—			—		—	—		1,625
Common stock dividends	—			—			—		(1,018	)		—			—			—		—	—		(1,018	)
Preferred and preference stock dividends	—			—			—		(9	)		—			—			—		—	—		(9	)
Other capital stock transactions, net	—			—			—		(4	)		—			—			—		—	—		(4	)
Balance December 31, 2004	957		$	11,266		$	—	$	4,525		$	540		$	526		$	(416	)	—	—	$	16,441
Net income	—			—			—		1,824			—			—			—		—	—		1,824
Other Comprehensive Income
Foreign currency translation adjustments(a)	—			—			—		—			306			—			—		—	—		306
Net unrealized gains on cash flow hedges(b)	—			—			—		—			—			413			—		—	—		413
Reclassification into earnings from cash flow hedges(c)	—			—			—		—			—			(1,026	)		—		—	—		(1,026	)
Minimum pension liability adjustment(d)	—			—			—		—			—			—			356		—	—		356
Other(f)																				—	17		17
Total comprehensive income																							1,890
Dividend reinvestment and employee benefits	3			85					—			—			—			—		—	—		85
Stock repurchase	(33	)		(933	)				—			—			—			—		—	—		(933	)
Conversion of debt	1			28																			28
Common stock dividends	—			—			—		(1,093	)		—			—			—		—	—		(1,093	)
Preferred and preference stock dividends	—			—			—		(12	)		—			—			—		—	—		(12	)
Other capital stock transactions, net	��			—			—		33			—			—			—		—	—		33
Balance December 31, 2005	928		$	10,446		$	—	$	5,277		$	846		$	(87	)	$	(60	)	—	17	$	16,439

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PART II

DUKE ENERGY CORPORATION

Consolidated Statements of Common Stockholders’ Equity and Comprehensive Income—(Continued)

(In millions)

												Accumulated Other Comprehensive Income (Loss)
	Common Stock Shares		Common Stock			Additional Paid-in Capital			Retained Earnings			Foreign Currency Adjustments		Net Gains (Losses) on Cash Flow Hedges			Minimum Pension Liability Adjustment			SFAS No. 158 Adjustment		Other		Total
Balance December 31, 2005	928		$	10,446		$	—		$	5,277		$	846	$	(87	)	$	(60	)	—		17		$	16,439
Net income	—			—			—			1,863			—		—			—		—		—			1,863
Other Comprehensive Income
Foreign currency translation adjustments	—			—			—			—			103		—			—		—		—			103
Net unrealized gains on cash flow hedges(b)	—			—			—			—			—		6			—		—		—			6
Reclassification into earnings from cash flow hedges(c)	—			—			—			—			—		36			—		—		—			36
Minimum pension liability adjustment(d)	—			—			—			—			—		—			(1	)	—		—			(1	)
Other(f)	—			—			—			—			—		—			—		—		(15	)		(15	)
Total comprehensive income																									1,992
Retirement of old Duke Energy shares	(927	)		(10,399	)		—			—			—		—			—		—		—			(10,399	)
Issuance of new Duke Energy shares	927			1			10,398			—			—		—			—		—		—			10,399
Common stock issued in connection with Cinergy merger	313			—			8,993			—			—		—			—		—		—			8,993
Conversion of Cinergy options to Duke Energy options	—			—			59			—			—		—			—		—		—			59
Dividend reinvestment and employee benefits	6			22			172			—			—		—			—		—		—			194
Stock repurchase	(17	)		(69	)		(431	)		—			—		—			—		—		—			(500	)
Common stock dividends	—			—			—			(1,488	)		—		—			—		—		—			(1,488	)
Conversion of debt to equity	27			—			632			—			—		—			—		—		—			632
Tax benefit due to conversion of debt to equity	—			—			34			—			—		—			—		—		—			34
Adjustment due to SFAS No. 158 adoption(e)	—			—			—			—			—		—			61		(311	)	—			(250	)
Other capital stock transactions, net	—			—			(3	)		—			—		—			—		—		—			(3	)
Balance December 31, 2006	1,257		$	1		$	19,854		$	5,652		$	949	$	(45	)	$	—		(311	)	2		$	26,102

(a) Foreign currency translation adjustments, net of $62 tax benefit in 2005. The 2005 tax benefit related to the settled net investment hedges (see Note 8). Substantially all of the 2005 tax benefit is a correction of an immaterial accounting error related to prior periods.

(b) Net unrealized gains on cash flow hedges, net of $3 tax expense in 2006, $233 tax expense in 2005, and $170 tax expense in 2004.

(c) Reclassification into earnings from cash flow hedges, net of $19 tax expense in 2006, $583 tax benefit in 2005, and $45 tax benefit in 2004.

Reclassification into earnings from cash flow hedges in 2006, is due primarily to the recognition of Duke Energy North America’s (DENA) unrealized net

gains related to hedges on forecasted transactions which will no longer occur as a result of the sale to LS Power 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 8 and 13).

(d) Minimum pension liability adjustment, net of $0 tax benefit in 2006, $228 tax expense in 2005, and $18 tax expense in 2004.

(e) Adjustment due to SFAS No. 158 adoption, net of $144 tax benefit in 2006. Excludes $595 recorded as a regulatory asset (see Note 22).

(f) Net of $9 tax benefit in 2006, and $10 tax expense in 2005.

See Notes to Consolidated Financial Statements

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Notes To Consolidated Financial Statements

1. Summary of Significant Accounting Policies

Nature of Operations and Basis of Consolidation.Duke Energy Corporation (collectively with its subsidiaries, Duke Energy), is an energy company located in the Americas. These Consolidated Financial Statements include, after eliminating intercompany transactions and balances, the accounts of Duke Energy and all majority-owned subsidiaries where Duke Energy has control, and those variable interest entities where Duke Energy is the primary beneficiary. These Consolidated Financial Statements also reflect Duke Energy’s proportionate share of certain generation and transmission facilities in North Carolina and the Midwest.

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 or 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). As a result of the merger transactions, each outstanding share of Cinergy common stock was converted into 1.56 shares of common stock of Duke Energy, which resulted in the issuance of approximately 313 million shares. Additionally, each share of common stock of Old Duke Energy was converted into one share of Duke Energy common stock. Old Duke Energy is the predecessor of Duke Energy for purposes of U.S. securities regulations governing financial statement filing. Therefore, the accompanying Consolidated Financial Statements reflect the results of operations of Old Duke Energy for the three months ended March 31, 2006 and the years ended December 31, 2005 and 2004 and the financial position of Old Duke Energy as of December 31, 2005. New Duke Energy had separate operations for the period beginning with the effective date of the Cinergy merger, and references to amounts for periods after the closing of the merger relate to New Duke Energy. Cinergy’s results have been included in the accompanying Consolidated Statements of Operations from the effective date of acquisition and thereafter (see “Cinergy Merger” in Note 2). Both Old Duke Energy and New Duke Energy are referred to as Duke Energy herein.

Shares of common stock of New Duke Energy carry a stated par value of $0.001, while shares of common stock of Old Duke Energy had been issued at no par. In April 2006, as a result of the conversion of all outstanding shares of Old Duke Energy common stock to New Duke Energy common stock, the par value of the shares issued was recorded in Common Stock within Common Stockholders’ Equity in the Consolidated Balance Sheets and the excess of issuance price over stated par value was recorded in Additional Paid-in Capital within Common Stockholders’ Equity in the Consolidated Balance Sheets. Prior to the conversion of common stock from shares of Old Duke Energy to New Duke Energy, all proceeds from issuances of common stock were solely reflected in Common Stock within Common Stockholders’ Equity in the Consolidated Balance Sheets.

On September 7, 2006, Duke Energy 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 Energy has deconsolidated DCP Midstream, LLC (formerly Duke Energy Field Services, LLC) (DEFS) due to a reduction in ownership and its inability to exercise control over DEFS (see Note 13). DEFS has been subsequently accounted for as an equity method investment.

On January 2, 2007, Duke Energy completed the spin-off of its natural gas businesses, including Duke Energy’s 50% interest in DEFS, to shareholders. The new natural gas business, which is named Spectra Energy Corp. (Spectra Energy), consists principally of the operations of Spectra Energy Capital LLC (Spectra Energy Capital, formerly Duke Capital LLC), excluding certain operations which were transferred from Spectra Energy Capital to Duke Energy in December 2006, primarily International Energy and Duke Energy’s effective 50% interest in the Crescent JV. The use of the term Spectra Energy Capital relates to operations of the former Duke Capital LLC or the post-spin Spectra Energy Capital, as the context requires. Amounts contained in these Notes, as well as the accompanying Consolidated Financial Statements, include assets and liabilities, results of operations and cash flows, as well as certain litigation matters and guarantee obligations, which have been transferred to Spectra Energy as part of the spin-off.

Recasting of Previously Issued Financial Statements.As discussed above, on January 2, 2007, Duke Energy completed the spin-off of its natural gas businesses, which primarily consists of Duke Energy’s former Natural Gas Transmission business segment and Duke Energy’s former Field Services business segment, which represented Duke Energy’s 50% ownership interest in DEFS. Accordingly, the results of operations of these businesses are presented as discontinued operations for all periods presented in the accompanying

52

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DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

Consolidated Statements of Operations. Assets and liabilities of entities included in the spin-off of Spectra Energy were transferred from Duke Energy on a historical cost basis on the date of the spin-off transaction. No gain or loss was recognized on the distribution of these operations to Duke Energy shareholders. Approximately $20.5 billion of assets, $14.9 billion of liabilities (which includes approximately $8.6 billion of debt) and $5.6 billion of common stockholders’ equity (which includes approximately $1.0 billion of accumulated other comprehensive income) were distributed from Duke Energy as of the date of the spin-off. The primary businesses remaining in Duke Energy post-spin are the U.S. Franchised Electric and Gas business segment, the Commercial Power business segment, the International Energy business segment and Duke Energy’s effective 50% interest in the Crescent JV.

Additionally, in February 2007, International Energy completed the disposition of its assets in Bolivia. Accordingly, the results of operations related to Bolivia have been reflected as a component of discontinued operations for all periods presented. See Note 13.

The changes to reflect these operations as discontinued operations impact Notes 1, 2, 3, 6, 8, 9, 11, 12, 13, 17, 19, 20, 22, 24, and 26. Except as required to reflect these operations as discontinued operations, the financial statements have not been otherwise modified or updated from those presented in Duke Energy’s Form 10-K for the year ended December 31, 2006, except for updates related to the Duke Energy Carolinas rate case in the “Duke Energy Carolinas Rate Case” subsection of the “U.S. Franchised Electric and Gas” section of Note 4 and the Cliffside Steam Station and the William States Lee III nuclear station in the “Other” subsection of the “U.S. Franchised Electric and Gas” section of Note 4.

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

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

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

Restricted Funds Held in Trust. At December 31, 2006, Duke Energy had approximately $212 million of restricted cash related primarily to proceeds from debt issuances that are held in trust, primarily for the purpose of funding future environmental expenditures. This amount is reflected in Other Investments and Other Assets on the Consolidated Balance Sheets.

Short-term Investments. Duke Energy actively invests a portion of its available cash balances in various financial instruments, such as tax-exempt debt securities that frequently have stated maturities of 20 years or more and tax-exempt money market preferred securities. These instruments provide for a high degree of liquidity through features such as daily and seven day notice put options and 7, 28, and 35 day auctions which allow for the redemption of the investments at their face amounts plus earned income. As Duke Energy intends to sell these instruments within one year or less, generally within 30 days from the balance sheet date, they are classified as current assets. Duke Energy 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; and coal held for electric generation. Inventory is recorded at the lower of cost or market value, primarily using the average cost method. The increase in inventory at December 31, 2006 as compared to December 31, 2005 is primarily attributable to inventory acquired as part of the merger with Cinergy.

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Notes To Consolidated Financial Statements—(Continued)

Components of Inventory

	December 31,
	2006		2005
	(in millions)
Materials and supplies	$	586	$	434
Natural gas		290		269
Coal held for electric generation		383		115
Petroleum products		99		45
Total inventory	$	1,358	$	863

Accounting for Risk Management and Hedging Activities and Financial Instruments. Duke Energy 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 swaps, futures, forwards, options and swaptions. All derivative instruments not designated and qualifying for the normal purchases and normal sales exception under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS No. 133), as amended, are recorded on the Consolidated Balance Sheets at their fair value as Unrealized Gains or Unrealized Losses on Mark-to-Market and Hedging Transactions. Cash inflows and outflows related to derivative instruments, except those that contain financing elements and those related to net 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.

Duke Energy designates 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 Energy’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 Energy Accounting Model	Presentation of Gains & Losses or Revenue & Expense
Trading derivatives	Mark-to-market(a)	Net basis in Non-regulated Electric, Natural Gas, Natural Gas Liquids (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 Energy 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 Energy’s application of this term could differ from that of other companies.

(b) An accounting term used by Duke Energy 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 Energy’s application of this term could differ from that of other companies.

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Notes To Consolidated Financial Statements—(Continued)

Where Duke Energy’s derivative instruments are subject to a master netting agreement and the criteria of the Financial Accounting Standards Board (FASB) Interpretation (FIN) 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 Energy 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 Energy prepares formal documentation of the hedge in accordance with SFAS No. 133. In addition, at inception and every three months, Duke Energy formally assesses whether the hedge contract is highly effective in offsetting changes in cash flows or fair values of hedged items. Duke Energy 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 Common Stockholders’ Equity and Comprehensive Income (Loss) as Accumulated Other Comprehensive Income (Loss) (AOCI) until earnings are affected by the hedged transaction. Duke Energy 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 Energy 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. On a limited basis, Duke Energy Carolinas and Duke Energy Ohio apply the normal purchase and normal sales exception to certain contracts. If contracts cease to meet this exception, the fair value of the contracts is recognized on the Consolidated Balance Sheets and the contracts are accounted for using the 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, Duke Energy discontinued hedge accounting for forward natural gas and power contracts accounted for as cash flow hedges related to the former DENA operations and disqualified other forward power contracts previously designated under the normal purchases normal sales exception effective September 2005.

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 Energy 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 Energy 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 Energy performs the annual review for goodwill impairment at the reporting unit level, which Duke Energy 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.

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Duke Energy primarily 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 an estimated run rates of operation, maintenance, and general and administrative costs. In estimating cash flows, Duke Energy 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 marketable securities held in the Nuclear Decommissioning Trust Funds (NDTF) and 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 Energy’s Consolidated Balance Sheets. Unrealized and realized gains and losses, net of tax, on the NDTF are reflected in regulatory assets or liabilities on Duke Energy’s Consolidated Balance Sheets as Duke Energy expects to recover all costs for decommissioning its nuclear generation assets through regulated rates. Unrealized holding gains and losses, net of tax, on all other available-for-sale securities are reflected in AOCI in Duke Energy’s Consolidated Balance Sheets until they are realized, at which time they are reflected in earnings. Cash flows from purchases and sales of long-term investments (including the NDTF) 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 fair value, if impaired. Duke Energy capitalizes all construction-related direct labor and material costs, as well as indirect construction costs. Indirect costs include general engineering, taxes and the cost of funds used during construction. The cost of renewals and betterments that extend the useful life of property, plant and equipment is also capitalized. The cost of repairs, replacements and major maintenance projects, which do not extend the useful life or increase the expected output of property, plant and equipment, is expensed as it is incurred. Depreciation is generally computed over the asset’s estimated useful life using the straight-line method. The composite weighted-average depreciation rates, excluding nuclear fuel, were 3.51% for 2006, 3.34% for 2005, and 3.49% for 2004. Also, see “Deferred Returns and Allowance for Funds Used During Construction (AFUDC),” discussed below.

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

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

Investments in Residential, Commercial, and Multi-Family Real Estate. Prior to the deconsolidation of Crescent in September 2006, investments in residential, commercial and multi-family real estate were 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, which are carried at lower of cost or fair value less costs to sell 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 Energy 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

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undiscounted cash flows. If the carrying value of the long-lived asset is not recoverable based on these estimated future undiscounted cash flows, the impairment loss is measured as the excess of the asset’s carrying value over its fair value, such that the asset’s carrying value is adjusted to its estimated fair value.

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

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

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

Captive Insurance Reserves.Duke Energy has captive insurance subsidiaries which provide insurance coverage to Duke Energy 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 Energy’s captive insurance entities also have reinsurance coverage, which provides reimbursement to Duke Energy for certain losses above a per incident and/or aggregate retention. Duke Energy’s captive insurance entities also have an aggregate stop-loss insurance coverage, which provides reimbursement from third parties to Duke Energy for its paid losses above certain per line of coverage aggregate amounts during a policy year. Duke Energy 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 Energy eliminated intercompany reserves at its captive insurance subsidiaries of approximately $64 million which was a correction of an immaterial accounting error related to prior periods.

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.

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

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

Duke Energy has entered into various indemnification agreements related to purchase and sale agreements and other types of contractual agreements with vendors and other third parties. These agreements typically cover environmental, tax, litigation and other matters, as well as breaches of representations, warranties and covenants. Typically, claims may be made by third parties for various periods of time, depending on the nature of the claim. Duke Energy’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 (see Note 18).

Stock-Based Compensation. Effective January 1, 2006, Duke Energy adopted the provisions of SFAS No. 123(R), “Share-Based Payment” (SFAS No. 123(R)) (see Note 20). SFAS No. 123(R) establishes accounting for stock-based awards exchanged for employee and certain non-employee services. Accordingly, for employee awards, equity classified stock-based compensation cost is measured at the grant date, based on the fair value of the award, and is recognized as expense over the requisite service period, which generally begins on the date the award is granted through the earlier of the date the award vests or the date the employee becomes retirement eligible. Awards, including stock options, granted to employees that are already retirement eligible are deemed to have vested immediately upon issuance, and therefore, compensation cost for those awards is recognized on the date such awards are granted.

Duke Energy elected to adopt the modified prospective application method as provided by SFAS No. 123(R), and accordingly, financial statement amounts periods prior to January 1, 2006 in this Form 10-K have not been restated. There were no modifications to outstanding stock options prior to the adoption of SFAS 123(R).

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 stock options granted under those plans was equal to the market value of the underlying common stock on the grant date, no compensation cost was recognized in the accompanying Consolidated Statements of Operations.

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

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 actual and estimated unbilled revenues are immaterial.

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. Prior to the deconsolidation of Crescent in September 2006, profit was 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 were allocated to land sold based on relative sales values. Crescent recognized revenues from commercial and multi-family project sales at closing, or later using a deferral method when the criteria for sale accounting had not been met at closing. Profit was recognized based on the difference between the sales price and the carrying cost of the project. Revenue was recognized under the completed contract method for condominium units that Crescent developed and sold in Florida.

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

Deferred Returns and Allowance for Funds Used During Construction (AFUDC). Deferred returns, recorded in accordance with SFAS No. 71, represent the estimated financing costs associated with funding certain regulatory assets or liabilities of U.S. Franchised Electric and Gas. Those costs arise primarily from the funding of purchased capacity costs collected in rates. Deferred returns are non-cash items and are primarily recognized as an addition to purchased capacity costs, which are included in Other Current Liabilities and Other Deferred Credits and Other Liabilities on the Consolidated Balance Sheets, with an offsetting debit or credit to Other Income and Expenses, net. The amount of deferred returns included in Other Income and Expenses, net was ($14) million in 2006, ($13) million in 2005, and ($9) million in 2004.

AFUDC, which represents the estimated debt and equity costs of capital funds necessary to finance the construction of new regulated facilities, consists of two components, an equity component and an interest component. The equity component is a non-cash item. AFUDC is capitalized as a component of Property, Plant and Equipment cost, with offsetting credits to the Consolidated Statements of Operations. After construction is completed, Duke Energy is permitted to recover these costs through inclusion in the rate base and in the depreciation provision. The total amount of AFUDC included within income from continuing operations in the Consolidated Statements of Operations was $75 million in 2006, which consisted of an after-tax equity component of $46 million and a before-tax interest expense component of $29 million. The total amount of AFUDC included within income from continuing operations in the Consolidated Statements of Operations was $31 million in 2005, which consisted of an after-tax equity component of $22 million and a before-tax interest expense component of $9 million. The total amount of AFUDC included within income from continuing operations in the Consolidated Statements of Operations was $23 million in 2004, which consisted of an after-tax equity component of $16 million and a before-tax interest expense component of $7 million. The preceding amounts exclude AFUDC of approximately $22 million, $17 million and $16 million for the years ended December 31, 2006, 2005 and 2004, respectively, which is included in Income From Discontinued Operations, net of tax, on the Consolidated Statements of Operations.

Accounting For Sales of Stock by a Subsidiary. Duke Energy accounts for sales of stock by a subsidiary under Staff Accounting Bulletin (SAB) No. 51, “Accounting for Sales of Stock of a Subsidiary” (SAB 51). 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 Energy 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 year ended December 31, 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 13), which is reflected in Income From Discontinued Operations, net of tax, in the Consolidated Statements of Operations.

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Accounting For Purchases and Sales of Emission Allowances.Duke Energy recognizes emission allowances in earnings as they are consumed or sold. Gains or losses on sales of emission allowances for non-regulated businesses are presented on a net basis in Gains (Losses) on Sales of Other Assets and Other, net, in the accompanying Consolidated Statements of Operations. For regulated businesses that do provide for direct recovery of emission allowances, any gains or losses on sales of recoverable emission allowances are included in the rate structure of the regulated entity and are deferred as a regulatory asset or liability. Future rates charged to retail customers are impacted by any gain or loss on sales of recoverable emission allowances and, therefore, as the recovery of the gain or loss is recognized in operating revenues, the regulatory asset or liability related to the emission allowance activity is recognized as a component of Fuel Used in Electric Generation and Purchased Power in the Consolidated Statements of Operations. For regulated businesses that do not provide for direct recovery of emission allowances through a cost tracking mechanism, gains and losses on sales of emission allowances are included in Gains (Losses) on Sales of Other Assets and Other, net in the Consolidated Statements of Operations, or are deferred, depending on level of regulatory certainty. Purchases and sales of emission allowances are presented gross as investing activities on the Consolidated Statements of Cash Flows.

Income Taxes. Duke Energy and its subsidiaries file a consolidated federal income tax return and other state and foreign jurisdictional returns as required. Deferred income taxes have been provided for temporary differences between the GAAP and tax carrying amounts of assets and liabilities. These differences create taxable or tax-deductible amounts for future periods. Investment tax credits have been deferred and are being amortized over the estimated useful lives of the related properties.

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

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

	Year Ended December 31, 2006		Year Ended December 31, 2005		Year Ended December 31, 2004
	(in millions)
Excise Taxes	$	221	$	121	$	116

Segment Reporting. SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information” (SFAS No. 131), establishes standards for a public company to report financial and descriptive information about its reportable operating segments in annual and interim financial reports. Operating segments are components of an enterprise about which separate financial information is available and evaluated regularly by the chief operating decision maker in deciding how to allocate resources and evaluate performance. Two or more operating segments may be aggregated into a single reportable segment provided aggregation is consistent with the objective and basic principles of SFAS No. 131, if the segments have similar economic characteristics, and the segments are considered similar under criteria provided by SFAS No. 131. There is no aggregation within Duke Energy’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 general-purpose financial statements, and changes in the measurement of segment amounts from period to period. The description of Duke Energy’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.

Foreign Currency Translation. The local currencies of Duke Energy’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. Gains and losses arising from transactions denominated in currencies other than the functional currency, 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

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and losses where Duke Energy 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.

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

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

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

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

SFAS No. 123(R)“Share-Based Payment” (SFAS No. 123(R)). In December 2004, the Financial Accounting Standards Board (FASB) issued SFAS No. 123(R), which replaces SFAS No. 123, “Accounting for Stock-Based Compensation,” and supersedes APB Opinion No. 25, “Accounting for Stock Issued to Employees.” SFAS No. 123(R) requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values. For Duke Energy, 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 Energy to record compensation expense for all unvested awards beginning January 1, 2006.

Duke Energy currently also has retirement eligible employees with outstanding share-based payment awards (unvested stock awards, stock based performance awards and phantom stock awards). Compensation cost related to those awards was previously expensed over the stated vesting period or until actual retirement occurred. Effective January 1, 2006, Duke Energy 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 Energy in periods subsequent to adoption of SFAS No. 123(R) will be largely dependent upon the nature of any new share-based compensation awards issued to employees. (See Note 20.)

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

FASB Staff Position (FSP) No. FAS 123(R)-4, “Classification of Options and Similar Instruments Issued as Employee Compensation That Allow for Cash Settlement upon the Occurrence of a Contingent Event” (FSP No. FAS 123(R)-4).In February 2006, the FASB staff

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issued FSP FAS No. 123(R)-4 to address the classification of options and similar instruments issued as employee compensation that allow for cash settlement upon the occurrence of a contingent event. The guidance amends SFAS No. 123(R). FSP No. FAS 123(R)-4 provides that cash settlement features that can be exercised only upon the occurrence of a contingent event that is outside the employee’s control does not require classifying the option or similar instrument as a liability until it becomes probable that the event will occur. FSP No. FAS 123(R)-4 applies only to options or similar instruments issued as part of employee compensation arrangements. The guidance in FSP No. FAS 123(R)-4 was effective for Duke Energy as of April 1, 2006. Duke Energy adopted SFAS No. 123(R) as of January 1, 2006 (see Note 20). The adoption of FSP No. FAS 123(R)-4 did not have a material impact on Duke Energy’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 Energy beginning January 1, 2006. This FSP addresses the determination as to when an investment is considered impaired, whether that impairment is other than temporary, and the measurement of an impairment loss. This FSP also includes accounting considerations subsequent to the recognition of an other-than-temporary impairment and requires certain disclosures about unrealized losses that have not been recognized as other-than-temporary impairments. The guidance in this FSP amends SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities,” and SFAS No. 124, “Accounting for Certain Investments Held by Not-for-Profit Organizations,” and APB Opinion No. 18. The adoption of FSP No. FAS 115-1 and 124-1 did not have a material impact on Duke Energy’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 Energy first becomes involved or existing entities for which a reconsideration event occurs after July 1, 2006. The adoption of FSP No. FIN 46(R)-6 did not have a material impact on Duke Energy’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 Energy for all conversions within its scope that resulted from the exercise of call options beginning July 1, 2006. The adoption of EITF No. 05-1 did not have a material impact on Duke Energy’s 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 of 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 Energy 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 (see Note 22). Retrospective application is not permitted. The adoption of SFAS No. 158 recognition and disclosure provisions resulted in an increase in total assets of approximately $211 million (consisting of an increase in regulatory assets of $595 million, an increase in deferred tax assets of $144 million, offset by a decrease in pre-funded pension costs of $522 million and a decrease in intangible assets of $6 million), an increase in total liabilities of approximately $461 million and a decrease in accumulated other comprehensive income, net of tax, of approximately $250 million as of December 31, 2006. The adoption of SFAS No. 158 did not have any material impact on Duke Energy’s consolidated results of operations or cash flows.

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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 Energy 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 Energy 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. 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 focuses primarily on the impact of a misstatement on the income statement—including the reversing effect of prior year misstatements—but its use can lead to the accumulation of misstatements in the balance sheet. The balance sheet approach, on the other hand, focuses primarily on the effect of correcting the period-end balance sheet with less emphasis on the reversing effects of prior year errors on the income statement. The SEC staff believes that registrants should quantify errors using both a balance sheet and an income statement approach (a “dual approach”) and evaluate whether either approach results in quantifying a misstatement that, when all relevant quantitative and qualitative factors are considered, is material.

SAB No. 108 was effective for Duke Energy’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 Energy has historically used a dual approach for quantifying identified financial statement misstatements. Therefore, the adoption of SAB No. 108 did not have any material impact on Duke Energy’s consolidated results of operations, cash flows or financial position.

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

SFAS No. 153, “Exchanges of Nonmonetary Assets — an amendment of APB Opinion No. 29” (SFAS No. 153). In December 2004, the FASB issued SFAS No. 153 which amends APB Opinion No. 29, “Accounting for Nonmonetary Transactions,” by eliminating the exception to the fair-value principle for exchanges of similar productive assets, which were accounted for under APB Opinion No. 29 based on the book value of the asset surrendered with no gain or loss recognition. SFAS No. 153 also eliminates APB Opinion No. 29’s concept of culmination of an earnings process. The amendment requires that an exchange of nonmonetary assets be accounted for at fair value if the exchange has commercial substance and fair value is determinable within reasonable limits. Commercial substance is assessed by comparing the entity’s expected cash flows immediately before and after the exchange. If the difference is significant, the transaction is considered to have commercial substance and should be recognized at fair value. SFAS No. 153 is effective for nonmonetary transactions occurring on or after July 1, 2005. The adoption of SFAS No. 153 did not have a material impact on Duke Energy’s consolidated results of operations, cash flows or financial position.

FASB Interpretation No. (FIN) 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, “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 47 were effective for Duke Energy as of December 31, 2005, and resulted in an increase in assets of $31 million, an increase in liabilities of $35 million and a net-of-tax cumulative effect adjustment to earnings of approximately $4 million.

FASB Staff Position (FSP) No. APB 18-1, “Accounting by an Investor for Its Proportionate Share of Accumulated Other Comprehensive Income of an Investee Accounted for under the Equity Method in Accordance with APB Opinion No. 18 upon a Loss of Significant

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

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

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

The provisions of FIN 46 applied immediately to variable interest entities created, or interests in variable interest entities obtained, after January 31, 2003, while the provisions of FIN 46R were required to be applied to those entities, except for special purpose entities, by the end of the first reporting period ending after March 15, 2004 (March 31, 2004 for Duke Energy). For variable interest entities created, or interests in variable interest entities obtained, on or before January 31, 2003, FIN 46 or FIN 46R was required to be applied to special-purpose entities by the end of the first reporting period ending after December 15, 2003 (December 31, 2003 for Duke Energy), and was required to be applied to all other non-special purpose entities by the end of the first reporting period ending after March 15, 2004 (March 31, 2004 for Duke Energy). See Note 23 for a discussion of certain variable interest entities acquired by Duke Energy as part of the Cinergy merger. Duke Energy 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, 2006 and 2005. The impact of consolidating these entities on Duke Energy’s consolidated financial statements was not material. In addition, at December 31, 2005, Duke Energy recorded Net Property, Plant and Equipment of $109 million and Long-term Debt of $173 million on the Consolidated Balance Sheets, associated with a natural gas processing variable interest entity that was consolidated by Duke Energy. In 2006, Duke Energy exercised its right to repurchase the assets held by the variable interest entity and repaid the loan.

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

• 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

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• 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 Energy effective December 31, 2003 with the interim period disclosures applied beginning with the quarter ended March 31, 2004, except for the disclosure provisions of estimated future benefit payments which were effective for Duke Energy for the year ended December 31, 2004. (See Note 22 for the additional related disclosures).

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

The provisions of FSP No. FAS 106-2 were effective for the first interim period beginning after June 15, 2004. Duke Energy adopted FSP No. FAS 106-2 retroactively to the date of enactment of the Modernization Act, December 8, 2003, as allowed by the FSP. (See Note 22 for discussion of the effects of adopting this FSP).

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

Under the guidance in FSP No. FAS 109-1, which was issued in December 2004, the deduction will be treated as a “special deduction” as described in SFAS No. 109, “Accounting for Income Taxes” (SFAS No. 109). As such, for Duke Energy, the special deduction had no material impact on deferred tax assets and liabilities existing at the enactment date. Rather, the impact of this deduction is reported in the periods in which the deductions are claimed on the tax returns. For the years ended December 31, 2006 and 2005, Duke Energy recognized a benefit of approximately $0 and $9 million, respectively, relating to the deduction from qualified domestic activities.

FSP No. FAS 109-2, “Accounting and Disclosure Guidance for the Foreign Earnings Repatriation Provision within the American Jobs Creation Act of 2004” (FSP No. FAS 109-2). In addition to the qualified domestic production activities deduction discussed above, the Act creates a temporary incentive for U.S. corporations to repatriate accumulated income earned abroad by providing an 85 percent dividends received deduction for certain dividends from controlled foreign corporations. FSP No. FAS 109-2, which was issued in December 2004, states that a company is allowed time beyond the financial reporting period of enactment to evaluate the effect of the Act on its plan for reinvestment or repatriation of foreign earnings, as it applies to the application of SFAS No. 109. Although the deduction is subject to a number of limitations and some uncertainty remains as to how to interpret numerous provisions in the Act, Duke Energy believes that it has the information necessary to make an informed decision on the impact of the Act on its repatriation plans. Based on that decision, Duke Energy has repatriated approximately $500 million in extraordinary dividends, as defined in the Act, and accordingly recorded a corresponding tax liability of $39 million as of December 31, 2005. However, Duke Energy has not provided for U.S. deferred income taxes or foreign withholding tax on basis differences for its non-U.S. subsidiaries that result primarily from undistributed earnings of approximately $420 million as of December 31, 2006 and $290 million as of December 31, 2005, which Duke Energy intends to reinvest

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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.

EITF Issue No. 04-08, “The Effect of Contingently Convertible Debt on Diluted Earnings per Share” (EITF 04-08). In September 2004, the EITF reached a consensus on Issue No. 04-8. The consensus requires that the potential common stock related to contingently convertible securities (Co-Cos) with market price contingencies be included in diluted earnings per share calculations using the if-converted method specified in SFAS No. 128, “Earnings per Share” (SFAS No. 128), whether the market price contingencies have been met or not. Co-Cos generally require conversion into a company’s common stock if certain specified events occur, such as a specified market price for the company’s common stock. Prior to the issuance of EITF 04-08, Co-Cos were treated as contingently issuable shares under SFAS No. 128, and therefore, the contingencies, must have been met in order for the potential common shares to be included in diluted EPS. Therefore, Co-Cos were only included in diluted EPS during periods in which the contingencies had been met. The consensus is effective for fiscal years ended after December 15, 2004 and is required to be applied retroactively to all periods in which any Co-Cos were outstanding, resulting in restatement of diluted EPS if the impact of the Co-Cos was dilutive.

As discussed in Note 15, Duke Energy issued $770 million par value of contingently convertible notes in May of 2003, bearing an interest rate of 1.75% per annum that contain several contingencies, including a market price contingency that, if met, may require conversion of the notes into Duke Energy common stock. Conversion may be required, at the option of the holder, if any one of the contingencies is met. During 2006 and 2005, these convertible senior notes became convertible into shares of Duke Energy common stock due to the market price of Duke Energy common stock. Holders of the convertible senior notes were allowed to exercise their right to convert on or prior to December 31, 2006. During 2006 and 2005, approximately 27 million and 1.2 million shares of common stock, respectively, were issued related to this conversion, which resulted in the retirement of approximately $632 million and $28 million of convertible senior notes, respectively. Therefore, as discussed in Note 19, Duke Energy has included potential weighted average common shares outstanding of approximately 14 million, 32 million and 33 million for the years ended December 31, 2006, 2005 and 2004, respectively, in the calculation of diluted EPS.

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

SFAS No. 155, “Accounting for Certain Hybrid Financial Instruments — an amendment of FASB Statements No. 133 and 140” (SFAS No. 155).In February 2006, the FASB issued SFAS No. 155, which amends SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” and SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities.” SFAS No. 155 allows financial instruments that have embedded derivatives to be accounted for at fair value at acquisition, at issuance, or when a previously recognized financial instrument is subject to a remeasurement (new basis) event, on an instrument-by-instrument basis, in cases in which a derivative would otherwise have to be bifurcated. SFAS No. 155 is effective for Duke Energy for all financial instruments acquired, issued, or subject to remeasurement after January 1, 2007, and for certain hybrid financial instruments that have been bifurcated prior to the effective date, for which the effect is to be reported as a cumulative-effect adjustment to beginning retained earnings. Duke Energy 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. 156, “Accounting for Servicing of Financial Assets — an amendment of FASB Statement No. 140” (SFAS No. 156).In March 2006, the FASB issued SFAS No. 156, which amends SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities.” SFAS No. 156 requires recognition of a servicing asset or liability when an entity enters into arrangements to service financial instruments in certain situations. Such servicing assets or servicing liabilities are required to be initially measured at fair value, if practicable. SFAS No. 156 also allows an entity to subsequently measure its servicing assets or servicing liabilities using either an amortization method or a fair value method. SFAS No. 156 is effective for Duke Energy as of January 1, 2007, and must be applied prospectively, except that where an entity elects to remeasure separately recognized existing arrangements and reclassify certain available-for-sale securities to trading securities, any effects must be reported as a cumulative-effect adjustment to retained earnings. Duke Energy does not anticipate the adoption of SFAS No. 156 will have any material impact on its consolidated results of operations, cash flows or financial position.

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

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Duke Energy is currently evaluating the impact of adopting SFAS No. 157, and cannot currently estimate the impact of SFAS No. 157 on its consolidated results of operations, cash flows or financial position.

SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (SFAS No. 159).In February 2007, the FASB issued SFAS No. 159, which permits entities to choose to measure many financial instruments and certain other items at fair value. For Duke Energy, SFAS No. 159 is effective as of January 1, 2008 and will have no impact on amounts presented for periods prior to the effective date. Duke Energy cannot currently estimate the impact of SFAS No. 159 on its consolidated results of operations, cash flows or financial position and has not yet determined whether or not it will choose to measure items subject to SFAS No. 159 at fair value.

FIN 48,“Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109”. In July 2006, the FASB issued FIN 48, which provides guidance on accounting for income tax positions about which Duke Energy has concluded there is a level of uncertainty with respect to the recognition in Duke Energy’s financial statements. FIN 48 prescribes a minimum recognition threshold a tax position is required to meet. Tax positions are defined very broadly and include not only tax deductions and credits but also decisions not to file in a particular jurisdiction, as well as the taxability of transactions. Duke Energy will implement FIN 48 effective January 1, 2007. The implementation is expected to result in a cumulative effect adjustment to beginning Retained Earnings on the Consolidated Statement of Common Stockholders’ Equity and Comprehensive Income (Loss) in the first quarter 2007 in the range of $15 million to $30 million. Corresponding entries will impact a variety of balance sheet line items, including Deferred income taxes, Taxes accrued, Other Liabilities, and Goodwill. Upon implementation of FIN 48, Duke Energy will reflect interest expense related to taxes as Interest Expense, in the Consolidated Statement of Operations. In addition, subsequent accounting for FIN 48 (after January 1, 2007) will involve an evaluation to determine if any changes have occurred that would impact the existing uncertain tax positions as well as determining whether any new tax positions are uncertain. Any impacts resulting from the evaluation of existing uncertain tax positions or from the recognition of new uncertain tax positions would impact income tax expense and interest expense in the Consolidated Statement of Operations, with offsetting impacts to the balance sheet line items described above. Because of the spin-off of Spectra Energy in the first quarter of 2007, certain liabilities and deferred tax assets related to uncertain tax positions filed on Spectra Energy tax returns will be removed from Duke Energy’s balance sheet. Uncertain tax positions on consolidated or combined tax returns filed by Duke Energy which are indemnified by Spectra Energy will be recorded as receivables from Spectra Energy.

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

FSP No. AUG AIR-1, “Accounting for Planned Major Maintenance Activities,” (FSP No. AUG AIR-1).In September 2006, the FASB Staff issued FSP No. AUG AIR-1. This FSP prohibits the use of the accrue-in-advance method of accounting for planned major maintenance activities in annual and interim financial reporting periods, if no liability is required to be recorded for an asset retirement obligation based on a legal obligation for which the event obligating the entity has occurred. The FSP also requires disclosures regarding the method of accounting for planned major maintenance activities and the effects of implementing the FSP. The guidance in this FSP is effective for Duke Energy as of January 1, 2007 and will be applied retrospectively for all financial statements presented. Duke Energy 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

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seller and a customer and may include, but are not limited to, sales, use, value added, and some excise taxes. For taxes within the issue’s scope, the consensus requires that entities present such taxes on either a gross (i.e. included in revenues and costs) or net (i.e. exclude from revenues) basis according to their accounting policies, which should be disclosed. If such taxes are reported gross and are significant, entities should disclose the amounts of those taxes. Disclosures may be made on an aggregate basis. The consensus is effective for Duke Energy beginning January 1, 2007. Duke Energy 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 Energy 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 Energy does not anticipate the adoption of EITF No. 06-5 will have any material impact on its consolidated results of operations, cash flows or financial position.

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

2. Acquisitions and Dispositions

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

Cinergy Merger. On April 3, 2006, the previously announced merger between Duke Energy and Cinergy was consummated (see Note 1 for additional information). For accounting purposes, the effective date of the merger was April 1, 2006. The merger combines the Duke Energy and Cinergy regulated franchises as well as deregulated generation in the Midwestern United States. The merger provides more regulatory, geographic and weather diversity to Duke Energy’s earnings. See Note 4 for discussion of regulatory impacts of the merger.

The merger has been accounted for under the purchase method of accounting with Duke Energy treated as the acquirer for accounting purposes. As a result, the assets and liabilities of Cinergy were recorded at their respective fair values as of April 3, 2006 and the results of Cinergy’s operations are included in the Duke Energy consolidated financial statements beginning as of the effective date of the merger. Except for an adjustment related to pension and other postretirement benefit obligations, as mandated by SFAS No. 87, “Employers’ Accounting for Pensions” (SFAS No. 87) and SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions,” (SFAS No. 106), the accompanying consolidated financial statements do not reflect any pro forma adjustments related to

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Cinergy’s regulated operations that are accounted for pursuant to SFAS No. 71, which are comprised of the regulated transmission and distribution operations of Duke Energy Ohio, Inc. (Duke Energy Ohio) (formerly The Cincinnati Gas & Electric Company’s regulated transmission and distribution), Duke Energy Indiana, Inc. (Duke Energy Indiana) (formerly PSI Energy, Inc. ) and Duke Energy Kentucky, Inc. (Duke Energy Kentucky) (formerly The Union Light, Heat and Power Company). Under the rate setting and recovery provisions currently in place for these regulated operations which provide revenues derived from cost, the fair values of the individual tangible and intangible assets and liabilities are considered to approximate their carrying values.

The fair values used for recording the assets acquired and liabilities assumed are based on valuation analyses.

In connection with the merger, Duke Energy issued 1.56 shares of Duke Energy common stock for each outstanding share of Cinergy common stock, which resulted in the issuance of approximately 313 million shares of Duke Energy common stock. Based on the market price of Duke Energy common stock during the period including the two trading days before through the two trading days after May 9, 2005, the date Duke Energy and Cinergy announced the merger, the transaction is valued at approximately $9.1 billion and has resulted in incremental goodwill to Duke Energy of approximately $4.5 billion. The amount of goodwill results from significant strategic and financial benefits of the merger including:

• increased financial strength and flexibility;

• stronger utility business platform;

• greater scale and fuel diversity, as well as improved operational efficiencies for the merchant generation business;

• broadened electric distribution platform;

• improved reliability and customer service through the sharing of best practices;

• increased scale and scope of the electric and gas businesses with stand-alone strength;

• complementary positions in the Midwest;

• greater customer diversity;

• combined expertise; and

• significant cost savings synergies.

The following table summarizes the estimated fair values of the assets acquired and liabilities assumed at the date of acquisition:

Purchase Price Allocation

	April 3, 2006
	(in millions)
Purchase price	$	9,115
Current assets		2,670
Investments and other assets		1,499
Property, plant and equipment(a)		10,595
Intangible assets		1,091
Regulatory assets and deferred debits		1,449
Total assets acquired		17,304
Current liabilities		4,137
Long-term debt		4,295
Deferred credits and other liabilities		4,266
Minority interests		11
Net identifiable assets acquired		4,595
Goodwill	$	4,520

(a) Amounts recorded for regulated property, plant and equipment by Duke Energy on the acquisition date are net of approximately $3,995 million of accumulated depreciation of acquired assets.

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Goodwill recorded as of December 31, 2006 resulting from Duke Energy’s merger with Cinergy is $4,385 million, none of which is deductible for income tax purposes. Approximately $135 million of goodwill was allocated to Cinergy Marketing and Trading, LP, and Cinergy Canada, Inc. (collectively CMT) (see Note 13), which was sold in October 2006. As of December 31, 2006, the allocation of the remaining goodwill to the reporting units was substantially complete, with approximately $3,500 million and $885 million being allocated to the U.S. Franchised Electric and Gas and Commercial Power segments, respectively (see Note 10).

The following unaudited consolidated pro forma financial results are presented as if the Cinergy merger had occurred at the beginning of each of the periods presented:

Unaudited Consolidated Pro Forma Results

	Year Ended December 31,
	2006		2005
	(in millions, except per share amounts)
Operating revenues	$	12,270	$	12,022
Income from continuing operations		1,073		1,261
Net income		1,854		2,230
Earnings available for common stockholders		1,854		2,218
Earnings per share (from continuing operations)
Basic	$	0.86	$	1.01
Diluted	$	0.85	$	0.98
Earnings per share
Basic	$	1.48	$	1.78
Diluted	$	1.46	$	1.73

Pro forma results for the year ended December 31, 2006 include approximately $128 million of charges related to costs to achieve the merger and related synergies, which are recorded within Operating Expenses on the Consolidated Statements of Operations. Pro forma results for the years ended December 31, 2006 and 2005 do not reflect the pro forma effects of any significant transactions completed by Duke Energy other than the merger with Cinergy. The pre-tax impacts of purchase accounting on the 2006 results of operations of Duke Energy were charges of approximately $98 million.

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

During the first quarter of 2006, Duke Energy acquired the remaining 33 ¹/3% interest in Bridgeport Energy LLC (Bridgeport) from United Bridgeport Energy LLC (UBE) for approximately $71 million. No goodwill was recorded as a result of this acquisition. The assets and liabilities of Bridgeport were included as part of DENA’s power generation assets which were sold to a subsidiary of LS Power Equity Partners (LS Power) (see Note 13).

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

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See Note 13 for acquisitions related to discontinued operations.

The pro forma results of operations for Duke Energy as if those acquisitions (other than the Cinergy merger) which closed prior to December 31, 2006 occurred as of the beginning of the periods presented do not materially differ from reported results.

Dispositions.In December 2006, Duke Energy Indiana agreed to sell one unit of its Wabash River Power Station (Unit 1) to the Wabash Valley Power Association. The price of the transaction will be based on the book value of Unit 1 at the time of closing, which is currently estimated to be approximately $110-$120 million. The sale must be approved by the Indiana Utility Regulatory Commission (IURC), the FERC, the FTC and the Department of Justice (DOJ). These approvals are anticipated by mid-2007. Duke Energy does not anticipate recognizing a material gain or loss on this transaction.

On January 12, 2007, Duke Energy Indiana filed a petition with the IURC requesting authority to sell Wabash River Unit #1 to the Wabash Valley Power Association, Inc. pursuant to an Asset Purchase Agreement along with approval of the Operation and Maintenance Agreement and the Common Facilities Agreement associated with the sale. Wabash River Unit #1 will be replaced by the Wheatland facility which was purchased by Duke Energy Indiana in 2005. Duke Energy Indiana is also requesting approval of the accounting and ratemaking treatment of the sale to reflect the difference in costs of the two facilities.

For the year ended December 31, 2006, the sale of other assets and businesses resulted in approximately $2 billion in proceeds and net pre-tax gains of $229 million recorded in Gains (Losses) 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 13, and sales by Crescent prior to deconsolidation which are discussed separately below. Significant sales of other assets during 2006 are detailed as follows:

• On September 7, 2006, an indirect wholly owned subsidiary of Duke Energy 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 Energy 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 $1.21 billion, net of transaction costs, of which approximately $1.19 billion was immediately distributed to Duke Energy. Immediately following the debt transaction, the MS Members collectively acquired a 49% membership interest in the Crescent JV from Duke Energy for a purchase price of approximately $415 million. A 2% interest in the Crescent JV was also 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 2% 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 Energy has an effective 50% ownership in the equity of Crescent JV for financial reporting purposes. In conjunction with this transaction, Duke Energy recognized a pre-tax gain on the sale of approximately $250 million which has been classified as a component of Gains (Losses) on Sales of Other Assets and Other, net in the accompanying Consolidated Statement of Operations for the year ended December 31, 2006. As a result of the Crescent transaction, Duke Energy 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 Energy’s equity investment in the Crescent JV is approximately $180 million as of December 31, 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.

• Commercial Power’s sale of emission allowances, which resulted in proceeds of $136 million and pre-tax losses on sales of approximately $29 million (see Note 10), which was recorded in Gains (Losses) on Sales of Other Assets and Other, net, in the Consolidated Statements of Operations. This was partially offset by the sale of the Pine Mountain synthetic fuel facility, which resulted in proceeds of approximately $8 million and a pre-tax gain of approximately $6 million, which was recorded in Gains (Losses) on Sales of Other Assets and Other, net, in the Consolidated Statements of Operations.

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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 year ended December 31, 2005, the sale of other assets, businesses and equity investments resulted in approximately $10 million in proceeds, pre-tax losses of $55 million recorded in Gains (Losses) on Sales of Other Assets and Other, net, 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 13, and commercial and multi-family 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 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 and Other, 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 (see Note 24).

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 13, and sales by Crescent which are discussed separately below) resulted in approximately $677 million in cash proceeds plus a $48 million note receivable from the buyers, and net pre-tax losses of $435 million recorded in Gains (Losses) on Sales of Other Assets and Other, net and pre-tax gains of $3 million recorded in (Losses) Gains on Sales and Impairments of Equity Method Investments on the Consolidated Statements of Operations. Significant sales of other assets in 2004 are detailed as follows:

• Commercial Power’s asset sales totaled approximately $464 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 and Other, net in the Consolidated Statements of Operations. Significant sales included:

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

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letter of credit. In February 2007, this guarantee was cancelled (see Note 18). Duke Energy will continue to provide services under a long-term operating agreement for one of the plants. As a result of Duke Energy’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.”

• During 2004, a 25% undivided interest in Commercial Power’s Vermillion facility was sold for proceeds of approximately $44 million. This sale was anticipated in 2003 and, therefore, an $18 million loss on sale was recorded during 2003.

• 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 $153 million in net proceeds. Those sales resulted in net pre-tax losses of $74 million, of which $75 million was recorded in Gains (Losses) on Sales of Other Assets, net and a $1 million gain was recorded in (Losses) Gains on Sales and Impairments of Equity Method Investments in the Consolidated Statements of Operations. These sales primarily related to some contracts at Duke Energy Trading and Marketing, LLC (DETM). DETM held a net liability position in certain 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 and Other, net in the 2004 Consolidated Statement of Operations. Other significant sales included Duke Energy Royal LLC’s interest in six energy service agreements and DukeSolutions Huntington Beach, LLC.

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.

See Note 13 for dispositions related to discontinued operations.

3. Business Segments

In conjunction with Duke Energy’s merger with Cinergy, effective with the second quarter of 2006, Duke Energy adopted new business segments that management believes properly align the various operations of Duke Energy with how the chief operating decision maker views the business. Duke Energy operates the following business units: U.S. Franchised Electric and Gas, Natural Gas Transmission, Field Services, Commercial Power, International Energy and Crescent. Prior to Duke Energy’s sale of an effective 50% ownership interest in Crescent in September 2006 (see below), this segment represented Duke Energy’s 100% ownership of Crescent Resources, LLC. Duke Energy’s chief operating decision maker regularly reviews financial information about each of these business units in deciding how to allocate resources and evaluate performance. As discussed in Note 1, on January 2, 2007, Duke Energy completed the spin-off of its natural gas businesses, which primarily consists of Duke Energy’s former Natural Gas Transmission business segment and Duke Energy’s former Field Services business segment, which represented Duke Energy’s 50% ownership interest in DEFS. Duke Energy operates the following business units subsequent to the spin-off of the natural gas businesses: U.S. Franchised Electric and Gas, Commercial Power, International Energy and Crescent. All of the Duke Energy business units are considered reportable segments under SFAS No. 131. Prior to the September 2005 announcement of the exiting of the majority of former DENA’s businesses (see below), former DENA’s operations were considered a separate reportable segment. The term DENA, as used throughout the Notes to Consolidated Financial Statements, refers to the former merchant generation operations in the Western and Eastern U.S., as well as operations in the Midwest and Southeast. Under Duke Energy’s new segment structure, the merchant generation operations of the Midwest and Southeast are presented in continuing operations as a component of the Commercial Power segment for all periods presented and the Western and Eastern operations are presented as a component of discontinued operations within Other for all periods presented. Prior to the change in business segments, former DENA’s continuing operations, which primarily include the merchant generation operations in the Midwest and Southeast, were included in Other in 2005 and as a component of the DENA segment in all prior periods, and discontinued operations were included in the former DENA segment for all periods. There is no aggregation within Duke Energy’s defined business segments.

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U.S. Franchised Electric and Gas generates, transmits, distributes and sells electricity in central and western North Carolina, western South Carolina, southwestern Ohio, central and southern Indiana, and northern Kentucky. U.S. Franchised Electric and Gas also transports and sells natural gas in southwestern Ohio and northern Kentucky. It conducts operations primarily through Duke Energy Carolinas, Duke Energy Ohio, Duke Energy Indiana and Duke Energy Kentucky. These electric and gas operations are subject to the rules and regulations of the FERC, the NCUC, the Public Service Commission of South Carolina (PSCSC), the Public Utilities Commission of Ohio (PUCO), the IURC and the Kentucky Public Service Commission (KPSC).

Cinergy, a Delaware corporation organized in 1993, owns all outstanding common stock of its public utility companies, Duke Energy Ohio and Duke Energy Indiana, as well as other businesses including (a) cogeneration and energy efficiency investments and (b) natural gas and power marketing and trading operations, conducted primarily through CMT, which was sold to Fortis in October 2006 (see Note 13).

Duke Energy Ohio, an Ohio corporation organized in 1837, is a combination electric and gas public utility company that provides service in the southwestern portion of Ohio and, through its wholly-owned subsidiary Duke Energy Kentucky, in nearby areas of Kentucky. Its principal lines of business include generation, transmission, and distribution of electricity, the sale of and/or transportation of natural gas, and power marketing and trading. The regulated operations of Duke Energy Ohio are included in the U.S. Franchised Electric and Gas segment, whereas the unregulated portion of the business is included in the Commercial Power segment.

Duke Energy Indiana, an Indiana corporation organized in 1942, is a vertically integrated and regulated electric utility that provides service in central and southern Indiana. Its primary line of business is generation, transmission, and distribution of electricity.

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 rules and regulations, while natural gas gathering, processing, transmission, distribution and storage operations in Canada are primarily subject to the rules and regulations of the National Energy Board (NEB) and the Ontario Energy Board (OEB). Natural Gas Transmission also includes 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, processes, transports, trades and markets, and stores natural gas; and fractionates, transports, gathers, treats, processes, trades and markets, and stores NGLs. It conducts operations primarily through DEFS, which is owned 50 percent by ConocoPhillips and 50 percent by Duke Energy. Field Services gathers raw natural gas through gathering systems located in seven major natural gas producing regions: Permian, Mid-Continent, East Texas-North Louisiana, South, Central, Rocky Mountain and Gulf Coast.

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 EPCO, an unrelated third party. As a result of the DEFS disposition transaction discussed in Note 13, Duke Energy 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 Energy’s Natural Gas Transmission segment.

As discussed above, on January 2, 2007, Duke Energy completed the spin-off of its natural gas businesses, which included the Natural Gas Transmission business segment and Duke Energy’s 50% interest in DEFS, to shareholders. Accordingly, results of operations for these business segments are included in Income From Discontinued Operations, net of tax, on the Consolidated Statements of Operations for all periods presented.

Commercial Power owns, operates and manages non-regulated merchant power plants and engages in the wholesale marketing and procurement of electric power, fuel and emission allowances related to these plants as well as other contractual positions. Commercial Power also develops and implements customized energy solutions. Commercial Power’s generation asset fleet consists of Duke Energy Ohio’s non-regulated generation in Ohio and the five Midwestern gas-fired merchant generation assets that were a portion of former DENA. Commercial Power’s assets comprise approximately 8,100 megawatts (MW) of power generation primarily located in the Midwestern United States. The asset portfolio has a diversified fuel mix with base-load and mid-merit coal-fired units as well as combined cycle and peaking natural gas-fired units. Most of the generation asset output in Ohio has been contracted through the Rate Stabilization Plan (RSP).

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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 equity investments in National Methanol Company (NMC), located in Saudi Arabia, which is a leading regional producer of methanol and methyl tertiary butyl ether (MTBE), Compania de Servicios de Compression de Campeche, S.A. (Campeche), located in the Cantarell oil field in the Bay of Campeche, Mexico, which compresses and dehydrates natural gas and extracts NGLs, and Attiki Gas Supply S.A. (Attiki), located in Athens, Greece, which is a natural gas distributor.

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. On September 7, 2006, Duke Energy 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.

The remainder of Duke Energy’s operations is presented as “Other”. While it is not considered a business segment, Other primarily includes the following:

• The remaining portion of Duke Energy’s business formerly known as DENA, including its 100% owned affiliates Duke Energy Marketing America, LLC and Duke Energy Marketing Canada Corp. Duke Energy also participates in DETM. DETM is 40% owned by ExxonMobil Corporation and 60% owned by Duke Energy. During the third quarter of 2005, Duke Energy’s Board of Directors authorized and directed management to execute the sale or disposition of substantially all of former DENA’s remaining assets and contracts outside the Midwestern United States and certain contractual positions related to the Midwestern assets. The exit plan was completed in the second quarter of 2006 (see Note 13). In addition, management will continue to wind down the limited remaining operations of DETM. As a result of this exit plan, the results of operations for most of former DENA’s businesses which Duke Energy has exited have been reflected as discontinued operations in the accompanying Consolidated Statements of Operations for all years presented. Continuing operations related to the former DENA operations within Other consist primarily of DETM, which management continues to wind down.

• Other also includes certain unallocated corporate costs, DukeNet Communications, LLC (DukeNet), Bison Insurance Company Limited (Bison), Duke Energy’s wholly owned, captive insurance subsidiary, Cinergy’s equity financing business and Duke Energy’s 50% interest in Duke/Fluor Daniel (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. During 2003, Duke Energy determined that it would exit the refined products business at Duke Energy Merchants, LLC (DEM) in an orderly manner, and continues to unwind its portfolio of contracts. As of December 31, 2006, DEM had completed the exit of its business, and all of the results of operations have been classified as discontinued operations in the accompanying Consolidated Statements of Operations for all periods presented. Bison’s principal activities, as a captive insurance entity, 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 Energy. Bison also participates in reinsurance activities with certain third parties, on a limited basis. Cinergy has a business which invests in start up businesses utilizing new energy technologies as well as technologies utilizing energy infrastructure, such as broadband over power line services. D/FD is a 50/50 partnership between subsidiaries of Duke Energy and Fluor Corporation (Fluor). During 2003, Duke Energy 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, 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 Energy decided to exit the merchant finance business conducted by Duke Capital Partners, LLC (DCP). DCP had been previously included in Other. As of December 31, 2005, Duke Energy 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.

Duke Energy’s reportable segments offer different products and services and are managed separately as business units. Accounting policies for Duke Energy’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).

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

Transactions between reportable segments are accounted for on the same basis as revenues and expenses in the accompanying Consolidated Financial Statements.

Business Segment Data^(a)

	Unaffiliated Revenues			Intersegment Revenues			Total Revenues			Segment EBIT/ Consolidated Earnings from Continuing Operations before Income Taxes			Depreciation and Amortization		Capital and Investment Expenditures		Segment Assets(b)
	(in millions)
Year Ended December 31, 2006
U.S. Franchised Electric and Gas	$	8,077		$	21		$	8,098		$	1,811		$	1,280	$	2,381	$	34,346
Natural Gas Transmission		—			—			—			—			—		790		19,002
Field Services		—			—			—			—			—		—		1,233
Commercial Power(e)		1,396			6			1,402			21			160		209		6,826
International Energy		943			—			943			163			73		58		3,332
Crescent(c)(f)		221			—			221			532			1		507		180
Total reportable segments		10,637			27			10,664			2,527			1,514		3,945		64,919
Other(e)		41			99			140			(537	)		51		131		3,810
Eliminations and reclassifications		—			(126	)		(126	)		—			—		—		(29	)
Interest expense		—			—			—			(633	)		—		—		—
Interest income and other(d)		—			—			—			147			—		—		—
Total consolidated	$	10,678		$	—		$	10,678		$	1,504		$	1,565	$	4,076	$	68,700
Year Ended December 31, 2005
U.S. Franchised Electric and Gas	$	5,413		$	19		$	5,432		$	1,495		$	962	$	1,350	$	18,739
Natural Gas Transmission		—			—			—			—			—		930		18,823
Field Services		—			—			—			—			—		86		1,377
Commercial Power(e)		102			46			148			(118	)		60		2		1,619
International Energy		727			—			727			309			60		23		2,962
Crescent(c)(f)		495			—			495			314			1		599		1,507
Total reportable segments		6,737			65			6,802			2,000			1,083		2,990		45,027
Other(e)		169			40			209			(347	)		40		29		9,402
Eliminations and reclassifications		—			(105	)		(105	)		—			—		—		294
Interest expense		—			—			—			(381	)		—		—		—
Interest income and other(d)		—			—			—			(4	)		—		—		—
Total consolidated	$	6,906		$	—		$	6,906		$	1,268		$	1,123	$	3,019	$	54,723
Year Ended December 31, 2004
U.S. Franchised Electric and Gas	$	5,045		$	24		$	5,069		$	1,467		$	863	$	1,126	$	18,062
Natural Gas Transmission		—			—			—			—			—		544		17,783
Field Services		—			—			—			—			—		202		6,265
Commercial Power(e)		(29	)		208			179			(479	)		69		7		1,726
International Energy		605			—			605			219			54		28		3,058
Crescent(c)(f)		437			—			437			240			2		568		1,317
Total reportable segments		6,058			232			6,290			1,447			988		2,475		48,211
Other(e)		299			(97	)		202			(225	)		42		54		7,139
Eliminations and reclassifications		—			(135	)		(135	)		—			—		—		420
Interest expense		—			—			—			(425	)		—		—		—
Interest income and other(d)		—			—			—			13			—		—		—
Total consolidated	$	6,357		$	—		$	6,357		$	810		$	1,030	$	2,529	$	55,770

(a) Segment results exclude results of entities classified as discontinued operations

(b) Includes assets held for sale and assets of entities in discontinued operations

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(c) Capital expenditures for residential real estate are included in operating cash flows and were $322 million for the period from January 1, 2006 through the date of deconsolidation (September 7, 2006), $355 million in 2005 and $322 million in 2004.

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

(e) Amounts associated with former DENA operations are included in Other for all periods presented, except for the Midwestern generation and Southeast operations, which are reflected in Commercial Power.

(f) In September 2006, Duke Energy completed 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.

Geographic Data

	U.S.		Canada			Latin America		Other Foreign		Consolidated
	(in millions)
2006
Consolidated revenues	$	9,718	$	(24	)	$	943	$	41	$	10,678
Consolidated long-lived assets		43,468		10,541			2,474		245		56,728
2005
Consolidated revenues	$	6,126	$	14		$	722	$	44	$	6,906
Consolidated long-lived assets		29,658		10,544			2,241		228		42,671
2004
Consolidated revenues	$	5,937	$	(234	)	$	597	$	57	$	6,357
Consolidated long-lived assets		30,960		9,902			2,136		233		43,231

4. Regulatory Matters

Regulatory Assets and Liabilities. Duke Energy’s regulated operations are subject to SFAS No. 71. Accordingly, Duke Energy 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 Energy’s Regulatory Assets and Liabilities:

	As of December 31,				Recovery/Refund Period Ends
	2006		2005
	(in millions)
Regulatory Assets(a)
Net regulatory asset related to income taxes(b)	$	1,361	$	1,338	(l	)
Accrued pension and post retirement(c)(r)		975		—	(p	)
ARO costs(c)		463		546	2043
Regulatory Transition Charges (RTC)(c)		331		—	2011
Gasification services agreement buyout costs(c)		207		—	2018
Deferred debt expense(d)		192		166	2039
Vacation accrual(c)		121		80	2007
Post-in-service carrying costs and deferred operating expense(c)		92		—	2065
Under-recovery of fuel costs(f)(i)		61		—	2008
Hedge costs and other deferrals(c)		48		—	2007
Regional Transmission Organization (RTO)(q)		41		41	(o	)
Other(c)		180		148	(p	)
Total Regulatory Assets	$	4,072	$	2,319
Regulatory Liabilities(a)
Removal costs(d)(h)	$	2,345	$	1,670	(n	)
Other deferred tax credits(d)(f)(h)		5		8	(f	)
Nuclear property and liability reserves(d)(h)		173		167	2043
Gas purchase costs(g)		173		—	2007
Purchased capacity costs(e)(j)		107		121	(k	)
Demand-side management costs(e)(h)		78		59	(m	)
Deferred emission allowance revenue		41		—	(p	)
Over-recovery of fuel costs(f)(g)		20		76	2007
North Carolina clean air compliance(d)(h)		—		164	2011
Other(h)		116		73	(p	)
Total Regulatory Liabilities	$	3,058	$	2,338

(a) All regulatory assets and liabilities are excluded from rate base unless otherwise noted.

(b) Natural Gas Transmission’s amounts of $848 million at December 31, 2006 and $954 million at December 31, 2005 are expected to be included in future rate filings. U.S. Franchised Electric and Gas’s amounts of $513 million at December 31, 2006 and $384 million at December 31, 2005 are included in rate base.

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(c) Included in Other Regulatory Assets and Deferred Debits on the Consolidated Balance Sheets.

(d) Included in rate base.

(e) Earns a negative return.

(f) In 2005, Duke Energy Carolinas reduced the previously recorded excess deferred tax liability by approximately $150 million. Additionally, in 2005, Duke Energy Carolinas received approval from the NCUC to credit approximately $100 million against fuel rates for North Carolina retail customers. Similarly, the PSCSC granted approval to credit approximately $40 million against fuel rates for South Carolina retail customers. These amounts were credited to customer rates during 2006 and 2005. The remaining reduction was achieved by crediting fuel rates for certain wholesale customers and writing off a portion of the balance against income.

(g) Included in Accounts Payable on the Consolidated Balance Sheets.

(h) Included in Other Deferred Credits and Other Liabilities on the Consolidated Balance Sheets.

(i) Included in Receivables on the Consolidated Balance Sheets.

(j) Included in Other Current Liabilities and Other Deferred Credits and Other Liabilities on the Consolidated Balance Sheets.

(k) Incurred costs were deferred and are being recovered in rates. U.S. Franchised Electric and Gas is currently over-recovered for these costs and is refunding the liability through retail rates. Refund period will be determined by the volume of sales.

(l) Recovery/refund is over the life of the associated asset or liability.

(m) Incurred costs were deferred and are being recovered in rates. U.S. Franchised Electric and Gas is currently over-recovered for these costs in the South Carolina jurisdiction. Refund period is dependent on volume of sales and cost incurrence.

(n) Liability is extinguished over the lives of the associated assets.

(o) To be recovered through future transmission rates. Recovery period currently unknown.

(p) Recovery/Refund period currently unknown.

(q) Investment in RTO reclassified as regulatory asset from Other Deferred Credits during 2005 after termination of GridSouth Transco project.

(r) Includes $595 million related to adoption of SFAS No. 158 (see Note 22) and $380 million related to impacts of purchase accounting as a result of the merger with Cinergy (see Note 2).

Regulatory Merger Approvals.As discussed in Note 1 and Note 2, on April 3, 2006, the merger between Duke Energy and Cinergy was consummated to create a newly formed company. Duke Energy Holding Corp. (subsequently renamed Duke Energy Corporation). As a condition to the merger approval, the PUCO, the KPSC, the PSCSC and the NCUC required that certain merger related savings be shared with consumers in Ohio, Kentucky, South Carolina, and North Carolina, respectively. The commissions also required Duke Energy Holding Corp., Cinergy, Duke Energy Ohio, Duke Energy Kentucky, and/or Duke Energy Carolinas to meet additional conditions. While the merger itself was not subject to approval by the IURC, the IURC approved certain affiliate agreements in connection with the merger subject to similar conditions. Key elements of these conditions include:

• The PUCO required that Duke Energy Ohio provide (i) a rate reduction of approximately $15 million for one year to facilitate economic development in a time of increasing rates and market prices (ii) a reduction of approximately $21 million to its gas and electric consumers in Ohio for one year, with both credits beginning January 1, 2006. In April 2006, the Office of the Ohio Consumers’ Council (OCC) filed a Notice of Appeal with the Supreme Court of Ohio, requesting the Court remand the PUCO’s merger approval for a full evidentiary hearing. The OCC alleged that the PUCO improperly failed to: (i) set the matter for a full evidentiary hearing; (ii) consider evidence regarding the transfer of certain DENA assets to Duke Energy Ohio; and (iii) lift the stay on discovery. Duke Energy Ohio and the OCC settled this matter and in June 2006, the Court granted the OCC’s motion to dismiss. As of December 31, 2006, Duke Energy Ohio has returned $14 million and $20 million, respectively, on each of these rate reductions.

• The KPSC required that Duke Energy Kentucky provide $8 million in rate reductions to its customers over five years, ending when new rates are established in the next rate case after January 1, 2008. As of December 31, 2006, Duke Energy Kentucky has returned $1 million to customers on this rate reduction.

• The PSCSC required that Duke Energy Carolinas provide a $40 million rate reduction for one year and a three-year extension to the Bulk Power Marketing profit sharing arrangement. Approximately $23 million of the rate reduction has been passed through to customers since the ruling by the PSCSC.

• The NCUC required that Duke Energy Carolinas provide (i) a rate reduction of approximately $118 million for its North Carolina customers through a credit rider to existing base rates for a one-year period following the close of the merger, and (ii) $12 million to support various low income, environmental, economic development and educationally beneficial programs, the cost of which was incurred in the second quarter of 2006. Approximately $54 million of the rate reduction has been passed through to customers since the ruling by the NCUC.

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

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• The IURC required that Duke Energy Indiana provide a rate reduction of $40 million to its customers over a one year period and $5 million over a five year period for low-income energy assistance and clean coal technology. In April 2006, Citizens Action Coalition of Indiana, Inc., an intervenor in the merger proceeding, filed a Verified Petition for Rehearing and Reconsideration claiming that Duke Energy Indiana should be ordered to provide an additional $5 million in rate reduction to customers to be consistent with the terms of the NCUC’s order approving the merger. In May 2006, the IURC denied the petition for rehearing and reconsideration. As of December 31, 2006, Duke Energy Indiana has returned approximately $27 million to customers on this rate reduction.

• The FERC approved the merger without conditions. In January 2006, Public Citizen’s Energy Program, Citizens Action Coalition of Indiana, Inc., Ohio Partners for Affordable Energy and Southern Alliance for Clean Energy requested rehearing of the FERC approval. In February 2006, the FERC issued an order granting rehearing of FERC’s order for further consideration. On February 5, 2007, after further consideration, the FERC issued an order dismissing the request for a rehearing.

Spent Nuclear Fuel. Under provisions of the Nuclear Waste Policy Act of 1982, Duke Energy contracted with the DOE for the disposal of spent nuclear fuel. The DOE failed to begin accepting spent nuclear fuel on January 31, 1998, the date specified by the Nuclear Waste Policy Act and in Duke Energy’s contract with the DOE. In 1998, Duke Energy filed a claim with the U.S. Court of Federal Claims against the DOE related to the DOE’s failure to accept commercial spent nuclear fuel by the required date. Damages claimed in the lawsuit are based upon Duke Energy’s costs incurred as a result of the DOE’s partial material breach of its contract, including the cost of securing additional spent fuel storage capacity. The matter has been stayed pending the result of ongoing settlement negotiations between Duke Energy and the DOE. Duke Energy will continue to safely manage its spent nuclear fuel until the DOE accepts it. Payments made to the DOE for expected future disposal costs are based on nuclear output and are included in the Consolidated Statements of Operations as Fuel Used in Electric Generation and Purchased Power. Duke Energy expects resolution of this matter in the first quarter of 2007.

U.S. Franchised Electric and Gas.Rate Related Information. The NCUC, PSCSC, IURC and KPSC approve rates for retail electric and gas sales within their states. The PUCO approves rates and market prices for retail electric and gas sales within Ohio. The FERC approves rates for electric sales to wholesale customers served under cost-based rates.

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

Duke Energy Carolinas Rate Case. In June 2007, Duke Energy Carolinas filed an application with the NCUC seeking authority to increase its rates and charges for electric service in North Carolina effective January 1, 2008. This application complies with a condition imposed by the NCUC in approving the Cinergy merger. Overall, Duke Energy Carolinas is asking for a 3.6% increase (or approximately $140 million) in total revenues. The proposed revenue increases would be distributed among classes of customers and rate schedules. In conjunction with the rate case, the NCUC will consider Duke Energy Carolinas’ environmental compliance costs under the NC Clean Air Act and the appropriate recovery method for the period beyond 2007. Certain parties have filed as intervenors in this case and may challenge aspects of the application. Testimony from such intervenors is due on October 4, 2007. The NCUC will hear evidence on Duke Energy Carolinas’ application beginning on October 16, 2007.

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Duke Energy Indiana Environmental Compliance Case. In November 2004, Duke Energy Indiana applied to the IURC for approval of its plan for complying with SO₂, NO_X, and mercury emission reduction requirements. Duke Energy Indiana also requested approval of cost recovery for certain proposed compliance projects. An evidentiary hearing was held in May 2005. In December 2005, Duke Energy Indiana, the Indiana Office of Utility Consumer Counselor (OUCC), and the Duke Energy Indiana Industrial Group filed a settlement agreement providing for approval of Duke Energy Indiana’s compliance plan, and approval of financing, depreciation, and operation and maintenance cost recovery. In May 2006, the IURC approved the settlement agreement in its entirety. The approved Settlement Agreement provides for: (1) the construction of Phase 1 CAIR and Clean Air Mercury Rule (CAMR) projects with estimated expenditures of approximately $1.08 billion, (2) timely recovery of financing, construction, operation and maintenance cost and depreciation associated with the Phase 1 CAIR and CAMR plan, (3) recovery of emission allowances in connection with SO₂, NOx and mercury, (4) accelerated 20 year depreciation rate, (5) timely recovery of Phase 1 plan development and presentation costs and Phase 2 plan development, engineering and pre-construction, and coal and equipment testing costs, and (6) authority to defer post-in-service AFUDC, depreciation costs and operation and maintenance cost until applicable costs are reflected in rates.

Duke Energy Ohio Electric Rate Filings.Duke Energy Ohio operates under a RSP, a Market Based Standard Service Offer (MBSSO) approved by the PUCO in November 2004. In March 2005, the OCC appealed the PUCO’s approval of the MBSSO to the Supreme Court of Ohio and the court issued its decision in November 2006. It upheld the MBSSO in virtually every respect but remanded to the PUCO on two issues. The Court ordered the PUCO to support a certain portion of its order with reasoning and record evidence and to require Duke Energy Ohio to disclose certain confidential commercial agreements with other parties previously requested by the OCC. Duke Energy Ohio has complied with the disclosure order. Such confidential commercial agreements are relatively common in the jurisdiction and the PUCO has not allowed production of such agreements in past cases in which the PUCO was presented with a settlement agreement on the basis that they are irrelevant. A hearing on remand is expected in March 2007. Duke Energy Ohio has filed for a regulatory extension of the RSP through 2010.

On August 2, 2006, Duke Energy Ohio filed an application with the PUCO to amend its MBSSO. The proposal provides for continued electric system reliability, a simplified market price structure and clear price signals for customers, while helping to maintain a stable revenue stream for Duke Energy Ohio. The application is pending and Duke Energy Ohio cannot predict the outcome of this proceeding.

Duke Energy Ohio’s MBSSO includes a fuel clause recovery component which is audited annually by the PUCO. In January 2006, Duke Energy Ohio entered into a settlement resolving all open issues identified in the 2005 audit. The PUCO approved the settlement in February 2006. Duke Energy and Duke Energy Ohio do not expect the agreement to have a material impact on their consolidated results of operations, cash flows or financial position.

In addition to the fuel clause recovery component, Duke Energy Ohio’s MBSSO includes a reserve capacity component known as the System Reliability Tracker, and an Annually Adjusted Component to recover environmental, tax and homeland security costs. In 2006, Duke Energy Ohio filed an application requesting to modify each of these components. After the Ohio Supreme Court issued its remand order in the MBSSO appeal, the PUCO issued an order permitting Duke Energy Ohio to continue to charge its existing market prices (except for the System Reliability Tracker) with true-up to actual costs to be decided at a later date. The PUCO allowed Duke Energy Ohio’s System Reliability Tracker to expire by its terms on January 1, 2007. In the meantime, consideration of Duke Energy Ohio’s proposed modifications is suspended pending the outcome of the remand case. Duke Energy Ohio does not expect a significant change, if any to the MBSSO components but cannot predict the outcome of the cases. The PUCO is expected to decide these matters in 2007.

Duke Energy Kentucky Electric Rate Case. In May 2006, Duke Energy Kentucky filed an application for an increase in its base electric rates. The application, which sought an increase of approximately $67 million in revenue, or approximately 28 percent, to be effective in January 2007, was filed pursuant to the KPSC’s 2003 Order approving the transfer of 1,100 MW of generating assets from Duke Energy Ohio to Duke Energy Kentucky. Duke Energy Kentucky also sought to reinstitute its fuel cost recovery mechanism which had been frozen since 2001, and has proposed to refresh the pricing for the back-up power supply contract to reflect current market pricing. In the fourth quarter of 2006, Duke Energy Kentucky reached a settlement agreement in principle with all parties to this proceeding resolving all the issues raised in the proceeding. Among other things, the settlement agreement provided for a $49 million increase in Duke Energy Kentucky’s base electric rates and reinstitution of the fuel cost recovery mechanism. In December 2006, the KPSC approved the settlement agreement.

Duke Energy Kentucky Gas Rate Cases. In 2002, the KPSC approved Duke Energy Kentucky’s gas base rate case which included, among other things, recovery of costs associated with an accelerated gas main replacement program. The approval authorized a track-

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ing mechanism to recover certain costs including depreciation and a rate of return on the program’s capital expenditures. The Kentucky Attorney General appealed to the Franklin Circuit Court the KPSC’s approval of the tracking mechanism as well as the KPSC’s subsequent approval of annual rate adjustments under this tracking mechanism. In 2005, both Duke Energy Kentucky and the KPSC requested that the court dismiss these cases. At the present time, Duke Energy and Duke Energy Kentucky cannot predict the timing or outcome of this litigation.

In February 2005, Duke Energy Kentucky filed a gas base rate case with the KPSC requesting approval to continue the tracking mechanism and for a $14 million annual increase in base rates. A portion of the increase is attributable to recovery of the current cost of the accelerated main replacement program in base rates. In December 2005, the KPSC approved an annual rate increase of $8 million and re-approved the tracking mechanism through 2011. In February 2006, the Kentucky Attorney General appealed the KPSC’s order to the Franklin Circuit Court, claiming that the order improperly allows Duke Energy Kentucky to increase its rates for gas main replacement costs in between general rate cases, and also claiming that the order improperly allows Duke Energy Kentucky to earn a return on investment for the costs recovered under the tracking mechanism which permits Duke Energy Kentucky to recover its gas main replacement costs. At this time, Duke Energy and Duke Energy Kentucky cannot predict the outcome of this litigation.

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

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

Other. U.S. Franchised Electric and Gas is engaged in planning efforts to meet projected load growth in its service territory. Long-term projections indicate a need for significant capacity additions, which may include new nuclear, integrated gasification combined cycle (IGCC), coal facilities or gas fired generation units. Because of the long lead times required to develop such assets, U.S. Franchised Electric and Gas is taking steps now to ensure those options are available. In March 2006, Duke Energy Carolinas announced that it has entered into an agreement with Southern Company to evaluate potential construction of a new nuclear plant at a site jointly owned in Cherokee County, South Carolina. In May 2007, Duke Energy announced its intent to purchase Southern Company’s 500-megawatt interest in the proposed William States Lee III nuclear power project, making the plant’s total output available to electric customers in the Carolinas. With selection of the Cherokee County site, Duke Energy Carolinas is moving forward with previously announced plans to develop an application to the U.S. Nuclear Regulatory Commission (NRC) for a combined construction and operating license (COL) for two Westinghouse AP1000 (advanced passive) reactors. Each reactor is capable of producing approximately 1,117 MW. The COL application submittal to the NRC is anticipated in late 2007 or early 2008. Submitting the COL application does not commit Duke Energy Carolinas to build nuclear units. On September 20, 2006, Duke Energy Carolinas filed an application with the NCUC for assurance that pursuit of the

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

On June 2, 2006, Duke Energy Carolinas also filed an application with the NCUC for a Certificate of Public Convenience and Necessity (CPCN) to construct two 800 MW state of the art coal generation units at its existing Cliffside Steam Station in North Carolina. The NCUC held public hearings in August 2006, and an evidentiary hearing in Raleigh, North Carolina concluded on September 14, 2006. Post-hearing briefs and proposed orders were filed on October 13, 2006. After the evidentiary hearing, Duke Energy Carolinas received competitive proposals for two major scopes of equipment for the Cliffside Project which suggest that the capital costs for these major components are increasing significantly due to various market pressures that will likely impact utility generation construction projects across the United States. In October 2006, Duke Energy made a filing with the NCUC related to the Duke Energy Carolinas’ request for a CPCN for the Cliffside project. In this filing, Duke Energy stated that due to the rising costs described above, the cost of building the Cliffside units could be approximately $3 billion, excluding allowance for funds used during construction (AFUDC). The costs described above are expected to continue to increase causing the overall cost of the Cliffside project to increase, until such time as the NCUC issues a CPCN and Duke Energy is able to enter into definitive agreements with necessary material and service providers. The NCUC issued orders requiring additional public and evidentiary hearings. From January 17, 2007 to January 19, 2007 the NCUC held an evidentiary hearing to consider evidence limited to Duke Energy Carolinas updated cost information for the project. On February 28, 2007, the NCUC issued a notice of decision approving the construction of one unit at the Cliffside Steam Station. On March 21, 2007, the NCUC issued its Order, which explained the basis for its decision to approve construction of one unit, with an approved cost estimate of $1.93 billion (including AFUDC), and certain conditions providing for updates on construction cost estimates. A group of environmental intervenors filed a motion for reconsideration with the NCUC on April 20, 2007, and a subsequent motion for reconsideration on May 25, 2007. Duke Energy Carolinas filed its responses in opposition of the motions for reconsideration on May 11, 2007 and June 4, 2007, respectively. The NCUC denied the motions for reconsideration in orders issued on June 6, 2007 and June 14, 2007. On May 30, 2007, Duke Energy Carolinas filed the updated cost estimate for the approved new Cliffside Unit 6. The current capital cost estimate is $1.8 billion, which excludes AFUDC of $600 million. Duke Energy Carolinas believes that the overall cost of Cliffside Unit 6 will be reduced by approximately $63 million in federal advanced clean coal tax credits.

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

In August 2005, Duke Energy Indiana filed an application with the IURC for approval of study and preconstruction costs related to the joint development of an IGCC project with Southern Indiana Gas and Electric Company d/b/a Vectren Energy Delivery of Indiana, Inc. (Vectren). Duke Energy Indiana and Vectren reached a Settlement Agreement with the OUCC providing for the recovery of such costs if the IGCC project is approved and constructed and for the partial recovery of such costs if the IGCC project does not go forward. The IURC issued an order on July 26, 2006 approving the Settlement Agreement in its entirety.

On September 7, 2006, Duke Energy Indiana and Vectren filed a joint petition with the IURC seeking certificates of public convenience and necessity for the construction of a 630 MW IGCC power plant at Duke Energy Indiana’s Edwardsport Generating Station in

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Knox County, Indiana. The petition describes the applicants’ need for additional baseload generating capacity and requests timely recovery of all construction and operating costs related to the proposed generating station, including financing costs, together with certain incentive ratemaking treatment. Duke Energy Indiana and Vectren filed their cases in chief with the IURC on October 24, 2006. As with Duke Energy Carolinas’ Cliffside project, Duke Energy Indiana’s estimated costs for the potential IGCC project have also increased. Duke Energy Indiana’s publicly filed testimony with the IURC indicates that industry (EPRI) total capital requirement estimates for a facility of this type and size are now in the range of $1.6 billion to $2.1 billion (including escalation to 2011 and owners’ specific site costs). The case is scheduled for an evidentiary hearing in June 2007. On February 16, 2007, Duke Energy Indiana filed a request for deferral and subsequent cost recovery of the costs expected to be incurred prior to the anticipated date of an order by the IURC regarding Duke Energy Indiana’s request for a certificate of public convenience and necessity for the construction of the Edwardsport Generating Station. These costs relate to the continued investigation, analysis and development of the IGCC project, and must be incurred, to assure the project can achieve a targeted in-service date of 2011.

On August 15, 2006, Duke Energy Indiana filed a petition with the IURC requesting recovery of its costs of purchasing electricity to be produced by a 100 megawatt wind energy farm under development pursuant to a 20-year purchased power agreement between Duke Energy Indiana and Benton County Wind Farm, LLC. The IURC issued an order on December 6, 2006 approving recovery of the retail portion of the purchased power cost plus the retail portion of Midwest ISO costs over the 20-year life of the agreement.

Duke Energy Indiana recovers its actual fuel costs quarterly through a rate adjustment mechanism. In two recent fuel clause proceedings, certain industrial customers and the Citizens Action Coalition of Indiana, Inc. have intervened and sub-dockets have been established to address issues raised by the OUCC and the intervenors concerning the allocation of fuel costs between native load customers and non-native load sales, the reasonableness of various Midwest Independent Transmission System Operator, Inc. (Midwest ISO) costs for which Duke Energy Indiana has sought recovery and Duke Energy Indiana’s recovery of costs associated with certain power hedging activities. Duke Energy Indiana is defending its practices, its costs, and the allocation of such costs. A hearing was conducted in one of these proceedings on September 20, 2006. A decision is expected in the first quarter of 2007. An evidentiary hearing in the second proceeding is set to begin in May 2007. The IURC has authorized Duke Energy Indiana to collect through rates the costs which it sought recovery in the two sub-docket proceedings, subject to refund pending the outcome of these proceedings. Duke Energy cannot predict the outcome of these proceedings but does not expect the outcome to be material to its consolidated results of operations, cash flows or financial position.

In April 2005, the PUCO issued an order opening a statewide investigation into riser leaks in gas pipeline systems throughout Ohio. The investigation followed four explosions since 2000 caused by gas riser leaks, including an April 2000 explosion in Duke Energy Ohio’s service area. In November 2006, the PUCO Staff released the expert report, which concluded that certain types of risers are prone to leaks under various conditions, including over-tightening during initial installation. The PUCO Staff recommended that natural gas companies continue to monitor the situation and study the cause of any further riser leaks to determine whether further remedial action is warranted. Duke Energy Ohio has approximately 87,000 of these risers on its distribution system. If the PUCO orders natural gas companies to replace all of these risers, Duke Energy Ohio estimates a replacement cost of $35 million. At this time, Duke Energy Ohio cannot predict the outcome or the impact of the statewide Ohio investigation.

In April 2006, the FERC issued an order on the Midwest ISO’s revisions to its Transmission and Energy Markets Tariffs regarding its RSG. The FERC found that the Midwest ISO violated the tariffs when it did not charge RSG costs to virtual supply offers. The FERC, among other things, ordered the Midwest ISO to recalculate the rate and make refunds to customers, with interest, to reflect the correct allocation of RSG costs. Duke Energy Shared Services, on behalf of Duke Energy Indiana and Duke Energy Ohio, filed a Request for Rehearing, and in October 2006, the FERC issued an order which, among other things, granted rehearing on the issue of refunds. The FERC stated that it would not require recalculation of the rates and, as such, refunds are no longer required. As a result, neither Duke Energy Ohio nor Duke Energy Indiana believe that this issue will have a material effect on their consolidated results of operations, cash flows, or financial position.

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

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

Natural Gas Transmission.Rate Related Information. On August 17, 2006, the NEB approved a settlement for 2006 and 2007 tolls.

Union Gas has rates that are approved by the 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 November 2006, Union Gas received a decision from the OEB on the regulation of rates for gas storage services in Ontario. The OEB found the storage market is competitive. As a result, the OEB will not regulate the rates for storage services to customers outside Union’s franchise area or the rates for new storage services to customers within its franchise area. Existing storage services to customers within Union’s franchise area will continue to be provided at regulated cost-based rates. The decision creates an unregulated storage operation within Union Gas, and provides support for new storage investment in Ontario.

In December 2006, the OEB issued a final rate order for new rates effective January 1, 2007. The average rate increase is approximately 3.1% and includes the impact of an increase in the common equity component of Union Gas’ capital structures from 35% to 36% and a decrease in the allowed return of equity from 9.63% to 8.54%.

Rates for the sale of gas of Union 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.

As a result of the spin-off of the natural gas businesses to Spectra Energy effective January 2, 2007, the above matters related to Natural Gas Transmission will have no impact on Duke Energy’s future consolidated results of operations, cash flows or financial position.

5. Joint Ownership of Generating and Transmission Facilities

Duke Energy Carolinas, along with North Carolina Municipal Power Agency Number 1, North Carolina Electric Membership Corporation, Piedmont Municipal Power Agency and Saluda River Electric Cooperative, Inc., have joint ownership of Catawba Nuclear Station, which is a facility operated by Duke Energy Carolinas. Duke Energy Ohio, Columbus Southern Power Company, and Dayton Power & Light jointly own electric generating units and related transmission facilities in Ohio. Duke Energy Ohio and Wabash Valley Power Association, Inc (WVPA) jointly own Vermillion Station. Additionally, Duke Energy Indiana is a joint-owner of Gibson Station Unit No. 5 with WVPA, and Indiana Municipal Power Agency (IMPA), as well as a joint-owner with WVPA and IMPA of certain Indiana transmission property and local facilities. These facilities constitute part of the integrated transmission and distribution systems, which are operated and maintained by Duke Energy Indiana.

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As of December 31, 2006, Duke Energy’s shares in jointly-owned plant or facilities were as follows:

	Ownership Share		Property, Plant, and Equipment		Accumulated Depreciation		Construction Work in Progress
	(in millions)
Duke Energy Carolinas
Production:
Catawba Nuclear Station (Units 1 and 2)(c)	12.5	%	$	563	$	302	$	10
Duke Energy Ohio
Production:
Miami Fort Station (Units 7 and 8)(b)	64.0			330		147		197
W.C. Beckjord Station (Unit 6)(b)	37.5			46		32		3
J.M. Stuart Station(a)(b)	39.0			420		179		153
Conesville Station (Unit 4)(a) (b)	40.0			81		52		28
W.M. Zimmer Station(b)	46.5			1,315		482		10
Killen Station(a)(b)	33.0			210		122		44
Vermillion(b)	75.0			197		34		—
Transmission	Various			88		47		1
Duke Energy Indiana
Production:
Gibson Station (Unit 5)(c)	50.05			287		146		6
Transmission and local facilities	94.28			2,740		1,126		—
Duke Energy Kentucky
Production:
East Bend Station(c)	69.0			423		217		4

(a) Station is not operated by Duke Energy Ohio.

(b) Included in Commercial Power segment

(c) Included in U.S. Franchised Electric and Gas segment

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

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

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6. Income Taxes

The following details the components of income tax expense:

Income Tax Expense

	For the Years Ended December 31,
	2006			2005			2004
	(in millions)
Current income taxes
Federal	$	624		$	59		$	(69	)
State		60			66			(1	)
Foreign		48			63			34
Total current income taxes		732			188			(36	)
Deferred income taxes
Federal		(306	)		188			340
State		(20	)		(34	)		(123	)
Foreign		27			43			22
Total deferred income taxes		(299	)		197			239
Investment tax credit amortization		(12	)		(10	)		(11	)
Total income tax expense from continuing operations		421			375			192
Total income tax expense from discontinued operations		408			477			369
Total income tax benefit from cumulative effect of change in accounting principle		—			(1	)		—
Total income tax expense presented in Consolidated Statements of Operations	$	829		$	851		$	561

Earnings from Continuing Operations before Income Taxes

	For the Years Ended December 31,
	2006		2005		2004
	(in millions)
Domestic	$	1,307	$	978	$	635
Foreign		197		290		175
Total earnings from continuing operations before income taxes	$	1,504	$	1,268	$	810

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

	For the Years Ended December 31,
	2006			2005			2004
	(in millions)
Income tax expense (benefit), computed at the statutory rate of 35%	$	527		$	444		$	284
State income tax, net of federal income tax effect		26			21			(81	)
Tax differential on foreign earnings		6			4			(5	)
Employee stock ownership plan dividends		(29	)		(22	)		(19	)
U.S. tax on repatriation of foreign earnings		—			(2	)		36
Other items, net		(109	)		(70	)		(23	)
Total income tax expense from continuing operations	$	421		$	375		$	192
Effective tax rate		28.0	%		29.6	%		23.7	%

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During 2006, Duke Energy had favorable tax settlements on research and development costs and nuclear decommissioning costs of approximately $30 million, tax benefits related to the impairment of an investment in Bolivia of approximately $25 million and tax credits recognized on synthetic fuel operations of approximately $20 million. The reduction in 2006 is reflected in the above table in Other items, net.

During 2005, Duke Energy reorganized various entities and reestimated its liability which enabled it to reduce the $45 million tax liability to $39 million. The reduction in 2005 is included in the Statutory Rate Reconciliation as follows: Federal income taxes of $2 million are included in “U.S. tax on repatriation of foreign earnings” and $4 million of state taxes are included in “State income tax, net of federal income tax effect.”

During 2004, Duke Energy recorded a $53 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 $53 million benefit is included in the Statutory Rate Reconciliation as follows: a $40 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”.

During 2004, Duke Energy recorded a $20 million income tax benefit from the change in state tax rates relating to deferred taxes as a result of a reorganization of certain subsidiaries. The $20 million benefit is included in “State income tax, net of federal income tax effect” in the Statutory Rate Reconciliation.

During 2004, Duke Energy recorded a $45 million income tax expense for the repatriation of foreign earnings which occurred during 2005 related to the American Jobs Creation Act of 2004. The $45 million is included in the Statutory Rate Reconciliation as follows: Federal income taxes of $36 million are included in “U.S. tax on repatriation of foreign earnings,” $4 million of state taxes are included in “State income tax, net of federal income tax effect,” and $5 million of foreign taxes are included in “Tax differential on foreign earnings.”

Net Deferred Income Tax Liability Components

	December 31,
	2006			2005
	(in millions)
Deferred credits and other liabilities	$	1,657		$	1,364
Other		167			60
Total deferred income tax assets		1,824			1,424
Valuation allowance		(20	)		(26	)
Net deferred income tax assets		1,804			1,398
Investments and other assets		(1,359	)		(1,444	)
Accelerated depreciation rates		(4,740	)		(3,233	)
Regulatory assets and deferred debits		(2,244	)		(1,692	)
Total deferred income tax liabilities		(8,343	)		(6,369	)
Total net deferred income tax liabilities	$	(6,539	)	$	(4,971	)

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

Deferred Tax Liabilities

	December 31,
	2006			2005
	(in millions)
Current deferred tax assets, included in other current assets	$	357		$	68
Non-current deferred tax assets, included in other investments and other assets		153			254
Current deferred tax liabilities, included in other current liabilities		(46	)		(40	)
Non-current deferred tax liabilities		(7,003	)		(5,253	)
Total net deferred income tax liabilities	$	(6,539	)	$	(4,971	)

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As of December 31, 2006, Duke Energy has net operating loss carryforwards of approximately $20 million relating to state income taxes which mostly expire in years 2016 and later.

Although the outcome of tax audits is uncertain, management believes that adequate provisions for income and other taxes, such as sales and use, franchise, and property, have been made for potential liabilities resulting from such matters. As of December 31, 2006, Duke Energy has total provisions of approximately $190 million for uncertain tax positions, as compared to approximately $150 million as of December 31, 2005, including interest. The increase in total provisions since December 31, 2005 is primarily attributable to the merger with Cinergy. Management is not aware of any issues for open tax years that upon final resolution are expected to have a material adverse effect on Duke Energy’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). The Act provides a deduction for income from qualified domestic production activities, which will be phased in from 2005 to 2010.

Under the guidance in FSP No. FAS 109-1, which was issued in December 2004, the deduction will be treated as a “special deduction” as described in SFAS No. 109. As such, for Duke Energy, the special deduction had no material impact on deferred tax assets and liabilities existing at the enactment date. Rather, the impact of this special deduction will be reported in the periods in which the deductions are claimed on the tax returns. For the year ended December 31, 2006, Duke Energy did not recognize any benefit relating to the deduction from qualified domestic activities.

In addition to the qualified domestic production activities deduction discussed above, the Act creates a temporary incentive for U.S. corporations to repatriate accumulated income earned abroad by providing an 85 percent dividends received deduction for certain dividends from controlled foreign corporations. FSP No. FAS 109-2, which was issued in December 2004, states that a company is allowed time beyond the financial reporting period of enactment to evaluate the effect of the Act on its plan for reinvestment or repatriation of foreign earnings, as it applies to the application of SFAS No. 109. Although the deduction is subject to a number of limitations and some uncertainty remains as to how to interpret numerous provisions in the Act, Duke Energy recorded a $45 million tax liability at December 31, 2004 based upon Duke Energy’s plans that it would repatriate approximately $500 million in extraordinary dividends in 2005. In 2005, Duke Energy repatriated approximately $500 million in extraordinary dividends. During this process, Duke Energy reorganized various entities and reduced its liability from $45 million to $39 million. There is no remaining liability as of December 31, 2006 and 2005.

Deferred income taxes and foreign withholding taxes have not been provided on the remaining undistributed earnings of Duke Energy’s foreign subsidiaries as such amounts are deemed to be permanently reinvested. The cumulative undistributed earnings as of December 31, 2006 on which Duke Energy has not provided deferred income taxes and foreign withholding taxes, is approximately $420 million.

7. Asset Retirement Obligations

In June 2001, the FASB issued SFAS No. 143, which was adopted by Duke Energy on January 1, 2003 and addresses financial accounting and reporting for legal obligations associated with the retirement of tangible long-lived assets and the related asset retirement costs. The standard applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset. SFAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset. This additional carrying amount is then depreciated over the life of the asset. The liability increases due to the passage of time based on the time value of money until the obligation is settled. Subsequent to the initial recognition, the liability is adjusted for any revisions to the expected value of the retirement obligation (with corresponding adjustments to property, plant, and equipment), and for accretion of the liability due to the passage of time. Additional depreciation expense is recorded prospectively for any property, plant and equipment increases.

Asset retirement obligations at Duke Energy relate primarily to the decommissioning of nuclear power facilities, the retirement of certain gathering pipelines and processing facilities, obligations related to right-of-way agreements, asbestos removal and contractual

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leases for land use. In accordance with SFAS No. 143, Duke Energy 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 Energy’s regulated electric and regulated natural gas operations classified removal costs for property that does not have an associated legal retirement obligation as a regulatory liability, in accordance with regulatory treatment under SFAS No. 71. Duke Energy does not accrue the estimated cost of removal when no legal obligation associated with retirement or removal exists for any of our non-regulated assets (including Duke Energy Ohio’s generation assets). The total amount of removal costs included in Other Deferred Credits and Other Liabilities on the Consolidated Balance Sheets was $2,345 million and $1,670 million as of December 31, 2006 and 2005, respectively, which consisted of $1,954 million and $1,320 million, respectively, related to regulated electric operations and $391 million and $350 million, respectively, related to regulated natural gas operations.

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

In March 2005, the FASB issued FIN 47. As a result of the adoption of FIN 47 in 2005, an increase in total assets of $31 million was recorded, consisting of an increase in regulatory assets of $24 million, an increase in net property, plant and equipment of $7 million and an increase in ARO liabilities of approximately $35 million. The adoption of FIN 47 had no impact on the income of the regulated electric operations, as the effects were offset by the establishment of regulatory assets and liabilities pursuant to SFAS No. 71. For obligations related to other operations, 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.

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,
	2006			2005
	(in millions)
Balance as of January 1,	$	2,058		$	1,926
Liabilities incurred due to new acquisitions(a)		59			—
Liabilities settled		(7	)		(46	)
Accretion expense		143			131
Revisions in estimated cash flows		48			12
Adoption of FIN 47		—			35
Balance as of December 31,	$	2,301		$	2,058

(a) Primarily represents Duke Energy’s acquisition of Cinergy in April 2006.

Accretion expense for the years ended December 31, 2006 and 2005 included approximately $140 million and $130 million, respectively, related to Duke Energy’s regulated electric operations which has been deferred as regulatory assets and liabilities in accordance with SFAS No. 71, as discussed above. The fair value of assets legally restricted for the purpose of settling asset retirement obligations associated with nuclear decommissioning was $1,421 million as of December 31, 2006 and $1,194 million as of December 31, 2005.

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

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In 2005, the NCUC and PSCSC approved a $48 million annual amount for contributions and expense levels for decommissioning. In each of the years ended December 31, 2006 and 2005, Duke Energy expensed approximately $48 million and contributed cash of approximately $48 to the NDTF for decommissioning costs. These amounts are presented in the Consolidated Statements of Cash Flows in Purchases of Available-For-Sale Securities within Cash Flows from Investing Activities.

In both 2006 and 2005, $48 million was contributed entirely to the funds reserved for contaminated costs. Contributions were discontinued to the funds reserved for non-contaminated costs since the current estimates indicate existing funds to be sufficient to cover projected future costs. The balance of the external funds was $1,775 million as of December 31, 2006 and $1,504 million as of December 31, 2005. These amounts are reflected in the Consolidated Balance Sheets as Nuclear Decommissioning Trust Funds (asset).

Estimated site-specific nuclear decommissioning costs, including the cost of decommissioning plant components not subject to radioactive contamination, total approximately $2.3 billion in 2003 dollars, based on a decommissioning study completed in 2004. This includes costs related to Duke Energy’s 12.5% ownership in the Catawba Nuclear Station. The other joint owners of the Catawba Nuclear Station are responsible for decommissioning costs related to their ownership interests in the station. Both the NCUC and the PSCSC have allowed Duke Energy to recover estimated decommissioning costs through retail rates over the expected remaining service periods of Duke Energy’s nuclear stations. Management believes that the decommissioning costs being recovered through rates, when coupled with expected fund earnings, are sufficient to provide for the cost of decommissioning.

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

Current Operating Licenses for Duke Energy’s Nuclear Units

Unit	Expiration Year
McGuire 1	2041
McGuire 2	2043
Catawba 1	2043
Catawba 2	2043
Oconee 1 and 2	2033
Oconee 3	2034

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

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

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

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Notes To Consolidated Financial Statements—(Continued)

Duke Energy’s Derivative Portfolio Carrying Value as of December 31, 2006

Asset/(Liability)	Maturity in 2007			Maturity in 2008			Maturity in 2009		Maturity in 2010 and Thereafter			Total Carrying Value
	(in millions)
Hedging	$	4		$	—		$	17	$	(8	)	$	13
Trading		2			—			—		—			2
Undesignated		(33	)		(5	)		2		4			(32	)
Total	$	(27	)	$	(5	)	$	19	$	(4	)	$	(17	)

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 Energy’s Consolidated Balance Sheets, excluding approximately $39 million of derivative assets and $39 million of derivative liabilities presented as assets and liabilities held for sale at December 31, 2006.

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 13). As a result, Duke Energy 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 was 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. Duke Energy retained the Midwestern generation assets of DENA, representing approximately 3,600 megawatts of power generation, and combined the assets with Cinergy’s commercial operations subsequent to the merger with Cinergy on April 3, 2006 (see Note 1 and Note 2 for further details on the completed Cinergy merger). Derivative activity associated with these combined assets is reported in Commercial Power for segment reporting purposes for all periods presented.

Commodity Cash Flow Hedges. Some Duke Energy 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 Energy 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 Energy uses commodity instruments, such as swaps, futures, forwards and options, as cash flow hedges for electricity, natural gas and natural gas liquid transactions. Duke Energy 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 a pre-tax gain of $5 million in 2006, a pre-tax loss of $12 million in 2005 and a pre-tax gain of $3 million in 2004, reported primarily in Income 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, which is classified in Income From Discontinued Operations, net of tax in the Consolidated Statements of Operations, was a loss of approximately $67 million in 2006, a gain of approximately $1.2 billion in 2005 and was not material in 2004.

As of December 31, 2006, $2 million of pre-tax deferred net gains on derivative instruments related to commodity cash flow hedges were accumulated on the Consolidated Balance Sheets in a separate component of stockholders’ equity, in AOCI, and are expected to be recognized in earnings during the next twelve months as the hedged transactions occur. 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 Energy 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 Energy 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 2006, a pre-tax loss of $4 million in 2005 and was not material in 2004, and is reported primarily in Income From Discontinued Operations, net of tax on the Consolidated Statements of Operations.

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

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Notes To Consolidated Financial Statements—(Continued)

“Amendment of Statement 133 on Derivative Instruments and Hedging Activities,” to certain contracts involving the purchase and sale of electricity at fixed prices in future periods. These contracts, which relate primarily to the delivery of electricity over the next 8 years, are not included in the table above. As discussed above, during 2005, Duke Energy recognized a pre-tax loss of approximately $1.9 billion for the disqualification of its power and gas forward sales contracts.

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. The amount recognized for transactions that no longer qualified as hedged firm commitments was not material in 2006 and 2004.

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

Foreign Currency (Fair Value, Net Investment or Cash Flow) Hedges. Duke Energy 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 naturally hedged through debt denominated or issued in the foreign currency. Duke Energy may also use foreign currency derivatives, where possible, to manage its risk related to foreign currency fluctuations. There was no recognition, a net gain of $1 million and a net loss of $43 million included in the cumulative translation adjustment for hedges of net investments in foreign operations, during 2006, 2005, and 2004, respectively. To monitor its currency exchange rate risks, Duke Energy uses sensitivity analysis, which measures the impact of devaluation of foreign currencies.

During the first quarter of 2005, Duke Energy 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 used in 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 Energy’s investment in Westcoast occurs.

Other Derivative Contracts. Trading. Duke Energy has been 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 Energy prospectively discontinued proprietary trading. As a result of the Cinergy merger, Duke Energy acquired natural gas and power marketing and trading operations, conducted primarily through CMT, the results of which have been reflected in Income (Loss) from Discontinued Operations, net of tax, from the date of the Cinergy acquisition to the date of sale. In October 2006, the CMT sale transaction was completed and Duke Energy entered into a series of Total Return Swaps (TRS) with Fortis (see Note 13). As of December 31, 2006, the remaining CMT trading contract assets and liabilities and offsetting TRS were classified as Assets Held for Sale in the Consolidated Balance Sheets.

Undesignated. In addition, Duke Energy 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 as of December 31, 2006 are primarily associated with forward power sales and coal purchases for the Commercial Power operations and remaining DENA exit activity announced in 2005 (see Note 13). As of December 31, 2005, this category primarily included disqualified 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 Energy related to Field Services commodity price risk. Duke Energy’s exposure to price risk is influenced by a number of factors, including contract size, length, market liquidity, location and unique or specific contract terms.

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Notes To Consolidated Financial Statements—(Continued)

In connection with the Barclays Bank PLC (Barclays) transaction discussed in Note 13, Duke Energy 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. The fair value of the TRS as of December 31, 2006 is an asset of approximately $56 million, which offsets the net fair value of the underlying contracts, which is a liability of approximately $56 million. The TRS will be cancelled as the underlying contracts are transferred to Barclays.

Credit Risk. Duke Energy’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 Energy 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 Energy’s overall credit risk in that risk factors can negatively impact the credit quality of the entire sector. Where exposed to credit risk, Duke Energy analyzes the counterparties’ financial condition prior to entering into an agreement, establishes credit limits and monitors the appropriateness of those limits on an ongoing basis.

Duke Energy’s industry has historically operated under negotiated credit lines for physical delivery contracts. Duke Energy 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.

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

Collateral amounts held or posted may be fixed or may vary depending on the terms of the collateral agreement and the nature of the underlying exposure and generally cover trading, normal purchases and normal sales, hedging contracts, and optimization contracts outstanding. Duke Energy may be required to return certain held collateral and post additional collateral should price movements adversely impact the value of open contracts or positions. In many cases, Duke Energy’s 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 Energy 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.

Included in Other Current Assets in the Consolidated Balance Sheets as of December 31, 2006 and December 31, 2005 are collateral assets of approximately $92 million and $1,279 million, respectively, which represents cash collateral posted by Duke Energy with other third parties. This decrease in cash collateral posted by Duke Energy is primarily due the sale and wind-down of trading operations. Included in Other Current Liabilities and Other Deferred Credits and Other Liabilities in the Consolidated Balance Sheets as of December 31, 2006 and December 31, 2005 are collateral liabilities of approximately $239 million and $664 million, respectively, which represents cash collateral posted by other third parties to Duke Energy. 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 Energy from Barclays in January 2006 was approximately $540 million based on current market prices of the contracts (see Note 13).

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

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Notes To Consolidated Financial Statements—(Continued)

Financial Instruments

	As of December 31,
	2006				2005
	Book Value		Approximate Fair Value		Book Value		Approximate Fair Value
	(in millions)
Long-term debt(a)	$	19,723	$	20,765	$	15,947	$	17,014
Long-term SFAS 115 securities		1,946		1,946		1,735		1,735

(a) Includes current maturities.

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

9. Marketable Securities

Short-term investments. At December 31, 2006 and 2005 Duke Energy had $1,514 million and $632 million, respectively, of short-term investments consisting primarily of highly liquid tax-exempt debt securities. These instruments are classified as available-for-sale securities under SFAS No. 115 as management does not intend to hold them to maturity nor are they bought and sold with the objective of generating profits on short-term differences in price. The carrying value of these instruments approximates their fair value as they contain floating rates of interest. During 2006, Duke Energy purchased approximately $31,521 million and received proceeds on sale of approximately $30,692 million of short-term investments. During 2005, Duke Energy purchased approximately $38,535 million and received proceeds on sale of approximately $38,386 million of short-term investments. During 2004, Duke Energy purchased approximately $63,879 million and received proceeds on sale of approximately $63,323 million of short-term investments. The weighted-average maturity of these debt securities is less than 1 year.

During 2006, Duke Energy recognized an approximate $51 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. This gain was recorded as a component of Income from Discontinued Operations in Other.

Other Long-term investments. Duke Energy also invests in debt and equity securities that are held in the NDTF (see Note 7 for further information on the nuclear decommissioning trust funds) and the captive insurance investment portfolio that are classified as available-for-sale under SFAS No. 115 and therefore are carried at estimated fair value based on quoted market prices. These investments are classified as long-term as management does not intend to use them in current operations. The NDTF is managed by independent investment managers with discretion to buy, sell and invest pursuant to the objectives set forth by the trust agreement. As of December 31, 2006 Duke Energy’s NDTF ($1,775 million and $1,504 million at December 31, 2006 and 2005, respectively) consists of approximately 70% equity securities, 24% debt securities, and 6% cash and cash equivalents with a weighted-average maturity of the debt securities of approximately 13 years. Duke Energy’s captive insurance investment portfolio ($171 million and $203 million at December 31, 2006 and 2005, respectively) consists of approximately 88% debt securities and 12% equity securities with a weighted-average maturity of the debt securities of approximately 21 years, as of December 31, 2006. The cost of securities sold is determined using the specific identification method. During 2006, Duke Energy purchased approximately $1,915 million and received proceeds on sales of approximately $1,904 million on other long-term investments. During 2005, Duke Energy purchased approximately $1,782 million and received proceeds on sales of approximately $1,745 million on other long-term investments. During 2004, Duke Energy purchased approximately $2,050 million and received proceeds on sales of approximately $1,775 million on other long-term investments. Most of these purchases and sales relate to the NDTF.

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Notes To Consolidated Financial Statements—(Continued)

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,
	2006						2005
	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	$	—	$	—	$	1,514	$	—	$	—	$	632
Total short-term investments	$	—	$	—	$	1,514	$	—	$	—	$	632
Equity Securities	$	467	$	—	$	1,268	$	333	$	—	$	1,098
Corporate Debt Securities		1		1		85		—		1		61
Municipal Bonds		1		—		236		1		—		203
U.S. Government Bonds		7		—		159		13		—		230
Other		1		1		198		—		1		143
Total long-term investments	$	477	$	2	$	1,946	$	347	$	2	$	1,735

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

For the years ended December 31, 2006, 2005, and 2004 gains of approximately $57 million (including $51 million reclassified to Income from Discontinued Operations, net of tax), $3 million and $3 million, respectively, were reclassified out of AOCI into earnings.

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

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Notes To Consolidated Financial Statements—(Continued)

10. Goodwill and Intangible Assets

Duke Energy 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 2006 directly related to these tests. As discussed further in Note 2, in April 2006, Duke Energy and Cinergy consummated the previously announced merger, which resulted in Duke Energy recording goodwill and intangible assets of approximately $5.6 billion. The following table shows the components of goodwill at December 31, 2006:

Changes in the Carrying Amount of Goodwill

	Balance December 31, 2005		Acquisitions(a)		Other(b)(e)			Balance December 31, 2006
	(in millions)
U.S. Franchised Electric and Gas	$	—	$	3,500	$	—		$	3,500
Natural Gas Transmission		3,512		—		11			3,523
Commercial Power		—		1,020		(135	)		885
International Energy		256		—		11			267
Crescent(c)		7		—		(7	)		—
Total consolidated	$	3,775	$	4,520	$	(120	)	$	8,175
	Balance December 31, 2004		Acquisitions		Other(d)(e)			Balance December 31, 2005
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

(a) Goodwill recorded as of December 31, 2006 resulting from Duke Energy’s merger with Cinergy is $4,385 million.

(b) Primarily relates to foreign currency translation and approximately $135 million of goodwill allocated to the disposition of CMT (see Note 13).

(c) Reduction in goodwill at December 31, 2006 reflects the deconsolidation of Crescent in September 2006 (see Note 2).

(d) 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 13).

(e) Except as noted in (b), (c) and (d), other amounts consist primarily of foreign currency translation.

Intangible Assets

In April 2006, in connection with the merger with Cinergy, Duke Energy recorded gross intangible assets of approximately $1,091 million, primarily relating to approximately $712 million of emission allowances, approximately $295 million of gas, coal and power contracts and approximately $84 million of other intangible assets.

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Notes To Consolidated Financial Statements—(Continued)

The carrying amount and accumulated amortization of intangible assets as of December 31, 2006 and December 31, 2005 are as follows:

	December 31, 2006			December 31, 2005			Weighted Average Life
				(in millions)
Emission allowances	$	587		$	24		(a	)
Gas, coal and power contracts		322			23		(b	)
Other		57			23		25
Total gross carrying amount		966			70
Accumulated amortization—gas, coal and power contracts		(56	)		(1	)
Accumulated amortization—other		(5	)		(4	)
Total accumulated amortization		(61	)		(5	)
Total intangible assets, net	$	905		$	65

(a) Emission allowances do not have a contractual term or expiration date.

(b) Of this balance, as of December 31, 2006, approximately $115 million will be amortized on a consumption basis and does not have a definitive life, approximately $155 million will be amortized on a straight line basis over 20 years, and the remaining balance of approximately $52 million will be amortized on a straight line basis over a weighted average life of approximately 14 years.

Emission allowances sold or consumed during the years ended December 31, 2006, 2005 and 2004 were $428 million, $8 million and $6 million, respectively.

Amortization expense for intangible assets for the years ended December 31, 2006, 2005 and 2004 was approximately $48 million, $1 million and $1 million, respectively.

The table below shows the expected amortization expense for the next five years for intangible assets as of December 31, 2006. The expected amortization expense includes estimates of emission allowances consumption and estimates of consumption of commodities such as gas and coal under existing contracts. The amortization amounts discussed below are estimates. Actual amounts may differ from these estimates due to such factors as changes in consumption patterns, sales or impairments of emission allowances or other intangible assets, additional intangible acquisitions and other events.

	2007		2008		2009		2010		2011
	(in millions)
Amortization expense	$	391	$	167	$	143	$	102	$	87

In April 2006, Duke Energy recorded an intangible liability in connection with the merger with Cinergy amounting to approximately $113 million associated with the MBSSO in Ohio that will be recognized in earnings over the remaining regulatory period, which ends on December 31, 2008. The carrying amount of this intangible liability was approximately $95 million at December 31, 2006. Amortization expense related to the MBSSO is estimated to amount to approximately $27 million of income in 2007 and $68 million of income in 2008. Duke Energy also recorded approximately $56 million of intangible liabilities associated with other power sale contracts in connection with the merger with Cinergy. The carrying amount of this intangible liability was approximately $39 million at December 31, 2006. This balance will be amortized to income as follows: approximately $17 million in 2007, approximately $6 million in each of the years 2008 through 2010, and approximately $4 million in 2011.

11. Investments in Unconsolidated Affiliates and Related Party Transactions

Investments in domestic and international affiliates that are not controlled by Duke Energy, but over which it has significant influence, are accounted for using the equity method. Duke Energy received distributions of $893 million in 2006 from those investments. Of these distributions, $741 million are included in Other, assets within Cash Flows from Operating Activities on the accompanying Consolidated Statements of Cash Flows and $152 million are included in Distributions from Equity Investments within Cash Flows from Investing Activities on the accompanying Consolidated Statements of Cash Flows. Duke Energy received distributions of $856 million in 2005. Of these distributions, $473 million are included in Other, assets within Cash Flows from Operating Activities on the accompanying Consolidated Statements of Cash Flows and $383 million are included in Distributions from Equity Investments within Cash Flows from Investing Activities on the accompanying Consolidated Statements of Cash Flows. Duke Energy received distributions of $139 million in 2004, which are

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included in Other, assets within Cash Flows from Operating Activities on the accompanying Consolidated Statements of Cash Flows. Duke Energy’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 2006 dispositions.)

As of December 31, 2006 and 2005, the carrying amount of investments in affiliates approximated the amount of underlying equity in net assets.

Natural Gas Transmission. As of December 31, 2006, 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 Energy owns a significant portion of Gulfstream, it is not consolidated as Duke Energy does not hold a majority of voting control or have the ability to exercise control over Gulfstream.

Field Services. In July 2005, Duke Energy completed the transfer of a 19.7% interest in DEFS to ConocoPhillips, Duke Energy’s co-equity owner in DEFS, which reduced Duke Energy’s ownership interest in DEFS from 69.7% to 50% (the DEFS disposition transactions) and resulted in Duke Energy and ConocoPhillips becoming equal 50% owners in DEFS. As a result of the DEFS disposition transaction, Duke Energy deconsolidated its investment in DEFS which has subsequently been accounted for as an investment utilizing the equity method of accounting (see Note 13). 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 Energy sold its limited partner interest in TEPPCO LP for approximately $100 million, in each case to Enterprise GP Holdings LP, an unrelated third party. These transactions resulted in pre-tax gains of approximately $1.8 billion, which is included in Income From Discontinued Operations, net of tax, on the Consolidated Statements of Operations. For the three months ended March 31, 2005, TEPPCO LP had operating revenues of approximately $1,524 million, operating expenses of approximately $1,463 million, operating income of approximately $61.2 million, income from continuing operations of approximately $46.3 million, and net income of approximately $47.4 million.

Commercial Power. As of December 31, 2006, investments primarily included a 50% interest in South Houston Green Power, L.P (Green Power). Green Power is a cogeneration facility containing three combustion turbines in Texas City, Texas. Although Duke Energy owns a significant portion of Green Power, it is not consolidated as Duke Energy does not hold a majority voting control or have the ability to exercise control over Green Power.

International Energy. As of December 31, 2006, investments primarily included a 25% indirect interest in NMC, which owns and operates a methanol and MTBE business in Jubail, Saudi Arabia. International Energy also has a 50% ownership in Campeche, a natural gas compression facility in the Cantarell oil field in the Gulf of Mexico and a 25% indirect interest in Attiki, a natural gas distributor in Athens, Greece.

Campeche project revenues are generated from the gas compression services agreement (GCSA) with the Mexican national oil company (PEMEX). The original five year GCSA expired in November 2006 and a nine month extension was executed in October 2006. The facility ownership will transfer to PEMEX in August 2007. See Note 12 for a discussion of the impairment recognized on the Campeche investment.

Crescent. In September 2006, Duke Energy 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.

Other. As of December 31, 2006 investments primarily includes Cinergy’s telecom investments. 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 Energy 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 was included in DENA’s Western United States generation assets that were sold to LS Power during 2006 (see Note 13). As a result, the investment was classified as Assets Held for Sale in the Consolidated Balance Sheets as of December 31, 2005 and earnings and losses from this investment are classified as Income from Discontinued Operations, net of tax in the accompanying Consolidated Statements of Operations.

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Investments in Unconsolidated Affiliates

	As of:
	December 31, 2006						December 31, 2005
	Domestic		International		Total		Domestic		International		Total
	(in millions)
U.S. Franchised Electric and Gas	$	2	$	—	$	2	$	2	$	—	$	2
Natural Gas Transmission		434		18		452		428		20		448
Field Services(a)		1,166		—		1,166		1,290		—		1,290
Commercial Power		223		—		223		—		—		—
International Energy		—		165		165		—		155		155
Crescent(b)		180		—		180		17		—		17
Other		104		13		117		14		7		21
Total	$	2,109	$	196	$	2,305	$	1,751	$	182	$	1,933

(a) Includes Duke Energy’s 50 percent interest in DEFS subsequent to deconsolidation of DEFS on July 1, 2005.

(b) Includes Duke Energy’s effective 50 percent interest in Crescent subsequent to deconsolidation of Crescent during September 2006.

Equity in Earnings of Unconsolidated Affiliates

	For the Years Ended:
	December 31, 2006								December 31, 2005								December 31, 2004
	Domestic			International		Total			Domestic			International		Total			Domestic		International		Total
	(in millions)
U.S. Franchised Electric and Gas	$	(2	)	$	—	$	(2	)	$	—		$	—	$	—		$	—	$	—	$	—
Commercial Power		21			—		21			—			—		—			—		—		—
International Energy		—			80		80			—			114		114			—		51		51
Crescent(a)		23			—		23			(1	)		—		(1	)		3		—		3
Other(b)		(2	)		3		1			11			—		11			18		1		19
Total(c)	$	40		$	83	$	123		$	10		$	114	$	124		$	21	$	52	$	73

(a) Includes approximately $15 million for the year ended December 31, 2006 that represents Duke Energy’s effective 50% interest in Crescent earnings subsequent to deconsolidation of Crescent in September 2006.

(b) Includes equity investments at the corporate level.

(c) Excludes equity in earnings of approximately $609 million, $355 million and $88 million for the years ended December 31, 2006, 2005 and 2004, respectively, included in Income From Discontinued Operations, net of tax, related to equity method investments held by the natural gas businesses and included in Duke Energy’s spin-off of Spectra Energy on January 2, 2007.

Summarized Combined Financial Information of Unconsolidated Affiliates

	As of December 31,
	2006		��	2005
	(in millions)
Balance Sheet(a)
Current assets	$	3,656		$	3,414
Non-current assets		10,848			7,744
Current liabilities		(3,354	)		(3,395	)
Non-current liabilities		(5,155	)		(3,237	)
Net assets	$	5,995		$	4,526

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	For the Years Ended December 31,
	2006		2005		2004
	(in millions)
Income Statement(a)
Operating revenues	$	14,259	$	8,830	$	7,326
Operating expenses		12,365		7,683		6,872
Net income		1,657		1,075		415

(a) Amounts include DEFS and Crescent for the respective periods subsequent to deconsolidation.

Related Party Transactions. Outstanding notes receivable from unconsolidated affiliates were $226 million as of December 31, 2006 and $50 million as of December 31, 2005. Amounts are included in Notes Receivable on the Consolidated Balance Sheets. The balance outstanding as of December 31, 2006 represents International Energy’s $16 million note receivable from the Campeche project, a 50% owned joint venture, and Duke Energy Ohio and Duke Energy Indiana’s $210 million note receivable from Cinergy Receivables Company LLC (Cinergy Receivables) (see Note 23). The outstanding notes receivable had interest rates approximating current market rates.

International Energy loaned money to Campeche to assist in the costs to build. International Energy received principal and interest payments of approximately $11 million, $5 million and $7 million from Campeche, a 50% owned DEI affiliate, during 2006, 2005 and 2004, respectively.

Duke Energy Ohio and Duke Energy Indiana sell their receivables to Cinergy Receivables. During 2006 (subsequent to the closing of the Cinergy merger in April 2006), Duke Energy Ohio and Duke Energy Indiana collectively sold approximately $3.5 billion of receivables to Cinergy Receivables and received approximately $3.5 billion in proceeds from the sales, including the notes receivable (see Note 23).

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, which are included in Income From Discontinued Operations, net of tax, on the Consolidated Statements of Operations, from these affiliates of $19 million, $12 million, and $8 million during 2006, 2005, and 2004, respectively. The outstanding receivable from these affiliates was $5 million and $2 million as of December 31, 2006 and 2005, 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).

In December 2005, Duke Energy completed a 140 million Canadian dollars initial public offering on its Canadian income trust fund (the Income Fund) and sold 14 million Trust Units at an offering price of 10 Canadian dollars per Trust Unit. In January 2006, a subsequent greenshoe sale of 1.4 million additional Trust Units, pursuant to an overallotment option, were sold at a price of 10 Canadian dollars per Trust Unit. Subsequent to the January 2006 sale of additional Trust Units, Duke Energy held an approximate 58% ownership interest in the businesses of the Income Fund. Proceeds of approximately 14 million Canadian dollars are included in Proceeds from Duke Energy Income Fund within Cash Flows from Financing Activities in the Consolidated Statements of Cash Flows. 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 other 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 Energy’s ownership interest in the businesses of the Income Fund to approximately 46% at December 31, 2006. As a result of the sale of additional Trust Units, Duke Energy recognized an approximate $15 million U.S. Dollar pre-tax SAB No. 51 gain on the sale of subsidiary stock, which is classified in Income From Discontinued Operations, net of tax, 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.

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

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 for the year ended December 31, 2004. Total purchases from these affiliates were approximately $77 million for the six months ended June 30, 2005, and $125 million for the year ended December 31, 2004. Total operating expenses were approximately $1 million for the six months ended June 30, 2005, and $4 million for the year ended December 31, 2004. 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. The aforementioned amounts are included in Income From Discontinued Operations, net of tax, on the Consolidated Statements of Operations.

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 Energy’s 50% of equity in earnings of DEFS for the year ended December 31, 2006 and the period July 1, 2005 through December 31, 2005 was $574 million and $292 million, respectively, and is included in Income From Discontinued Operations, net of tax, on the Consolidated Statements of Operations. Duke Energy’s investment in DEFS as of December 31, 2006 was $1,166 million, which is included in Investments in Unconsolidated Affiliates in the accompanying Consolidated Balance Sheets. For the year ended December 31, 2006, Duke Energy had gas sales to, purchases from, and other operating revenues from affiliates of DEFS of approximately $137 million, $41 million and $12 million, respectively. As of December 31, 2006, Duke Energy had trade receivables from and trade payables to DEFS amounting to approximately $71 million and $56 million, respectively. Between July 1, 2005 and December 31, 2005, Duke Energy had gas sales to, purchases from, and other operating revenues from affiliates of DEFS of approximately $67 million, $65 million and $12 million, respectively. As of December 31, 2005, Duke Energy had trade receivables from and trade payables to DEFS of approximately $18 million and $47 million, respectively. Additionally, Duke Energy received approximately $725 million and $360 million for its share of distributions paid by DEFS in 2006 and 2005, respectively. Duke Energy has recognized an approximate $64 million receivable as of December 31, 2006 due to its share of quarterly tax distributions declared by DEFS in 2006 and paid in 2007, as compared to $90 million in 2005, which was paid in 2006. Of these distributions $573 million and $287 million were included in Other, assets within Cash Flows from Operating Activities for the years ended 2006 and 2005, respectively, and approximately $152 million and $73 million were included in Distributions from Equity Investments within Cash Flows from Investing Activities for the years ended 2006 and 2005, respectively, within the accompanying Consolidated Statements of Cash Flows. Summary financial information for DEFS, which has been accounted for under the equity method since July 1, 2005 is as follows:

	Twelve-months Ended December 31, 2006		Six-months Ended December 31, 2005
	(in millions)
Operating revenues	$	12,335	$	7,463
Operating expenses	$	11,063	$	6,814
Operating income	$	1,272	$	649
Net income	$	1,139	$	584
	December 31, 2006		December 31, 2005
	(in millions)
Current assets	$	2,129	$	2,706
Non-current assets	$	4,767	$	5,005
Current liabilities	$	2,177	$	3,068
Non-current liabilities	$	2,391	$	2,038
Minority interest	$	71	$	95

As of December 31, 2006, there was an immaterial basis difference between Duke Energy’s carrying value of the investment in DEFS and the value of Duke Energy’s proportionate share of the underlying net assets in DEFS.

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DEFS is a limited liability company which is a pass-through entity for U.S. income tax purposes. DEFS also owns corporations who file their own respective, federal, foreign and state income tax returns and income tax expense related to these corporations is included in the income tax expense of DEFS. Therefore, DEFS’ net income does not include income taxes for earnings which are pass-through to the members based upon their ownership percentage and Duke Energy recognizes the tax impacts of its share of DEFS’ pass-through earnings in Income From Discontinued Operations, net of tax, 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 2005 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.

An indirect wholly owned subsidiary of Duke Energy contributed all the membership interest in Crescent to a newly-formed joint venture causing Duke Energy to deconsolidate Crescent as of September 7, 2006 (see Note 2). Duke Energy’s 50% of equity in earnings of Crescent for the period from September 8, 2006 through December 31, 2006 was $15 million and Duke Energy’s investment in Crescent as of December 31, 2006 was $180 million, which is included in Investments in Unconsolidated Affiliates in the accompanying Consolidated Balance Sheets. Summary financial information for Crescent, which has been accounted for under the equity method since September 7, 2006 is as follows:

	September 7 through December 31, 2006
	(in millions)
Operating revenues	$	179
Operating expenses	$	152
Operating income	$	27
Net income	$	30
	December 31, 2006
	(in millions)
Current assets	$	151
Non-current assets	$	1,810
Current liabilities	$	211
Non-current liabilities	$	1,414
Minority interest	$	31

In the normal course of business, Duke Energy’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 Energy’s Consolidated Financial Statements.

Also see Note 2, Note 12, Note 15, Note 18 and Note 23 for additional related party information.

12. Impairments, Severance, and Other Charges

International Energy. In 2006, International Energy recorded a $50 million other-than-temporary impairment charge related to an investment in Campeche, a natural gas compression facility in the Cantarell oil field in the Gulf of Mexico. Campeche project revenues are generated from the GCSA with the PEMEX. The current GCSA expired in November 2006 and a nine month extension was executed in October 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

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$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 year ended December 31, 2006, and a $33 million reserve against notes receivable from Campeche, which has been classified within Operations, Maintenance and Other in the Consolidated Statements of Operations for the year ended December 31, 2006. The facility ownership will transfer to PEMEX in August 2007. The carrying value of the note at December 31, 2006 was $16 million, which is management’s best estimate of the net realizable value of the note receivable from Campeche.

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 (Losses) Gains on Sales and Impairments of Equity Investments in the accompanying Consolidated Statements of Operations.

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.

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.

Other. See Note 8 for a discussion of the impacts of the DENA exit plan on certain cash flow hedges.

See Note 13 for impairments related to discontinued operations.

Severance.During the period from the effective date of the Cinergy merger through December 31, 2006, Duke Energy accrued approximately $89 million related to voluntary and involuntary severance as a result of the merger with Cinergy (see Note 2). Additionally, Duke Energy recorded approximately $45 million in severance liabilities related to legacy Cinergy that has been included in goodwill.

As discussed in Note 13, in June 2006, Duke Energy announced it had reached an agreement to sell CMT, as well as associated contracts managed by these companies, to Fortis, a Benelux-based financial services group. As such, results of operations for CMT have been reflected in Income from Discontinued Operations, net of tax, from the date of the Cinergy acquisition to the date of sale. The sale of CMT was consummated in October 2006 and Duke Energy did not record any material severance liabilities as a result of the disposal.

During the fourth quarter of 2006, in connection with Duke Energy’s spin-off of Spectra Energy, Duke Energy recognized approximately $12 million of severance costs under its ongoing severance plan. This amount is included in Income From Discontinued Operations, net of tax, on the Consolidated Statements of Operations. Future severance costs under this plan, if any, are not currently estimable.

As discussed further in Note 13, 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 DENA employees. Approximately $2 million of the related pre-tax expense is reflected in Operation, Maintenance and Other and approximately $20 million is reflected in Income from Discontinued Operations, net of tax in the accompanying Consolidated Statements of Operations for the year ended December 31, 2005. Additionally, DENA offered certain enhanced severance benefits to employees 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. During 2006, Duke Energy reversed approximately $9 million of previously recorded severance amounts due to a change in estimate. As a result of this exit plan, Duke Energy terminated approximately 207 employees through the end of 2006. Management anticipates future severance costs related to this exit plan, which relate to retention costs associated with future services, not included in the following table will not be material.

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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, 2006		Provision/ Adjustments		Noncash Adjustments			Cash Reductions			Balance at December 31, 2006
	(in millions)
Natural Gas Transmission(c)	$	3	$	—	$	—		$	(1	)	$	2
Other(c)		28		146		(11	)		(103	)		60
Total(a)	$	31	$	146	$	(11	)	$	(104	)	$	62
	Balance at January 1, 2005		Provision/ Adjustments		Noncash Adjustments			Cash Reductions			Balance at December 31, 2005
U.S. Franchised Electric and Gas	$	4	$	—	$	(2	)	$	(2	)	$	—
Natural Gas Transmission(c)		6		1		(1	)		(3	)		3
Field Services(b)(c)		—		1		(1	)		—			—
International Energy		1		—		(1	)		—			—
Other(c)		4		26		—			(2	)		28
Total(a)	$	15	$	28	$	(5	)	$	(7	)	$	31
	Balance at January 1, 2004		Provision/ Adjustments		Noncash Adjustments			Cash Reductions			Balance at December 31, 2004
U.S. Franchised Electric and Gas	$	60	$	—	$	(6	)	$	(50	)	$	4
Natural Gas Transmission(c)		29		1		(6	)		(18	)		6
Field Services(b)(c)		6		1		—			(7	)		—
International Energy		6		—		(4	)		(1	)		1
Other(c)		49		3		(5	)		(43	)		4
Total(a)	$	150	$	5	$	(21	)	$	(119	)	$	15

(a) Substantially all expected severance costs will be applied to the reserves within one year.

(b) Includes minority interest.

(c) Severance expense included in Income From Discontinued Operations, net of tax in the Consolidated Statements of Operations was $3 million, $24 million, and $3 million for 2006, 2005, and 2004, respectively.

13. Discontinued Operations and Assets Held for Sale

As discussed in Note 1, on January 2, 2007, Duke Energy completed the spin-off of Spectra Energy, which principally consists of Duke Energy’s former Natural Gas Transmission business segment and Duke Energy’s former 50% ownership interest in DCP Midstream, to Duke Energy shareholders. The results of operations of these businesses are presented as discontinued operations for the periods presented in the accompanying Consolidated Statements of Operations. Assets and liabilities of entities included in the spin-off of Spectra Energy were transferred from Duke Energy on a historical cost basis on the date of the spin-off transaction. No gain or loss was recognized on the distribution of these operations to Duke Energy shareholders. Approximately $20.5 billion of assets, $14.9 billion of liabilities (which includes approximately $8.6 billion of debt) and $5.6 billion of common stockholders’ equity (which includes approximately $1.0 billion of accumulated other comprehensive income) were distributed from Duke Energy as of the date of the spin-off.

Additionally, in February 2007, International Energy completed the disposition of its assets in Bolivia. Accordingly, the results of operations related to Bolivia have been reflected as a component of discontinued operations for all periods presented.

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

Discontinued Operations (in millions)

	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)			(Loss) Gain on Dispositions, Net of Tax			Income (Loss) from Discontinued Operations, Net of Tax
Year Ended December 31, 2006
Spectra Energy	$	4,514	$	1,383		$	430		$	953		$	—		$	—		$	—		$	953
Commercial Power		34		(7	)		(7	)		—			33			50			(17	)		(17	)
International Energy		18		(29	)		(3	)		(26	)		(10	)		(3	)		(7	)		(33	)
Other(a)		748		(55	)		(13	)		(42	)		(127	)		(46	)		(81	)		(123	)
Total consolidated	$	5,314	$	1,292		$	407		$	885		$	(104	)	$	1		$	(105	)	$	780
Year Ended December 31, 2005
Spectra Energy	$	9,341	$	2,507		$	884		$	1,623		$	—		$	—		$	—		$	1,623
International Energy		19		6			5			1			—			—			—			1
Crescent		2		1			—			1			10			4			6			7
Other(a)		2,655		(631	)		(224	)		(407	)		(481	)		(192	)		(289	)		(696	)
Total consolidated	$	12,017	$	1,883		$	665		$	1,218		$	(471	)	$	(188	)	$	(283	)	$	935
Year Ended December 31, 2004
Spectra Energy	$	13,136	$	775		$	257		$	518		$	—		$	—		$	—		$	518
International Energy		99		(11	)		4			(15	)		295			22			273			258
Crescent		2		—			—			—			9			4			5			5
Other(a)		3,144		172			82			90			1			—			1			91
Total consolidated	$	16,381	$	936		$	343		$	593		$	305		$	26		$	279		$	872

(a) Other includes the results for DENA’s discontinued operations, which were previously reported in the DENA segment.

Amounts in the table above are net of intercompany eliminations between Spectra Energy and the former DENA business, which is included in Other. Intercompany revenues and expenses in 2006 were not material. In 2005, Spectra Energy had intercompany revenues of approximately $36 million, which were expenses of the former DENA business, which is included in Other. In 2004, Spectra Energy had intercompany revenues of approximately $183 million, which were expenses of the former DENA business, which is included in Other. Additionally, in 2004, the former DENA business had intercompany revenues of approximately $36 million, which were expenses of Spectra Energy. All of these amounts eliminate in consolidation.

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Notes To Consolidated Financial Statements—(Continued)

The following table presents the carrying values of the major classes of assets and associated liabilities held for sale in the accompanying Consolidated Balance Sheets as of December 31, 2006 and 2005. Assets held for sale as of December 31, 2006 primarily relate to Duke Energy Indiana’s Wabash River Power Station (see Note 2). Assets held for sale as of December 31, 2005 primarily relate to DENA’s assets that were sold to LS Power, as discussed further below.

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

	December 31, 2006		December 31, 2005
	(in millions)
Current assets	$	28	$	1,528
Investments and other assets		19		2,059
Property, plant and equipment, net		115		1,538
Total assets held for sale	$	162	$	5,125
Current liabilities	$	26	$	1,488
Long-term debt		—		61
Deferred credits and other liabilities		18		2,024
Total liabilities associated with assets held for sale	$	44	$	3,573

As discussed above, the results of operations for all of the businesses transferred to Spectra Energy are presented as discontinued operations for all periods presented. Significant transactions occurring during the years ended December 31, 2006, 2005, and 2004 related to the operations transferred to Spectra Energy and significant transactions within the other operations of Duke Energy that resulted in discontinued operations presentation, are discussed below. Transactions under Spectra Energy primarily include transactions at Duke Energy’s former Natural Gas Transmission and Field Services business segments.

Year Ended December 31, 2006

Spectra Energy

As discussed further below under “Year Ended December 31, 2005,” 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 Energy discontinued hedge accounting for certain contracts held by Duke Energy 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 $19 million of realized and unrealized pre-tax losses related to these contracts were recognized in earnings by Duke Energy for the year ended December 31, 2006. Cash settlements on these contracts since the deconsolidation of DEFS on July 1, 2005 of approximately $163 million are classified as a component of net cash used in investing activities in the accompanying Consolidated Statements of Cash Flows for the year ended December 31, 2006.

The sale of certain Stone Mountain natural gas gathering system assets resulted in proceeds of $18 million (which is reflected in Net proceeds from the sales of equity investments and other assets, and sales of and collections on notes receivable within Cash Flows from Investing Activities in the Consolidated Statements of Cash Flows), and pre-tax gain of $5 million. In addition, proceeds of approximately $29 million (which is reflected in Other, assets within Cash Flows from Operating Activities in the Consolidated Statements of Cash Flows) were received and a pre-tax gain of $29 million was recorded on the sale of stock received as consideration for the settlement of a customers’ transportation contract.

As a result of a settlement of a property insurance claim, proceeds of approximately $30 million were received and a pre-tax gain of $10 million was recognized.

Approximately $60 million of expenses related to costs to achieve the spin-off of the natural gas businesses were incurred during the year ended December 31, 2006.

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Commercial Power

In June 2006, Duke Energy announced it had reached an agreement to sell CMT, as well as certain Duke Energy Ohio trading contracts, to Fortis, a Benelux-based financial services group. In October 2006, the sale transaction was completed. Under the purchase and sale agreement, Fortis purchased CMT at a base price of approximately $210 million. In addition, Fortis paid approximately $200 million for the portfolio of contracts and an amount equal to the estimated net working capital associated with these companies at the time of close. In October 2006, Duke Energy received total pre-tax cash proceeds of approximately $700 million and recorded an approximate $25 million pre-tax gain on the sale. Income tax expense recorded as a result of this transaction relates to the approximate $135 million of goodwill included in assets held for sale that was not deductible for tax purposes, thus creating a taxable gain that was greater than the gain for book purposes. Results of operations for CMT, as well as certain Duke Energy Ohio trading contracts, have been reflected in Income from Discontinued Operations, net of tax, from the date of the Cinergy acquisition through the date of sale.

In October 2006, in connection with this transaction, Duke Energy entered into a series of Total Return Swaps (TRS) with Fortis, which are accounted for as mark to market derivatives. The TRS offsets the net fair value of the contracts being sold to Fortis. The TRS will be cancelled for each underlying contracts as each is transferred to Fortis. All economic and credit risk associated with the contracts has been transferred to Fortis as of the date of the sale through the TRS. As of December 31, 2006, approximately 70% of the contracts had been novated by Fortis. At December 31, 2006, contracts with a net fair value of approximately $43 million remain in Assets Held for Sale and represent contracts that have yet to be novated by Fortis.

International Energy

In first quarter 2006, based on management’s best estimate of recoverability, International Energy recorded an allowance of approximately $19 million ($12 million after tax) against a receivable from Norsk Hydro ASA (Norsk) related to the 2003 sale of International Energy’s European business. During the second quarter of 2006, International Energy and Norsk signed a settlement agreement in which Norsk agreed to pay International Energy approximately $34 million in full settlement of International Energy’s receivable. In connection with this settlement, International Energy recorded an approximate $9 million write-up ($5 million after tax) of the receivable through a reduction in the valuation allowance. In July 2006, International Energy received the settlement proceeds.

In December 2006, Duke Energy engaged in discussions with a potential buyer of International Energy’s assets in Bolivia. Such discussions to sell the assets were subject to a binding agreement between the parties, which was finalized in February 2007, and resulted in the sale of International Energy’s 50 percent ownership interest in two hydroelectric power plants near Cochabamba, Bolivia to Econergy International for approximately $20 million. Based upon the agreed upon selling price of the assets, in December 2006 Duke Energy recorded pre-tax impairment charges of approximately $28 million. The impairment charges reduced the carrying value of the assets to the estimated selling price pursuant to the aforementioned agreement. As a result of the sale, International Energy no longer has any assets in Bolivia.

Other

In January 2006, Duke Energy 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. 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 Duke Energy of approximately $40 million, which Duke Energy recorded as an additional gain on the sale of assets.

In October 2006, Duke Energy 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.

In the fourth quarter of 2006, the last remaining contract related to DEM expired, which completed Duke Energy’s exit from DEM��s operations. Accordingly, results of operations for DEM for all periods presented have been reclassified to a component of Income From Discontinued Operations, net of tax, on the Consolidated Statements of Operations.

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Year Ended December 31, 2005

Spectra Energy

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

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

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 Energy discontinued hedge accounting for certain contracts held by Duke Energy 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 Energy for the year ended December 31, 2005. Of this amount, approximately $120 million was originally recorded in the Field Services segment and approximately $194 million was recorded in Other. Cash settlements on these contracts since the deconsolidation of DEFS on July 1, 2005 of approximately $133 million are classified as a component of net cash used in investing activities in the accompanying Consolidated Statements of Cash Flows for the year ended December 31, 2005.

In February 2005, Texas Eastern Products Pipeline Company, LLC (TEPPCO GP), which is the general partner of TEPPCO Partners, LP (TEPPCO LP), was sold for approximately $1.1 billion and Duke Energy sold its limited partner interest in TEPPCO LP for approximately $100 million, in each case to Enterprise GP Holdings LP (EPCO), an unrelated third party. These transactions resulted in pre-tax gains of $1.2 billion. 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 completed the agreement with ConocoPhillips, Duke Energy’s co-equity owner in DEFS, to reduce Duke Energy’s ownership interest in DEFS from 69.7% to 50% (the DEFS disposition transaction), which results in Duke Energy and ConocoPhillips becoming equal 50% owners in DEFS. Duke Energy has received, directly and indirectly through its ownership interest in DEFS, a total of approximately $1.1 billion from ConocoPhillips and DEFS, consisting of approximately $1.0 billion in cash and approximately $0.1 billion of assets. The DEFS disposition transaction resulted in a pre-tax gain of approximately $575 million. The DEFS disposition transaction includes the transfer to Duke Energy of DEFS’ Canadian natural gas gathering and processing facilities. Additionally, the DEFS disposition transaction included the acquisition of ConocoPhillips’ interest in the Empress System. Subsequent to the closing of the DEFS disposition transaction, effective on July 1, 2005, DEFS is no longer consolidated into Duke Energy’s consolidated financial statements and is accounted for by Duke Energy as an equity method investment. The Canadian natural gas gathering and processing facilities and the Empress System are included in the Natural Gas Transmission segment.

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 Energy Midstream Services Canada Corporation (Duke Midstream) from a subsidiary of Duke Energy. 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 Energy retains an ownership interest in the Income Fund of approximately 58% and will continue to operate and manage this business. Duke Energy continues to consolidate the results of this business.

Crescent

Crescent routinely develops real estate projects and operates those facilities until they are substantially leased and a sales agreement is finalized. In September 2006, Duke Energy deconsolidated its investment in Crescent (see Note 2) and subsequently accounts for its investment in the Crescent JV under the equity method of accounting. Prior to the date of deconsolidation, if Crescent did not retain any significant continuing involvement after the sale, Crescent classified the project as “discontinued operations” as required by SFAS No. 144.

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Notes To Consolidated Financial Statements—(Continued)

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 Income from Discontinued Operations, net of tax, in the accompanying Consolidated Statements of Operations.

Other

In the first quarter of 2005, Duke Energy’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, Duke Energy completed the sale of Bayside Power L.P. (Bayside) to affiliates of Irving Oil Limited (Irving), under which Irving would purchase Duke Energy’s 75% interest in Bayside. 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 Income 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.

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 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.

Management retained DENA’s Midwestern generation assets, consisting of approximately 3,600 MW of power generation, and certain contracts related to the Midwestern generating facilities, as the merger with Cinergy provided a sustainable business model for those assets (see Note 2 for further details on the Cinergy merger). Accordingly, these assets do not qualify for discontinued operations classification and remain in continuing operations as a component of the Commercial Power segment. Also transferred to Commercial Power were DENA’s Southeastern generation operations, including related commodity contracts, which do not meet the requirements for discontinued operations classification due to Duke Energy’s continuing involvement with these operations. In addition, management will continue to wind down the limited remaining operations of DETM, the results of which will be reported in Other’s continuing operations until the wind down of the operations is complete.

In connection with this exit plan, Duke Energy recognized pre-tax losses of approximately $1.1 billion in 2005. 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 $0.4 billion as the result of selling certain gas transportation and structured contracts (as discussed further below), and

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• Pre-tax deferred gains in AOCI of approximately $0.2 billion related to the discontinued cash flow hedges of forecasted gas purchase and power sale transactions, which were recognized as the forecasted transactions occurred.

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 12). 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. Approximately $700 million has been incurred from the announcement date through December 31, 2006, of which approximately $230 million was incurred during the year ended December 31, 2006, and approximately $470 million was incurred during the year ended December 31, 2005, approximately $400 million of which was recognized in Income From Discontinued Operations, net of tax. As of December 31, 2006 the DENA exit activities are substantially complete and no additional charges are anticipated.

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

Year Ended December 31, 2004

Spectra Energy

In December 2004, based upon management’s assessment of the probable disposition of some plant and transportation assets in Wyoming, the book value of those assets was written down by $4 million ($3 million net of minority interest) to $10 million, which represented the estimated fair value less cost to sell. In February 2005, these assets were exchanged for certain gathering assets in Oklahoma of equivalent fair value.

In December 2004, gas system and treating plant assets in Southeast New Mexico and South Texas, respectively, were sold for proceeds of approximately $6 million, with the carrying value being approximately equal to the sales price.

In the third quarter of 2004, impairment charges of approximately $68 million ($61 million net of minority interest) were recorded. These impairment charges related to the following:

• approximately $22 million related to various operating assets.

• approximately $23 million related to management’s assessment of the recoverability of some equity method investments. It was 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.

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

In the third quarter of 2004, additional interests in three separate entities (for which ownership was less than 100%, but the entities had been consolidated) were acquired for a total purchase price of $4 million, and the exchange of some assets. Two of these acquisitions, Mobile Bay Processing Partners (MBPP) and Gulf Coast NGL Pipeline, LLC (GC), resulted in 100% ownership. 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 Energy 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. 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.

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Notes To Consolidated Financial Statements—(Continued)

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

In the second quarter of 2004, gathering, processing and transmission assets in southeast New Mexico were acquired 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.

Sales of other assets totaled $38 million in net proceeds and total pre-tax gains of approximately $35 million. Significant sales included the sale of storage gas related to the Canadian distribution operations, the sale of an interest in the Millennium Pipeline, and the sale of land.

International Energy

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

International Energy held a receivable from Norsk related to the 2003 sale of International Energy’s European business. In 2004, International Energy recorded a $14 million ($9 million after tax) allowance against the carrying value of the note based on management’s assessment of the probability of not collecting the entire note.

Crescent

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 Income from Discontinued Operations, net of tax, in the accompanying Consolidated Statements of Operations.

Other

For the year ended December 31, 2004, Duke Energy’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.

• 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.

• In December 2004, Duke Energy agreed to sell the partially completed Grays Harbor facility to an affiliate of Invenergy LLC and terminated its 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. As discussed above, in the first quarter of 2005, Grays Harbor was sold.

Additionally, during 2004, the Western and Northeast operations had operating losses, which substantially offset the above 2004 gains.

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Notes To Consolidated Financial Statements—(Continued)

During 2004, Duke Energy received approximately $58 million from the sale or collection of all of DCP notes receivable. An immaterial after tax gain related to this transaction was recorded.

14. Property, Plant and Equipment

	Estimated Useful Life	December 31,
		2006			2005
	(Years)	(in millions)
Land	—	$	684		$	571
Plant—Regulated
Electric generation, distribution and transmission(a)	20 – 125		29,845			18,935
Natural gas transmission and distribution	20 – 82		12,374			10,810
Gathering and processing facilities(a)	20 – 25		2,219			1,570
Other buildings and improvements(a)	16 – 90		613			388
Plant—Unregulated
Electric generation, distribution and transmission(a)	20 – 125		6,036			3,869
Natural gas transmission and distribution	20 – 82		68			32
Gathering and processing facilities	20 – 25		198			678
Other buildings and improvements(a)	16 – 90		43			27
Nuclear fuel	4		890			890
Equipment(a)	3 – 40		1,098			669
Vehicles	3 – 25		134			125
Construction in process	—		2,257			946
Other(a)	5 – 122		1,871			1,313
Total property, plant and equipment			58,330			40,823
Total accumulated depreciation—regulated(b), (c)			(15,538	)		(10,721	)
Total accumulated depreciation—unregulated(c)			(1,345	)		(902	)
Total net property, plant and equipment		$	41,447		$	29,200

(a) Includes capitalized leases: $161 million for 2006 and $48 million for 2005.

(b) Includes accumulated amortization of nuclear fuel: $541 million for 2006 and $583 million for 2005.

(c) Includes accumulated amortization of capitalized leases: $28 million for 2006 and $19 million for 2005.

Capitalized interest, which includes the interest expense component of AFUDC, amounted to $56 million for 2006, $23 million for 2005, and $18 million for 2004.

15. Debt and Credit Facilities

Summary of Debt and Related Terms

	Weighted- Average Rate		Year Due	December 31,
				2006			2005
				(in millions)
Unsecured debt	6.6	%	2007 – 2036	$	14,504		$	12,600
Secured debt	6.5	%	2007 – 2024		1,453			1,570
First and refunding mortgage bonds	5.2	%	2008 – 2032		1,507			1,214
Capital leases	5.4	%	2007 – 2025		94			10
Other debt(a)	4.9	%	2007 – 2040		1,875			208
Commercial paper(b)	5.4	%			751			383
Fair value hedge carrying value adjustment			2008 – 2032		43			58
Unamortized debt discount and premium, net					(54	)		(13	)
Total debt(c)					20,173			16,030
Current maturities of long-term debt					(1,605	)		(1,400	)
Short-term notes payable and commercial paper(d)					(450	)		(83	)
Total long-term debt(e)				$	18,118		$	14,547

(a) Includes $1,329 million and $172 million of Duke Energy pollution control bonds as of December 31, 2006 and 2005, respectively. As of December 31, 2006 and 2005, $408 million and $40 million, respectively, was secured by first and refunding mortgage bonds and $344 million and $77 million, respectively, was secured by a letter of credit.

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(b) Includes $300 million as of both December 31, 2006 and 2005 that was classified as Long-term Debt on the Consolidated Balance Sheets due to the existence of long-term credit facilities which back-stop these commercial paper balances along with Duke Energy’s ability and intent to refinance these balances on a long-term basis. The weighted-average days to maturity were 25 days as of December 31, 2006 and 18 days as of December 31, 2005.

(c) As of December 31, 2006, $508 million of debt was denominated in Brazilian Reals and $3,820 million of debt was denominated in Canadian dollars. 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.

(d) Weighted-average rates on outstanding short-term notes payable and commercial paper was 5.4% as of December 31, 2006 and 3.3% as of December 31, 2005.

(e) The current and non-current portions of Crescent’s long-term debt balances of approximately $2 million and approximately $23 million, respectively, as of December 31, 2005, are no longer included in Duke Energy’s consolidated debt balance due to the deconsolidation of Crescent in September 2006.

Unsecured Debt.At December 31, 2006, approximately $629 million of pollution control bonds and approximately $300 million of commercial paper, which are short-term obligations by nature, were classified as long-term debt on the Consolidated Balance Sheets due to Duke Energy’s intent and ability to utilize such borrowings as long-term financing. Duke Energy’s credit facilities with non-cancelable terms in excess of one year as of the balance sheet date give Duke Energy the ability to refinance these short-term obligations on a long-term basis.

In November 2006, Union Gas issued 4.85% fixed-rate debenture bonds denominated in 125 million Canadian dollars (approximately $108 million U.S. dollar equivalents as of the closing date) due in 2022.

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

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 Energy. As a result of Duke Energy’s deconsolidation of Crescent effective September 7, 2006, Crescent’s outstanding debt balance of $1,298 million was removed from Duke Energy’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%.

In August 2006, Duke Energy Kentucky issued approximately $77 million principal amount of floating rate tax-exempt notes due August 1, 2027. Proceeds from the issuance were used to refund a like amount of debt on September 1, 2006 then outstanding at Duke Energy Ohio. Approximately $27 million of floating rate debt was swapped to a fixed rate concurrent with closing.

In June 2006, Duke Energy Indiana issued $325 million principal amount of 6.05% senior unsecured notes due June 15, 2016. Proceeds from the issuance were used to repay $325 million of 6.65% First Mortgage Bonds that matured on June 15, 2006.

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.

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.

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 8% Equity Units in November 2004.

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Convertible Debt.As of December 31, 2006 and 2005, unsecured debt included $110 million and $742 million, respectively, of 1.75% convertible senior notes due in 2023. These senior notes, which were issued in May 2003, are convertible to Duke Energy common stock at a premium of 40% above the May 1, 2003 closing common stock market price of $16.85 per share. The senior notes outstanding as of December 31, 2006 are potentially convertible into approximately 4.7 million shares of common stock which are included as outstanding shares in the diluted EPS calculation (see Note 19). The conversion of these senior notes into shares of Duke Energy common stock is contingent upon the occurrence of certain events during specified periods. These events include whether the price of Duke Energy common stock reaches specified thresholds, the credit rating of Duke Energy falls below certain thresholds, the convertible notes are called for redemption by Duke Energy, or specified transactions have occurred. In addition to the aforementioned events that could trigger early redemption, holders of the senior notes may require Duke Energy to purchase all or a portion of their senior notes for cash on May 15, 2007, May 15, 2012, and May 15, 2017, at a price equal to the principal amount of the senior notes plus accrued interest, if any. Duke Energy may redeem for cash all or a portion of the senior notes at any time on or after May 20, 2007, at a price equal to the sum of the issue price plus accrued interest, if any, on the redemption date. These convertible senior notes became convertible into shares of Duke Energy common stock during fiscal quarters beginning April 1, 2006 due to the market price of Duke Energy common stock achieving a specified threshold for each respective quarter. Holders of the convertible senior notes were allowed to exercise their right to convert on or prior to December 31, 2006. During 2006, approximately 27 million shares of common stock were issued related to this conversion, which resulted in the retirement of approximately $632 million of convertible senior notes. During 2005, as a result of the same market price trigger, approximately 1.2 million shares of common stock were issued related to this conversion, which resulted in the retirement of approximately $28 million of convertible senior notes.

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

Other Assets Pledged as Collateral. As of December 31, 2006, secured debt also consisted of various project financings, including Maritimes & Northeast Pipeline, LLC, Maritimes & Northeast Pipeline, LP (collectively, M&N Pipeline). A portion of the assets, ownership interest and business contracts in these various projects are pledged as collateral. Additionally, as of December 31, 2006, substantially all of U.S. Franchised Electric and gas’s electric plant in service was subject to a mortgage lien securing the first and refunding mortgage bonds.

Floating Rate Debt. Unsecured debt, secured debt and other debt included approximately $3.2 billion of floating-rate debt as of December 31, 2006, and $1.7 billion as of December 31, 2005. As of December 31, 2006 and 2005, $500 million and $488 million of Brazilian debt that is indexed annually to Brazilian inflation was included in floating rate debt. Floating-rate debt is primarily based on commercial paper rates or a spread relative to an index such as a London Interbank Offered Rate for debt denominated in U.S. dollars, and Banker’s Acceptances for debt denominated in Canadian dollars. As of December 31, 2006 and 2005, the average interest rate associated with floating-rate debt was approximately 4.8% and 6.4%, respectively.

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At December 31, 2006, Other debt included approximately $326 million of notes payable related to Cinergy’s Trust Preferred Securities (see Note 23), which will mature in February 2007. The entire outstanding balance of the debt is classified within Current Maturities of Long-term Debt on the Consolidated Balance Sheets at December 31, 2006.

Maturities, Call Options and Acceleration Clauses.

Annual Maturities as of December 31, 2006

	(in millions)
2007	$	1,605
2008		2,109
2009		1,634
2010		1,435
2011		604
Thereafter		12,336
Total long-term debt(a)	$	19,723

(a) Excludes short-term notes payable and commercial paper of $450 million.

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

Duke Energy may be required to repay certain debt should the credit ratings at Duke Energy Carolinas fall to a certain level at Standard & Poor’s (S&P) or Moody’s Investor Service (Moody’s). As of December 31, 2006, Duke Energy had $13 million of senior unsecured notes which mature serially through 2012 that may be required to be repaid if Duke Energy’s senior unsecured debt ratings fall below BBB- at S&P or Baa3 at Moody’s, and $23 million of senior unsecured notes which mature serially through 2016 that may be required to be repaid if Duke Energy’s senior unsecured debt ratings fall below BBB at S&P or Baa2 at Moody’s. As of February 1, 2007, Duke Energy Carolinas’ senior unsecured credit rating was BBB at S&P and A3 at Moody’s.

Available Credit Facilities and Restrictive Debt Covenants. During the year ended December 31, 2006, Duke Energy’s consolidated credit capacity increased by approximately $842 million compared to December 31, 2005 primarily due to the merger with Cinergy. This increase was net of other reductions in credit capacity due to the terminations of an $800 million syndicated credit facility and $590 million of other bi-lateral credit facilities. The terminations of these credit facilities primarily reflect Duke Energy’s reduced liquidity needs as a result of exiting the former DENA business.

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

Duke Energy’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 December 31, 2006, Duke Energy 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.

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Credit Facilities Summary as of December 31, 2006 (in millions)

	Expiration Date	Credit Facilities Capacity		Amounts Outstanding
				Commercial Paper		Letters of Credit		Total
Duke Energy Corporation
$400 364-day syndicated(a), (b)
Total Duke Energy Corporation	December 2007	$	400	$	—	$	111	$	111
Duke Energy Carolinas, LLC
$600 multi-year syndicated(a), (b), (c)	June 2011				300		4		304
$75 three-year bi-lateral(a), (b)	September 2009
$75 three-year bi-lateral(a), (b)	September 2009
Total Duke Energy Carolinas, LLC			750		300		4		304
Spectra Energy Capital LLC
$600 multi-year syndicated(a), (b)	June 2010				—		13		13
$350 364-day syndicated(b)	November 2007				350		—		350
Total Spectra Energy Capital LLC			950		350		13		363
Westcoast Energy Inc.
$173 multi-year syndicated(d)	June 2011		173		—		—		—
Union Gas Limited
$345 364-day syndicated(e)	June 2007		345		—		—		—
Cinergy Corp.
$1,500 multi-year syndicated(a), (b), (f)	June 2011		1,500		100		11		111
Total(g)		$	4,118	$	750	$	139	$	889

(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) Credit facility increased from $500 million to $600 million in November 2006.

(d) 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%.

(e) Credit facility is denominated in Canadian dollars totaling 400 million Canadian dollars and contains a covenant that requires 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.

(f) Contains $500 million sub limits each for Duke Energy Ohio and Duke Energy Indiana and a $100 million sub limit for Duke Energy Kentucky. Credit facility decreased from $2.0 billion to $1.5 billion in November 2006.

(g) This summary excludes certain demand facilities and committed facilities that are immaterial in size or which generally support very specific requirements.

Duke Energy has approximately $1,095 million of credit facilities which expire in 2007, of which approximately $695 million relates to credit facilities of Spectra Energy Capital. Of the $400 million of expiring credit facilities remaining with Duke Energy subsequent to the spin-off of the natural gas businesses (see Note 1), it is Duke Energy’s intent to resyndicate these expiring facilities and possibly increase the size of the facilities.

Other Loans. During 2006 and 2005, Duke Energy had loans outstanding against the cash surrender value of the life insurance policies that it owns on the lives of its executives. The amounts outstanding were $594 million as of December 31, 2006 and $552 million as of December 31, 2005. The amounts outstanding were carried as a reduction of the related cash surrender value that is included in Other Assets on the Consolidated Balance Sheets.

16. Preferred and Preference Stock at Duke Energy

As of December 31, 2006, as a result of the corporate restructuring in connection with the Cinergy merger, there were 44 million authorized shares of preferred stock, par value $0.001 per share, with no such preferred shares outstanding.

As of December 31, 2005, there were no shares of preferred and preference stock outstanding at Duke Energy.

Preferred Stock without Sinking Fund Requirements.In December 2005, Duke Energy redeemed all Preferred and Preference stock without Sinking Fund Requirements for approximately $137 million and recognized an immaterial loss on the redemption.

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Preferred and Preference Stock of Duke Energy’s Subsidiaries. In connection with the Westcoast acquisition in 2002, Duke Energy 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, 2006 and 2005. 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, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity.” As such, these preferred and preference shares are considered contingently redeemable shares and are included in Minority Interests on the Consolidated Balance Sheets.

Additionally, in connection with the Cinergy merger in April 2006, Duke Energy assumed approximately $11 million of authorized and issued preferred stock at Duke Energy Indiana. All outstanding shares of Duke Energy Indiana preferred stock were redeemed in May 2006 at par, plus accrued and unpaid dividends.

17. Commitments and Contingencies

General Insurance

Duke Energy carries, either directly or 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 Energy’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 Energy’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) insurance policies in support of the indemnification provisions of Duke Energy’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 extra expense. All coverages are subject to certain deductibles, terms and conditions common for companies with similar types of operations.

In 2006, Bison was a member of Oil Insurance Limited (OIL) and sEnergy Insurance Limited (sEnergy), which provided property and business interruption reinsurance coverage respectively for Duke Energy’s non-nuclear facilities. Duke Energy accounts for its memberships under the cost method, as it does not have the ability to exert significant influence over these investments. Bison terminated its membership in OIL effective December 31, 2006 and will pay a withdrawal premium during 2007 as a result of this decision. sEnergy ceased insuring events subsequent to May 15, 2006 and is currently winding down its operations and settling its outstanding claims. Bison will continue to pay additional premiums to sEnergy as it settles its outstanding claims during its wind-down. Duke Energy does not expect the termination of Bison’s membership in OIL or the continued wind-down of sEnergy will have a material impact on its consolidated results of operations, cash flows, or financial position in 2007.

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

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

Nuclear Insurance

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

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

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

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

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

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

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

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

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

Environmental

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

Remediation activities. Like others in the energy industry, Duke Energy and its affiliates are responsible for environmental remediation at various contaminated sites. These include some properties that are part of ongoing Duke Energy operations, sites formerly owned or used by Duke Energy entities, and sites owned by third parties. Remediation typically involves management of contaminated soils and may involve groundwater remediation. Managed in conjunction with relevant federal, state and local agencies, activities vary with site conditions and locations, remedial requirements, complexity and sharing of responsibility. If remediation activities involve statutory joint and several liability provisions, strict liability, or cost recovery or contribution actions, Duke Energy or its affiliates could potentially be held responsible for contamination caused by other parties. In some instances, Duke Energy may share liability associated with contamination with other potentially responsible parties, and may also benefit from insurance policies or contractual indemnities that cover some or all cleanup costs. All of these sites generally are managed in the normal course of business or affiliate operations. Management believes that completion or resolution of these matters will have no material adverse effect on Duke Energy’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 established aquatic protection requirements for existing facilities that withdraw 50 million gallons or more of water per day from rivers, streams, lakes, reservoirs, estuaries, oceans, or other U.S. waters for cooling purposes. Fourteen of the 23 coal and nuclear-fueled generating facilities in which Duke Energy is either a whole or partial owner are affected sources under that rule.

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On January 25, 2007, the U.S. Court of Appeals for the Second Circuit issued its opinion inRiverkeeper, Inc. v. EPA, Nos. 04-6692-ag(L) et. al. (2d Cir. 2007) remanding most aspects of EPA’s rule back to the agency. The court effectively disallowed those portions of the rule most favorable to industry, and the decision creates a great deal of uncertainty regarding future requirements and their timing. While Duke Energy is still unable to estimate costs to comply with the EPA’s rule, it is expected that costs will increase as a result of the court’s decision. The magnitude of any such increase cannot be estimated at this time.

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

The emission controls Duke Energy is installing to comply with North Carolina clean air legislation will contribute significantly to achieving compliance with CAMR and CAIR requirements (see Note 4). In addition, Duke Energy currently estimates that it will spend approximately $710 million between 2007 and 2011 to comply with Phase 1 of CAMR and CAIR at its Midwest electric operations. Duke Energy currently estimates that any additional costs it might incur to comply with Phase 1 of CAMR or CAIR will have no material adverse effect on its consolidated results of operations, cash flows or financial position. Duke Energy currently estimates its CAIR Phase 2 compliance costs at approximately $150 million for Duke Energy Carolinas’ electric operations over the period 2010-2016. Duke Energy estimates its CAIR/CAMR Phase 2 compliance costs at approximately $450 million for its Midwest electric operations over the period 2007-2016. Duke Energy is currently unable to estimate the cost of complying with Phase 2 of CAMR beyond 2016. The IURC issued an order in 2006 granting Duke Energy Indiana approximately $1.08 billion in rate recovery to cover its estimated Phase 1 of CAIR/CAMR compliance costs in Indiana (see Note 4). Duke Energy Ohio receives partial recovery of depreciation and financing costs related to environmental compliance projects for 2005-2008 through its rate stabilization plan (see Note 4).

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 $73 million and $55 million as of December 31, 2006 and 2005, respectively. These accruals represent Duke Energy’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 Energy’s consolidated results of operations, cash flows or financial position.

Litigation

New Source Review (NSR). In 1999-2000, the U.S. Justice Department, acting on behalf of the EPA, filed a number of complaints and notices of violation against multiple utilities across the country for alleged violations of the NSR provisions of the Clean Air Act (CAA). Generally, the government alleged that projects performed at various coal-fired units were major modifications, as defined in the CAA, and that the utilities violated the CAA when they undertook those projects without obtaining permits and installing emission controls for SO₂, NOx and particulate matter. The complaints seek (1) injunctive relief to require installation of pollution control technology on various allegedly violating generating units, and (2) unspecified civil penalties in amounts of up to $27,500 per day for each violation. A number of Duke Energy’s owned and operated plants have been subject to these allegations and lawsuits. Duke Energy asserts that there were no CAA violations because the applicable regulations do not require permitting in cases where the projects undertaken are “routine” or otherwise do not result in a net increase in emissions.

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

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In November 1999, the United States brought a lawsuit in the United States Federal District Court for the Southern District of Indiana against Cinergy, Duke Energy Ohio, and Duke Energy Indiana alleging various violations of the CAA for various projects at six of Duke Energy owned and co-owned generating stations in the Midwest. Additionally, the suit claims that Duke Energy violated an Administrative Consent Order entered into in 1998 between the EPA and Cinergy relating to alleged violations of Ohio’s State Implementation Plan (SIP) provisions governing particulate matter at Unit 1 at Duke Energy Ohio’s W.C. Beckjord Station. In addition, three northeast states and two environmental groups have intervened in the case. In August 2005, the district court issued a ruling regarding the emissions test that it will apply to Cinergy, Duke Energy Ohio, and Duke Energy Indiana at the trial of the case. Contrary to Cinergy’s, Duke Energy Ohio’s, and Duke Energy Indiana’s argument (and the decision of the district court in the Duke Carolinas NSR case described above), the district court ruled that in determining whether a project was projected to increase annual emissions, it would not hold hours of operation constant. However, the district court subsequently certified the matter for interlocutory appeal to the Seventh Circuit Court of Appeals. In August 2006, the Seventh Circuit upheld the district court’s opinion. Cinergy has petitioned the U.S. Supreme Court for a writ of certiorari, which is pending. This issue is before the U.S. Supreme Court in the Duke Energy Carolinas NSR case, and we do not expect further dispositive legal proceedings in this case until after the Supreme Court ruling.

In March 2000, the United States also filed in the United States District Court for the Southern District of Ohio an amended complaint in a separate lawsuit alleging violations of the CAA regarding various generating stations, including a generating station operated by Columbus Southern Power Company (CSP) and jointly-owned by CSP, The Dayton Power and Light Company (DP&L), and Duke Energy Ohio. This suit is being defended by CSP (the CSP case). In April 2001, the United States District Court for the Southern District of Ohio in that case ruled that the Government and the intervening plaintiff environmental groups cannot seek monetary damages for alleged violations that occurred prior to November 3, 1994; however, they are entitled to seek injunctive relief for such alleged violations. Neither party appealed that decision. This matter was heard in trial in July 2005. A decision is pending, but any finding of liability will also be dependent upon the Supreme Court’s decision in the Duke Energy Carolinas case.

In addition, Cinergy and Duke Energy Ohio have been informed by DP&L that in June 2000, the EPA issued a Notice of Violation (NOV) to DP&L for alleged violations of CAA requirements at a station operated by DP&L and jointly-owned by DP&L, CSP, and Duke Energy Ohio. The NOV indicated the EPA may (1) issue an order requiring compliance with the requirements of the Ohio SIP, or (2) bring a civil action seeking injunctive relief and civil penalties of up to $27,500 per day for each violation. In September 2004, Marilyn Wall and the Sierra Club brought a lawsuit against Duke Energy Ohio, DP&L and CSP for alleged violations of the CAA at this same generating station. This case is currently in discovery in front of the same judge who has the CSP case.

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

Carbon Dioxide Litigation.In July 2004, the states of Connecticut, New York, California, Iowa, New Jersey, Rhode Island, Vermont, Wisconsin, and the City of New York brought a lawsuit in the United States District Court for the Southern District of New York against Cinergy, American Electric Power Company, Inc., American Electric Power Service Corporation, The Southern Company, Tennessee Valley Authority, and Xcel Energy Inc. A similar lawsuit was filed in the United States District Court for the Southern District of New York against the same companies by Open Space Institute, Inc., Open Space Conservancy, Inc., and The Audubon Society of New Hampshire. These lawsuits allege that the defendants’ emissions of carbon dioxide (CO₂) from the combustion of fossil fuels at electric generating facilities contribute to global warming and amount to a public nuisance. The complaints also allege that the defendants could generate the same amount of electricity while emitting significantly less CO₂. The plaintiffs are seeking an injunction requiring each defendant to cap its CO₂emissions and then reduce them by a specified percentage each year for at least a decade. In September 2005, the district court granted the defendants’ motion to dismiss the lawsuit. The plaintiffs have appealed this ruling to the Second Circuit Court of Appeals. Oral argument was held before the Second Circuit Court of Appeals on June 7, 2006.

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

Hurricane Katrina Lawsuit.In April 2006, Duke Energy and Cinergy were named in the third amended complaint of a purported class action lawsuit filed in the United States District Court for the Southern District of Mississippi. Plaintiffs claim that Duke Energy and Cinergy, along with numerous other utilities, oil companies, coal companies and chemical companies, are liable for damages relating to losses suffered by victims of Hurricane Katrina. Plaintiffs claim that defendants’ greenhouse gas emissions contributed to the frequency and intensity of storms such as Hurricane Katrina. In October 2006, Duke Energy and Cinergy were served with this lawsuit. It is not

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possible to predict with certainty whether Duke Energy or Cinergy will incur any liability or to estimate the damages, if any, that Duke Energy or Cinergy might incur in connection with this matter.

San Diego Price Indexing Cases. Duke Energy and several of its affiliates, as well as other energy companies, are parties to 25 lawsuits which have been coordinated as the “Price Indexing Cases” in San Diego, California. Twelve of the lawsuits seek class-action certification. The plaintiffs allege that the defendants conspired to manipulate price of natural gas in violation of state and/or federal antitrust laws, 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. In December 2006, Duke Energy executed an agreement to settle the 12 class action cases. Such agreement is subject to execution of mutually acceptable agreements and approval by the class members and the court. Duke Energy does not expect that the proposed settlement will have a material adverse effect on its consolidated results of operations, cash flows or financial position.

Other Price Reporting Cases. A total of 11 lawsuits have been filed against Duke Energy affiliates and other energy companies, including a lawsuit filed in December 2006 in Wisconsin state court. In February 2007, Duke Energy was served in the Wisconsin case. 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. Oral argument on these appeals was heard February 13, 2007. Each of these 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 Energy is unable to express an opinion regarding the probable outcome or estimate damages, if any, related to these matters at this time.

Western Electricity Litigation. Plaintiffs, on behalf of themselves and others, in three lawsuits allege that Duke Energy Affiliates, among other energy companies, artificially inflated the price of electricity in certain western states. Two of the cases were dismissed and plaintiffs have appealed to the U.S. Court of Appeal for the Ninth Circuit. In December 2006, a fourth case, the single remaining electricity case pending in California state court was dismissed. Plaintiffs in these cases seek damages in unspecified amounts, but which could total billions of dollars. It is not possible to predict with certainty whether Duke Energy will incur any liability or to estimate the damages, if any, that Duke Energy might incur in connection with these lawsuits, but Duke Energy does not presently believe the outcome of these matters will have a material adverse effect on its results of operations, cash flows or financial position.

Trading Related Investigations.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 is unable to express an opinion regarding the probable outcome or estimate damages, if any, related to this matter at this time.

Southern California Edison. 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 Energy’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 and CMT, 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 Energy 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 Energy’s consolidated results of operations, cash flows or financial position.

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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 tribunal issued its award on damages on November 30, 2006. Duke LNG was awarded approximately $20 million, plus interest, for Sonatrach’s breach of its shipping obligations. Sonatrach and Sonatrading were awarded an unspecified amount that management believes will, when calculated, be substantially less than the amount awarded to Duke LNG, and result ultimately in a net positive, but immaterial, award to Duke LNG. This matter was assigned to Spectra Energy in connection with the spin-off in January 2007.

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). This matter and the financial obligation of any settlement or judgment were assigned to Spectra Energy in connection with the spin-off in January 2007. In January 2007 Spectra Energy and Citrus settled this litigation for a payment by Spectra Energy to Citrus of $100 million. As a result, in 2006, Duke Energy recognized a reserve of $100 million related to the settlement offer.

ExxonMobil Disputes. In April 2004, Mobil Natural Gas, Inc. (MNGI) and 3946231 Canada, Inc. (3946231, and collectively with MNGI, ExxonMobil) filed a Demand for Arbitration against Duke Energy, DETMI Management Inc. (DETMI), DTMSI Management Ltd. (DTMSI) and other affiliates of Duke Energy. 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, ExxonMobil 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. ExxonMobil 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 Energy denies these allegations, and has filed counterclaims asserting that ExxonMobil breached its Venture 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 ExxonMobil’s claims. ExxonMobil filed a motion for reconsideration of the ruling as well as for an extension of the date for the arbitration hearing. ExxonMobil 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. The parties agreed that the damages due to Duke Energy 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, with a subsequent hearing in January 2007. In August 2004, DEMLP initiated arbitration proceedings in Canada against certain ExxonMobil 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. Hearings to determine the damages to be paid as the result of the first ruling, as well as the damages to be paid to Duke Energy as the result of the termination of the U.S. gas supply agreement were held on

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November 9 and 10, 2006, and January 22, 2007, before the same panel of arbitrators. In February 2007, Duke Energy and ExxonMobil reached agreement in principle on a global settlement of both arbitrations. Such agreement is subject to execution of final settlement documents. Duke Energy does not expect that the proposed settlement will have a material effect on its consolidated results of operations, cash flows or financial position. The gas supply agreements with other parties, under which DEMLP continues to remain obligated, are currently estimated to result in losses of between $50 million and $100 million through 2011. As Duke Energy has an ownership interest of approximately 60% in DEMLP, only 60% of any losses would impact pretax earnings for Duke Energy. However, these losses are subject to change in the future in the event of changes in market conditions and underlying assumptions.

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, alleging violations of Employee Retirement Income Security Act (ERISA) and the Age Discrimination in Employment Act. These allegations arise out of the conversion of the Duke Energy Company Employees’ Retirement Plan into the Duke Energy Retirement Cash Balance Plan. The case also raises some Plan administration issues, alleging errors in the application of Plan provisions (e.g., the calculation of interest rate credits in 1997 and 1998 and the calculation of lump-sum distributions). 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. The plaintiffs also seek to divide the putative class into sub-classes based on age. Six causes of action are alleged, ranging from age discrimination, to various alleged ERISA violations, to allegations of breach of fiduciary duty. The plaintiffs seek a broad array of remedies, including a retroactive reformation of the Duke Energy Retirement Cash Balance Plan and a recalculation of participants’/ beneficiaries’ benefits under the revised and reformed plan. 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. A portion of this liability was assigned to Spectra Energy in connection with the spin-off in January 2007. The matter is currently in discovery with a tentative trial date of March 2008. It is not possible to predict with certainty whether Duke Energy will incur any liability or to estimate the damages, if any, that Duke Energy might incur in connection with this matter.

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

Duke Energy Indiana and Duke Energy Ohio have been named as defendants or co-defendants in lawsuits related to asbestos at their electric generating stations. Currently, there are approximately 130 pending lawsuits (the majority of which are Duke Energy Indiana cases). In these lawsuits, plaintiffs claim to have been exposed to asbestos-containing products in the course of their work as outside contractors. The plaintiffs further claim that as the property owner of the generating stations, Duke Energy Indiana and Duke Energy Ohio should be held liable for their injuries and illnesses based on an alleged duty to warn and protect them from any asbestos exposure. The impact on Duke Energy’s financial position, cash flows, or results of operations of these cases to date has not been material.

Of these lawsuits, one case filed against Duke Energy Indiana has been tried to verdict. The jury returned a verdict against Duke Energy Indiana on a negligence claim and a verdict for Duke Energy Indiana on punitive damages. Duke Energy Indiana appealed this decision up to the Indiana Supreme Court. In October 2005, the Indiana Supreme Court upheld the jury’s verdict. Duke Energy Indiana paid the judgment of approximately $630,000 in the fourth quarter of 2005. In addition, Duke Energy Indiana has settled over 150 other claims for amounts, which neither individually nor in the aggregate, are material to Duke Energy Indiana’s financial position or results of operations. Based on estimates under varying assumptions, concerning uncertainties, such as, among others: (i) the number of con-

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tractors potentially exposed to asbestos during construction or maintenance of Duke Energy Indiana generating plants; (ii) the possible incidence of various illnesses among exposed workers, and (iii) the potential settlement costs without federal or other legislation that addresses asbestos tort actions, Duke Energy estimates that the range of reasonably possible exposure in existing and future suits over the next 50 years could range from an immaterial amount to approximately $60 million, exclusive of costs to defend these cases. This estimated range of exposure may change as additional settlements occur and claims are made in Indiana and more case law is established.

Duke Energy Ohio has been named in fewer than 10 cases and as a result has virtually no settlement history for asbestos cases. Thus, Duke Energy is not able to reasonably estimate the range of potential loss from current or future lawsuits. However, potential judgments or settlements of existing or future claims could be material to Duke Energy.

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

Duke Energy has exposure to certain legal matters that are described herein. As of December 31, 2006, Duke Energy has recorded reserves of approximately $1.3 billion for these proceedings and exposures. Duke Energy has insurance coverage for certain of these losses incurred. As of December 31, 2006, Duke Energy has recognized approximately $1.0 billion of probable insurance recoveries related to these losses. These reserves represent management’s best estimate of probable loss as defined by SFAS No. 5, “Accounting for Contingencies.”

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

Other Commitments and Contingencies

Commercial Power produces synthetic fuel from facilities that qualify for tax credits (through 2007) in accordance with Section 29/45K of the Internal Revenue Code if certain requirements are satisfied. These credits reduce Duke Energy’s income tax liability and therefore Duke Energy’s effective tax rate. Commercial Power’s sale of synthetic fuel has generated $339 million in tax credits through December 31, 2005. During the first quarter of 2006, an agreement was in place with the plant operator which would indemnify Duke Energy in the event that tax credits are insufficient to support operating expenses. This agreement did not continue for the remainder of 2006. After reducing for the possibility of phase-outs in 2006, the amount of additional credits generated through December 31, 2006 was approximately $20 million. Duke Energy’s net investment in the plants at December 31, 2006 was approximately $20 million.

Section 29/45K provides for a phase-out of the credit if the average price of crude oil during a calendar year exceeds a specified threshold. The phase-out is based on a prescribed calculation and definition of crude oil prices. If Commercial Power were to operate its synthetic fuel facilities based on December 31, 2006 prices throughout the entire forthcoming year, yet crude oil prices were to rise such that the tax credit is completely phased-out, net income in 2007 would be negatively impacted. Duke Energy is unlikely to experience a material loss because the exposure to synthetic fuel tax credit phase-out is monitored and Duke Energy may choose to reduce or cease synthetic fuel production depending on the expectation of any potential tax credit phase-out. Duke Energy may also reduce its exposure to crude prices through the execution of derivative transactions. The objective of these activities is to reduce potential losses incurred if the reference price in a year exceeds a level triggering a phase-out of synthetic fuel tax credits.

In August 2006, Duke Energy successfully completed the sale of one of its synthetic fuel facilities resulting in an immaterial gain. This sale was driven by Internal Revenue Service (IRS) requirements that stipulate that in order to qualify for tax credits in accordance with Section 29/45K, the sales of the synthetic fuel must be made to an unrelated third party.

The IRS has completed the audit of Cinergy for the 2002, 2003, and 2004 tax years including the synthetic fuel facility owned during that period. That facility represents $219 million of tax credits generated during that audit period. The IRS has not proposed any adjustment that would disallow the credits claimed during that period. Subsequent periods are still subject to audit. Duke Energy believes that it operates in conformity with all the necessary requirements to be allowed such credits under Section 29/45K.

Duke Energy is party to an agreement with a third party service provider related to future purchases to be made through late 2007. The agreement contains certain damage payment provisions if the purchases are not made by the specified date. The maximum pretax

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exposure under the agreement is currently estimated at approximately $100 million. In the fourth quarter of 2006, Duke Energy initiated early settlement discussions regarding this agreement and recorded a reserve of approximately $65 million during December of 2006 based upon probable penalty payments to be incurred. Future adjustments to this reserve could be material depending on the level of actual purchase commitments.

In October 2006, Duke Energy began an internal investigation into improper data reporting to the U.S. Environmental Protection Agency (USEPA) regarding air emissions under the NOx Budget Program at Duke Energy’s DEGS of Narrows, L.L.C. power plant facility in Narrows, Virginia. The investigation has revealed evidence of falsification of data by an employee relating to the quality assurance testing of its continuous emissions monitoring system (CEMS) to monitor heat input and NOx emissions. In December 2006, Duke Energy voluntarily disclosed the potential violations to the USEPA and Virginia Department of Environmental Quality (VDEQ), and in January 2007, Duke Energy made a full written disclosure of the investigation’s findings to the USEPA and the VDEQ. Duke Energy has taken appropriate disciplinary action, including termination, with respect to the employees involved with the false reporting. It is not possible to predict with certainty whether Duke Energy will incur any liability or to estimate the damages, if any, that Duke Energy might incur in connection with this matter.

Other. As part of its normal business, Duke Energy 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. These arrangements are largely entered into by Duke Energy and Spectra Energy Capital. 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 Energy or Spectra Energy 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 18.)

In addition, Duke Energy 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 18 for discussion of Calpine guarantee obligation).

Operating and Capital Lease Commitments

Duke Energy leases assets in several areas of its operations. Consolidated rental expense for operating leases included in income from continuing operations was $110 million in 2006, $66 million in 2005 and $60 million in 2004, which is included in Operation, Maintenance and Other on the Consolidated Statements of Operations. Consolidated rental expense for operating leases included in Income From Discontinued Operations, net of tax, was $36 million in 2006, $53 million in 2005 and $64 million in 2004. 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, 2006:

	Operating Leases		Capital Leases
	(in millions)
2007	$	116	$	11
2008		108		15
2009		94		16
2010		84		11
2011		59		9
Thereafter		257		32
Total future minimum lease payments	$	718	$	94

18. Guarantees and Indemnifications

Duke Energy 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 guaran-

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tees, surety bonds and indemnifications. Duke Energy 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.

In contemplation of the spin-off of the natural gas businesses on January 2, 2007 (see Note 1), certain guarantees that were previously issued by Spectra Energy Capital were transferred to Duke Energy prior to the consummation of the spin-off. Under FIN 45, guarantees that are modified after issuance are required to be remeasured at fair value at the date of modification. Accordingly, as a result of these modifications, Duke Energy recorded immaterial liability amounts in 2006 associated with these guarantees. Additionally, at December 31, 2006, Duke Energy has certain guarantees of wholly-owned subsidiaries that became guarantees of third party performance upon the spin-off of the natural gas businesses in January 2007. Duke Energy has received back-to-back indemnification from Spectra Energy Capital indemnifying Duke Energy for any amounts paid related to these guarantees.

Guarantees that were issued by or assigned to Duke Energy, Cinergy or International Energy on or prior to December 31, 2006 remained with Duke Energy subsequent to the spin-off. Guarantees issued by Spectra Energy Capital or Natural Gas Transmission on or prior to December 31, 2006 remained with Spectra Energy Capital subsequent to the spin-off, except for certain guarantees discussed below that are in the process of being assigned to Duke Energy. During this assignment period, Duke Energy has indemnified Spectra Energy Capital against any losses incurred under these guarantee obligations.

Duke Energy 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 Energy could have been required to make under these performance guarantees as of December 31, 2006 was approximately $27 million. Approximately $4 million of the performance guarantees expire in 2009, with the remaining performance guarantees having no contractual expiration.

Additionally, Duke Energy 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 Energy 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 Energy has received back-to-back indemnification from the buyer of DE&S indemnifying Duke Energy for any amounts paid by Spectra Energy Capital related to the DE&S guarantees. Duke Energy also received indemnification from the buyer of DukeSolutions for the first $2.5 million paid by Duke Energy related to the DukeSolutions guarantees. Further, Duke Energy 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 Energy has recourse to subcontractors involved in providing services to a customer. These guarantees have various terms ranging from 2007 to 2019, with others having no specific term. The maximum potential amount of future payments under these guarantees as of December 31, 2006 was approximately $81 million.

Cinergy has issued performance guarantees to customers and other third parties that guarantee the payment and performance of certain non-wholly-owned consolidated entities. Additionally, Cinergy has issued guarantees of debt of certain non-consolidated entities and less than wholly owned consolidated entities. The maximum potential amount of future payments Cinergy could have been required to make under these performance guarantees as of December 31, 2006 was approximately $171 million. Approximately $92 million of the performance guarantees expire between 2008 and 2017, with the remaining performance guarantees having no contractual expiration.

Spectra Energy 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 Spectra Energy Capital could have been required to make under these performance guarantees as of December 31, 2006 was approximately $615 million, of which approximately $220 million is in the process of being assigned to Duke Energy, as discussed above. Of this amount, approximately $25 million relates to guarantees of the payment and performance of less than wholly owned consolidated entities. Approximately $40 million of the performance guarantees expire between 2007 and 2009, with the remaining performance guarantees expiring after 2009 or having no contractual expiration.

Additionally, Spectra Energy 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. Substantially all of these guarantees have no contractual expiration and no stated maximum amount of future payments that Spectra Energy 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

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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, 2006 was approximately $15 million. Of those guarantees, approximately $10 million expire in 2007, with the remainder having no contractual expiration.

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 December 31, 2006, Natural Gas Transmission was the guarantor of approximately $17 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 2007 and 2008.

Duke Energy 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 Energy 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 Energy could have been required to make under these letters of credit as of December 31, 2006 was approximately $55 million. Substantially all of these letters of credit were issued on behalf of less than wholly owned consolidated entities and expire in 2007.

In connection with Duke Energy’s sale of the Murray merchant generation facility to KGen, in August 2004, Duke Energy 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 2007, is related to the obligation of a KGen subsidiary under a seven-year power sales agreement, commencing in May 2005. Duke Energy 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 Energy 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 Energy for any payments Duke Energy makes with respect to the $120 million letter of credit. In February 2007, this guarantee was cancelled and Duke Energy has no future obligations associated with this matter.

Spectra Energy 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, 2006, Spectra Energy Capital had guaranteed approximately $210 million of outstanding surety bonds related to obligations of non-wholly owned entities. The majority of these bonds expire in various amounts in 2007 and 2008. Approximately $206 million of surety bonds were transferred to Duke Energy upon the consummation of the spin-off in January 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 Energy. Spectra Energy Capital unconditionally and irrevocably guaranteed the lease payments of Hidalgo to IDC through 2028. In 2000, Hidalgo was sold to Calpine Corporation and Spectra Energy 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 December 31, 2006 is approximately $200 million, including principal and interest payments. Duke Energy does not believe a loss under the guarantee obligation is probable as of December 31, 2006, but continues to evaluate the situation. Therefore, no reserves have been recorded for any contingent loss as of December 31, 2006. No demands for payment have been made under the guarantee. If losses are incurred under the guarantee, Spectra Energy Capital has certain rights which should allow it to mitigate such loss. Subsequent to the spin-off of the natural gas businesses, this guarantee remained with Spectra Energy Capital. However, Duke Energy indemnified Spectra Energy Capital against any future losses that could arise from payments required under this guarantee.

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Duke Energy has entered into various indemnification agreements related to purchase and sale agreements and other types of contractual agreements with vendors and other third parties. These agreements typically cover environmental, tax, litigation and other matters, as well as breaches of representations, warranties and covenants. Typically, claims may be made by third parties for various periods of time, depending on the nature of the claim. Duke Energy’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 Energy 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.

At December 31, 2006, the amounts recorded for the guarantees and indemnifications mentioned above are immaterial, both individually and in the aggregate.

19. Earnings Per Share (EPS)

Basic EPS is computed by dividing earnings available for common stockholders by the weighted-average number of common shares outstanding during the period. Diluted EPS is computed by dividing earnings available for common stockholders, as adjusted, by the diluted weighted-average number of common shares outstanding during the period. Diluted EPS reflects the potential dilution that could occur if securities or other agreements to issue common stock, such as stock options, stock-based performance unit awards, contingently convertible debt and phantom stock awards, were exercised, settled or converted into common stock.

The following tables illustrate Duke Energy’s basic and diluted EPS calculations and reconcile the weighted-average number of common shares outstanding to the diluted weighted-average number of common shares outstanding for 2006, 2005, and 2004.

(in millions, except per share data)	Income			Average Shares	EPS
2006
Income from continuing operations	$	1,083
Less: Dividends and premiums on redemption of preferred and preference stock		—
Income from continuing operations—basic		1,083		1,170	$	0.93
Effect of dilutive securities:
Stock options, phantom, performance and restricted stock				4
Contingently convertible bond		4		14
Income from continuing operations—diluted	$	1,087		1,188	$	0.91
2005
Income from continuing operations	$	893
Less: Dividends and premiums on redemption of preferred and preference stock		(12	)
Income from continuing operations—basic		881		934	$	0.94
Effect of dilutive securities:
Stock options, phantom, performance and restricted stock				4
Contingently convertible bond		8		32
Income from continuing operations—diluted	$	889		970	$	0.92
2004
Income from continuing operations	$	618
Less: Dividends and premiums on redemption of preferred and preference stock		(9	)
Income from continuing operations—basic		609		931	$	0.65
Effect of dilutive securities:
Stock options, phantom, performance and restricted stock				2
Contingently convertible bond		8		33
Income from continuing operations—diluted	$	617		966	$	0.64

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The increase in weighted-average shares outstanding for the year ended December 31, 2006 compared to the same period in 2005 was due primarily to the April 2006 issuance of approximately 313 million shares in conjunction with the merger with Cinergy (see Note 2), the conversion of debt into approximately 27 million shares of Duke Energy common stock during the year ended December 31, 2006 (see Note 21), and the repurchase and retirement of approximately 17.5 million shares of Duke Energy common stock during the year ended December 31, 2006 (see Note 21).

As of December 31, 2006, 2005 and 2004, approximately 14 million, 19 million and 23 million, respectively, of options, unvested stock, performance and phantom stock awards were not included in the “effect of dilutive securities” in the above table because either the option exercise prices were greater than the average market price of the common shares during those periods, or performance measures related to the awards had not yet been met.

20. Stock-Based Compensation

Effective January 1, 2006, Duke Energy adopted the provisions of SFAS No. 123(R). SFAS No. 123(R) establishes accounting for stock-based awards exchanged for employee and certain nonemployee services. Accordingly, for employee awards, equity classified stock-based compensation cost is measured at the grant date, based on the fair value of the award, and is recognized as expense over the requisite service period. 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. Since the exercise price for all options granted under those plans was equal to the market value of the underlying common stock on the grant date, no compensation cost was recognized in the accompanying Consolidated Statements of Operations.

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

Duke Energy recorded pre-tax stock-based compensation expense included in Income From Continuing Operations for the years ended December 31, 2006, 2005 and 2004 as follows, the components of which are further described below:

	For the Years Ended December 31,
	2006		2005		2004
	(in millions)
Stock Options	$	7	$	—	$	—
Stock Appreciation Rights		1		—		—
Phantom Stock		30		17		9
Performance Awards		24		19		10
Other Stock Awards		2		1		—
Total	$	64	$	37	$	19

The tax benefit associated with the recorded expense in Income From Continuing Operations for the year ended December 31, 2006, 2005 and 2004 was approximately $24 million, $14 million and $7 million, respectively. There were no material differences in income from continuing operations, income tax expense, net income, cash flows, or basic and diluted earnings per share from the adoption of SFAS No. 123(R). As discussed in Note 1, on January 2, 2007, Duke Energy completed the spin-off of its natural gas businesses to its shareholders, and the results of these businesses are presented as discontinued operations. Accordingly, pre-tax stock-based compensation expense of approximately $18 million, $10 million and $7 million for the years ended December 31, 2006, 2005 and 2004, respectively, are included in Income From Discontinued Operations, net of tax, on the Consolidated Statements of Operations. A corresponding tax benefit of approximately $7 million, $3 million and $3 million for the years ended December 31, 2006, 2005 and 2004, respectively, are included in Income From Discontinued Operations, net of tax, on the Consolidated Statements of Operations.

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

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Pro Forma Stock-Based Compensation

	Year ended December 31, 2005			Year ended December 31, 2004
	(in millions, except per share amounts)
Earnings available for common stockholders, as reported	$	1,812		$	1,481
Add: stock-based compensation expense included in reported earnings available to common stockholders, net of related tax effects		30			16
Deduct: total stock-based compensation expense determined under fair value-based method for all awards, net of related tax effects		(32	)		(27	)
Pro forma earnings available for common stockholders, net of related tax effects	$	1,810		$	1,470
Earnings per share:
Basic—as reported	$	1.94		$	1.59
Basic—pro forma	$	1.94		$	1.58
Diluted—as reported	$	1.88		$	1.54
Diluted—pro forma	$	1.87		$	1.53

Duke Energy’s 2006 Long-term Incentive Plan (the 2006 Plan), approved by shareholders in October 2006, reserved 60 million shares of common stock for awards to employees and outside directors. Duke Energy’s 1998 Long-term Incentive Plan, as amended (the 1998 Plan), reserved 60 million shares of common stock for awards to employees and outside directors. The 2006 Plan supersedes the 1998 Plan and no additional grants will be made from the 1998 Plan. Under the 2006 Plan and the 1998 Plan, the exercise price of each option granted cannot be less than the market price of Duke Energy’s common stock on the date of grant and the maximum option term is 10 years. The vesting periods range from immediate to five years. Duke Energy has historically issued new shares upon exercising or vesting of share-based awards. In 2007, Duke Energy may use a combination of new share issuances and open market repurchases for share-based awards which are exercised or vested. Duke Energy has not determined with certainty the amount of such new share issuances or open market repurchases.

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.

Upon the acquisition of Cinergy, Duke Energy converted all stock options outstanding under the Cinergy 1996 Long-Term Incentive Compensation Plan and Cinergy Corp. Stock Option Plan to Duke Energy stock options. The exercise price of these options equaled the market price on the date of grant and the maximum option term is 10 years. The vesting periods are generally three years. The 2006 Plan supersedes both Cinergy Plans and no additional grants will be made from these plans.

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	25,506		$	29
Granted(a)	9,173			24
Exercised	(6,369	)		23
Forfeited or expired	(1,595	)		34
Outstanding at December 31, 2006	26,715			29	4.9	$	173
Exercisable at December 31, 2006	21,923		$	30	4.3	$	122
Options Expected to Vest	4,744		$	22	7.92	$	51

(a) Includes 7,294,994 converted Cinergy stock options.

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On December 31, 2005 and 2004, Duke Energy had approximately 22 million exercisable options with a $32 weighted-average exercise price. The total intrinsic value of options exercised during the years ended December 31, 2006, 2005 and 2004 was approximately $46 million, $17 million and $7 million, respectively. Cash received from options exercised during the year ended December 31, 2006 was approximately $127 million, with a related tax benefit of approximately $17 million. At December 31, 2006, Duke Energy had approximately $7 million of future compensation cost which is expected to be recognized over a weighted-average period of 1.5 years.

In addition to the conversion of the Cinergy stock options noted above, Duke Energy granted 1,877,646 options (fair value of approximately $10 million based on a Black-Scholes model valuation) during the year ended December 31, 2006. There were no options granted during the years ended December 31, 2005 and 2004. Remaining compensation expense to be recognized for unvested converted Cinergy options was determined using a Black-Scholes model.

Weighted-Average Assumptions for Option Pricing

	2006
Risk-free interest rate(1)	4.78	%
Expected dividend yield(2)	4.40	%
Expected life(3)	6.29 yrs.
Expected volatility(4)	24	%

(1) The risk free rate is based upon the U.S. Treasury Constant Maturity rates as of the grant date.

(2) The expected dividend yield is based upon annualized dividends and the 1-year average closing stock price.

(3) The expected term of options is derived from historical data.

(4) Volatility is based upon 50% historical and 50% implied volatility. Historic volatility is based on the weighted average between Duke and Cinergy historical volatility over the expected life using daily stock prices. Implied volatility is the average for all option contracts with a term greater than six months using the strike price closest to the stock price on the valuation date.

The 2006 Plan allows for a maximum of 15 million shares of common stock to be issued under various stock-based awards other than options and stock appreciation rights. The 1998 Plan allows for a maximum of 12 million shares of common stock to be issued under various stock-based awards. Payments for cash settled awards during the period were immaterial.

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 to a pre-defined peer group (relative TSR). These awards are valued using a path-dependent model that incorporates expected relative TSR into the fair value determination of Duke Energy’s performance-based share awards with the adoption of SFAS No. 123(R). The model uses three year historical volatilities and correlations for all companies in the pre-defined peer group, including Duke Energy, to simulate Duke Energy’s relative TSR as of the end of the performance period. For each simulation, Duke Energy’s relative TSR associated with the simulated stock price at the end of the performance period plus expected dividends within the period results in a value per share for the award portfolio. The average of these simulations is the expected portfolio value per share. Actual life to date results of Duke Energy’s relative TSR for each grant is incorporated within the model. Other awards not containing market conditions are measured at grant date price. Duke Energy awarded 1,610,350 shares (fair value of approximately $32 million) in the year ended December 31, 2006, 1,275,020 shares (fair value of approximately $34 million, based on the market price of Duke Energy’s common stock at the grant date) in the year ended December 31, 2005, and 1,584,840 shares (fair value of approximately $34 million, based on the market price of Duke Energy’s common stock at the grant date) in the year ended December 31, 2004.

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

	Shares		Weighted Average Grant Date Fair Value
Number of Stock-based Performance Awards:
Outstanding at December 31, 2005	2,940,768		$	25
Granted	1,610,350			20
Vested	(114,000	)		27
Forfeited	(310,838	)		26
Canceled	—			—
Outstanding at December 31, 2006	4,126,280		$	23
Stock-based Performance Awards Expected to Vest	3,955,865		$	23

The total fair value of the shares vested during the year ended December 31, 2006 and 2005 was approximately $3 million. As of December 31, 2006, Duke Energy had approximately $31 million of future compensation cost which is expected to be recognized over a weighted-average period of 1.0 years.

Phantom Stock Awards

Phantom stock awards outstanding under the 1998 Plan generally vest over periods from immediate to five years. Duke Energy awarded 1,181,370 shares (fair value of approximately $34 million) based on the market price of Duke Energy’s common stock at the grant dates in the year ended December 31, 2006, 1,139,880 shares (fair value of approximately $31 million) in the year ended December 31, 2005, and 1,283,220 shares (fair value of approximately $27 million) in the year ended December 31, 2004. Converted Cinergy phantom stock awards are paid in cash and are measured and recorded as liability awards.

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

	Shares		Weighted Average Grant Date Fair Value
Number of Phantom Stock Awards:
Outstanding at December 31, 2005	2,517,020		$	25
Granted(b)	1,213,532			29
Vested	(917,441	)		25
Forfeited	(200,791	)		26
Canceled	—			—
Outstanding at December 31, 2006	2,612,320		$	27
Phantom Stock Awards Expected to Vest	2,507,432		$	27

(b) Includes 32,162 converted Cinergy awards.

The total fair value of the shares vested during the years ended December 31, 2006, 2005 and 2004 was approximately $23 million, $10 million and $7 million, respectively. As of December 31, 2006, Duke Energy had approximately $24 million of future compensation cost which is expected to be recognized over a weighted-average period of 3.0 years.

Other Stock Awards

Other stock awards outstanding under the 1998 Plan generally vest over periods from three to five years. Duke Energy awarded 279,000 shares (fair value of approximately $8 million) based on the market price of Duke Energy’s common stock at the grant dates in the year ended December 31, 2006, 47,000 shares (fair value of approximately $1 million) in the year ended December 31, 2005, and 169,160 shares (fair value of approximately $4 million) in the year ended December 31, 2004.

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

	Shares		Weighted Average Grant Date Fair Value
Number of Other Stock Awards:
Outstanding at December 31, 2005	178,337		$	25
Granted(c)	329,980			28
Vested	(71,610	)		26
Forfeited	(10,200	)		33
Canceled	—			—
Outstanding at December 31, 2006	426,507		$	28
Other Stock Awards Expected to Vest	395,671		$	28

(c) Includes 50,980 converted Cinergy awards

The total fair value of the shares vested during the years ended December 31, 2006, 2005 and 2004 was approximately $2 million, $1 million and $1 million, respectively. As of December 31, 2006, Duke Energy had approximately $8 million of future compensation cost which is expected to be recognized over a weighted-average period of 2.9 years.

21. Common Stock

During 2006, Duke Energy’s $742 million of convertible debt became convertible into approximately 31.7 million shares of Duke Energy common stock due to the market price of Duke Energy common stock achieving a specified threshold for each pricing period prior to respective quarter. Holders of the convertible debt were able to exercise their right to convert on or prior to each quarter end. During 2006, approximately $632 million of debt was converted into approximately 26.7 million shares of Duke Energy common stock. At December 31, 2006, the balance of the convertible debt is approximately $110 million, which is convertible into approximately 4.7 million shares of common stock.

See Note 1 for discussion of 313 million shares of common stock issued in April 2006 as a result of the merger with Cinergy.

Effective in the third quarter 2006, the Board of Directors of Duke Energy approved a quarterly dividend increase of $0.01 per share, increasing the annual dividend to $1.28 per share.

In February 2005, Duke Energy announced plans to execute up to approximately $2.5 billion in common stock repurchases over a three year period. In May 2005, Duke Energy suspended additional repurchases, pending further assessment. At the time of suspension, Duke Energy had repurchased approximately $933 million of common stock. In the first quarter of 2006, as a result of the March 10, 2006 shareholder approval of the Cinergy merger, Duke Energy’s Board of Directors authorized the repurchase of up to an additional $1 billion of common stock under the previously announced share repurchase plan. In June 2006, Duke Energy suspended additional repurchases of Duke Energy common stock under the repurchase plan due to its plan to spin off the natural gas businesses (see Note 25). Prior to the June 2006 suspension, Duke Energy repurchased 17.5 million shares for total consideration of approximately $500 million during 2006. The repurchases and corresponding commissions and other fees were recorded in Common Stockholders’ Equity as a reduction in Common Stock and Additional Paid-in Capital. In October 2006, Duke Energy’s Board of Directors authorized the reactivation of the share repurchase plan for Duke Energy of up to $500 million of share repurchases after the spin-off of the natural gas businesses has been completed.

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

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

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

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

Duke Energy also sponsors an employee savings plan that covers substantially all U.S. employees. In April 2004, Duke Energy stopped issuing shares under the plan and the plan began making open market purchases with cash provided by Duke Energy. There were no issuances of common stock under the plan in either 2006 or 2005. Issuances of common stock under the plan were $51 million in 2004. Duke Energy also issues shares of its common stock to meet other employee benefit requirements. Issuances of common stock to meet other employee benefit requirements were approximately $146 million for 2006, $39 million for 2005 and approximately $12 million for 2004.

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

22. Employee Benefit Plans

Duke Energy U.S. Retirement Plans.Duke Energy and its subsidiaries (including legacy Cinergy businesses) maintain qualified, non-contributory defined benefit retirement plans. The plans cover most U.S. employees using a cash balance formula. Under a cash balance formula, a plan participant accumulates a retirement benefit consisting of pay credits that are based upon a percentage (which may vary with age and years of service) of current eligible earnings and current interest credits. Certain legacy Cinergy U.S. employees are covered under plans that use a final average earnings formula. Under a final average earnings formula, a plan participant accumulates a retirement benefit equal to a percentage of their highest 3-year average earnings, plus a percentage of the their highest 3-year average earnings in excess of covered compensation per year of participation (maximum of 35 years), plus a percentage of their highest 3-year average earnings times years of participation in excess of 35 years.

Duke Energy also maintains non-qualified, non-contributory defined benefit retirement plans which cover certain U.S. executives.

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 contributed approximately $124 million to the legacy Cinergy qualified pension plans in 2006. Duke Energy did not make any contributions to its defined benefit retirement plans in 2005. Duke Energy made voluntary contributions of $250 million in the fourth quarter of 2004.

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Actuarial gains and losses are amortized over the average remaining service period of the active employees. The average remaining service period of active employees covered by the qualified retirement plans is 11 years. The average remaining service period of active employees covered by the non-qualified retirement plans is 8 years. Duke Energy determines the market-related value of plan assets using a calculated value that recognizes changes in fair value of the plan assets in a particular year on a straight line basis over the next five years. Duke Energy uses a September 30 measurement date for its defined benefit retirement plans.

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

Westcoast’s policy is to fund the DB plans on an actuarial basis and in accordance with Canadian pension standards legislation, in order to accumulate assets sufficient to meet benefits to be paid. Contributions to the DC plans are determined in accordance with the terms of the plan. Duke Energy made contributions to the Westcoast DB plans of approximately $44 million in 2006, $42 million in 2005 and $26 million in 2004. Duke Energy also made contributions to the DC plans of $4 million in 2006, $3 million in 2005 and $3 million in 2004.

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 qualified DB retirement plans is 10 years. The average remaining service period of the active employees covered by the non-qualified DB retirement plan is 14 years. Westcoast uses a September 30 measurement date for its plans.

As discussed in Note 1, on January 2, 2007, Duke Energy completed the spin-off of its natural gas businesses to shareholders. The Westcoast Canadian DB plans and DC plans were transferred to Spectra Energy as part of the spin-off.

Duke Energy adopted the disclosure and recognition provisions of SFAS No. 158, effective December 31, 2006. The following table describes the total incremental effect of the adoption of SFAS No. 158 on individual line items in the December 31, 2006 Consolidated Balance Sheet, including Accumulated Other Comprehensive Income.

Incremental Effect of the Adoption of SFAS No. 158 on Individual Line Items in the Consolidated Balance Sheet As of December 31, 2006^(a)

	Duke Energy U.S.									Westcoast
	Before Application of SFAS No. 158			Adjustment			After Application of SFAS No. 158(b)			Before Application of SFAS No. 158			Adjustment			After Application of SFAS No. 158
	(in millions)
Accrued pension and other post-retirement liabilities(c)	$	(1,562	)	$	(385	)	$	(1,947	)	$	(223	)	$	(69	)	$	(292	)
Intangible assets		—			—			—			6			(6	)		—
Pre-funded pension costs		697			(522	)		175			—			—			—
Regulatory assets		—			595			595			—			—			—
Deferred income tax assets		—			115			115			32			27			59
Accumulated other comprehensive income, net of tax		—			197			197			61			48			109
Total Recognized	$	(865	)	$	—		$	(865	)	$	(124	)	$	—		$	(124	)

(a) Excludes approximately $7 million in accrued pension and other post-retirement liabilities, approximately $2 million in deferred income tax assets and $5 million in accumulated other comprehensive income associated with a Brazilian retirement plan.

(b) Includes approximately $87 million in accrued pension and other post-retirement liabilities and $4 million in accumulated other comprehensive income related to delayed recognition provisions associated with post-employment benefits.

(c) Includes approximately $89 million that is reflected in Other within Current Liabilities in the Consolidated Balance Sheets at December 31, 2006.

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Notes To Consolidated Financial Statements—(Continued)

Qualified Pension Plans

Components of Net Periodic Pension Costs (Income): Qualified Pension Plans

	Duke Energy U.S.
	For the Years Ended December 31,
	2006(a)			2005(a)			2004(a)
	(in millions)
Service cost benefit earned during the year	$	84		$	53		$	56
Interest cost on projected benefit obligation		190			140			142
Expected return on plan assets		(243	)		(196	)		(200	)
Amortization of prior service cost		(1	)		(2	)		(2	)
Amortization of net transition asset		—			—			(4	)
Curtailment (gain)		—			—			(1	)
Amortization of loss		49			32			14
Special termination benefit cost		2			—			—
Net periodic pension costs	$	81		$	27		$	5

(a) These amounts exclude pre-tax qualified pension cost of approximately $21 million, $12 million and $8 million for the years ended 2006, 2005 and 2004, respectively, primarily related to the Westcoast plans transferred to Spectra Energy, which is included in Income From Discontinued Operations, net of tax, in the Consolidated Statements of Operations.

Reconciliation of Funded Status to Net Amount Recognized: Qualified Pension Plans

	Duke Energy U.S.						Westcoast
	As of and for the Years Ended December 31,
	2006			2005			2006			2005
	(in millions)
Change in Projected Benefit Obligation
Obligation at prior measurement date	$	2,853		$	2,693		$	616		$	480
Service cost		93			61			13			9
Interest cost		207			157			31			29
Actuarial losses		42			105			20			89
Plan amendments		19			—			—			—
Participant contributions		—			—			3			3
Benefits paid		(263	)		(163	)		(32	)		(28	)
Obligation assumed from acquisition		1,872			—			—			11
Foreign currency impact		—			—			2			23
Obligation at measurement date	$	4,823		$	2,853		$	653		$	616

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Notes To Consolidated Financial Statements—(Continued)

	Duke Energy U.S.						Westcoast
	As of and for the Years Ended December 31,
	2006			2005			2006			2005
	(in millions)
Change in Fair Value of Plan Assets
Plan assets at prior measurement date	$	2,948		$	2,477		$	475		$	362
Actual return on plan assets		316			384			32			63
Benefits paid		(263	)		(163	)		(32	)		(28	)
Employer contributions		124			250			45			48
Plan participants’ contributions		—			—			3			3
Assets received on acquisition		1,199			—			—			10
Foreign currency impact		—			—			2			17
Plan assets at measurement date	$	4,324		$	2,948		$	525		$	475
Funded status	$	(499	)	$	95		$	(128	)	$	(141	)
Unrecognized net experience loss		—			655			—			122
Unrecognized prior service cost		—			(3	)		—			8
Contributions between measurement date and year end		—			—			12			13
Net amount recognized	$	(499	)	$	747		$	(116	)	$	2

For the Duke Energy U.S. plans, the accumulated benefit obligation was $4,408 million at September 30, 2006 and $2,753 million at September 30, 2005.

For Westcoast, the accumulated benefit obligation was $588 million at September 30, 2006 and $562 million at September 30, 2005.

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

	Duke Energy U.S.					Westcoast
	As of December 31,
	2006			2005		2006			2005
	(in millions)
Accrued pension liability	$	(674	)	$	—	$	(116	)	$	(76	)
Intangible asset		—			—		—			7
Pre-funded pension costs		175			747		—			—
Deferred income tax asset		—			—		—			25
Accumulated other comprehensive income		—			—		—			46
Net amount recognized	$	(499	)	$	747	$	(116	)	$	2

As a result of the adoption of SFAS No. 158, certain previously unrecognized amounts were recognized in the amounts noted above with an offset to Accumulated Other Comprehensive Income, Deferred Income Taxes and Regulatory Assets as of December 31, 2006. The table below details the components of these balances.

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Notes To Consolidated Financial Statements—(Continued)

Qualified Pension Plans—Amounts Recognized in Regulatory Assets and Accumulated Other Comprehensive Income Consist of:

	Duke Energy U.S.			Westcoast
	As of December 31, 2006
	(in millions)
Regulatory assets	$	481		$	—
Accumulated other comprehensive income
Deferred income tax asset	$	(50	)	$	(49	)
Net transition obligation		—			—
Prior service cost		10			8
Net actuarial loss		126			132
Net amount recognized—Accumulated other comprehensive income	$	86		$	91

Qualified Pension Plans—Amounts in Regulatory Assets and Accumulated Other Comprehensive Income to be Recognized in Net Periodic Pension Costs in 2007 Consist of:

	Duke Energy U.S.
	(in millions)
Unrecognized (gains)/losses	$	42
Unrecognized prior service cost		—
Net amount to be recognized	$	42

Amounts in the above table exclude Westcoast due to the spin-off of the natural gas businesses on January 2, 2007.

Additional Information:

Qualified Pension Plans—Information for Plans with Accumulated Benefit Obligation in Excess of Plan Assets

	Duke Energy U.S.				Westcoast
	As of December 31,
	2006		2005		2006		2005
	(in millions)
Projected benefit obligation	$	1,976	$	—	$	637	$	602
Accumulated benefit obligation		1,688		—		576		551
Fair value of plan assets		1,302		—		511		464

Qualified Pension Plans—Assumptions Used for Pension Benefits Accounting

	Duke Energy U.S.			Westcoast
Benefit Obligations	2006	2005	2004	2006	2005	2004
	(percentages)
Discount rate	5.75	5.50	6.00	5.00	5.00	6.25
Salary increase	5.00	5.00	5.00	3.50	3.25	3.25
Determined Expense	2006	2005	2004	2006	2005	2004
Discount rate	5.50 – 6.00	6.00	6.00	5.00	6.25	6.00
Salary increase	5.00	5.00	5.00	3.25	3.25	3.25
Expected long-term rate of return on plan assets	8.50	8.50	8.50	7.25	7.50	7.50

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Notes To Consolidated Financial Statements—(Continued)

For the Duke Energy U.S. plans the discount rate used to determine the pension obligation is based on a AA bond yield curve. The yield is selected based on bonds with cash flows that match the timing and amount of the expected benefit payments under the plan. For legacy Cinergy plans, the discount rate used to determine expense reflects remeasurement as of April 1, 2006 due to the merger between Duke Energy and Cinergy.

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.

Qualified Pension Plan Assets—Duke Energy U.S.:

			Percentage of Plan Assets at September 30
Asset Category	Target Allocation		2006		2005
U.S. equity securities	46	%	46	%	46	%
Non-U.S. equity securities	18		19		21
Debt securities	32		32		29
Real estate	4		3		4
Total	100	%	100	%	100	%

Duke Energy U.S. assets for both the pension and other post retirement benefits are maintained by two Master Trusts. The investment objective of the master trusts 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 plan participants. The asset allocation targets were set after considering the investment objective and the risk profile with respect to the trusts. U.S. equities are held for their high expected return. Non-U.S. equities, debt securities, and real estate are held for diversification. Investments within asset classes are to be diversified to achieve broad market participation and reduce the impact of individual managers or investments. Duke Energy regularly reviews its actual asset allocation and periodically rebalances its investments to the targeted allocation when considered appropriate.

The long-term rate of return of 8.5% as of September 30, 2006 for the Duke Energy U.S. 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 4.2% for U.S. equities, 1.8% for Non-U.S. equities, 2.2% for fixed income securities, and 0.3% for real estate.

Qualified Pension Plan Assets—Westcoast:

			Percentage of Plan Assets at September 30
Asset Category	Target Allocation		2006		2005
Canadian equity securities	30	%	29	%	42	%
U.S. equity securities	15		15		11
EAFE equity securities(a)	15		16		15
Debt securities	40		40		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 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.

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Notes To Consolidated Financial Statements—(Continued)

The long-term rate of return of 7.25% as of September 30, 2006 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 2.5% for Canadian equities, 1.3% for U.S. equities, 1.4% for Europe, Australasia and Far East equities, and 2.0% 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:

Qualified Pension Plans—Expected Benefit Payments

	U.S. Plans		Westcoast Plans
	(in millions)
Years Ended December 31,
2007	$	311	$	31
2008		309		31
2009		323		32
2010		342		33
2011		377		34
2012 – 2016		2,101		201

Non-Qualified Pension Plans

Components of Net Periodic Pension Costs: Non-Qualified Pension Plans

	Duke Energy U.S.
	For the Years Ended December 31,
	2006(a)		2005(a)		2004(a)
	(in millions)
Service cost benefit earned during the year	$	2	$	1	$	2
Interest cost on projected benefit obligation		7		4		5
Expected return on plan assets		—		—		—
Amortization of prior service cost		1		1		1
Amortization of net transition liability		—		1		1
Curtailment loss		—		—		1
Amortization of loss		—		—		—
Net periodic pension costs	$	10	$	7	$	10

(a) These amounts exclude pre-tax qualified pension cost of approximately $7 million, $6 million and $5 million for the years ended 2006, 2005 and 2004, respectively, primarily related to the Westcoast plans transferred to Spectra Energy, which is included in Income From Discontinued Operations, net of tax, in the Consolidated Statements of Operations.

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Notes To Consolidated Financial Statements—(Continued)

Reconciliation of Funded Status to Net Amount Recognized: Non-Qualified Pension Plans

	Duke Energy U.S.						Westcoast
	As of and for the Years Ended December 31,
	2006			2005			2006			2005
	(in millions)
Change in Projected Benefit Obligation
Obligation at prior measurement date	$	86		$	86		$	84		$	66
Service cost		2			1			1			1
Interest cost		8			5			4			4
Actuarial losses		4			2			3			14
Plan amendments		(2	)		—			—			—
Participant contributions		—			—			—			—
Benefits paid		(36	)		(8	)		(4	)		(3	)
Obligation assumed from acquisition		137			—			—			—
Foreign currency impact		—			—			—			2
Obligation at measurement date	$	199		$	86		$	88		$	84
	Duke Energy U.S.						Westcoast
	As of and for the Years Ended December 31,
	2006			2005			2006			2005
	(in millions)
Change in Fair Value of Plan Assets
Plan assets at prior measurement date	$	—		$	—		$	—		$	—
Actual return on plan assets		—			—			—			—
Benefits paid		(36	)		(8	)		(4	)		(3	)
Employer contributions		36			8			4			3
Plan participants’ contributions		—			—			—			—
Assets received on acquisition		—			—			—			—
Foreign currency impact		—			—			—			—
Plan assets at measurement date	$	—		$	—		$	—		$	—
Funded status	$	(199	)	$	(86	)	$	(88	)	$	(84	)
Unrecognized net experience loss		—			(7	)		—			23
Unrecognized prior service cost		—			8			—			—
Contributions between measurement date and year end		21			2			2			1
Accrued pension liability	$	(178	)	$	(83	)	$	(86	)	$	(60	)

For the Duke Energy U.S. plans, the accumulated benefit obligation was $184 million at September 30, 2006 and $79 million at September 30, 2005.

For Westcoast, the accumulated benefit obligation was $83 million at September 30, 2006 and $82 million at September 30, 2005.

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Notes To Consolidated Financial Statements—(Continued)

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

	Duke Energy U.S.						Westcoast
	As of December 31,
	2006			2005			2006			2005
	(in millions)
Accrued pension liability(a)	$	(178	)	$	(83	)	$	(86	)		(81	)
Pre-funded pension costs		—			—			—			—
Accumulated other comprehensive income		—			—			—			21
Net amount recognized	$	(178	)	$	(83	)	$	(86	)	$	(60	)

(a) Duke Energy U.S. includes approximately $41 million and Westcoast includes approximately $6 million recognized in Other within Current Liabilities on the Consolidated Balance Sheets as of December 31, 2006.

As a result of the adoption of SFAS No. 158, certain previously unrecognized amounts were recognized in the amounts noted above with an offset to Accumulated Other Comprehensive Income, Deferred Income Taxes and Regulatory Assets as of December 31, 2006. The table below details the components of these balances.

Non-Qualified Pension Plans—Amounts Recognized in Regulatory Assets and Accumulated Other Comprehensive Income Consist of:

	Duke Energy U.S.			Westcoast
	As of December 31, 2006
	(in millions)
Regulatory assets	$	4		$	—
Accumulated other comprehensive income
Deferred income tax liability (asset)	$	1		$	(9	)
Net transition obligation		—			—
Prior service cost		5			—
Net actuarial loss		(7	)		25
Net amount recognized- Accumulated other comprehensive income	$	(1	)	$	16

Non-Qualified Pension Plans—Amounts in Regulatory Assets and Accumulated Other Comprehensive Income to be Recognized in Net Periodic Pension Costs in 2007 Consist of:

	Duke Energy U.S.
	(in millions)
Unrecognized (gains)/losses	$	—
Unrecognized prior service cost		2
Net amount to be recognized	$	2

Amounts in the above table exclude Westcoast due to the spin-off of the natural gas businesses on January 2, 2007.

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Notes To Consolidated Financial Statements—(Continued)

Additional Information:

Non-Qualified Pension Plans—Information for Plans with Accumulated Benefit Obligation in Excess of Plan Assets

	Duke Energy U.S.				Westcoast
	As of December 31,
	2006		2005		2006		2005
	(in millions)
Projected benefit obligation	$	199	$	86	$	88	$	84
Accumulated benefit obligation		184		79		83		82
Fair value of plan assets		—		—		—		—

Non-Qualified Pension Plans—Assumptions Used for Pension Benefits Accounting

	Duke Energy U.S.			Westcoast
Benefit Obligations	2006	2005	2004	2006	2005	2004
	(percentages)
Discount rate	5.75	5.50	6.00	5.00	5.00	6.25
Salary increase	5.00	5.00	5.00	3.50	3.25	3.25
Determined Expense	2006	2005	2004	2006	2005	2004
Discount rate	5.50 – 6.00	6.00	6.00	5.00	6.25	6.00
Salary increase	5.00	5.00	5.00	3.25	3.25	3.25

For the Duke Energy U.S. plans the discount rate used to determine the pension obligation is based on a AA bond yield curve. The yield is selected based on bonds with cash flows that match the timing and amount of the expected benefit payments under the plan. For legacy Cinergy plans, the discount rate used to determine expense reflects remeasurement as of April 1, 2006 due to the merger between Duke Energy and Cinergy.

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.

Non-Qualified Plans—Expected Benefit Payments

	U.S. Plans		Westcoast Plans
	(in millions)
Years Ended December 31,
2007	$	41	$	5
2008		16		5
2009		20		5
2010		16		5
2011		16		5
2012 – 2016		66		26

Duke Energy also sponsors employee savings plans that cover substantially all U.S. employees. Most employees participate in a matching contribution formula where Duke Energy provides a matching contribution generally equal to 100% of before-tax employee contributions, of up to 6% of eligible pay per pay period. Duke Energy expensed employer matching contributions of $67 million in 2006, $54 million in 2005 and $50 million in 2004. These amounts exclude pre-tax expenses of $8 million, $7 million and $7 million for the years ended 2006, 2005 and 2004, respectively, related to Spectra Energy, which is included in Income from Discontinued Operations, net of tax, in the Consolidated Statements of Operations. Dividends on Duke Energy shares held by the savings plans are charged to retained earnings when declared and shares held in the plans are considered outstanding in the calculation of basic and diluted earnings per share.

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Notes To Consolidated Financial Statements—(Continued)

Other Post-Retirement Benefit Plans

Duke Energy U.S. Other Post-Retirement Benefits.Duke Energy and most of its subsidiaries 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 13 years.

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.

As discussed in Note 1, on January 2, 2007, Duke Energy completed the spin-off of its natural gas businesses to shareholders. The Westcoast other post-retirement benefit plans were transferred to Spectra Energy as part of the spin-off.

Components of Net Periodic Other Post-Retirement Benefit Costs

	Duke Energy U.S.
	For the Years Ended December 31,
	2006(a)			2005(a)			2004(a)
	(in millions)
Service cost benefit earned during the year	$	9		$	5		$	5
Interest cost on accumulated post-retirement benefit obligation		50			39			40
Expected return on plan assets		(13	)		(15	)		(16	)
Amortization of prior service cost		2			2			2
Amortization of net transition liability		12			12			12
Amortization of loss		7			5			6
Net periodic other post-retirement benefit costs	$	67		$	48		$	49

(a) These amounts exclude pre-tax qualified pension cost of approximately $21 million, $18 million and $17 million for the years ended 2006, 2005 and 2004, respectively, primarily related to the Westcoast plans transferred to Spectra Energy, which is included in Income From Discontinued Operations, net of tax, in the Consolidated Statements of Operations.

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Notes To Consolidated Financial Statements—(Continued)

Reconciliation of Funded Status to Accrued Other Post-Retirement Benefit Costs

	Duke Energy U.S.						Westcoast
	As of and for the Years Ended December 31,
	2006			2005			2006			2005
	(in millions)
Change in Benefit Obligation
Accumulated post-retirement benefit obligation at prior measurement date	$	791		$	782		$	117		$	86
Service cost		10			6			4			3
Interest cost		56			45			7			6
Plan participants’ contributions		25			21			—			—
Actuarial (gain) / loss		(4	)		17			(34	)		21
Benefits paid		(88	)		(80	)		(4	)		(3	)
Accrued RDS subsidy		4			—			—			—
Obligation assumed from acquisition		470			—			—			—
Foreign currency impact		—			—			1			4
Accumulated post-retirement benefit obligation at measurement date	$	1,264		$	791		$	91		$	117
	Duke Energy U.S.						Westcoast
	As of and for the Years Ended December 31,
	2006			2005			2006			2005
	(in millions)
Change in Fair Value of Plan Assets
Plan assets at prior measurement date	$	242		$	243		$	—		$	—
Actual return on plan assets		12			21			—			—
Benefits paid		(88	)		(80	)		(4	)		(3	)
Employer contributions		46			37			4			3
Plan participants’ contributions		25			21			—			—
Plan assets at measurement date	$	237		$	242		$	—		$	—
Funded status	$	(1,027	)	$	(549	)	$	(91	)	$	(117	)
Employer contributions made after measurement date		17			10			1			1
Unrecognized net experience loss		—			209			—			49
Unrecognized prior service cost		—			1			—			(11	)
Unrecognized transition obligation		—			111			—			—
Accrued other post-retirement benefit costs recognized	$	(1,010	)	$	(218	)	$	(90	)	$	(78	)

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

	Duke Energy U.S.						Westcoast
	As of December 31,
	2006			2005			2006			2005
	(in millions)
Accrued other post-retirement liability(a)	$	(1,010	)	$	(218	)	$	(90	)	$	(78	)
Intangible asset		—			—			—			—
Pre-funded pension costs		—			—			—			—
Net amount recognized	$	(1,010	)	$	(218	)	$	(90	)	$	(78	)

(a) Duke Energy U.S. includes approximately $26 million and Westcoast includes approximately $4 million recognized in Other within Current Liabilities on the Consolidated Balance Sheets as of December 31, 2006.

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Notes To Consolidated Financial Statements—(Continued)

As a result of the adoption of SFAS No. 158, certain previously unrecognized amounts were recognized in the amounts noted above with an offset to Accumulated Other Comprehensive Income, Deferred Income Taxes and Regulatory Assets as of December 31, 2006. The table below details the components of these balances.

Other Post-Retirement Benefit Plans—Amounts Recognized in Regulatory Assets and Accumulated Other Comprehensive Income Consist of:

	Duke Energy U.S.			Westcoast
	As of December 31, 2006
	(in millions)
Regulatory Assets	$	111		$	—
Accumulated other comprehensive income
Deferred income tax asset	$	(66	)	$	(1	)
Net Transition Obligation		95			—
Prior Service Cost		(2	)		(11	)
Net Actuarial Loss	��	89			14
Net amount recognized—Accumulated other comprehensive income	$	116		$	2

Other Post Retirement Benefit Plans—Amounts in Regulatory Assets and Accumulated Other Comprehensive Income to be Recognized in Net Periodic Other Post-Retirement Benefit Costs in 2007 Consist of:

	Duke Energy U.S.
	(in millions)
Unrecognized Transition (Asset)/Liability	$	16
Unrecognized (Gains)/Losses		8
Unrecognized Prior Service Cost		1
Net amount to be recognized	$	25

Amounts in the above table exclude Westcoast due to the spin-off of the natural gas businesses on January 2, 2007.

For measurement purposes, plan assets were valued as of September 30 for both the Duke Energy U.S. and Westcoast plans. In May 2004, the FASB staff issued FSP No. FAS 106-2. The Modernization Act introduced a prescription drug benefit under Medicare as well as a federal subsidy to sponsors of retiree health care benefit plans. The FSP provides guidance on the accounting for the subsidy. Duke Energy adopted this FSP and retroactively applied this FSP as of the date of issuance for its U.S. plan. As a result of anticipated prescription drug subsidy, the accumulated post-retirement benefit obligation had a one time decrease of $96 million in 2004. The after-tax effect on net periodic post-retirement benefit cost was a decrease of $8 million in 2006, $7 million in 2005 and $12 million for 2004. The actuarial gain included in the change in benefit obligation of $134 million in 2004 is primarily due to the recognition of anticipated employer savings as a result of Medicare Part D. FSP No. FAS 106-2 provides guidance that the effect of the federal subsidy should be recognized as an actuarial gain. Duke Energy has recognized an approximate $5 million subsidy receivable, which is included in Receivables on the Consolidated Balance Sheets.

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DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

Assumptions Used for Other Post-Retirement Benefits Accounting

	Duke Energy U.S.			Westcoast
Determined Benefit Obligations	2006	2005	2004	2006	2005	2004
	(percentages)
Discount rate	5.75	5.50	6.00	5.00	5.00	6.25
Salary increase	5.00	5.00	5.00	3.50	3.25	3.25

	Duke Energy U.S.			Westcoast
Determined Expense	2006	2005	2004	2006	2005	2004
Discount rate	5.50 – 6.00	6.00	6.00	5.00	6.25	6.00

	Duke Energy U.S.			Westcoast
Determined Benefit Obligations	2006	2005	2004	2006	2005	2004
	(percentages)
Salary increase	5.00	5.00	5.00	3.25	3.25	3.25
Expected long-term rate of return on plan assets	5.53—8.50	8.50	8.50	—	—	—
Assumed tax ratea	35.0	35.0	35.0	—	—	—

(a) Applicable to the health care portion of funded post-retirement benefits

For the Duke Energy U.S. plans the discount rate used to determine the post-retirement obligation is based on a AA bond yield curve. The yield is selected based on bonds with cash flows that match the timing and amount of the expected benefit payments under the plan. For legacy Cinergy plans, the discount rate used to determine expense reflects remeasurement as of April 1, 2006 due to the merger between Duke Energy and Cinergy.

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.

Other Post-Retirement Plan Assets—Duke Energy U.S.:

	Target Allocation		Percentage of Plan Assets at September 30
Asset Category			2006		2005
U.S. equity securities	46	%	46	%	46	%
Non-U.S. equity securities	18		19		21
Debt securities	32		32		29
Real estate	4		3		4
Total	100	%	100	%	100	%

Duke Energy U.S. assets for both the pension and other post-retirement benefits are maintained by two Master Trusts. The investment objective of the trusts 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 plan participants. The asset allocation targets were set after considering the investment objective and the risk profile with respect to the trusts. U.S. equities are held for their high expected return. Non-U.S. equities, debt securities, and real estate are held for diversification. Investments within asset classes are to be diversified to achieve broad market participation and reduce the impact of individual managers or investments. Duke Energy regularly reviews its actual asset allocation and periodically rebalances its investments to the targeted allocation when considered appropriate. The long-term rate of return of 8.5% as of September 30, 2006 for the Duke Energy U.S. assets was developed using a weighted-average calculation of expected returns based primarily on future expected returns across asset classes considering the use of active asset managers. The weighted-average returns expected by asset classes were 4.2% for U.S. equities, 1.8% for Non-U.S. equities, 2.2% for fixed income securities, and 0.3% for real estate.

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Notes To Consolidated Financial Statements—(Continued)

Duke Energy also invests other post-retirement assets in the Duke Energy Corporation Employee Benefits Trust (VEBA I) and the Duke Energy Corporation Post-Retirement Medical Benefits Trust (VEBA II). The investment objective of the VEBA’s is to achieve sufficient returns on trust assets, subject to a prudent level of portfolio risk, for the purpose of promoting the security of plan benefits for participants. The VEBA trusts are passively managed. VEBA I has a target allocation of 30% U.S. equities, 45% fixed income securities and 25% cash. VEBA II has a target allocation of 50% U.S. equities and 50% fixed income securities.

Assumed Health Care Cost Trend Rates^(a)

	Duke Energy U.S.								Westcoast
	Medical Trend Rate						Prescription Drug Trend Rate
			Not Medicare Eligible		Medicare Eligible
	2006		2005				2006		2006		2005
Health care cost trend rate assumed for next year	8.50	%	8.50	%	11.50	%	13.00	%	8.0	%	7.00	%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)	4.75	%	5.50	%	5.50	%	4.75	%	5.00	%	5.00	%
Year that the rate reaches the ultimate trend rate	2013		2009		2012		2022		2009		2008

(a) Health care cost trend rates for 2006 include prescription drug trend rates due to the effect of the Modernization Act.

Sensitivity to Changes in Assumed Health Care Cost Trend Rates Duke Energy U.S. Plans(millions)

	1-Percentage- Point Increase		1-Percentage- Point Decrease
Effect on total service and interest costs	$	6	$	(5	)
Effect on post-retirement benefit obligation		86		(75	)

Sensitivity to Changes in Assumed Health Care Cost Trend Rates Westcoast Plans(millions)

	1-Percentage- Point Increase		1-Percentage- Point Decrease
Effect on total service and interest costs	$	2	$	(1	)
Effect on post-retirement benefit obligation		6		(5	)

Duke Energy and Westcoast expect to make the future benefit payments, which reflect expected future service, as appropriate. Duke Energy expects to receive future subsidies under Medicare Part D. The following benefit payments and subsidies are expected to be paid (or received) over each of the next five years and thereafter.

Other Post-Retirement Plan—Expected Benefit Payments and Subsidies(in millions)

	U.S. Plan Payments		U.S. Plan Expected Subsidies		Westcoast Plans
	(in millions)
2007	$	77	$	7	$	4
2008		81		7		4
2009		84		8		4
2010		88		8		4
2011		92		9		4
2012 – 2016		491		48		23

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DUKE ENERGY CORPORATION

Notes To Consolidated Financial Statements—(Continued)

23. Variable Interest Entities

Power Sale Special Purpose Entities (SPEs). In accordance with FIN 46, Duke Energy consolidates two SPEs that have individual power sale agreements with Central Maine Power Company (CMP) for approximately 45 megawatts (MW) of capacity, ending in 2009, and 35 MW of capacity, ending in 2016. In addition, these SPEs have individual power purchase agreements with Cinergy Capital & Trading, Inc. (Capital & Trading) to supply the power. Capital & Trading also provides various services, including certain credit support facilities. As a result of the consolidation of these two SPEs, approximately $171 million of notes receivable (which are included in Receivables on the Consolidated Balance Sheets), $160 million of non-recourse debt (which is included in Long-Term Debt on the Consolidated Balance Sheets), and miscellaneous other assets and liabilities are included on Duke Energy’s Consolidated Balance Sheets. The debt was incurred by the SPEs to finance the buyout of the existing power contracts that CMP held with the former suppliers. The notes receivable is comprised of two separate notes with one counterparty, whose credit rating is BBB. The cash flows from the notes receivable are designed to repay the debt. The first note receivable, with a December 31, 2006 balance of $62 million, bears an effective interest rate of 7.81 % and matures in August 2009. The second note receivable, with a balance of $109 million as of December 31, 2006, bears an effective interest rate of 9.23 % and matures in December 2016.

The following table reflects the maturities of the Notes Receivable as of December 31, 2006:

Notes Receivable Maturities

	(in millions)
2007	$	25
2008		29
2009		24
2010		8
2011		10
Thereafter		75
Total	$	171

Subsidiary Trust Preferred Securities. In 2001, Cinergy issued approximately $316 million notional amount of 6.9 % trust preferred securities, due February 2007. The trust preferred securities were issued through a trust whose common stock was 100 % owned by Cinergy. The trust loaned the proceeds from the issuance of the securities to Cinergy in exchange for a note payable to the trust. Each Unit receives quarterly cash payments of 6.9 % per annum of the notional amount, which represents a trust preferred security dividend. The trust’s ability to pay dividends on the trust preferred securities is solely dependent on its receipt of interest payments from Cinergy on the note payable. However, Cinergy has fully and unconditionally guaranteed the trust preferred securities. The trust preferred securities are not included in Duke Energy’s Balance Sheets. In addition, the note payable owed to the trust, which amounts to approximately $326 million at December 31, 2006, is included in Current Maturities of Long-Term Debt on the Consolidated Balance Sheets. In February 2007, these trust preferred securities were redeemed on their scheduled maturity date and the note payable was settled.

Accounts Receivable Securitization. During 2002, Duke Energy Ohio, Duke Energy Indiana and Duke Energy Kentucky entered into an agreement to sell certain of their accounts receivable and related collections through Cinergy Receivables, a bankruptcy remote, special purpose entity. Cinergy Receivables is a wholly owned limited liability company of Cinergy. As a result of the securitization, Duke Energy Ohio, Duke Energy Indiana and Duke Energy Kentucky sell, on a revolving basis, nearly all of their retail accounts receivable and related collections. The securitization transaction was structured to meet the criteria for sale treatment under SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities,” (SFAS No. 140) and accordingly Duke Energy does not consolidate Cinergy Receivables and the transfers of receivables are accounted for as sales.

The proceeds obtained from the sales of receivables are largely cash but do include a subordinated note from Cinergy Receivables for a portion of the purchase price (typically approximates 25 % of the total proceeds). The note, which amounts to approximately $210 million at December 31, 2006, is subordinate to senior loans that Cinergy Receivables obtains from commercial paper conduits controlled by unrelated financial institutions. Cinergy Receivables provides credit enhancement related to senior loans in the form of over-collateralization of the purchased receivables. However, the over-collateralization is calculated monthly and does not extend to the entire pool of receivables held by Cinergy Receivables at any point in time. As such, these senior loans do not have recourse to all assets of Cinergy Receivables. These loans provide the cash portion of the proceeds paid to Duke Energy Ohio, Duke Energy Indiana and Duke Energy Kentucky.

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Notes To Consolidated Financial Statements—(Continued)

This subordinated note is a retained interest (right to receive a specified portion of cash flows from the sold assets) under SFAS No. 140 and is classified within Receivables in the accompanying Consolidated Balance Sheets at December 31, 2006. In addition, Duke Energy’s investment in Cinergy Receivables constitutes a purchased beneficial interest (purchased right to receive specified cash flows, in our case residual cash flows), which is subordinate to the retained interests held by Duke Energy Ohio, Duke Energy Indiana and Duke Energy Kentucky.

The carrying values of the retained interests are determined by allocating the carrying value of the receivables between the assets sold and the interests retained based on relative fair value. The key assumptions used in estimating the fair value for 2006 were an anticipated credit loss ratio of 0.7%, a discount rate of 7.4% and a receivable turnover rate of 12.0%. Because (a) the receivables generally turnover in less than two months, (b) credit losses are reasonably predictable due to the broad customer base and lack of significant concentration, and (c) the purchased beneficial interest is subordinate to all retained interests and thus would absorb losses first, the allocated bases of the subordinated notes are not materially different than their face value. The hypothetical effect on the fair value of the retained interests assuming both a 10% and a 20% unfavorable variation in credit losses or discount rates is not material due to the short turnover of receivables and historically low credit loss history. Interest accrues to Duke Energy Ohio, Duke Energy Indiana and Duke Energy Kentucky on the retained interests using the accretable yield method, which generally approximates the stated rate on the notes since the allocated basis and the face value are nearly equivalent. Duke Energy records income from Cinergy Receivables in a similar manner. An impairment charge is recorded against the carrying value of both the retained interests and purchased beneficial interest whenever it is determined that an other-than-temporary impairment has occurred (which is unlikely unless credit losses on the receivables far exceed the anticipated level).

Duke Energy Ohio retains servicing responsibilities for its role as a collection agent on the amounts due on the sold receivables. However, Cinergy Receivables assumes the risk of collection on the purchased receivables without recourse to Duke Energy Ohio, Duke Energy Indiana and Duke Energy Kentucky in the event of a loss. While no direct recourse to Duke Energy Ohio, Duke Energy Indiana and Duke Energy Kentucky exists, these entities risk loss in the event collections are not sufficient to allow for full recovery of their retained interests. No servicing asset or liability is recorded since the servicing fee paid to Duke Energy Ohio approximates a market rate.

The following table shows the gross and net receivables sold, retained interests, purchased beneficial interest, sales, and cash flows during the period from the date of acquisition (April 1, 2006) through December 31, 2006:

	December 31, 2006
	(in millions)
Receivables sold as of December 31, 2006	$	573
Less: Retained interests		210
Net receivables sold as of December 31, 2006	$	363
Purchased beneficial interest	$	20
Sales from April 1, 2006 through December 31, 2006
Receivables sold	$	3,546
Loss recognized on sale		49
Cash flows from April 1, 2006 through December 31, 2006
Cash proceeds from sold receivables	$	3,465
Collection fees received		2
Return received on retained interests		23

Cash flows from the sale of receivables for the period from the date of acquisition through December 31, 2006 are reflected within Operating Activities on the Consolidated Statements of Cash Flows.

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Notes To Consolidated Financial Statements—(Continued)

24. Other Income and Expenses, net

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

	For the years ended December 31,
	2006		2005			2004
	(in millions)
Income/(Expense)
Interest income	$	159	$	33		$	44
Foreign exchange gains (losses)		9		(10	)		14
Deferred returns and AFUDC		32		9			7
Income related to a distribution from an investment at Crescent		—		45			—
Other		53		36			39
Total	$	253	$	113		$	104

25. Subsequent Events

The spin-off of the natural gas businesses was effective January 2, 2007. See Note 1. As a result of the spin-off transaction, on January 2, 2007, in lieu of adjusting the conversion ratio of the convertible debt, Duke Energy issued approximately 2.4 million shares of Spectra Energy common stock to holders of Duke Energy’s convertible senior notes due 2023, consistent with the terms of the debt agreements. The issuance of Spectra Energy shares to the convertible debt holders is expected to result in a pretax charge in the range of $20 million to $30 million in Duke Energy’s 2007 consolidated statement of operations.

For information on other subsequent events, see Notes 1, 2, 3, 4, 12, 17, 18 and 23.

26. Quarterly Financial Data (Unaudited)

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Total
	(In millions, except per share data)
2006(a)
Operating revenues	$	1,620	$	2,903	$	3,280	$	2,875	$	10,678
Operating income		364		373		900		157		1,794
Net income		358		355		763		387		1,863
Earnings available for common stockholders		358		355		763		387		1,863
Earnings per share:
Basic(b)	$	0.39	$	0.29	$	0.61	$	0.31	$	1.59
Diluted(b)	$	0.37	$	0.28	$	0.60	$	0.31	$	1.57
2005(a)
Operating revenues	$	1,523	$	1,576	$	2,030	$	1,777	$	6,906
Operating income		326		243		653		234		1,456
Net income		868		309		41		606		1,824
Earnings available for common stockholders		866		307		38		601		1,812
Earnings per share:
Basic(b)	$	0.91	$	0.33	$	0.04	$	0.65	$	1.94
Diluted(b)	$	0.88	$	0.32	$	0.04	$	0.63	$	1.88

(a) Operating revenues and operating income for quarterly periods in 2006 and 2005 have changed from prior filings as a result of the classification of the spin-off of the natural gas businesses to shareholders on January 2, 2007(see Note 1), the classification of International Energy’s operations in Bolivia to discontinued operations (see Note 1) and DEM from continuing operations to discontinued operations for all periods presented.

(b) Quarterly EPS amounts are meant to be stand-alone calculations and are not always additive to full-year amount due to rounding.

During the first quarter of 2006, Duke Energy recorded the following unusual or infrequently occurring item: an approximate $24 million pre-tax gain on the settlement of a customer’s transportation contract (see Note 13).

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Notes To Consolidated Financial Statements—(Continued)

During the second quarter of 2006, Duke Energy recorded the following unusual or infrequently occurring items: approximately $55 million pre-tax charge related to voluntary and involuntary severance as a result of the merger with Cinergy (see Note 12); an approximate $55 million pre-tax other-than-temporary impairment charge related to International Energy’s investment in Campeche (see Note 12) and the issuance of approximately 313 million shares of common stock in connection with the merger with Cinergy (see Note 1).

During the third quarter of 2006, Duke Energy recorded the following unusual or infrequently occurring items: an approximate $246 million pre-tax gain on the sale of an effective 50% interest in the Crescent JV (see Note 2); and an approximate $40 million additional gain on the sale of DENA’s assets to LS Power as a result of LS Power obtaining certain regulatory approvals (see Note 13).

During the fourth quarter of 2006, Duke Energy recorded the following unusual or infrequently occurring items: an approximate $65 million pre-tax contract settlement negotiation reserve (see Note 17); an approximate $100 million pre-tax charge to establish a settlement reserve related to the Citrus litigation (see Note 17); approximately $75 million of tax benefits (see Note 6); an approximate $25 million pre-tax gain on the sale of CMT (see Note 13); and an approximate $28 million pre-tax impairment charge at International Energy as a result of the pending sale of operations in Bolivia (see Note 13).

During the first quarter of 2005, Duke Energy 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 DEFS’ wholly-owned subsidiary, Texas Eastern Products Pipeline Company, LLC (see Note 13); an approximate $100 million pre-tax gain on sale of Duke Energy’s limited partner interest in TEPPCO Partners, L.P. (see Note 13); an approximate $21 million pre-tax gain on sale of DENA’s partially completed Grays Harbor power plant in Washington State (see Note 13); an approximate $230 million of unrealized pre-tax losses on certain 2005 and 2006 derivative contracts hedging Field Services commodity price risk which were discontinued as cash flow hedges as a result of the anticipated deconsolidation of DEFS by Duke Energy (see Note 13); and an approximate $30 million mutual liability adjustment related to Bison which was an immaterial correction of an accounting error related to prior periods.

During the third quarter of 2005, Duke Energy 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 contracts outside the Midwestern United States and certain contractual positions related to the Midwestern Assets (see Note 13); an approximate $575 million pre-tax gain associated with the transfer of 19.7% of Duke Energy’s interest in DEFS to ConocoPhillips, Duke Energy’s co-equity owner in DEFS, which reduced Duke Energy’s ownership interest in DEFS from 69.7% to 50% (see Note 13); an approximate $105 million of unrealized and realized pre-tax losses on certain 2005 and 2006 derivative contracts hedging Field Services commodity price risk which were discontinued as cash flow hedges as a result of the deconsolidation of DEFS by Duke Energy (see Note 13); and approximately $90 million of gains at Crescent due primarily to income related to a distribution from an interest in a portfolio of office buildings and a large land sale.

During the fourth quarter of 2005, Duke Energy 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 13).

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SCHEDULE II—VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

			Additions(c):
	Balance at Beginning of Period		Charged to Expense		Charged to Other Accounts		Deductions(a)		Balance at End of Period
	(In millions)
December 31, 2006:
Injuries and damages	$	1,216	$	7	$	10	$	49	$	1,184
Allowance for doubtful accounts		127		38		21		92		94
Other(b)		896		468		287		532		1,119
	$	2,239	$	513	$	318	$	673	$	2,397
December 31, 2005:
Injuries and damages	$	1,269	$	4	$	—	$	57	$	1,216
Allowance for doubtful accounts		135		33		10		51		127
Other(b)		905		336		77		422		896
	$	2,309	$	373	$	87	$	530	$	2,239
December 31, 2004:
Injuries and damages	$	1,319	$	8	$	2	$	60	$	1,269
Allowance for doubtful accounts		280		77		4		226		135
Other(b)		1,162		245		96		598		905
	$	2,761	$	330	$	102	$	884	$	2,309

(a) Principally cash payments and reserve reversals.

(b) Principally insurance related reserves at Bison, uncertain tax provisions, litigation and other reserves, included in Other Current Liabilities, or Deferred Credits and Other Liabilities on the Consolidated Balance Sheets.

(c) 2006 balances include balances and activity related to Duke Energy’s merger with Cinergy in April 2006.

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PART IV

Exhibit 12

COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES

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

	Year Ended December 31,
	2006(e)		2005		2004		2003			2002
	(dollars in millions)
Earnings as defined for fixed charges calculation
Add:
Pretax income (loss) from continuing operations(b)(d)	$	1,414	$	1,189	$	720	$	(990	)	$	1,054
Fixed charges		1,382		1,159		1,433		1,620			1,550
Distributed income of equity investees		893		473		140		263			369
Deduct:
Preference security dividend requirements of consolidated subsidiaries		27		27		31		139			170
Interest capitalized(c)		56		23		18		58			193
Total earnings(as defined for the Fixed Charges calculation)	$	3,606	$	2,771	$	2,244	$	696		$	2,610
Fixed charges:
Interest on debt, including capitalized portions	$	1,311	$	1,096	$	1,365	$	1,441		$	1,340
Estimate of interest within rental expense		44		36		37		40			40
Preference security dividend requirements of consolidated subsidiaries		27		27		31		139			170
Total fixed charges	$	1,382	$	1,159	$	1,433	$	1,620		$	1,550
Ratio of earnings to fixed charges(e)		2.6		2.4		1.6		(d	)		1.7

(a) Certain amounts above have been revised for businesses reclassified to discontinued operations.

(b) Excludes minority interest expenses and income or loss from equity investees.

(c) Excludes equity costs related to Allowance for Funds Used During Construction that are included in Other Income and Expenses in the Consolidated Statements of Operations.

(d) Earnings were inadequate to cover fixed charges by $924 million for the year ended December 31, 2003.

(e) Pretax income from continuing operations includes an approximate $250 million gain on the sale of an effective 50% interest in Crescent.

154