INTRODUCTION

Management's Discussion and Analysis should be read in conjunction with Item 8. Financial Statements and Supplementary Data. The Consolidated Statements of Operations and related discussions contained in this report have been re-cast to reflect the operating results of certain Western Canada Transmission & Processing natural gas gathering and processing facilities as discontinued operations for all periods presented. See Note 8 of Notes to Consolidated Financial Statements for further discussion.

EXECUTIVE OVERVIEW

Throughout 2008, we continued to successfully execute on the strategies and objectives we outlined for our shareholders. These included exceeding our earnings objectives and the successful execution on significant capital expansion plans that underlie our growth objectives.

We reported net income of $1,129 million, and $1.81 of diluted earnings per share for 2008, exceeding the employee incentive target earnings per share, primarily as a result of the positive impact of higher NGL prices in 2008, which correlate to higher crude oil prices, on the earnings from Field Services and the Empress operations. Although these commodity prices dropped dramatically in the fourth quarter of 2008, crude oil averaged $100 per barrel for 2008 versus $73 per barrel in 2007. Earnings in 2008 also reflected new capital projects in service, partially offset by higher project development costs charged to expense, an impairment of the Islander East project and higher operating costs.

We reported $2.0 billion of capital and investment expenditures for 2008, including expansion capital of $1.5 billion. We successfully completed our 2008 expansion plans, with returns on these projects expected to be slightly above our targeted 10-12% return on capital employed range. Return on capital employed as it relates to expansion projects is calculated by us as incremental earnings before interest and taxes generated by a project divided by the total cost of the project. Expansion expenditures for 2009 are currently expected to be significantly lower than the 2008 level of spending, mainly as a result of many of the larger projects that came into service in 2008 or early 2009, as well as our continuous assessment of the timing of projected long-term market requirements and general economic conditions. Based on our current assessment, we believe that expansion expenditures will continue to support our strategic objectives.

We successfully issued approximately $1.8 billion of new long-term debt in 2008, the need for which was driven by the significant 2008 capital expansion program. As of December 31, 2008, we continue to have ongoing access to approximately $2.6 billion in credit facilities and expect to continue to utilize commercial paper and revolving lines of credit, as needed, to fund liquidity needs throughout 2009. The level of borrowings in 2009 is expected to be significantly lower than in 2008, primarily as a result of lower anticipated expansion capital expenditures in 2009 and an equity issuance in February 2009.

In May 2008, our Board of Directors approved a share repurchase program, authorizing us to purchase in the aggregate up to $600 million of shares of our outstanding common stock. This share repurchase program was completed in August 2008.

In July 2008, we declared a 9% increase in our quarterly dividend from $0.23 to $0.25 per common share. The new annualized dividend rate is $1.00 per share, representing a nearly 14% increase over the 2007 level of $0.88 per share.

On February 13, 2009, in order to further protect our capitalization structure against a potential extreme decline in the Canadian dollar, we issued 32.2 million shares of our common stock and received net proceeds of $448 million.

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

• Deliver on 2009 financial commitments.

• Enhance and solidify our profile and position as a premier natural gas infrastructure company.

• Develop new opportunities and projects that add long-term shareholder value.

• Enhance core competencies of customer service, reliability, cost management and compliance.

• Build on our high-performance culture by focusing on safety, diversity, inclusion, leadership and employee development.

• Continue to focus on the future. We must be able to quickly change course when opportunities present themselves in order to be the "company of choice" for investors, employees, customers, communities, governments and regulators.

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

2008 Financial Results. We reported income from continuing operations of $1,129 million in 2008 compared to income from continuing operations of $940 million in 2007. The increase in income from continuing operations reflects higher earnings from Distribution, Western Canada Transmission & Processing and Field Services and lower corporate costs. Highlights for 2008 include the following:

• U.S. Transmission's earnings benefited from completed expansion projects and a customer bankruptcy settlement in the second quarter of 2008. These benefits were offset by higher project development costs charged to expense, an impairment of the Islander East project in the fourth quarter of 2008, and higher operating costs.

• Distribution results reflect higher storage and transportation revenues and less fuel used in operations, partially offset by earnings sharing under the incentive regulation framework implemented in 2008.

• Western Canada Transmission & Processing earnings increased primarily as a result of higher volumes and stronger NGL prices related to the Empress NGL business.

• Field Services earnings reflect higher NGL prices, improved efficiencies, higher volumes and non-cash mark-to-market gains from hedges used to protect the distributable cash flows at DCP Midstream Partners, LP (DCP Partners), DCP Midstream's master limited partnership.

• Other corporate costs were lower in 2008 as a result of 2007 costs associated with our spin-off from Duke Energy, and the favorable resolution of an insurance indemnity in 2008.

Significant Economic Factors For Our Business. Our regulated businesses are generally economically stable and are not significantly affected in the short-term by changing commodity prices. However, all of our businesses can be negatively affected in the long term by sustained downturns or sluggishness in the economy, which could affect long-term demand and market prices for natural gas and NGLs, all of which are beyond our control and could impair our ability to meet long-term goals.

Most of our revenues are based on regulated tariff rates, which include the recovery of certain fuel costs. However, lower overall economic output would cause a decline in the volume of natural gas transported and distributed or gathered and processed at our plants, resulting in lower earnings and cash flows. This decline would primarily affect distribution revenues in the short term. Transmission revenues could be affected by long-term economic declines that result in the non-renewal of long-term contracts at the time of expiration. Pipeline transportation and storage customers continue to renew most contracts as they expire. Processing revenues and the earnings and distributions from our Field Services segment are also affected by volumes of natural gas made

available to our systems, which are primarily driven by levels of natural gas drilling activity. While exploration and drilling activities slowed somewhat in 2006 and 2007, overall long-term growth rates associated with our Western Canada operations increased during 2008 as a result of strong indicators of interest for continued natural gas exploration and drilling in the areas of British Columbia and Alberta that are in close proximity to our facilities. We continue to monitor these growth activities.

Our key markets-the northeastern and the southeastern United States, Ontario and the Pacific Northwest-are projected to continue to exhibit higher than average annual growth in natural gas demand versus the North American and U.S. Lower 48 average growth rates through 2018. This demand growth is primarily driven by the natural gas-fired electric generation sector. The natural gas industry is currently experiencing a significant shift in the sources of supply, and this dramatic change is affecting our growth strategies. Traditionally, supply to our markets has come from the Gulf Coast region, onshore and offshore, as well as from fields in western Canada and, more recently, eastern Canada. The national supply profile is shifting to new sources of gas from basins in the Rockies, Mid-Continent, Appalachia, and East Texas. In addition, the natural gas supply outlook includes new LNG re-gasification facilities being built. LNG will clearly be an important new source of supply, but the timing and extent of incremental supply from LNG is yet to be determined and, at present, LNG remains a small percentage of the overall supply to the markets we serve. These supply shifts are shaping the growth strategies that we will pursue, and therefore, will affect the nature of the projects anticipated in the capital and investment expenditure increases discussed below in "-Liquidity and Capital Resources."

Our businesses in the United States are subject to regulations on the federal and state level. Regulations applicable to the gas transmission and storage industry have a significant effect on the nature of the businesses and the manner in which they operate. Changes to regulations are ongoing and we cannot predict the future course of changes in the regulatory environment or the ultimate effect that any future changes will have on our businesses. Additionally, investments and projects located in Canada expose us to risks related to Canadian laws, taxes, economic conditions, fluctuations in currency rates, political conditions and policies of the Canadian government. From 2002 through the third quarter of 2008, the Canadian dollar strengthened significantly compared to the U.S. dollar, which favorably affected earnings and equity during these periods. However, in the fourth quarter 2008, the Canadian dollar weakened significantly in a very short period of time. Changes in this exchange rate or other of these factors are difficult to predict and may affect our future results and financial position.

Certain of our earnings are affected by fluctuations in commodity prices, especially the earnings of DCP Midstream and the Empress NGL operations in Canada. We evaluate, on an ongoing basis, the risks associated with commodity price volatility and currently do not have any plans to enter into hedge positions around these earnings.

Our overall effective income tax rate largely depends on the proportion of earnings in the United States, taxed at a 35% federal rate, to the earnings of our Canadian operations which are generally taxed at rates below 30%. Based on current projections, it is expected that our effective income tax rate on continuing operations will approximate 29 - 30% for 2009, taking into consideration the U.S. and Canadian tax jurisdictions applicable to operations.

As we execute on our strategic objectives, capital expansion projects will continue to be an important part of our growth plan. We currently anticipate capital and investment expenditures in 2009 of approximately $1.0 billion. These capital requirements, along with the refinancings of normal maturities of existing debt, will require us to continue long-term borrowings, although not at the levels experienced in 2008. An inability to access capital at competitive rates could adversely affect our ability to implement our strategy. Market disruptions, or a downgrade in our credit ratings may increase the cost of borrowing or adversely affect the ability to access one or more sources of liquidity.

During the past several years, capital expansion projects have been exposed to cost pressures associated with the availability of skilled labor and the pricing of materials. Although certain costs have begun to decrease

in the current economic conditions, there will be continual focus on project management activities to address these pressures as we move forward with planned expansion opportunities. Significant cost increases could negatively affect the returns ultimately earned on current and future expansions.

For further information related to management's assessment of our risk factors, see Part I, Item 1A. Risk Factors.

Spin-off from Duke Energy. On January 2, 2007, Duke Energy completed the spin-off of Spectra Energy. Duke Energy contributed its natural gas businesses, primarily comprised of the Natural Gas Transmission and Field Services business segments of Duke Energy that were owned through Duke Energy's then wholly owned subsidiary, Spectra Capital. Duke Energy contributed its ownership interests in Spectra Capital to Spectra Energy and all of our outstanding common stock was distributed to Duke Energy's shareholders. Duke Energy's shareholders received one share of Spectra Energy common stock for every two shares of Duke Energy common stock, resulting in the issuance of approximately 631 million shares of Spectra Energy on January 2, 2007.

Prior to the distribution by Duke Energy, Spectra Capital implemented an internal reorganization in which the operations and assets of Spectra Capital that were not associated with the natural gas businesses were contributed by Spectra Capital to Duke Energy or its subsidiaries. The contribution to Duke Energy included the International Energy business segment, Crescent Resources (Crescent, a real estate business), the remaining portion of Spectra Capital's business formerly known as DENA (Duke Energy North America), and other miscellaneous operations.

The results of operations of substantially all of the businesses retained by Duke Energy are reflected as discontinued operations in the accompanying Consolidated Statements of Operations for 2006. Transferred corporate services entities remain presented within continuing operations.

RESULTS OF OPERATIONS

                                                             2008      2007      2006
                                                                   (in millions)
  Operating revenues                                        $ 5,074   $ 4,704   $ 4,501
  Operating expenses                                          3,636     3,291     3,314
  Gains on sales of other assets and other, net                  42        13        47

  Operating income                                            1,480     1,426     1,234
  Other income and expenses                                     844       649       736
  Interest expense                                              636       633       605
  Minority interest expense                                      63        62        40

  Earnings from continuing operations before income taxes     1,625     1,380     1,325
  Income tax expense from continuing operations                 496       440       393

  Income from continuing operations                           1,129       940       932
  Income from discontinued operations, net of tax                 -        17       312

  Net income                                                $ 1,129   $   957   $ 1,244

2008 Compared to 2007

Operating Revenues. The $370 million, or 8%, increase was driven primarily by:

• higher NGL prices and volumes associated with the Empress operations,

• expansion projects placed in service in late 2007 and the fourth quarter of 2008 at U.S. Transmission, and

• growth in the number of customers, an increase in customer usage due to colder weather, and higher storage and transportation revenues primarily due to favorable market conditions and growth of the transmission system at Distribution.

Operating Expenses. The $345 million, or 10%, increase was driven primarily by:

• higher prices and volumes of natural gas and NGLs purchased for the Empress facility,

• an increase in project development costs as a result of growth projects in 2008 and the capitalization of previously expensed costs on northeast expansions in 2007 and increased operating costs at U.S. Transmission, and

• growth in the number of customers and an increase in customer usage at Distribution.

Gain on Sales of Other Assets and Other, net. The $29 million increase was primarily due to a 2008 customer bankruptcy settlement of $27 million.

Operating Income. The $54 million increase is primarily as a result of higher NGL margins from the Empress operations, a 2008 customer bankruptcy settlement and higher earnings from expansion projects, partially offset by higher project development costs charged to expense and higher operating costs.

Other Income and Expenses. The $195 million increase primarily represents higher equity in earnings from the Field Services segment, reflecting higher commodity prices in 2008 compared to 2007.

Interest Expense. The $3 million increase reflects the successful completion of our planned debt issuances in 2008, offset by lower balances and rates on commercial paper in 2008.

Minority Interest Expense. The $1 million increase primarily resulted from earnings from Spectra Energy Partners formed in July 2007, partially offset by the purchase of the Income Fund in the second quarter of 2008.

Income Tax Expense from Continuing Operations. The $56 million increase was a result of higher earnings from continuing operations. The effective tax rate for income from continuing operations was 30.5% compared to 31.9% for the same period in 2007. The lower effective tax rate for 2008 was primarily a result of reductions in Canadian and U.S. state tax rates.

Income from Discontinued Operations, net of tax. The $17 million decrease is driven by proceeds received from a litigation settlement in 2007. This decrease also reflects the operating results of certain Western Canada Transmission & Processing natural gas gathering and processing facilities. In December 2008, we closed on the sale of our interests in these facilities.

For a more detailed discussion of earnings drivers, see the segment discussions that follow.

2007 Compared to 2006

Operating Revenues. The $203 million, or 5%, increase was driven primarily by:

• the effects of the strong Canadian dollar on revenues at Western Canada Transmission & Processing and Distribution, and

• the growth in revenues from higher demand for transmission and storage services and expansion projects.

Operating Expenses. The $23 million decrease was driven primarily by:

• the capitalization of Northeast expansion project costs initially charged to operating expense. We expense project development costs until such time as recovery of costs is determined to be probable. At that time, these costs are capitalized to property, plant and equipment and operating expenses are reduced,

• a decrease in corporate costs primarily as a result of the reduced portfolio and activity of the U.S. captive insurance entity, partially offset by

• the stronger Canadian dollar in 2007 compared to 2006.

Gain on Sales of Other Assets and Other, net. The $34 million decrease was primarily due to the 2006 gains of $28 million on settlements of customers' transportation contracts at U.S. Transmission.

Operating Income. The $192 million increase primarily reflects growth in revenues and lower expenses resulting from the net capitalization in 2007 of Northeast expansion project costs.

Other Income and Expenses. The $87 million decrease represents lower equity earnings from the Field Services segment and management fees we billed to certain Duke Energy operations in 2006. These were partially offset by higher equity earnings on joint ventures that resulted primarily from capitalization of previously expensed project development costs.

Interest Expense. The $28 million increase was primarily due to interest costs capitalized in 2006 related to capital projects of businesses that were transferred to Duke Energy.

Minority Interest Expense. The $22 million increase primarily resulted from higher earnings on Maritimes & Northeast Pipeline, the formation in July 2007 of Spectra Energy Partners and a decrease in the ownership of the operations of the Income Fund in the third quarter of 2006.

Income Tax Expense from Continuing Operations. The $47 million increase was a result of higher earnings from continuing operations in 2007 and tax benefits recorded in 2006. The effective tax rate was 31.9% for 2007 compared to 29.7% for the same period in 2006. The lower effective tax rate in 2006 resulted from a reduction in the unitary state tax rate as a result of Duke Energy's merger with Cinergy Corp (Cinergy) and a 2006 tax benefit related to the impairment of an international investment no longer owned by us.

Income from Discontinued Operations, net of tax. Income from discontinued operations, net of tax was $17 million for 2007 and $312 million for 2006. These amounts primarily represent results of operations and gains (losses) on dispositions related to DENA's assets and contracts outside the Midwestern and Southeastern United States, which are included in Other, as well as the operations of International Energy and our effective 50% interest in Crescent, and a number of businesses previously included in Other, which are classified in discontinued operations as a result of transferring these businesses from Spectra Energy to Duke Energy in December 2006.

For a more detailed discussion of earnings drivers, see the segment discussions that follow.

Segment Results

We evaluate segment performance based on earnings before interest and taxes from continuing operations (EBIT), after deducting minority interest expense related to those profits. On a segment basis, EBIT excludes discontinued operations, represents all profits from continuing operations (both operating and non-operating) before deducting interest and taxes, and is net of the minority interest expense related to those profits. Cash, cash equivalents and investments are managed centrally, so the gains and losses on foreign currency remeasurement, and interest and dividend income on those balances, are excluded from the segments' EBIT. We consider segment EBIT to be a good indicator of each segment's operating performance from its continuing operations, as it represents the results of our ownership interest in operations without regard to financing methods or capital structures.

U.S. Transmission provides transportation and storage of natural gas for customers in various regions of the northeastern and southeastern United States and the Maritime Provinces in Canada.

Distribution provides retail natural gas distribution service in Ontario, Canada, as well as natural gas transportation and storage services to other utilities and energy market participants.

Western Canada Transmission & Processing provides transportation of natural gas, natural gas gathering and processing services, and NGL extraction, fractionation, transportation, storage and marketing to customers in western Canada and the northern tier of the United States.

Field Services gathers and processes natural gas, and fractionates, markets and trades NGLs. It conducts operations through DCP Midstream, which is owned 50% by us and 50% by ConocoPhillips. Field Services gathers raw natural gas through gathering systems located in nine major natural gas producing regions:
Mid-Continent, Rocky Mountain, East Texas-North Louisiana, Barnett Shale, Gulf Coast, South Texas, Central Texas, Antrim Shale and Permian Basin.

Our 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



                                                             2008         2007         2006
                                                                      (in millions)
U.S. Transmission                                           $   844      $   894      $   816
Distribution                                                    353          322          265
Western Canada Transmission & Processing                        398          359          339
Field Services                                                  716          533          569

Total reportable segment EBIT                                 2,311        2,108        1,989
Other                                                           (78 )       (112 )        (77 )

Total reportable segment and other EBIT                       2,233        1,996        1,912
Interest expense                                                636          633          605
Interest income and other(a)                                     28           17           18

Consolidated earnings from continuing operations before
income taxes                                                $ 1,625      $ 1,380      $ 1,325

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

Minority interest expense as presented in the following segment-level discussions includes only minority interest expense related to EBIT of non-wholly owned entities. It does not include minority interest expense related to interest and taxes of those operations. The amounts discussed below include intercompany transactions that are eliminated in the consolidated financial statements.

U.S. Transmission



                                                                  Increase                     Increase
                                           2008       2007       (Decrease)        2006       (Decrease)
                                                         (in millions, except where noted)
Operating revenues                        $ 1,600    $ 1,540    $         60      $ 1,503    $         37
Operating expenses
Operating, maintenance and other              595        473             122          544             (71 )
Depreciation and amortization                 232        217              15          203              14
Gains on sales of other assets and
other, net                                     42          8              34           44             (36 )

Operating income                              815        858             (43 )        800              58
Other income and expenses                      86         85               1           44              41
Minority interest expense                      57         49               8           28              21
. . .