UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K/A

Amendment No. 1

x    ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE        

SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2008

or

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

For the transition period from             to             

Commission file number 001-33556

SPECTRA ENERGY PARTNERS, LP

(Exact name of registrant as specified in its charter)

Delaware	41-2232463
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
5400 Westheimer Court, Houston, Texas	77056
(Address of principal executive offices)	(Zip Code)

713-627-5400

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class	Name of Each Exchange on Which Registered
Common Units Representing Limited Partner Interests	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None.

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

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer  ¨ Accelerated filer  x Non-accelerated filer  ¨ Smaller reporting company  ¨

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

Estimated aggregate market value of the Common Units held by non-affiliates of the registrant at June 30, 2008: $265,000,000.

At March 6, 2009, there were 48,852,175 Common Units, 21,638,730 Subordinated Units and 1,438,291 General Partner Units outstanding.

Explanatory Comment

Spectra Energy Partners, LP is filing this Amendment No. 1 on Form 10-K/A to its Annual Report on Form 10-K for the fiscal year ended December 31, 2008 to correct an inadvertent omission on the signature page of the Form 10-K filed on March 11, 2009 (the “Original Form 10-K”). In addition, we are refiling Exhibits 10.6, 10.8 and 10.11 to include previously omitted schedules and the Exhibit Index has been modified to refer to the previous Exhibit 10.9 as Exhibit 2.1. Except as described above, there are no other changes to the Original Form 10-K, and this amendment does not speak to, or reflect, events occurring after the filing of the Original Form 10-K.

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SPECTRA ENERGY PARTNERS, LP

FORM 10-K FOR THE YEAR ENDED

DECEMBER 31, 2008

TABLE OF CONTENTS

Item		Page
	PART I.
1.	Business	4
	General	4
	Initial Public Offering	4
	East Tennessee	5
	Saltville	5
	Gulfstream	7
	Market Hub	8
	Contract Mix Summary	10
	Supplies and Raw Materials	10
	Regulations	11
	Environmental Matters	11
	Employees	12
	Executive Officers	12
	Glossary	13
	Additional Information	16
1A.	Risk Factors	16
1B.	Unresolved Staff Comments	34
2.	Properties	34
3.	Legal Proceedings	34
4.	Submission of Matters to a Vote of Security Holders	34
	PART II.
5.	Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	35
6.	Selected Financial Data	38
7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	39
7A.	Quantitative and Qualitative Disclosures About Market Risk	55
8.	Financial Statements and Supplementary Data	56
9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	89
9A.	Controls and Procedures	89
9B.	Other Information	90
	PART III.
10.	Directors, Executive Officers and Corporate Governance	91
11.	Executive Compensation	96
12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	118
13.	Certain Relationships and Related Transactions, and Director Independence	120
14.	Principal Accounting Fees and Services	123
	PART IV.
15.	Exhibits, Financial Statement Schedules	125
Signatures		126
Exhibit Index

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

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

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

• the timing and extent of changes in interest rates;

• general economic conditions, which can affect the long-term demand for natural gas and related services;

• potential effects arising from terrorist attacks and any consequential or other hostilities;

• changes in environmental, safety and other laws and regulations;

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

• increases in the cost of goods and services required to complete capital projects;

• growth in opportunities, including the timing and success of efforts to develop domestic pipeline, storage, and other infrastructure projects and the effects of competition;

• the performance of natural gas transmission and storage facilities;

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

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

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

In light of these risks, uncertainties and assumptions, the events described in forward-looking statements might not occur or might occur to a different extent or at a different time than Spectra Energy Partners, LP has described. Spectra Energy Partners, LP 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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PART I

Item 1. Business.

The terms “we,” “our,” “us,” and “Spectra Energy Partners” as used in this report refer collectively to Spectra Energy Partners, LP and its subsidiaries unless the context suggests otherwise. These terms are used for convenience only and are not intended as a precise description of any separate legal entity within Spectra Energy Partners.

General

Spectra Energy Partners, LP, through our subsidiaries and equity affiliates, is engaged in the transportation of natural gas through interstate pipeline systems with over 2,200 miles of pipelines that serve the southeastern United States, and the storage of natural gas in underground facilities with aggregate working gas storage capacity of approximately 42 billion cubic feet (Bcf) that are located in southeast Texas, south central Louisiana and southwest Virginia. We are a Delaware master limited partnership formed on March 19, 2007.

We transport and store natural gas for a broad mix of customers, including local gas distribution companies (LDC), municipal utilities, interstate and intrastate pipelines, direct industrial users, electric power generators, marketers and producers. In addition to serving directly connected southeastern markets, our pipeline and storage systems have access to customers in the mid-Atlantic, northeastern and midwestern regions of the United States through numerous interconnections with major pipelines. Our rates are regulated under the Federal Energy Regulatory Commission (FERC) rate-making policies, and, in the case of Market Hub’s storage facility in Texas, by the Texas Railroad Commission (TRC).

Our operations and activities are managed by our general partner, Spectra Energy Partners (DE) GP, LP, which in turn is managed by its general partner, Spectra Energy Partners GP, LLC, (the General Partner). The General Partner is wholly owned by a subsidiary of Spectra Energy Corp (Spectra Energy). Spectra Energy is a separate, publicly traded entity which trades on the New York Stock Exchange under the symbol “SE.”

Initial Public Offering

On July 2, 2007, immediately prior to the closing of our initial public offering (IPO), Spectra Energy contributed to us 100% of the ownership of East Tennessee Natural Gas, LLC (East Tennessee), 50% of the ownership of Market Hub Partners Holding (Market Hub), and a 24.5% interest in Gulfstream Natural Gas System, L.L.C. (Gulfstream). Spectra Energy indirectly owned 100% of us prior to the closing of the IPO. On July 2, 2007, we issued 11.5 million common units to the public, representing 17% of our outstanding equity. Spectra Energy retained an 83% equity interest in us, including common units, subordinated units and a 2% general partner interest. As a result of the 2008 acquisition of the Saltville Gas Storage L.L.C (Saltville) assets discussed below, Spectra Energy now has an 84% ownership interest in us.

Gas Transportation and Storage

Our sole segment, Gas Transportation and Storage includes East Tennessee and Saltville. Prior to the Saltville acquisition, East Tennessee was considered our sole reportable segment. The Gas Transportation and Storage segment provides interstate transportation and storage of natural gas and the storage and redelivery of liquefied natural gas (LNG) for customers in the southeastern U.S. These operations are primarily subject to the FERC’s and the Department of Transportation’s (DOT) rules and regulations.

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General

East Tennessee

We own and operate 100% of the 1,510-mile East Tennessee interstate natural gas transportation system, which extends from central Tennessee eastward into southwest Virginia and northern North Carolina, and southward into northern Georgia. East Tennessee supports the energy demands of the southeast and mid-Atlantic regions of the United States through connections to 28 receipt points and more than 175 delivery points and has market delivery capability of approximately 1.5 billion cubic feet per day (Bcf/d) of natural gas. East Tennessee also owns and operates an LNG storage facility in Kingsport, Tennessee with working gas storage capacity of 1.1 Bcf and regasification capability of 150  million cubic feet per day (MMcf/d).

Saltville

We own and operate 100% of the Saltville natural gas storage facilities which consists of 5.5 Bcf of total storage capacity. The storage facilities interconnect with the East Tennessee Natural Gas system in southwest Virginia. This salt cavern facility offers high deliverability salt cavern and reservoir storage capabilities and is strategically located near markets in Tennessee, Virginia and North Carolina.

Customers and Contracts

Gas Transportation and Storage’s customers include LDCs, utilities, industrial companies, natural gas marketers and producers and electric power generators. Gas Transportation and Storage’s largest customer in 2008 was Atmos Energy Corporation, which accounted for approximately 14% of Gas Transportation and Storage’s revenues.

Gas Transportation and Storage has contracts with its customers to provide firm transportation and storage services. Payments under these services are based on the volume of capacity reserved on the system regardless of the capacity actually used, plus a variable charge based on the volume of natural gas actually transported. As a result, firm transportation revenues typically remain relatively constant over the term of the contract. Maximum and minimum rates for services are governed by the applicable FERC-approved natural gas tariff.

In 2005, East Tennessee entered into a rate settlement with its customers which established new base rates under the tariff. The 2005 rate settlement provides rate certainty through the settlement’s expiration in 2010, at which time East Tennessee’s rates will remain the same, subject to further negotiation or the filing of a rate case. Neither regulation nor the terms of the settlement require East Tennessee to file a rate case at any time.

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In September 2008, Saltville placed into effect new rates approved by the FERC as a result of a rate proceeding initiated by us to satisfy a certificate condition. A rate settlement with customers was reached in August 2008 on this rate proceeding which was subsequently approved by the FERC in December 2008 and which includes a rate moratorium until October 1, 2011.

Gas Transportation and Storage also provides interruptible transportation and storage services under which gas is transported or stored for customers when operationally feasible and customers pay only for the actual volume of gas transported or stored. Under all contracts, Gas Transportation and Storage retains, at no cost, a fixed percentage of the natural gas it transports in order to supply the fuel needed for natural gas compression on the system.

As of December 31, 2008, Gas Transportation and Storage’s firm transportation and storage contracts had a weighted average remaining life of approximately eight years. For the year ended December 31, 2008, 97% of Gas Transportation and Storage’s revenues were derived from capacity reservation charges under firm contracts (including LNG storage services), with the remainder representing variable usage fees under firm and interruptible transportation contracts.

Source of Supply

Although Gas Transportation and Storage does not own the natural gas transported or stored on its systems, gas supply attachments are a critical factor for its customers. The majority of the gas supply benefiting our customers comes from the Gulf Coast region through Tennessee Gas Pipeline Company, and to a lesser degree Texas Eastern Transmission, L.P. (Texas Eastern Transmission), a subsidiary of Spectra Energy, Southern Natural Gas Company, Columbia Gulf Transmission Company and Midwestern Gas Pipeline System. Our customers also receive natural gas supply from the Appalachian region through several producers and receive natural gas supply through the Jewell Ridge and Nora Laterals that connect to Appalachian supply basins. Natural gas withdrawn from East Tennessee’s LNG storage facility and other on-system storage fields, including our Saltville natural gas storage facility, provide customers with additional supply sources used to supplement supplies during periods of peak demand.

Competition

The mountainous geography of the regions served by East Tennessee creates natural barriers to entry that make competition from new pipeline entrants difficult and expensive. As a result, East Tennessee is the sole source of interstate natural gas transportation for many of the firm capacity customers that transport natural gas on this system. At both ends of this system, East Tennessee is subject to competition from other pipelines.

Natural gas is in direct competition with electricity for residential and commercial heating demand in East Tennessee’s and Saltville’s market areas. While this competition does not directly affect firm sales, LDC customers’ growth is partially dependent upon the installation of natural gas furnaces in new home construction. Although substitution of electric heat for natural gas heat could have a long-term effect on customers’ demand requirements, East Tennessee and Saltville have already benefited from the addition of natural gas fired electric generation supplied by the pipeline.

An increase in competition in the region served by East Tennessee and Saltville could arise from new ventures or expanded operations from existing competitors. Other competitive factors include the quantity, location and physical flow characteristics of interconnected pipelines, the ability to offer service from multiple storage or production locations, and the cost of service and rates offered by East Tennessee’s and Saltville’s competitors.

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Gulfstream

General

We own a 24.5% interest in the approximate 745-mile Gulfstream interstate natural gas transportation system which extends from Pascagoula, Mississippi and Mobile, Alabama across the Gulf of Mexico and into Florida. The Gulfstream pipeline currently includes approximately 295 miles of onshore pipeline in Florida, 15 miles of onshore pipeline in Alabama and Mississippi, and 435 miles of offshore pipeline in the Gulf of Mexico. Facilities also include gas treatment facilities and a compressor station in Coden, Alabama. Gulfstream supports the south and central Florida markets through its connection to eight receipt points and 23 delivery points and has market delivery capability of approximately 1.25 Bcf/d of natural gas. Spectra Energy and The Williams Companies, Inc. (Williams) own the remaining 25.5% and 50% interests in Gulfstream, respectively, and jointly operate the system.

Customers, Contracts and Supply

In 2008, Florida Power & Light Company, Florida Power Corporation and Tampa Electric Company and its affiliates accounted for approximately 49%, 25% and 10%, respectively, of Gulfstream’s revenues.

Gulfstream provides firm and interruptible transportation services, interruptible park and loan services, and operational balancing agreements to resolve any differences between scheduled and actual receipts and deliveries. All of Gulfstream’s firm transportation contracts include negotiated rates through the life of the contract. These negotiated rates are currently less than the maximum applicable recourse rate allowed by the FERC.

As of December 31, 2008, Gulfstream’s firm transportation and storage contracts had a weighted average remaining life of 19 years. For the year ended December 31, 2008, 94% of Gulfstream’s revenues were derived from capacity reservation charges under firm contracts, 3% of revenues were derived from variable usage fees under firm contracts and 3% of revenues were derived from interruptible transportation contracts.

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Gulfstream shippers increasingly have the option of buying natural gas supplies from a wide range of producers in the Eastern Gulf of Mexico and from onshore sites along the entire Gulf Coast. Gulfstream is connected to processing plants and supply pipelines in the Mobile Bay area. Currently, shippers have the ability to source supply at eight access points. In addition, anticipated increasing LNG imports along the Gulf Coast should further diversify the gas supplies available to Gulfstream’s customers, potentially offsetting some of the risks associated with offshore Gulf of Mexico natural gas production.

Starting in September 2008, Gulfstream shippers have access to supplies delivered by Spectra Energy’s Southeast Header Supply, LLC (SESH) joint venture. SESH originates in Perryville, LA and interconnects with Gulfstream near Coden, Alabama.

Competition

Within the Florida market for natural gas, Gulfstream competes with other pipelines that transport and supply natural gas to end-users. Gulfstream’s competitors attempt to either attract new supply or attach new load to their pipelines, including those that are currently connected to markets served by Gulfstream. Gulfstream’s most direct competitor is Florida Gas Transmission Company, owned by subsidiaries of El Paso Corporation and Southern Union Company.

An increase in competition in the market could arise from new ventures or expanded operations from existing competitors. Other competitive factors include the quantity, location and physical flow characteristics of interconnected pipelines, access to natural gas storage, the cost of service and rates, and the terms of service offered.

Market Hub

General

We own a 50% interest in Market Hub, which owns and operates two high-deliverability salt cavern natural gas storage facilities — the Egan facility and the Moss Bluff facility. These storage facilities are capable of being fully or partially filled and depleted, or “cycled,” multiple times per year. Market Hub’s storage facilities offer access to traditional Gulf of Mexico natural gas supplies, onshore Texas, and Louisiana supplies and growing imports of LNG to the Gulf Coast, and each facility interconnects with the Texas Eastern Transmission system. Spectra Energy owns the remaining 50% interest in Market Hub and operates the system.

The Egan storage facility, located in Acadia Parish, Louisiana, has a working gas capacity of approximately 22 Bcf, and includes a 38-mile pipeline system that interconnects with seven interstate pipeline systems and one intrastate pipeline system. Egan offers access to Gulf Coast, midwest, southeast and northeast markets.

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The Moss Bluff storage facility, located in Liberty County, Texas, has a working gas capacity of approximately 15 Bcf, and includes a 20-mile pipeline system that interconnects with two interstate pipeline systems and three intrastate pipeline systems. Moss Bluff offers access to Texas, northeast and midwest markets.

Customer, Contracts and Supply

Market Hub provides storage services to a broad mix of customers including marketers, electric power generators, gas producers, pipelines and LDCs. In 2008, Spectra Energy subsidiaries accounted for 10% of Market Hub’s revenues.

Market Hub provides firm storage, park and loan, and wheeling services. Under firm storage contracts, customers pay a reservation rate for the right to inject, withdraw and store a specified volume of natural gas. Under park and loan contracts, customers pay for the interruptible right to park (store) or loan (borrow) gas for a specific period of time. Customers who desire to wheel gas through a Market Hub facility pay for the interruptible right to receive natural gas at one interconnecting pipeline on the storage facility header system and have it simultaneously delivered to a different interconnecting pipeline on the storage facility header system.

As of December 31, 2008, Market Hub’s firm storage contracts had a weighted average remaining life of approximately three years, which is typical of the shorter contract life of market based storage facilities as compared to transportation systems. For the year ended December 31, 2008, approximately 88% of Market Hub’s revenues were derived from capacity reservation fees under firm storage contracts, with the remaining 12% primarily from interruptible storage contracts, including park and loan and wheeling services.

Egan has aggregate receipt capacity from major interconnecting pipelines of approximately 3.5 Bcf/d compared to an injection capability of 1.3 Bcf/d. Moss Bluff has aggregate receipt capacity from major interconnecting pipelines of approximately 1.7 Bcf/d compared to an injection capability of 0.6 Bcf/d. Egan has access to major interstate pipelines, while Moss Bluff has access to major interstate and intrastate pipelines. This level of supply connectivity gives customers access to a broad range of natural gas supply sources from existing onshore and offshore Gulf Coast and Mid-Continent production areas as well as LNG supplies.

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Competition

Market Hub competes with several regional storage facilities along the Gulf Coast as well as the storage services offered by interstate and intrastate pipelines that serve the same markets as Market Hub. The principal elements of competition among storage facilities are rates, terms of service, types of service, deliverability, supply and market access, and flexibility and reliability of service. An increase in competition in the market could arise from new ventures or expanded operations from existing competitors.

Contract Mix Summary

We compete for transportation and storage customers based on the specific type of service a customer needs, operating flexibility, available capacity and price. As noted previously, we provide a significant portion of our transportation and storage services through firm contracts and derive a smaller portion of our revenue through interruptible contracts, seeking to maximize the portion of physical capacity sold under firm contracts. To the extent that physical capacity that is contracted for firm service is not being fully utilized, we can contract such capacity for interruptible service. The table below summarizes certain information regarding our contracts and revenues as of and for the year ended December 31, 2008:

	Revenue Composition %						% of Physical Capacity Subscribed Under Firm Contracts		Weighted Average Remaining Contract Life (in years)(a)
	Firm Contracts				Interruptible Contracts
	Capacity Reservation Fees		Variable Fees
Asset
East Tennessee	99	%	1	%	—	%	96	%	8
Saltville	89		7		4		96		8
Gulfstream	94		3		3		90		19
Market Hub	88		—		12		100		3

(a) The average life of each contract is calculated based on contract revenues.

Supplies and Raw Materials

We purchase a variety of manufactured equipment and materials for use in our operations and expansion projects. The primary equipment and materials utilized in our operations and project execution processes are steel pipe, compression engines, valves, fittings, polyethylene plastic pipe, gas meters and other consumables.

We utilize Spectra Energy’s supply chain management function which operates a North American supply chain management network with employees dedicated to this function in the United States and Canada. The supply chain management group uses the economies-of-scale of Spectra Energy to maximize the efficiency of supply networks where applicable.

The recent sharp declines in both economic activity and basic consumer prices are beginning to impact the costs of certain materials used in our maintenance and expansion projects. Specialty steel prices in particular have declined 10-15% from recent highs, and the effect is being seen in lower prices for steel pipe and related materials. The ultimate impact of lower consumer prices will depend upon the length and depth of the worldwide contraction in economic activity.

There can be no assurance that the ability to obtain sufficient equipment and materials will not be adversely affected by unforeseen developments. In addition, the price of equipment and materials may vary, perhaps substantially, from year to year.

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Regulations

Our interstate gas transmission pipeline and our storage operations are regulated by the FERC with the exception of Moss Bluff. The FERC regulates natural gas transportation in U.S. interstate commerce including the establishment of rates for services. The FERC also regulates the construction of U.S. interstate pipelines and storage facilities including extension, enlargement and abandonment of facilities. In addition, the Moss Bluff intrastate storage operations are subject to oversight by the TRC.

The FERC may propose and implement new rules and regulations affecting interstate natural gas transmission and storage companies, which remain subject to the FERC’s jurisdiction. These initiatives may also affect certain transportation of gas by intrastate pipelines.

Our gas transmission operations are subject to the jurisdiction of the Environmental Protection Agency (EPA) and various other federal, state and local environmental agencies. See “Environmental Matters” for a discussion of environmental regulation. Our interstate natural gas pipelines are also subject to the regulations of the DOT concerning pipeline safety.

Under current policy, the FERC permits pipelines and storage companies to include a tax allowance in the cost-of-service used as the basis for calculating their regulated rates. For pipelines and storage companies owned by partnerships or limited liability company interests, the tax allowance will reflect the actual or potential income tax liability on the FERC jurisdictional income attributable to all partnership or limited liability company interests, if the ultimate owner of the interest has an actual or potential income tax liability on such income. This policy was recently upheld by the Court of Appeals for the District of Columbia Circuit. Whether the owners of a pipeline or storage company have such actual or potential income tax liability will be reviewed by the FERC on a case-by-case basis. In a future rate case, the pipelines and storage companies in which we own an interest may be required to demonstrate the extent to which inclusion of an income tax allowance in the applicable cost-of-service is permitted under the current income tax allowance policy. Egan and Moss Bluff have authority to charge market-based rates and therefore this tax allowance issue does not affect the rates that they charge their customers.

Environmental Matters

We are subject to federal, state and local laws and regulations with regard to air and water quality, hazardous and solid waste disposal and other environmental matters. These regulations often impose substantial testing and certification requirements.

Environmental laws and regulations affecting us include, but are not limited to:

• The Clean Air Act (CAA) and the 1990 amendments to the CAA, as well as state laws and regulations affecting air emissions (including State Implementation Plans related to existing and new national ambient air quality standards), which may limit new sources of air emissions. Our natural gas transmission and storage assets are considered sources of air emissions and are thereby subject to the CAA. Owners and/or operators of air emission sources, such as us, are responsible for obtaining permits for existing and new sources of air emissions and for annual compliance and reporting.

• The Federal Water Pollution Control Act, which requires permits for facilities that discharge wastewaters into the environment. The Oil Pollution Act (OPA), was enacted in 1990 and amends parts of the Clean Water Act and other statutes as they pertain to the prevention of and response to oil spills. OPA imposes certain spill prevention, control and countermeasure requirements. Although we are primarily a natural gas business, OPA affects our business primarily because of the presence of liquid hydrocarbons (condensate) in our offshore pipeline.

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• The Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act, which requires certain solid wastes, including hazardous wastes, to be managed pursuant to a comprehensive regulatory regime. As part of our business, we generate solid waste within the scope of these regulations and therefore must comply with such regulations.

• The National Environmental Policy Act, which requires federal agencies to consider potential environmental effects in their decisions, including site approvals. Many of our capital projects require federal agency review, and therefore the environmental effect of proposed projects is a factor in determining whether we will be permitted to complete proposed projects.

For more information on environmental matters involving us, including possible liability and capital costs, see Item 8. Financial Statements and Supplementary Data, Note 14 of Notes to Consolidated Financial Statements.

Except to the extent discussed in Note 14, compliance with federal, state and local provisions regulating the discharge of materials into the environment, or otherwise protecting the environment, is incorporated into the routine cost structure of our partnership and is not expected to have a material adverse effect on our competitive position, consolidated results of operations, financial position or cash flows.

Employees

We do not have any employees. We are managed by the directors and officers of our general partner. Our general partner or its affiliates currently employ 77 people who spend a majority of their time operating the East Tennessee and Saltville facilities, and 5 people who are primarily dedicated to us. Market Hub is operated by Spectra Energy pursuant to an operating and maintenance agreement and the employees who operate the Market Hub assets are therefore not included in the above numbers. Gulfstream is operated by Spectra Energy (with respect to business functions) and Williams (with respect to technical functions) pursuant to an operating and maintenance agreement, and therefore, the employees who operate the Gulfstream assets are not included in the above numbers.

Executive Officers

The following table sets forth information regarding our executive officers.

Name	Age	Position
Gregory J. Rizzo	52	President and Chief Executive Officer and Director
Laura Buss Sayavedra	41	Vice President and Chief Financial Officer

Gregory J. Rizzo was elected to the Board of Directors of Spectra Energy Partners GP, LLC in May 2007. He was named to his current position in December 2008. He also serves as Group Vice President of U.S. Regulatory Affairs for Spectra Energy Corp, which was spun off from Duke Energy Corporation in January 2007. Mr. Rizzo previously served as Group Vice President for Duke Energy Gas Transmission — Northeast Pipelines from March 2004 until assuming his position in January 2007. Prior to then, Mr. Rizzo served as Executive Vice President of Duke Energy Gas Transmission from February 2003 until March 2004 and Senior Vice President Marketing and Capacity Management from March 2002 until February 2003.

Laura Buss Sayavedra was named to her current position in May 2008. Prior to that, she was Vice President, Strategic Development and Analysis for Spectra Energy Corp, which was spun off from Duke Energy Corporation. She previously served at Duke Energy Gas Transmission as General Manager, Strategic Planning and Development from July 2005 to December 2006. Prior to then, she served as Vice President, Operations and Analytics of Duke Energy North America from May 2004 to June 2005 and Senior Director of Energy Marketing from January 2003 to April 2004.

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Glossary

Terms used to describe our business are defined below.

Allowance for Funds Used During Construction (AFUDC). An accounting convention of regulators that represents the estimated composite interest costs of debt and a return on equity funds used to finance construction. The allowance is capitalized in the property accounts and included in income.

Available Cash: For any quarter ending prior to liquidation:

(a) the sum of:

(1) all cash and cash equivalents of the partnership and our subsidiaries on hand at the end of that quarter; and

(2) if our general partner so determines all or a portion of any additional cash or cash equivalents of our partnership and our subsidiaries on hand on the date of determination of Available Cash for that quarter;

(b) less the amount of cash reserves established by our general partner to:

(1) provide for the proper conduct of the business of the partnership and our subsidiaries (including reserves for future capital expenditures and for future credit needs of the partnership and our subsidiaries) after that quarter;

(2) comply with applicable law or any debt instrument or other agreement or obligation to which we or any of our subsidiaries are a part or our assets are subject; and

(3) provide funds for minimum quarterly distributions and cumulative common unit arrearages for any one or more of the next four quarters;

provided, however, that our general partner may not establish cash reserves pursuant to clause (b)(3) immediately above unless our general partner has determined that the establishment of reserves will not prevent us from distributing the minimum quarterly distribution on all common units and any cumulative common unit arrearages thereon for that quarter; and provided, further, that disbursements made by us or any of our subsidiaries or cash reserves established, increased or reduced after the end of that quarter but on or before the date of determination of Available Cash for that quarter shall be deemed to have been made, established, increased or reduced, for purposes of determining Available Cash, within that quarter if our general partner so determines.

British Thermal Unit (Btu). A standard unit for measuring thermal energy or heat commonly used as a gauge for the energy content of natural gas and other fuels.

Cubic Foot (cf). The most common unit of measurement of gas volume; the amount of natural gas required to fill a volume of one cubic foot under stated conditions of temperature, pressure and water vapor.

Cumulative Common Unit Arrearage. The amount by which the minimum quarterly distribution for a quarter during the subordination period exceeds the distribution of Available Cash from operating surplus actually made for that quarter on a common unit, cumulative for that quarter and all prior quarters during the subordination period.

Derivative. A financial instrument or contract in which the price is based on the value of underlying securities, equity indices, debt instruments, commodities or other benchmarks or variables. Often used to hedge risk, derivatives involve the exchange of rights or obligations, but not the direct transfer of property.

Environmental Protection Agency (EPA). The U.S. agency that is responsible for researching and setting national standards for a variety of environmental programs, and delegates to states the responsibility for issuing permits and for monitoring and enforcing compliance.

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Federal Energy Regulatory Commission (FERC). The U.S. agency that regulates the transportation of natural gas in interstate commerce.

Liquefied Natural Gas (LNG). Natural gas that has been converted to a liquid by cooling it to minus 260 degrees Fahrenheit.

Local Distribution Company (LDC). A company that obtains the major portion of its revenues from the operations of a retail distribution system for the delivery of gas for ultimate consumption.

Operating Expenditures. All of our expenditures and expenditures of our subsidiaries, including, but not limited to, taxes, payments to the general partner for reimbursements of expenses incurred by the general partner on our behalf, non-pro rata purchases of units, interest payments, payments made in the ordinary course of business under interest rate swap agreements and commodity hedge contracts and maintenance capital expenditures, subject to the following:

(a) Payments (including prepayments) of principal of and premium on indebtedness do not constitute operating expenditures.

(b) Operating expenditures do not include:

(1) expansion capital expenditures;

(2) payment of transaction expenses (including taxes) relating to interim capital transactions;

(3) distributions to unitholders; and

(4) non-pro rata purchases of units of any class made with the proceeds of an interim capital transaction.

Where capital expenditures consist of both maintenance capital expenditures and expansion capital expenditures, the general partner, with the concurrence of the Board of Directors of the general partner’s conflicts committee (the Conflicts Committee), shall determine the allocation between the amounts paid for each.

Operating Surplus. For any period prior to liquidation, on a cumulative basis and without duplication:

(a) the sum of:

(1) all cash receipts of our partnership and our subsidiaries for the period beginning on the closing date of our initial public offering and ending with the last day of the period, other than cash receipts from interim capital transactions; and

(2) an amount equal to the sum of (A) two times the amount needed for any one quarter for us to pay the minimum quarterly distribution on all units (including the general partner units) and (B) two times the amount in excess of the minimum quarterly distribution for any quarter to pay a distribution on all Common Units at the same per unit amount as was distributed on the Common Units in excess of the minimum quarterly distribution in the immediately preceding quarter, provided the amount in (B) will be deemed to be Operating Surplus only to the extent that the distribution paid in respect of such amounts is paid on Common Units, less

(b) the sum of:

(1) operating expenditures for the period beginning on the closing date of our initial public offering and ending with the last day of that period; and

(2) the amount of cash reserves (or our proportionate share of cash reserves in the case of subsidiaries that are not wholly owned) established by our general partner to provide funds for future operating expenditures; provided however, that disbursements made (including contributions to us or our subsidiaries or disbursements on behalf of us or our subsidiaries) or cash reserves established, increased or reduced after the end of that period but on or before the date of determination of Available Cash for that period shall be deemed to have been made, established, increased or reduced for purposes of determining operating surplus, within that period if our general partner so determines.

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Organic Growth. Growth due to the expansion or optimization of existing assets.

Subordination Period. The subordination period began with the closing of the initial public offering on July 2, 2007, and will last until the first to occur of the following dates:

(a) The first day of any quarter beginning after June 30, 2010 in respect of which each of the following tests are met:

(1) distribution of Available Cash from operating surplus on each of the outstanding common units and subordinated units equaled or exceeded the sum of the minimum quarterly distributions on all of the outstanding common units and subordinated units for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;

(2) the adjusted operating surplus generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of the minimum quarterly distributions on all of the outstanding common units, subordinated units and general partner units during those periods on a fully diluted basis; and

(3) there are no outstanding cumulative common units arrearages.

(b) The first date after we have earned and paid at least $0.45 per quarter (150% of the minimum quarterly distribution of $0.30 per quarter, which is $1.80 on an annualized basis) on each outstanding limited partner unit and general partner unit for any four consecutive quarters ending on or after June 30, 2008; and

(c) The date on which the general partner is removed as our general partner upon the requisite vote by the limited partners under circumstances where cause does not exist and units held by our general partner and its affiliates are not voted in favor of the removal.

When the subordination period ends, all remaining subordinated units will convert into common units on a one-for-one basis, and the common units will no longer be entitled to arrearages.

Throughput. The amount of natural gas transported through a pipeline system.

Transmission System. An interconnected group of natural gas pipelines and associated facilities for transporting natural gas in bulk between points of supply and delivery points to industrial customers, LDCs, or for delivery to other natural gas transmission systems.

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Additional Information

We were formed on March 19, 2007 as a Delaware master limited partnership. Our principal executive offices are located at 5400 Westheimer Court, Houston, Texas 77056 and our telephone number is 713-627-5400. We electronically file reports with the Securities and Exchange Commission (SEC), including annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to such reports. The public may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains an internet site that contains reports and information statements, and other information regarding issuers that file electronically with the SEC at http://www.sec.gov. Additionally, information about us, including our reports filed with the SEC, is available through our web site at http://www.spectraenergypartners.com. Such reports are accessible at no charge through our web site and are made available as soon as reasonably practicable after such material is filed with or furnished to the SEC. Our website and the information contained on that site, or connected to that site, is not incorporated by reference into this report.

Item 1A. Risk Factors.

Discussed below are the more significant risk factors relating to us.

Risks Related to our Business

We may not have sufficient cash from operations to enable us to make cash distributions to holders of common and subordinated units.

In order to make cash distributions at our minimum distribution rate of $0.30 per common unit per complete quarter, or $1.20 per unit per year, we will require Available Cash of approximately $21.1 million per quarter, or $84.6 million per year, depending on the actual number of common units and subordinated units outstanding. We may not have sufficient Available Cash from operating surplus each quarter to enable us to make cash distributions at the minimum distribution rate. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from operations, which will fluctuate based on, among other things:

• the rates charged for transportation and storage services, and the volumes of natural gas contracted by customers for transportation and storage services;

• the overall demand for natural gas in the southeastern and mid-Atlantic regions of the United States and the quantities of natural gas available for transport, especially from the Gulf of Mexico, Appalachian and mid-Continent areas;

• regulatory action affecting the demand for natural gas, the supply of natural gas, the rates we can charge, contracts for services, existing contracts, operating costs and operating flexibility;

• regulatory and economic limitations on the development of LNG import terminals in the Gulf Coast region;

• successful development of LNG import terminals in the eastern or northeastern United States, which could provide customers with more basin choices when purchasing natural gas and provide producers with additional choices of where to drill. These changes could reduce the need for natural gas to be transported on the East Tennessee pipeline system and for the development of additional natural gas storage capacity in the Gulf Coast region; and

• the level of operating and maintenance, and general and administrative costs.

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In addition, the actual amount of cash available for distribution will depend on other factors, some of which are beyond our control, including:

• the level of capital expenditures to complete construction projects;

• the cost and form of payment of acquisitions;

• debt service requirements and other liabilities;

• fluctuations in working capital needs;

• the ability to borrow funds and access capital markets;

• restrictions on distributions contained in debt agreements; and

• the amount of cash reserves established by our general partner.

Gulfstream and Market Hub are controlled by Spectra Energy and other third parties who are responsible for the management and operations of those assets. As a result, we cannot control the amount of cash that will be received from Gulfstream and Market Hub, and we may be required to contribute significant cash to fund their operations.

Market Hub and Gulfstream are expected to generate approximately one-half of the cash we distribute. Spectra Energy operates Market Hub and the operation of Gulfstream is shared between Spectra Energy and Williams. Accordingly, we do not control the amount of cash distributed to us nor do we control ongoing operational decisions, including the incurrence of capital expenditures that we may be required to fund.

Our lack of control over the operations of Gulfstream and Market Hub may mean that we do not receive the amount of cash we expect to be distributed to us. In addition, we may be required to provide additional capital, and these contributions may be material. Neither Gulfstream nor Market Hub is prohibited from incurring indebtedness by the terms of their respective limited liability company agreement and general partnership agreement. If Gulfstream or Market Hub were to incur significant additional indebtedness, it could inhibit their respective abilities to make distributions to us. This lack of control may significantly and adversely affect our ability to distribute cash.

Natural gas transportation and storage operations are subject to regulation by the FERC, which could have an adverse effect on our ability to establish transportation and storage rates that would allow us to recover the full cost of operating our pipelines, including a reasonable return, and our ability to make distributions.

Our interstate natural gas transportation and storage operations are subject to federal, state and local regulatory authorities. Specifically, our natural gas pipeline systems and certain of our storage facilities and related assets are subject to regulation by the FERC. Its authority to regulate natural gas pipeline transportation services includes the rates charged for the services, terms and conditions of service, certification and construction of new facilities, the extension or abandonment of services and facilities, the maintenance of accounts and records, the acquisition and disposition of facilities, the initiation and discontinuation of services, and various other matters.

In addition, we cannot give any assurance regarding the likely future regulations under which we will operate our natural gas transportation and storage businesses or the effect such regulation could have on our business, financial condition, results of operations and our ability to make distributions.

Certain transportation services are subject to long-term, fixed-price “negotiated rate” contracts that are not subject to adjustment, even if our cost to perform services exceeds the revenues received from such contracts, and, as a result, our costs could exceed our revenues received under such contracts.

Under the FERC policy, a regulated service provider and a customer may mutually agree to sign a contract for service at a “negotiated rate” which may be above or below the FERC regulated “recourse rate” for that

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service. For 2008, all of Gulfstream’s firm revenues were derived from such negotiated rate contracts, approximately 46% of Gas Transportation and Storage’s firm revenues were derived from capacity reservation charges under negotiated rate contracts. These negotiated rate contracts are not subject to adjustment for increased costs which could be produced by inflation or other factors relating to the specific facilities being used to perform the services. It is possible that Gulfstream’s, East Tennessee’s and Saltville’s costs to perform services under these negotiated rate contracts will exceed the negotiated rates. If this occurs, it could decrease cash flows from Gulfstream, East Tennessee and Saltville.

Market Hub’s right to charge “market-based rates” at one of its facilities is subject to the continued existence of certain conditions related to the competitive position of Market Hub and, if those conditions change, the right to charge “market-based rates” could be terminated.

Certain of the rates charged by Market Hub are regulated by the FERC pursuant to its “market-based rate” policy, which allows regulated storage companies to charge rates above those which would be permitted under traditional cost-of-service regulation. The right of Market Hub to charge market-based rates is based upon determinations by the FERC that it does not have market power in the relevant market areas it serves. This determination of a lack of market power is subject to review and revision by the FERC if circumstances change. In the event of an adverse determination concerning market power with respect to Market Hub, its rates could become subject to cost-of-service regulation which could have adverse consequences for the cash flow of Market Hub.

Increased competition from alternative natural gas transportation and storage options and alternative fuel sources could have a significant financial effect on us.

We compete primarily with other interstate and intrastate pipelines and storage facilities in the transportation and storage of natural gas. Some of our competitors have greater financial resources and access to greater supplies of natural gas than we do. Some of these competitors may expand or construct transportation and storage systems that would create additional competition for the services we provide to our customers. Moreover, Spectra Energy and its affiliates are not limited in their ability to compete with us. Further, natural gas also competes with other forms of energy available to our customers, including electricity, coal and fuel oils.

The principal elements of competition among natural gas transportation and storage assets are rates, terms of service, access to natural gas supplies, flexibility and reliability. The FERC’s policies promoting competition in natural gas markets are having the effect of increasing the natural gas transportation and storage options for our traditional customer base. As a result, we could experience some “turnback” of firm capacity as existing agreements expire. If East Tennessee, Saltville, Gulfstream or Market Hub are unable to remarket this capacity or can remarket it only at substantially discounted rates compared to previous contracts, they may have to bear the costs associated with the turned back capacity. Increased competition could reduce the volumes of natural gas transported or stored by our systems or, in cases where we do not have long-term fixed rate contracts, could force us to lower our transportation or storage rates. Competition could intensify the negative effect of factors that significantly decrease demand for natural gas in the markets served by our pipeline systems, such as competing or alternative forms of energy, a recession or other adverse economic conditions, weather, higher fuel costs and taxes or other governmental or regulatory actions that directly or indirectly increase the cost or limit the use of natural gas. Our ability to renew or replace existing contracts at rates sufficient to maintain current revenues and cash flows could be adversely affected by the activities of our competitors. All of these competitive pressures could have a material adverse effect on our business, financial condition, results of operations, and ability to make distributions.

Any significant decrease in supplies of natural gas in our areas of operation could adversely affect business and operating results, and reduce cash available for distribution.

All of our businesses are dependent on the continued availability of natural gas production and reserves. Low prices for natural gas or regulatory limitations could adversely affect development of additional reserves and production that is accessible by our pipeline and storage assets. Production from existing wells and natural

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gas supply basins with access to our pipelines will naturally decline over time. Additionally, the amount of natural gas reserves underlying these wells may also be less than anticipated, and the rate at which production from these reserves declines may be greater than anticipated. Accordingly, to maintain or increase throughput on our pipelines and cash flows associated with the transportation of gas, our customers must continually obtain new supplies of natural gas.

If new supplies of natural gas are not obtained to replace the natural decline in volumes from existing supply basins, the overall volume of natural gas transported and stored on our systems would decline, which could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions.

We may not be able to maintain or replace expiring natural gas transportation and storage contracts at favorable rates.

Our primary exposure to market risk occurs at the time existing transportation and storage contracts expire and are subject to renegotiation and renewal. A portion of the revenue generated by our systems in 2008 is attributable to firm capacity reservation fees that are set to expire on or prior to December 31, 2011. For Gas Transportation and Storage, Gulfstream, and Market Hub, those portions were 34%, 0% and 51%, respectively. Upon expiration, we may not be able to extend contracts with existing customers or obtain replacement contracts at favorable rates or on a long-term basis.

The extension or replacement of existing contracts depends on a number of factors beyond our control, including:

• the level of existing and new competition to deliver natural gas to our markets;

• the growth in demand for natural gas in our markets;

• whether the market will continue to support long-term contracts;

• whether our business strategy continues to be successful; and

• the effects of state regulation on customer contracting practices.

Our key markets 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 of approximately 1.5% according to ICF International. This demand growth is primarily driven by the natural gas-fired electric generation sector.

Any failure to extend or replace a significant portion of our existing contracts may have a material adverse effect on our business, financial condition, results of operations and ability to make distributions.

We depend on certain key customers for a significant portion of our revenues. The loss of any of these key customers could result in a decline in our revenues and cash available to make distributions.

We rely on a limited number of customers for a significant portion of revenues. For the year ended December 31, 2008, the three largest customers for Gas Transportation and Storage were Atmos Energy Corporation, CNX Gas Company LLC and KGen Murray I and II LLC; for Gulfstream were Florida Power & Light Company, Florida Power Corporation (d/b/a Progress Energy Florida, Inc.) and Tampa Electric Company and its affiliates; and for Market Hub were Texas Eastern Transmission, NiSource and AGL Resources. In 2008, these customers accounted for approximately 31%, 84% and 28% of the operating revenues for Gas Transportation and Storage, Gulfstream and Market Hub, respectively. While most of these customers are subject to long-term contracts, the loss of all or even a portion of the contracted volumes of these customers as a result of competition, creditworthiness, inability to negotiate extensions or replacements of contracts or otherwise, could have a material adverse effect on our financial condition, results of operations and ability to make distributions, unless we are able to contract for comparable volumes from other customers at favorable rates.

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If third-party pipelines and other facilities interconnected to our pipelines become unavailable to transport natural gas, our revenues and cash available to make distributions could be adversely affected.

We depend upon third-party pipelines and other facilities that provide delivery options to and from our pipelines and storage facilities. Because we do not own these third-party pipelines or facilities, their continuing operation is not within our control. If these or any other pipeline connection were to become unavailable for current or future volumes of natural gas due to repairs, damage to the facility, lack of capacity or any other reason, our ability to operate efficiently and continue shipping natural gas to end-markets could be restricted, thereby reducing revenues. Any temporary or permanent interruption at any key pipeline interconnect could have a material adverse effect on our business, results of operations, financial condition and ability to make distributions.

If we do not complete expansion projects or make and integrate acquisitions, our future growth may be limited.

A principal focus of our strategy is to continue to grow the cash distributions on our units by expanding our business. Our ability to grow depends on our ability to complete expansion projects and make acquisitions that result in an increase in cash generated. We may be unable to complete successful, accretive expansion projects or acquisitions for any of the following reasons:

• an inability to identify attractive expansion projects or acquisition candidates or we are outbid by competitors;

• an inability to obtain necessary rights of way or government approvals, including regulatory agencies;

• an inability to integrate successfully the businesses we build or acquire;

• we are unable to raise financing for such expansion projects or acquisitions on economically acceptable terms;

• incorrect assumptions about volumes, reserves, revenues and costs, including synergies and potential growth; or

• we are unable to secure adequate customer commitments to use the newly expanded or acquired facilities.

Acquisitions or expansion projects that appear to be accretive may nevertheless reduce our cash from operations on a per unit basis.

Even if we make acquisitions or complete expansion projects that we believe will be accretive, these acquisitions or expansion projects may nevertheless reduce our cash from operations on a per unit basis. Any acquisition or expansion project involves potential risks, including, among other things:

• a decrease in our liquidity as a result of our using a significant portion of our Available Cash or borrowing capacity to finance the project or acquisition;

• an inability to complete expansion projects on schedule or within the budgeted cost due to the unavailability of required construction personnel, equipment or materials, and the risk of cost overruns resulting from inflation or increased costs of materials, labor and equipment;

• an inability to complete expansion projects on schedule due to accidents, weather conditions or an inability to obtain necessary permits;

• an inability to receive cash flows from a newly built or acquired asset until it is operational;

• unforeseen difficulties operating in new product areas or new geographic areas; and

• customer losses at the acquired business.

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Any of these risks could prevent a project from proceeding, delay its completion or increase our anticipated costs. As a result, our new facilities may not achieve expected investment returns, which could adversely affect our results of operations, financial position or cash flows. If any expansion projects or acquisitions that we ultimately complete are not accretive to cash available for distribution, our ability to make distributions may be reduced.

The amount of our cash available for distribution depends primarily on our cash flow and not solely on profitability, which may prevent us from making cash distributions during periods when we record net income.

Our amount of cash available for distribution depends primarily upon our cash flow, including cash flow from financial reserves and working capital or other borrowings, and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record a net loss for financial accounting purposes and may not make cash distributions during periods when we record net earnings for financial accounting purposes.

Significant prolonged changes in natural gas prices could affect supply and demand, reducing contracted volumes on our systems and adversely affecting revenues and cash available to make distributions over the long-term.

Higher natural gas prices over the long term could result in a decline in the demand for natural gas and, therefore, in the throughput on our systems. Also, lower natural gas prices over the long term could result in a decline in the production of natural gas resulting in reduced contracted volumes on our systems. In addition, prolonged reduced price volatility could reduce the revenues generated by our parking-and-lending and interruptible storage services. As a result, significant prolonged changes in natural gas prices could have a material adverse effect on our financial condition, results of operations and ability to make distributions.

Our operations are subject to environmental laws and regulations that may expose us to significant costs and liabilities.

Our natural gas transportation and storage activities are subject to stringent and complex federal, state and local environmental laws and regulations. We may incur substantial costs in order to conduct our operations in compliance with these laws and regulations. Moreover, new, stricter environmental laws, regulations or enforcement policies could be implemented that significantly increase our compliance costs or the cost of any remediation of environmental contamination that may become necessary, and these costs could be material.

Failure to comply with environmental laws and regulations, or the permits issued under them, may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations and the issuance of injunctions limiting or preventing some or all of our operations. In addition, strict joint and several liability may be imposed under certain environmental laws, which could cause us to become liable for the conduct of others or for consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. Private parties may also have the right to pursue legal actions against us to enforce compliance, as well as to seek damages for non-compliance, with environmental laws and regulations or for personal injury or property damage that may result from environmental and other effects of operations. We may not be able to recover some or any of these costs through insurance or increased revenues, which may have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions.

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We may incur significant costs and liabilities as a result of pipeline integrity management program testing and any necessary pipeline repair or preventative or remedial measures.

The DOT has adopted regulations requiring pipeline operators to develop integrity management programs for transportation pipelines located where a leak or rupture could do the most harm in “high consequence areas.” The regulations require operators to:

• perform ongoing assessments of pipeline integrity;

• identify and characterize applicable threats to pipeline segments that could affect a high consequence area;

• improve data collection, integration and analysis;

• repair and remediate the pipeline as necessary; and

• implement preventive and mitigating actions.

Our actual implementation costs may be affected by industry-wide demand for the associated contractors and service providers. Additionally, should we fail to comply with DOT regulations, we could be subject to penalties and fines.

We do not own all of the land on which our pipelines and facilities are located, which could disrupt our operations.

We do not own all of the land on which our pipelines and facilities have been constructed, and we are therefore subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid rights-of-way or if such rights-of-way lapse or terminate. We obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, results of operations and financial condition and our ability to make cash distributions.

Our operations are subject to operational hazards and unforeseen interruptions.

Our operations are subject to many hazards inherent in the transportation and storage of natural gas, including:

• damage to pipelines, facilities and related equipment caused by hurricanes, tornadoes, floods, fires and other natural disasters, explosions and acts of terrorism;

• inadvertent damage from third parties, including from construction, farm and utility equipment;

• leaks of natural gas and other hydrocarbons or losses of natural gas as a result of the malfunction of equipment or facilities;

• collapse of storage caverns;

• operator error;

• environmental pollution;

• explosions and blowouts;

• risks related to underwater pipelines in the Gulf of Mexico, which are susceptible to damage from shifting as a result of water currents (as seen in the Gulf of Mexico following Hurricanes Katrina, Rita, Gustav and Ike), as well as damage from vessels;

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• risks related to pipeline that traverses areas in Florida where karst conditions exist. Karst conditions refers to terrain, usually found where limestone or other carbonate rock is present, that may subside or result in a sinkhole collapse when the underlying water table changes; and

• risks related to operating in a marine environment.

These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment, and pollution or other environmental damage which may result in curtailment or suspension of our related operations. A natural disaster or other hazard affecting the areas in which we operate could have a material adverse effect on our operations.

We do not insure against all potential losses and could be seriously harmed by unexpected liabilities.

We are not fully insured against all risks inherent to our business. We are not insured against all environmental accidents that might occur. If a significant accident or event occurs that is not fully insured, it could adversely affect our operations and financial condition. In addition, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. Changes in the insurance markets subsequent to the September 11, 2001 terrorist attacks, and Hurricanes Katrina, Rita, Gustav and Ike have made it more difficult for us to obtain certain types of coverage, and we may elect to self insure a portion of our asset portfolio. In addition, we do not maintain offshore business interruption insurance. There can be no assurance that we will be able to obtain the levels or types of insurance we would otherwise have obtained prior to these market changes or that the insurance coverage we do obtain will not contain large deductibles or fail to cover certain hazards or cover all potential losses. The occurrence of any operating risks not fully covered by insurance could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions.

Our debt levels may limit our flexibility in obtaining additional financing and in pursuing other business opportunities.

At December 31, 2008, we had $31 million in term debt and $209 million in revolving debt under our $500 million credit facility. We continue to have the ability to incur additional debt, subject to limitations in our credit facility. Our level of debt could have important consequences, including the following:

• our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;

• we will need a substantial portion of our cash flow to make principal and interest payments on our indebtedness, reducing the funds that would otherwise be available for operations, future business opportunities and distributions to unitholders; and

• our debt level could make us more vulnerable than our competitors with less debt to competitive pressures or a downturn in our business or the economy in general.

Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. In addition, our ability to service debt under our revolving credit facility will depend on market interest rates, since we anticipate that the interest rates applicable to our borrowings will fluctuate with movements in interest rate markets. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets, restructuring or refinancing debt, or seeking additional equity capital. We may not be able to affect any of these actions on satisfactory terms, or at all.

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Restrictions in our credit facility may limit our ability to make distributions and may limit our ability to capitalize on acquisition and other business opportunities.

We are a holding company with no business operations. As such, we depend upon the earnings and cash flow of our subsidiaries and equity investments and the distribution of that cash to us in order to meet our obligations and to allow us to make distributions to our unitholders. Any interruption of distributions to us from our subsidiaries and equity investments may limit our ability to satisfy our obligations and to make distributions. The operating and financial restrictions and covenants in our credit facility and any future financing agreements could restrict our ability to finance future operations or capital needs or to expand or pursue business activities associated with our subsidiaries and equity investments. Our credit facility contains covenants, some of which may be modified or eliminated upon our receipt of an investment grade rating, that restrict or limit our ability to:

• make distributions if any default or event of default, as defined, occurs;

• make other restricted distributions or dividends on account of the purchase, redemption, retirement, acquisition, cancellation or termination of partnership interests;

• incur additional indebtedness or guarantee other indebtedness;

• grant liens or make certain negative pledges;

• make certain loans or investments;

• engage in transactions with affiliates;

• make any material change to the nature of our business from the midstream energy business;

• make a disposition of assets; or

• enter into a merger, consolidate, liquidate, wind up or dissolve.

The credit facility contains covenants requiring us to maintain certain financial ratios and tests. The ability to comply with the covenants and restrictions contained in the credit facility may be affected by events beyond our control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. If we violate any of the restrictions, covenants, ratios or tests in our credit facility, the lenders will be able to accelerate the maturity of all borrowings under the credit facility and demand repayment of amounts outstanding, the lenders’ commitment to make further loans to us may terminate, and the operating partnership will be prohibited from making any distributions. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. Any subsequent replacement of our credit facility or any new indebtedness could have similar or greater restrictions.

The credit and risk profile of our general partner and its owner, Spectra Energy, could adversely affect our credit ratings and risk profile, which could increase our borrowing costs or hinder our ability to raise capital.

The credit and business risk profiles of our general partner and Spectra Energy may be factors considered in credit evaluations of us. This is because our general partner controls our business activities, including our cash distribution policy, acquisition strategy and business risk profile. Another factor that may be considered is the financial condition of Spectra Energy, including the degree of its financial leverage and its dependence on cash flow from the partnership to service its indebtedness.

If we were to have a credit rating in the future, our credit rating may be adversely affected by the leverage of our general partner or Spectra Energy, as credit rating agencies may consider the leverage and credit profile of Spectra Energy and its affiliates because of their ownership interest in and control of us and the strong operational links between Spectra Energy and us. Any adverse effect on our credit rating would increase our cost of borrowing or hinder our ability to raise financing in the capital markets, which would impair our ability to grow our business and make distributions.

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Terrorist attacks, and the threat of terrorist attacks, have resulted in increased costs to our business. Continued hostilities in the Middle East or other sustained military campaigns may adversely affect our results of operations.

The long-term effect of terrorist attacks and the threat of future terrorist attacks on our industry in general, and on us in particular, is not known at this time. However, the U.S. government has issued warnings that energy assets, including the U.S. pipeline infrastructure, may be the future target of terrorist organizations. Increased security measures taken by us as a precaution against possible terrorist attacks have resulted in increased costs. Uncertainty surrounding continued hostilities in the Middle East or other sustained military campaigns may affect our operations in unpredictable ways, including the possibility that infrastructure facilities could be direct targets of, or indirect casualties of, an act of terror. Any terrorist attack on our facilities or pipelines or those of our customers could have a material adverse effect on our business.

Changes in the insurance markets attributable to terrorist attacks may make certain types of insurance more difficult for us to obtain. Moreover, the insurance that may be available to us may be significantly more expensive than our existing insurance coverage. Instability in the financial markets as a result of terrorism or war could also affect our ability to raise capital.

Risks Inherent in an Investment in Us

Spectra Energy controls our general partner, which has sole responsibility for conducting our business and managing our operations. Our general partner and its affiliates, including Spectra Energy, have conflicts of interest with us and limited fiduciary duties, and may favor their own interests to the detriment of us.

Spectra Energy owns and controls our general partner. Some of our general partner’s directors, and some of its executive officers, are directors or officers of Spectra Energy or its affiliates. Although our general partner has a fiduciary duty to manage us in a manner beneficial to Spectra Energy and our unitholders, the directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to Spectra Energy. Therefore, conflicts of interest may arise between Spectra Energy and its affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. These conflicts include, among others, the following situations:

• neither our partnership agreement nor any other agreement requires Spectra Energy to pursue a business strategy that favors us. Spectra Energy’s directors and officers have a fiduciary duty to make these decisions in the best interests of the owners of Spectra Energy, which may be contrary to our interests;

• our general partner is allowed to take into account the interests of parties other than us, such as Spectra Energy and its affiliates, in resolving conflicts of interest;

• Spectra Energy and its affiliates are not limited in their ability to compete with us;

• our general partner may make a determination to receive a quantity of our Class B units in exchange for resetting the target distribution levels related to its incentive distribution rights without the approval of the Conflicts Committee of our general partner or our unitholders;

• some officers of Spectra Energy who provide services to us also will devote significant time to the business of Spectra Energy, and will be compensated by Spectra Energy for the services rendered to it;

• our general partner has limited its liability and reduced its fiduciary duties, and has also restricted the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty. By purchasing common units, unitholders will be deemed to have consented to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable law;

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• our general partner determines the amount and timing of asset purchases and sales, borrowings, issuances of additional partnership securities and reserves, each of which can affect the amount of cash that is distributed to unitholders;

• our general partner determines the amount and timing of any capital expenditures and, based on the applicable facts and circumstances, whether a capital expenditure is classified as a maintenance capital expenditure (which reduces operating surplus) or an expansion capital expenditure (which does not reduce operating surplus). This determination can affect the amount of cash that is distributed to our unitholders and the ability of the subordinated units to convert to common units;

• our general partner determines which costs incurred by it and its affiliates are reimbursable by us;

• in some instances, our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination period;

• our partnership agreement does not restrict our general partner from causing us to pay it or our affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;

• our general partner intends to limit its liability regarding our contractual and other obligations and, in some circumstances, is entitled to be indemnified by us;

• our general partner may exercise its limited right to call and purchase common units if it and its affiliates own more than 80% of the common units;

• our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates; and

• our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

Affiliates of our general partner, including Spectra Energy, DCP Midstream, LLC and DCP Midstream Partners, LP, are not limited in their ability to compete with us, which could limit commercial activities or our ability to acquire additional assets or businesses.

Neither our partnership agreement nor the omnibus agreement among us, Spectra Energy and others prohibits affiliates of our general partner, including Spectra Energy, DCP Midstream, LLC and DCP Midstream Partners, LP, from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, Spectra Energy and its affiliates may acquire, construct or dispose of additional transportation and storage or other assets in the future, without any obligation to offer us the opportunity to purchase or construct any of those assets. Each of these entities is a large, established participant in the midstream energy business, and each has significantly greater resources and experience than we have, which factors may make it more difficult for us to compete with these entities with respect to commercial activities as well as for acquisition candidates. As a result, competition from these entities could adversely affect our results of operations and cash available for distribution.

If a unitholder is not an Eligible Holder, such unitholder will not be entitled to receive distributions or allocations of income or loss on common units and those common units will be subject to redemption at a price that may be below the current market price.

In order to comply with certain FERC rate-making policies applicable to entities that pass through taxable income to their owners, we have adopted certain requirements regarding those investors who may own our common and subordinated units. Eligible Holders are individuals or entities subject to United States federal income taxation on the income generated by us or entities not subject to United States federal income taxation on the income generated by us, so long as all of the entity’s owners are subject to such taxation. If a unitholder is not

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a person who fits the requirements to be an Eligible Holder, such unitholder will not receive distributions or allocations of income and loss on the unitholder’s units and the unitholder runs the risk of having the units redeemed by us at the lower of the unitholder’s purchase price cost or the then-current market price. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner.

Cost reimbursements to our general partner and its affiliates for services provided, which will be determined by our general partner, will be substantial and will reduce our cash available for distribution.

Pursuant to an omnibus agreement we entered into with Spectra Energy, our general partner and certain of their affiliates, Spectra Energy will receive reimbursement for the payment of operating expenses related to our operations and for the provision of various general and administrative services for our benefit, including costs for rendering administrative staff and support services, and overhead allocated to us, which amounts will be determined by our general partner in its sole discretion. Payments for these services will be substantial and will reduce the amount of cash available for distribution. In addition, under Delaware partnership law, our general partner has unlimited liability for our obligations, such as our debts and environmental liabilities, except for contractual obligations that are expressly made without recourse to our general partner. To the extent our general partner incurs obligations on our behalf, we are obligated to reimburse or indemnify it. If we are unable or unwilling to reimburse or indemnify our general partner, our general partner may take actions to cause us to make payments of these obligations and liabilities. Any such payments could reduce the amount of our cash otherwise available for distribution.

Our partnership agreement limits our general partner’s fiduciary duties to holders of our common and subordinated units, and restricts the remedies available to holders of our common and subordinated units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions that reduce the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty laws. For example, our partnership agreement:

• permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting us, our affiliates or any limited partner;

• provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith, meaning it believed the decision was in the best interests of our partnership;

• generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the Conflicts Committee of the board of directors of our general partner acting in good faith and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or must be “fair and reasonable” to us, as determined by our general partner in good faith. In determining whether a transaction or resolution is “fair and reasonable,” the general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to unitholders;

• provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or those other persons acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and

• provides that in resolving conflicts of interest, it will be presumed that in making its decision the general partner or its Conflicts Committee acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

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By purchasing a common unit, a common unitholder will agree to become bound by the provisions in the partnership agreement, including the provisions discussed above.

Our general partner may elect to cause us to issue Class B units to the general partner in connection with a resetting of the target distribution levels related to the general partner’s incentive distribution rights without the approval of the Conflicts Committee of the general partner or holders of our common units and subordinated units. This may result in lower distributions to holders of our common units in certain situations.

Our general partner has the right, at a time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (48%) for each of the prior four consecutive fiscal quarters, to reset the initial cash target distribution levels at higher levels based on the distribution at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per common unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as the “reset minimum quarterly distribution”) and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution amount.

In connection with resetting these target distribution levels, our general partner will be entitled to receive a number of Class B units. The Class B units will be entitled to the same cash distributions per unit as our common units and will be convertible into an equal number of common units. The number of Class B units to be issued will be equal to that number of common units whose aggregate quarterly cash distributions equaled the average of the distributions to our general partner on the incentive distribution rights in the prior two quarters. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion; however, it is possible that our general partner could exercise this reset election at a time when it is experiencing, or may be expected to experience, declines in the cash distributions it receives related to its incentive distribution rights and may therefore desire to be issued our Class B units, which are entitled to receive cash distributions from us on the same priority as our common units, rather than retain the right to receive incentive distributions based on the initial target distribution levels. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued new Class B units to our general partner in connection with resetting the target distribution levels related to our general partner incentive distribution rights.

Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors, which could reduce the price at which the common units will trade.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will not elect our general partner or its board of directors, and will have no right to elect our general partner or board of directors on an annual or other continuing basis. The board of directors of our general partner, including the independent directors, will be chosen entirely by its owners and not by the unitholders. Furthermore, if the unitholders were dissatisfied with the performance of the general partner, they will have little ability to remove the general partner. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

Even if holders of our common units are dissatisfied, they cannot initially remove our general partner without its consent.

The unitholders will be unable initially to remove our general partner without its consent because the general partner and its affiliates own sufficient units to be able to prevent its removal. The vote of the holders of at least 66 2/3% of all outstanding units voting together as a single class is required to remove our general partner. Our general partner and our affiliates own 84% of our aggregate outstanding common and subordinated

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units. Also, if our general partner is removed without cause during the subordination period and units held by our general partner and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically convert into common units and any existing arrearages on our common units will be extinguished. A removal of our general partner under these circumstances would adversely affect our common units by prematurely eliminating their distribution and liquidation preference over the subordinated units, which would otherwise have continued until we had met certain distribution and performance tests. Cause is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding the general partner liable for actual fraud or willful or wanton misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business, so the removal of the general partner because of the unitholders’ dissatisfaction with the general partner’s performance in managing us will most likely result in the termination of the subordination period and conversion of all subordinated units to common units.

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.

Our partnership agreement restricts unitholders’ voting rights by providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.

We have a holding company structure in which our subsidiaries conduct operations and own our operating assets, which may affect our ability to make distributions.

We are a partnership holding company and our operating subsidiaries conduct all of the operations and own all of the operating assets. We have no significant assets other than the ownership interests in our subsidiaries and our equity investments, including Gulfstream and Market Hub. As a result, our ability to make distributions to our unitholders depends on the performance of these subsidiaries and equity investments and their ability to distribute funds to us. The ability of our subsidiaries and joint ventures to make distributions to us may be restricted by, among other things, the provisions of existing and future indebtedness, applicable state partnership and limited liability company laws and other laws and regulations, including the FERC policies.

If we are deemed an “investment company” under the Investment Company Act of 1940, it would adversely affect the price of our common units and could have a material adverse effect on our business.

Our initial assets consist of a 100% ownership interest in East Tennessee and Saltville, a 24.5% limited liability company interest in Gulfstream and a 50% general partner interest in Market Hub. If a sufficient amount of our assets, such as our ownership interests in Gulfstream and Market Hub or other assets acquired in the future, are deemed to be “investment securities” within the meaning of the Investment Company Act of 1940, we would either have to register as an investment company under the Investment Company Act, obtain exemptive relief from the Commission or modify the organizational structure or contract rights to fall outside the definition of an investment company. Although general partner interests are typically not considered “securities” or “investment securities,” there is a risk that our 50% general partner interest in Market Hub could be deemed to be an investment security. In that event, it is possible that our ownership of this interest, combined with our 24.5% interest in Gulfstream or assets acquired in the future, could result in us being required to register under the Investment Company Act if we were not successful in obtaining exemptive relief or otherwise modifying the organizational structure or applicable contract rights. Registering as an investment company could, among other things, materially limit our ability to engage in transactions with affiliates, including the purchase and sale of certain securities or other property to or from its affiliates, restrict our ability to borrow funds or engage in other transactions involving leverage and require us to add additional directors who are independent of us or our affiliates. The occurrence of some or all of these events would adversely affect the price of the common units and could have a material adverse effect on our business.

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Control of our general partner may be transferred to a third party without unitholder consent.

Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of the owners of our general partner or its parent, from transferring all or a portion of their respective ownership interest in the general partner or its parent to a third party. The new owners of our general partner or its parent would then be in a position to replace the board of directors and officers of its parent with its own choices and thereby influence the decisions taken by the board of directors and officers.

Increases in interest rates could adversely affect our unit price and our ability to issue additional equity to make acquisitions, incur debt or for other purposes.

In recent years, the U.S. credit markets experienced 50-year record lows in interest rates. Interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our unit price is affected by the level of our cash distributions and implied distribution yield. Therefore, changes in interest rates may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse effect on our unit price and the ability to issue additional equity to make acquisitions, to incur debt or for other purposes.

We may issue additional units without our common unitholders’ approval, which would dilute our existing common unitholders’ ownership interests.

Our partnership agreement does not limit the number of additional limited partner interests that we may issue at any time without the approval of our unitholders. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

• each unitholder’s proportionate ownership interest in us will decrease;

• the amount of cash available for distribution on each unit may decrease;

• because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;

• the ratio of taxable income to distributions may increase;

• the relative voting strength of each previously outstanding unit may be diminished; and

• the market price of the common units may decline.

Spectra Energy and its affiliates may sell units in the public or private markets, which sales could have an adverse effect on the trading price of the common units.

Spectra Energy and its affiliates hold an aggregate of 37,337,521 common units and 21,638,730 subordinated units. All of the subordinated units will convert into common units at the end of the subordination period, which could occur on the first business day after June 30, 2010, and all of the subordinated units may convert into common units if additional tests are satisfied. The sale of any of these units in the public or private markets could have an adverse effect on the price of the common units or on any trading market that may develop.

Our general partner has a limited call right that may require our common unitholder to sell the units at an undesirable time or price.

If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-

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current market price. As a result, our common unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. A common unitholder may also incur a tax liability upon a sale of their units. As of March 6, 2009, our general partner and its affiliates own approximately 76% of our outstanding common units. At the end of the subordination period, assuming no additional issuances of common units (other than for the conversion of the subordinated units into common units), our general partner and its affiliates will own approximately 84% of our aggregate outstanding common units.

Our common unitholder’s liability may not be limited if a court finds that unitholder action constitutes control of our business.

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. We are organized under Delaware law and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the states in which we do business. Our common unitholders could be liable for any and all of our obligations as if our common unitholders were a general partner if a court or government agency determined that:

• we were conducting business in a state but had not complied with that particular state’s partnership statute; or

• our common unitholder’s right to act with other unitholders to remove or replace the general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitutes “control” of our business.

Unitholders may have liability to repay distributions that were wrongfully distributed to them.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to the unitholder if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable for the obligations of the assignor to make contributions to the partnership that are known to the substituted limited partner at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the partnership agreement.

Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

Tax Risks to Common Unitholders

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service (the IRS) treats us as a corporation or we become subject to a material amount of entity-level taxation for state tax purposes, it would substantially reduce the amount of cash available for distribution.

The anticipated after-tax economic benefit of an investment in our common units depends largely on us being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter affecting us.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35% and would likely pay state income tax at varying rates. Distributions would generally be taxed again as corporate distributions, and no

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income, gains, losses or deductions would flow through to the common unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to a common unitholder, likely causing a substantial reduction in the value of our common units.

Current law may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. In addition, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation.

Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution levels may be adjusted to reflect the effect of that law.

An IRS contest of the federal income tax positions we take may adversely affect the market for our common units, and the cost of any IRS contest will reduce our cash available for distribution.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter. The IRS may adopt positions that differ from the conclusions of us. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take. A court may not agree with all of our conclusions or positions we take. Any contest with the IRS may materially and adversely affect the market for our common units and the price at which they trade. In addition, the costs of any contest with the IRS will be borne indirectly by the unitholders and our general partner because the costs will reduce our cash available for distribution.

The unitholder may be required to pay taxes on the unitholder’s share of our income even if the unitholder does not receive any cash distributions.

Because the unitholders will be treated as partners to whom we will allocate taxable income which could be different in amount than the cash distributed, common unitholders will be required to pay any federal income taxes and, in some cases, state and local income taxes on the common unitholder’s share of taxable income even if the common unitholders receive no cash distributions from us. The common unitholder may not receive cash distributions from us equal to the unitholder’s share of taxable income or even equal to the actual tax liability that results from that income.

Tax gain or loss on disposition of our common units could be more or less than expected.

If the common unitholder sells its common units, the unitholder will recognize a gain or loss equal to the difference between the amount realized and the common unitholder’s tax basis in those common units. Because distributions in excess of the common unitholder’s allocable share of our net taxable income decrease the common unitholder’s tax basis in the common units, the amount, if any, of such prior excess distributions with respect to the units the unitholder sells will, in effect, become taxable income to the unitholder if the unitholder sells such units at a price greater than the tax basis, even if the price the unitholder receives is less than the original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes the share of our nonrecourse liabilities, if the common unitholder sells the units, the common unitholder may incur a tax liability in excess of the amount of cash the unitholder receives from the sale.

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Tax-exempt entities and foreign persons face unique tax issues from owning common units that may result in adverse tax consequences to them.

Investment in common units by tax-exempt entities, such as individual retirement accounts (IRAs), other retirement plans and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file United States federal tax returns and pay tax on their share of our taxable income. If the unitholder is a tax-exempt entity or a foreign person, the unitholder should consult a tax advisor before investing in our common units.

We will treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

Because we cannot match transferors and transferees of common units and because of other reasons, we will adopt depreciation and amortization positions that may not conform to all aspects of existing U.S. Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to the common unitholder. It also could affect the timing of these tax benefits or the amount of gain from the sale of our common units and could have a negative effect on the value of our common units or result in audit adjustments to the tax returns.

We have adopted certain valuation methodologies that may result in a shift of income, gain, loss and deduction between the general partner and the unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.

When we issue additional units or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of the unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the general partner, which may be unfavorable to such unitholders. Moreover, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to tangible and intangible assets, and allocations of income, gain, loss and deduction between the general partner and certain of the unitholders.

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to the unitholders. It also could affect the amount of gain from the unitholders’ sale of common units and could have a negative effect on the value of the common units or result in audit adjustments to unitholders’ tax returns without the benefit of additional deductions.

The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of the partnership for federal income tax purposes.

We will be considered to have terminated the partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. Our termination would, among other things, result in the closing of the taxable year for all unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income.

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A common unitholder will likely be subject to state and local taxes and return filing requirements in states where the common unitholder does not live as a result of investing in our common units.

In addition to federal income taxes, a common unitholder will likely be subject to other taxes, including foreign, state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property, even if the common unitholder does not live in any of those jurisdictions. The common unitholder will likely be required to file foreign, state and local income tax returns and pay state and local income taxes in some or all of these jurisdictions. Further, the common unitholder may be subject to penalties for failure to comply with those requirements. We will initially own assets and do business in Alabama, Florida, Georgia, Louisiana, Mississippi, North Carolina, Tennessee, Texas and Virginia. Each of these states, other than Texas and Florida, currently imposes a personal income tax on individuals. A majority of these states impose an income tax on corporations and other entities. As we make acquisitions or expand our business, we may own assets or conduct business in additional states that impose an income tax. It is the common unitholder’s responsibility to file all United States federal, foreign, state and local tax returns. Our counsel has not rendered an opinion on the foreign, state or local tax consequences of an investment in the common units.

Item 1B. Unresolved Staff Comments.

None.

Item 2. Properties.

Our principal executive offices are located at 5400 Westheimer Court, Houston, Texas 77056, which is a facility leased by Spectra Energy. Our telephone number is 713-627-5400.

For a description of material properties, see Item 1. Business.

Item 3. Legal Proceedings.

For information regarding legal proceedings, including regulatory and environmental matters, see Notes  5 and 14 of Notes to Consolidated Financial Statements.

Item 4. Submission of Matters to a Vote of Security Holders.

None.

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PART II

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

             Securities.

Our common units have been listed on the New York Stock Exchange (NYSE) under the symbol “SEP” since June 27, 2007. Prior to that, our equity securities were not listed on any exchange or traded on any public trading market. Prior to the IPO, the operations comprising our partnership were owned by Spectra Energy. The following table sets forth the high and low closing sales prices of the common units, as reported by the NYSE, as well as the amount of cash distributions declared per quarter from the closing of our IPO through December 31, 2008.

Common Unit Data by Quarter

					Unit Price Range(a)
	Distributions per Common Unit		Distributions per Subordinated Unit		High		Low
2007
Second Quarter(b)		—		—	$	29.29	$	26.50
Third Quarter		—		—	$	30.99	$	24.65
Fourth Quarter	$	0.30	$	0.30	$	26.73	$	23.70
2008
First Quarter	$	0.32	$	0.32	$	25.97	$	21.17
Second Quarter	$	0.33	$	0.33	$	26.15	$	22.84
Third Quarter	$	0.34	$	0.34	$	25.00	$	17.06
Fourth Quarter	$	0.35	$	0.35	$	30.00	$	12.10

(a) Unit prices represent the intra-day high and low unit price.

(b) From June 27, 2007, the commencement of trading.

As of March 6, 2009, there were approximately 23 holders of record of our common units. A cash distribution to unitholders of $0.36 per unit was declared on January 27, 2009 and was paid on February 13, 2009, which is a $0.01 per unit increase over the cash distribution of $0.35 per unit paid on November 14, 2008.

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Unit Performance Graph

The following graph reflects the comparative changes in the value from June 27, 2007, the first trading day of our common units on the NYSE, through December 31, 2008 of $100 invested in (1) Spectra Energy Partners’ common units, (2) the Standard & Poor’s 500 Stock Index, and (3) the Alerian MLP Index. The amounts included in the table were calculated assuming the reinvestment of distributions, at the time distributions were paid.

	June 27, 2007		December 31,
			2007		2008
Spectra Energy Partners	$	100.00	$	90.42	$	74.64
S&P 500		100.00		98.36		60.50
Alerian MLP Index		100.00		91.97		53.84

Market Repurchases

We have not made any repurchases of common, subordinated or general partner units.

Distributions of Available Cash

General. Our partnership agreement requires that, within 45 days after the end of each quarter, beginning with the quarter ending September 30, 2007, we distribute all of our Available Cash, as defined, to unitholders of record on the applicable record date.

See the Glossary contained in Part I, Item 1. for the definition of Available Cash.

Minimum Quarterly Distribution. The Minimum Quarterly Distribution, as set forth in the partnership agreement, is $0.30 per unit per quarter, or $1.20 per unit per year. The quarterly distribution as of January 27, 2009 is $0.36 per unit, or $1.44 per unit annualized. There is no guarantee that this distribution rate will be maintained or that we will pay the Minimum Quarterly Distribution on the units in any quarter. Even if our cash distribution policy is not modified or revoked, the amount of distributions paid under our policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of the partnership agreement. We will be prohibited from making any distributions to unitholders if it would cause an event of default, or an event of default is existing, under our credit agreement.

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General Partner Interest and Incentive Distribution Rights. Our general partner is entitled to 2% of all quarterly distributions since inception. This general partner interest is represented by 1,438,291 general partner units. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its current general partner interest. The general partner’s initial 2% interest in these distributions will be reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to maintain its 2% general partner interest.

The general partner also currently holds incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 50%, of the cash we distribute from operating surplus in excess of $0.345 per unit per quarter. The maximum distribution of 50% includes distributions paid to the general partner on its 2% general partner interest and assumes that the general partner maintains its general partner interest at 2%. The maximum distribution of 50% does not include any distributions that the general partner may receive on units that it owns.

Equity Compensation Plans

The information relating to our equity compensation plans required by Item 5 is included in Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters contained herein.

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Item 6. Selected Financial Data.

The following selected financial data should be read in conjunction with Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Item 8. Financial Statements and Supplementary Data.

Basis of Presentation. For periods prior to the closing of our IPO on July 2, 2007, the selected financial data presented was prepared from the separate records maintained by Spectra Energy Capital, LLC for the entities that were originally contributed to us and for the operations included in the Saltville acquisition, and are based on Spectra Energy Capital, LLC’s historical ownership percentages of these operations. The combined financial results of these entities are treated as the historical results of our partnership for financial statement reporting purposes. The selected financial data covering periods prior to the closing of the IPO may not necessarily be indicative of the actual results of operations had those contributed entities been operated separately during those periods.

	2008		2007			2006		2005		2004
	(In millions, except per-unit amounts)
Statements of Operations(a)
Operating revenues	$	124.9	$	121.1		$	101.5	$	84.6	$	81.7
Operating income		51.9		60.6			47.9		28.1		33.6
Equity in earnings of unconsolidated affiliates		61.4		55.6			41.1		46.3		36.5
Net income		101.3		202.9	(b)		68.1		59.0		55.4
Net Income per Limited Partner Unit(c)
Common unit	$	1.40	$	0.68			n/a		n/a		n/a
Subordinated unit		1.40		0.68			n/a		n/a		n/a
Cash distributions declared per unit		1.34		0.30			n/a		n/a		n/a

	December 31,
	2008		2007		2006		2005		2004
	(In millions)
Balance Sheet
Total assets	$	1,601.5	$	1,611.3	$	1,399.5	$	1,336.7	$	1,345.9
Long-term debt		390.0		400.0		150.0		150.0		150.0

(a) Historical amounts for years ended December 31, 2007, 2006 and 2005 have been recast to retroactively reflect the Saltville acquisition.

(b) Includes a benefit of $110.5 million from the reversal of deferred income tax liabilities in 2007.

(c) Reflective of general and limited partners’ interests in Net Income since the closing of our IPO on July 2, 2007. See Item 8. Financial Statements and Supplementary Data, Note 7 for further discussion.

n/a Indicates not applicable

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

INTRODUCTION

Management’s Discussion and Analysis should be read in conjunction with Item 8. Financial Statements and Supplementary Data.

EXECUTIVE OVERVIEW

In 2008, our focus was to continue to deliver on the strategies we had communicated in conjunction with our IPO in 2007. This included a significant focus on growth opportunities that will support our cash distribution objectives. During 2008, we placed approximately $130 million in new expansion projects into service and also completed the Saltville acquisition. We continue to deliver on our primary business objective of increasing cash distributions per unit. We have increased the quarterly cash distributions each quarter of 2008 from $0.32 per unit for the fourth quarter of 2007 to $0.36 per unit for the fourth quarter of 2008, or 13%.

We reported net income of $101.3 million for 2008 compared with $202.9 million for the prior year. The decrease was due to a tax benefit of $110.5 million in 2007 from the reversal of income tax liabilities as a result of our limited partnership structure, partially offset by strong revenues from new firm transportation contracts at East Tennessee and increased equity earnings from Gulfstream and Market Hub.

In April 2008, we completed the acquisition of the equity interests of the Saltville natural gas storage facilities and the P-25 natural gas pipeline from Spectra Energy for a purchase price of $107 million. The Saltville acquisition represented a transaction among entities under common control. Accordingly, the consolidated financial statements and related information presented herein have been recast to include the historical results of Saltville and the P-25 pipeline for all periods presented. See Note 1 of Notes to Consolidated Financial Statements for further discussion.

Effective upon the completion of the Saltville acquisition, our sole business segment, Gas Transportation and Storage, includes East Tennessee and Saltville, and aligns the operations of our partnership with the chief operating decision maker’s view of the business. All prior period information discussed herein has been recast to reflect the new segment structure.

The consolidated results of operations, financial position and cash flows for periods prior to our IPO on July 2, 2007 and for periods prior to the Saltville acquisition may not necessarily be indicative of the actual results of operations, financial position and cash flows had those entities operated separately during those periods.

Business Strategies

Our primary business objective is to increase our cash available for distribution to unitholders over time by executing the following strategies:

• Build on our contracted capacity position for natural gas transportation and storage on our systems by further expanding our customer base and diverse sources of natural gas supply. Our transportation and storage systems have access to numerous natural gas producing regions, including the Gulf Coast, Mid- Continent and Appalachian regions. Additionally, we are seeking to attach new sources of supply, including LNG, to enhance the attractiveness of our system to current and future customers.

• Deliver on our organic growth expansion opportunities. We continually evaluate organic expansion opportunities in existing and new markets that could allow us to increase value and cash distributions to our investors.

• Opportunistically pursue acquisitions. We may expand our existing natural gas transportation and storage businesses by pursuing acquisitions that add value and are accretive to cash available for

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distribution. We would pursue acquisitions in areas where our assets currently operate that provide the opportunity for operational efficiencies or higher capacity utilization of existing assets, as well as acquisitions in new geographic areas of operation in order to grow the scale of our business.

• Optimize existing assets and achieve additional operating efficiencies. We intend to enhance the profitability of our existing assets by undertaking additional initiatives to enhance utilization, improve operating efficiencies and develop rate and contract structures that meet our customers’ needs.

Significant Economic Factors for Our Business

The high percentage of our business derived from capacity reservation fees mitigates the risk of revenue fluctuations due to near-term changes in natural gas supply and demand conditions. However, all of our businesses can be negatively affected in the long term by sustained downturns or sluggishness in the economy in general, and are impacted by shifts in supply and demand dynamics, the mix of services requested by our customers, and changes in regulatory requirements affecting our operations. Short-term contracts and interruptible service arrangements are not a significant component of our revenue; however, these services can be impacted positively or negatively to varying degrees by natural gas price volatility and other factors beyond our control. We mitigate our exposure to natural gas prices by contracting our available transportation capacity with long-term, fixed-rate arrangements.

We believe the key factors that impact our business are the supply of and demand for natural gas in the markets in which we operate, our customers and their requirements, and government regulation of natural gas pipelines and storage systems. These key factors play an important role in how we evaluate our operations and implement our long-term strategies.

Supply and Demand Dynamics

Changes in natural gas supply such as new discoveries of natural gas reserves, declining production in older fields and the introduction of new sources of natural gas supply, such as non-conventional and emerging natural gas shale plays, affect the demand for our services from both producers and consumers. As these supply dynamics shift, we anticipate that we will actively pursue projects that link these new sources of supply to producers and consumers willing to contract for transportation or storage on a long-term firm basis. Changes in demographics, the amount of natural gas fired power generation and shifts in residential usage affect the overall demand for natural gas. In turn, our customers, which include LDCs, utilities and power generators, increase or decrease their demand for our services as a result of these changes.

Growing Markets

Our key markets 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 of approximately 1.5% according to ICF International. This demand growth is primarily driven by the natural gas-fired electric generation sector.

Growth of Natural Gas Storage Facilities

Natural gas storage plays an important role in the natural gas transportation industry, due to the need to balance seasonal pricing, provide gas for power generation, and to balance the difference in timing of natural gas supplies and natural gas demand. A substantial number of natural gas storage projects have been announced in recent years and are in various stages of development, especially in Mississippi, Texas and Louisiana. In 2008, 63.3 Bcf of natural gas storage came into service in this region, while another 32.1 Bcf was delayed or cancelled. The southeastern region of the United States has a large number of high-deliverability, salt-cavern storage facilities, and the demand for this type of storage is expected to continue to grow. An increased supply of storage capacity competing with Market Hub’s storage facilities could negatively impact our operations.

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Regulation

Government regulation of natural gas transportation and storage has a significant impact on our business. Rates are regulated under the FERC rate-making policies, and, in the case of our storage facility in Texas, by the TRC. The FERC regulatory policies govern the rates that each pipeline is permitted to charge customers for interstate transportation and storage of natural gas. Under certain circumstances, we are permitted to enter into contracts with customers under “negotiated rates” that differ from the rates imposed by the FERC.

RESULTS OF OPERATIONS(a)

	2008			2007			2006
	(In millions)
Operating revenues	$	124.9		$	121.1		$	101.5
Operating, maintenance and other expenses		46.7			34.1			32.2
Depreciation and amortization		26.3			26.4			21.4
Operating income		51.9			60.6			47.9
Equity in earnings of unconsolidated affiliates		61.4			55.6			41.1
Other income and expenses, net		0.9			0.4			2.1
Interest income		3.5			5.5			—
Interest expense		17.8			17.1			7.7
Earnings before income taxes		99.9			105.0			83.4
Income tax expense (benefit)		(1.4	)		(97.9	)		15.3
Net income	$	101.3		$	202.9		$	68.1
Adjusted EBITDA(b)	$	78.2		$	87.0		$	69.3
Cash Available for Distribution(b)		119.0			126.3			92.5

(a) Historical amounts for years ended December 31, 2007 and 2006 have been recast to retroactively reflect the Saltville acquisition.

(b) See “Reconciliation of Non-GAAP Measures.” for a reconciliation of this measure to its most directly comparable financial measures calculated and presented in accordance with generally accepted accounting principles (GAAP).

2008 Compared to 2007

Operating Revenues. The $3.8 million increase was driven by a $6.4 million increase from new and replacement firm transportation contracts on East Tennessee’s Jewell Ridge lateral and Patriot systems, partially offset by the absence of $2.5 million of salt sales during 2008 due to the sale of the salt plant in the second quarter of 2007.

Operating, Maintenance and Other. The $12.6 million increase was driven by:

• a $6.2 million increase from lower net pipeline fuel recoveries recognized by East Tennessee in the 2008 period compared to the 2007 period,

• a $4.0 million increase in public company costs and governance expenses from a full year’s activity in 2008 compared to only six months of activity in 2007 subsequent to the July 2, 2007 formation of Spectra Energy Partners,

• a $2.2 million increase from higher project costs at East Tennessee related to activities around the proposed Greenway expansions,

• a $1.5 million increase in general and administrative expenses as a result of increased outside services and labor costs, partially offset by

• a $1.3 million decrease in ad valorem tax expense primarily related to lower tax rates and lower franchise tax.

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Equity in Earnings of Unconsolidated Affiliates. The $5.8 million increase consisted of a $4.0 million increase in earnings from Gulfstream and a $1.8 million increase in earnings from Market Hub.

The following discussion explains the factors affecting the equity earnings of Gulfstream and Market Hub, each representing 100% of the earnings drivers of those entities.

	2008			2007		Increase (Decrease)			2006		Increase (Decrease)
	(In millions)
Gulfstream
Operating revenues	$	206.7		$	185.3	$	21.4		$	180.3	$	5.0
Operating, maintenance and other expenses		31.1			15.9		15.2			33.1		(17.2	)
Depreciation and amortization		30.3			30.0		0.3			30.4		(0.4	)
Gain (loss) on sale of assets		(0.6	)		—		(0.6	)		0.1		(0.1	)
Other income and expenses, net		11.1			3.9		7.2			0.3		3.6
Interest expense		45.0			47.9		(2.9	)		48.8		(0.9	)
Net income	$	110.8		$	95.4	$	15.4		$	68.4	$	27.0
Spectra Energy Partners’ share	$	27.5		$	23.5	$	4.0		$	16.8	$	6.7

Gulfstream — Owned 24.5%

Gulfstream’s net income increased $15.4 million to $110.8 million in 2008 compared to $95.4 million in 2007. The increase was primarily driven by:

• a $21.4 million increase in revenues driven primarily by the Phase III and Phase IV expansion contracts,

• a $7.2 million increase in other income and expenses driven primarily by AFUDC as a result of capital expenditures for Gulfstream’s Phase III and Phase IV expansion projects,

• a $2.9 million decrease in interest expense resulting from higher interest costs capitalized as a result of capital expenditures for Gulfstream’s Phase III and Phase IV expansion projects, partially offset by

• a $15.2 million increase in operating, maintenance and other expense primarily resulting from a $7.0 million increase in ad valorem tax expense due to the impact of a favorable valuation in 2007, a $3.6 million increase in project costs due to the 2007 capitalization of previously expensed costs related to the Phase IV expansion, and a $4.6 million increase due to higher pipeline operations costs and a favorable adjustment to administrative and general expenses in 2007.

	2008		2007		Increase (Decrease)			2006		Increase (Decrease)
	(In millions)
Market Hub
Operating revenues	$	98.0	$	91.3	$	6.7		$	78.8	$	12.5
Operating, maintenance and other expenses		20.0		23.6		(3.6	)		30.3		(6.7	)
Depreciation and amortization		10.6		9.1		1.5			7.8		1.3
Gains on sale of other assets and other income and expenses		0.2		7.0		(6.8	)		10.6		(3.6	)
Interest income		3.1		2.3		0.8			—		2.3
Interest expense		1.0		3.6		(2.6	)		2.6		1.0
Income tax expense		0.4		0.1		0.3			—		0.1
Net income	$	69.3	$	64.2	$	5.1		$	48.7	$	15.5
Spectra Energy Partners’ share	$	33.9	$	32.1	$	1.8		$	24.3	$	7.8

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Market Hub — Owned 50%

Market Hub’s net income increased $5.1 million to $69.3 million in 2008 compared to $64.2 million in 2007. The increase was primarily due to:

• a $6.7 million increase in revenues driven by an increase of $11.6 million in firm storage revenues as a result of the completion of the Egan Cavern 4 expansion, partially offset by a decrease in interruptible services of $4.9 million driven by a change in market demand,

• a $0.8 million increase in interest income due to notes receivable with affiliates issued in the third quarter of 2007,

• a $2.6 million decrease in interest expense primarily due to lower interest rates associated with collateral held from counterparties and affiliates,

• a $3.6 million decrease in operating, maintenance and other expenses resulting primarily from a $5.1 million write-down of inventory at Egan in 2007, partially offset by a $0.8 million increase in ad valorem tax expense primarily due to a favorable valuation in the first quarter of 2007, and a $0.6 increase in operating expenses due to the Egan expansion in 2007, partially offset by

• a $7.0 million gain on sales of other assets in 2007 relating to the receipt of an insurance settlement associated with the 2005 Moss Bluff incident, and

• a $1.5 million increase in depreciation expense primarily due to the Egan horsepower expansion placed in service in July 2007.

Interest Income. The $2.0 million decrease was caused by lower interest earned due to the sale of marketable securities purchased with a portion of the IPO proceeds in July 2007.

Interest Expense. The $0.7 million increase was due to a full year’s expense in 2008 as compared to six months in 2007 from term and revolver borrowings entered into on July 2, 2007, mostly offset by lower interest rates in 2008.

Income Tax Expense (Benefit). Our income tax benefit in 2008 was $1.4 million compared to an income tax benefit of $97.9 million in the same period in 2007. As previously discussed, we recorded a one-time benefit of $110.5 million in the third quarter of 2007 from the reversal of deferred income tax liabilities. Effective July 2, 2007, as a result of our master limited partnership structure, we are no longer subject to federal income taxes. In addition, a tax benefit of $2.5 million was recognized in the second quarter of 2008 due to the elimination of deferred income tax liabilities associated with Saltville’s change in tax status as a result of the acquisition by Spectra Energy Partners.

2007 Compared to 2006

Operating Revenues. The $19.6 million increase was primarily due to new firm transportation contracts with contract terms varying from 10 to 15 years, from the Jewell Ridge expansion project placed into service during the fourth quarter of 2006, and additional firm transportation contracts on the Patriot lateral pipeline.

Operating, Maintenance and Other. The $1.9 million increase was driven by:

• a $5.7 million increase due to net capitalization in 2006 of previously expensed project costs for Jewell Ridge. We expense project 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 $3.2 million increase due to lower capitalization of expenses as a result of lower capital spending in 2007 as compared to 2006,

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• a $2.6 million increase in general and administrative cost primarily related to the acquisition of Saltville which was completed in 2008, and

• a $1.9 million increase in pipeline integrity costs in the 2007 period, partially offset by

• a $11.0 million increase in net pipeline fuel recoveries that reduced operating costs in 2007. The higher net recoveries primarily resulted from a timing difference related to the recognition of recoveries and

• a $1.0 million decrease in ad valorem taxes as a result of lower negotiated 2007 rates.

Depreciation and Amortization. The $5.0 million increase is primarily due to the Jewell Ridge expansion project placed in service in the fourth quarter of 2006.

Equity in Earnings of Unconsolidated Affiliates. The $14.5 million increase consisted of a $7.8 million increase in earnings from Market Hub and a $6.7 million increase in earnings from Gulfstream.

The following discussion explains the factors affecting the equity earnings of Gulfstream — Owned 24.5% and Market Hub — Owned 50%, each representing 100% of the earnings drivers of those entities.

Gulfstream’s net income increased $27.0 million to $95.4 million in 2007 compared to $68.4 million in 2006. The increase was primarily driven by:

• a $5.0 million increase in revenues related to increased demand for transportation services due to warmer summer weather and a favorable gas to oil commodity price relationship for Gulfstream’s generation customers,

• a $5.0 million decrease in expenses primarily resulting from $2.5 million of capitalization of previously expensed project costs of the Phase IV expansion project in 2007 compared to $2.8 million in project costs expensed in 2006,

• a $12.2 million decrease in ad valorem taxes primarily as a result of favorable valuations, and

• a $3.6 million increase in other income and expenses, net primarily due to a 2006 charge related to a sales and use tax matter, increased interest income and increased AFUDC resulting from higher capital spending in 2007.

Market Hub’s net income increased $15.5 million to $64.2 million in 2007 compared to $48.7 million in 2006. The increase was primarily due to:

• a $12.5 million increase in revenues primarily resulting from a $6.7 million increase in new firm storage revenues associated with additional Egan storage capacity that was placed in service during the third quarter 2006 and a $5.8 million increase resulting from higher demand for short-term interruptible storage services,

• a $6.7 million decrease in operating expenses, primarily driven by a $4.6 million decrease in corporate costs charged by Spectra Energy in 2007 as compared to allocated costs from Duke Energy Corporation in 2006, and a $1.7 million reduction in property and other taxes due to the favorable resolution of ad valorem tax matters in 2007, and

• $2.3 million of interest income from affiliates recognized in 2007 related to notes receivable from affiliates, partially offset by

• a $3.6 million decrease in gains on sales of other assets primarily as a result of property insurance gain in 2006 of $10.6 million as compared to $7.0 million in 2007.

• a $1.3 million increase in depreciation primarily due to an Egan expansion project placed in service in 2006.

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Other Income and Expenses, Net. Other income and expenses in 2006 primarily represented the equity component of AFUDC resulting from the Jewell Ridge expansion project placed in service in 2006.

Interest Income. The $5.5 million recognized in 2007 represents interest earned on marketable securities purchased with a portion of the IPO proceeds.

Interest Expense. The $9.4 million increase mainly results from the term and revolver borrowings entered into on July 2, 2007.

Income Tax Expense (Benefit). We recorded an income tax benefit in 2007 of $97.9 million compared to income tax expense of $15.3 million in 2006. Effective July 2, 2007, as a result of our master limited partnership structure, we are no longer subject to federal income taxes. Therefore, in the third quarter of 2007, we recorded a one-time benefit of $110.5 million from the reversal of deferred income tax liabilities. This tax benefit was partially offset by taxes on higher earnings of East Tennessee in the 2007 period. We are still subject to Tennessee state income tax.

Matters Affecting Future Results

We plan to continue earnings growth through capital efficient projects, such as transportation and storage expansion to support a two-pronged “supply push” / “market pull” strategy, as well as continued focus on optimizing the performance of the existing operations through organizational efficiencies and cost control. “Supply push” is when producers agree to pay to transport specified volumes of natural gas in order to support the construction of new pipelines. “Market pull” is taking gas away from established liquid supply points and building pipeline transportation capacity to satisfy end-user demand in new markets or demand growth in existing markets.

Future earnings growth will be dependent on the success of expansion plans in both the market and supply areas of the pipeline network, the ability to continue renewing service contracts and continued regulatory stability.

Adjusted EBITDA and Cash Available for Distribution

Adjusted EBITDA

We define Adjusted Earnings Before Interest, Taxes, Depreciation and Amortization (EBITDA) as Net Income plus Interest Expense, Income Taxes and Depreciation and Amortization less our Equity in Earnings of Gulfstream and Market Hub, Interest Income, and Other Income and Expenses, Net, which primarily consists of non-cash AFUDC. Our Adjusted EBITDA is not a presentation made in accordance with GAAP. Because Adjusted EBITDA excludes some, but not all, items that affect net income and is defined differently by companies in our industry, our definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies.

Adjusted EBITDA is used as a supplemental financial measure by our management and by external users of our financial statements to assess:

• the financial performance of assets without regard to financing methods, capital structure or historical cost basis;

• the ability to generate cash sufficient to pay interest on indebtedness and to make distributions to partners; and

• operating performance and return on invested capital as compared to those of other publicly traded limited partnerships that own energy infrastructure assets, without regard to financing methods and capital structure.

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Significant drivers of variances in Adjusted EBITDA between the periods presented are substantially the same as those previously discussed under Results of Operations. Other drivers include the timing of certain cash outflows, such as capital expenditures for maintenance and scheduled payments of interest.

Cash Available for Distribution

We define Cash Available for Distribution as our Adjusted EBITDA plus Cash Available for Distribution from Gulfstream and Market Hub, less cash paid for interest expense, net, and maintenance capital expenditures. Cash Available for Distribution does not reflect changes in working capital balances.

For Gulfstream and Market Hub, we define Cash Available for Distribution as Adjusted EBITDA less cash paid for interest expense, net, and maintenance capital expenditures. Cash Available for Distribution does not reflect changes in their working capital balances.

Cash Available for Distribution should not be viewed as indicative of the actual amount of cash available for distribution or that we plan to distribute for a given period.

Cash Available for Distribution should not be considered an alternative to Net Income, Operating Income, cash from operations or any other measure of financial performance or liquidity presented in accordance with GAAP. Cash Available for Distribution excludes some, but not all, items that affect Net Income and Operating Income and these measures may vary among other companies. Therefore, Cash Available for Distribution as presented may not be comparable to similarly titled measures of other companies.

Significant drivers of variances in Cash Available for Distribution between the periods presented are substantially the same as those previously discussed under Results of Operations. Other drivers include the timing of certain cash outflows, such as capital expenditures for maintenance and the scheduled payments of interest.

Spectra Energy Partners

Reconciliation of Non-GAAP “Adjusted EBITDA” and “Cash Available for Distribution”

	2008			2007			2006
	(In millions)
Net income	$	101.3		$	202.9		$	68.1
Add:
Interest expense		17.8			17.1			7.7
Income tax expense (benefit)		(1.4	)		(97.9	)		15.3
Depreciation and amortization		26.3			26.4			21.4
Less:
Equity in earnings of Gulfstream		27.5			23.5			16.8
Equity in earnings of Market Hub		33.9			32.1			24.3
Interest income		3.5			5.5			—
Other income and expenses, net		0.9			0.4			2.1
Adjusted EBITDA		78.2			87.0			69.3
Add:
Cash Available for Distribution from Gulfstream		30.4			28.9			23.8
Cash Available for Distribution from Market Hub		36.0			31.9			19.5
Less:
Cash paid for interest expense, net		14.3			10.3			8.6
Maintenance capital expenditures		11.3			11.2			11.5
Cash Available for Distribution	$	119.0		$	126.3		$	92.5

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Spectra Energy Partners

Reconciliation of Non-GAAP “Adjusted EBITDA” and “Cash Available for Distribution”

	2008			2007			2006
	(In millions)
Net cash provided by operating activities	$	139.2		$	84.9		$	74.8
Interest income		(3.5	)		(5.5	)		—
Interest expense		17.8			17.1			7.7
Income tax expense — current		0.6			5.7			0.1
Distributions received from Gulfstream		(28.5	)		(16.8	)		(20.3	)
Distributions received from Market Hub		(43.2	)		(5.9	)		—
Changes in working capital and other		(4.2	)		7.5			7.0
Adjusted EBITDA		78.2			87.0			69.3
Add:
Cash Available for Distribution from Gulfstream		30.4			28.9			23.8
Cash Available for Distribution from Market Hub		36.0			31.9			19.5
Less:
Cash paid for interest expense, net		14.3			10.3			8.6
Maintenance capital expenditures		11.3			11.2			11.5
Cash Available for Distribution	$	119.0		$	126.3		$	92.5

Gulfstream

Reconciliation of Non-GAAP “Adjusted EBITDA” and “Cash Available for Distribution”

	2008		2007		2006
	(In millions)
Net income	$	110.8	$	95.4	$	68.4
Add:
Interest expense		45.0		47.9		48.8
Depreciation and amortization		30.3		30.0		30.4
Less:
Other income and expenses, net		11.1		3.9		0.4
Adjusted EBITDA — 100%		175.0		169.4		147.2
Less:
Cash paid for interest expense, net		49.5		49.9		49.5
Maintenance capital expenditures		1.3		1.4		0.6
Cash Available for Distribution — 100%	$	124.2	$	118.1	$	97.1
Adjusted EBITDA — 24.5%	$	42.9	$	41.5	$	36.1
Cash Available for Distribution — 24.5%	$	30.4	$	28.9	$	23.8

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Market Hub

Reconciliation of Non-GAAP “Adjusted EBITDA” and “Cash Available for Distribution”

	2008		2007		2006
	(In millions)
Net income	$	69.3	$	64.2	$	48.7
Add:
Interest expense		1.0		3.6		2.6
Income tax expense		0.4		0.1		—
Depreciation and amortization		10.6		9.1		7.8
Less:
Interest income		3.1		2.2		—
Other income and expenses, net		0.2		7.1		10.6
Adjusted EBITDA — 100%		78.0		67.7		48.5
Less:
Cash paid for interest expense, net		—		—		—
Maintenance capital expenditures		5.9		4.0		9.6
Cash Available for Distribution — 100%	$	72.1	$	63.7	$	38.9
Adjusted EBITDA — 50%	$	39.0	$	33.9	$	24.3
Cash Available for Distribution — 50%	$	36.0	$	31.9	$	19.5

Effective January 1, 2009, we have revised the calculation of Cash Available for Distribution, within the definition contained in the partnership agreement. As discussed in Item 8. Financial Statements and Supplementary Data, Note 1, for our regulated entities that apply Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation,” we expense preliminary project costs until such time that management determines that recovery of these costs is probable. At that time, we capitalize those costs, which reduces operating expenses in that period. The revised calculation for Cash Available for Distribution will now add back project development expenses to EBITDA as those costs are initially incurred and it will deduct the expense reductions in the period the costs are capitalized. These project costs do not represent operating cash flow activity.

The effects of this change on the three years ended December 31, 2008 would have been as follows:

Spectra Energy Partners

	2008		2007			2006
	(In millions)
Cash Available for Distribution, as previously reported	$	119.0	$	126.3		$	92.5
Add:
Change in Cash Available for Distribution from Gulfstream		0.3		(0.6	)		0.7
Preliminary project costs, net		2.2		—			(5.7	)
Cash Available for Distribution, as revised	$	121.5	$	125.7		$	87.5

Gulfstream

	2008		2007			2006
	(In millions)
Cash Available for Distribution, as previously reported	$	124.2	$	118.1		$	97.1
Add:
Preliminary project costs, net		1.1		(2.5	)		2.8
Cash Available for Distribution, as revised — 100%	$	125.3	$	115.6		$	99.9
Cash Available for Distribution, as revised — 24.5%	$	30.7	$	28.3		$	24.5

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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 our operations change and accounting guidance is issued. We have identified a number of critical accounting policies and estimates that require the use of significant estimates and judgments.

We base our estimates and judgments on historical experience and on other various assumptions that we believe are reasonable at the time of application. The estimates and judgments may change as time passes and more information 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. We discuss our critical accounting policies and estimates and other significant accounting policies with our Audit Committee.

Regulatory Accounting

We account for our regulated operations at East Tennessee and Saltville under the provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” As a result, we record assets that result from the regulated ratemaking process that may not be recorded under GAAP for non-regulated entities. Regulatory assets generally represent incurred costs that have been deferred because such costs are probable of future recovery in customer rates. Regulatory liabilities generally represent obligations to make refunds to customers for previous collections for costs that either are not likely to or have yet to be incurred. We continually assess whether the regulatory assets are probable of future recovery by considering factors such as applicable regulatory changes and recent rate orders to other regulated entities. Based on this continual assessment, we believe the existing regulatory assets are probable of recovery. This assessment reflects the current political and regulatory climate, and is subject to change in the future. If future recovery of costs ceases to be probable, asset write-offs would be required to be recognized in operating income. Additionally, regulatory agencies can provide flexibility in the manner and timing of the depreciation of property, plant and equipment and amortization of regulatory assets. Total regulatory assets were $10.0 million as of December 31, 2008 and $9.6 million as of December 31, 2007. We had no regulatory liabilities for the periods included in the financial statements.

Impairment of Goodwill

Goodwill of our sole operating segment, Gas Transportation and Storage, was $118.3 million at both December 31, 2008 and 2007. We evaluate for the impairment of goodwill under SFAS No. 142, “Goodwill and Other Intangible Assets.” As required by SFAS No. 142, we perform an annual goodwill impairment test and update 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 and estimated future cash flows. In estimating cash flows, we incorporate expected growth rates, regulatory stability and the ability to renew contracts, as well as other factors that affect our revenue and expense forecasts.

Equity Method Investments

We account for investments in 20% to 50% owned affiliates, and investments in less than 20% owned affiliates where we have the ability to exercise significant influence, under the equity method. Accordingly, our 24.5% interest in Gulfstream and 50.0% interest in Market Hub are accounted for under the equity method.

Revenue Recognition

Revenues from the transportation and storage of natural gas and storage of LNG are recognized when the service is provided. Revenues related to these services provided but not yet billed are estimated each month. These estimates are generally based on contract data, regulatory information 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.

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LIQUIDITY AND CAPITAL RESOURCES

Known Trends and Uncertainties

We will rely primarily upon cash flows from operations, which includes our Gas Transportation and Storage segment and cash distributions received from Gulfstream and Market Hub, and additional financing transactions to fund our liquidity and capital requirements for 2009. As of December 31, 2008, we had negative net working capital of $23.6 million as compared to negative $37.3 million as of December 31, 2007, both of which included the $50.0 million note payable on demand to Market Hub. Additionally, we have access to a revolving credit facility with a capacity of $500.0 million, of which we consider $244 million available at December 31, 2008.

Cash flows from operations for our business are fairly stable given that most of our revenues are derived from regulated operations that primarily represent fee-based services. See Part I, Item 1A. Risk Factors for discussion of factors that could affect these cash flows.

As we execute on our strategic objectives around organic expansion opportunities, capital expenditures could be significant, ranging from $60 million to $100 million per year over the next few years. The timing and extent of these expenditures are likely to vary significantly from year to year, depending primarily on general economic conditions and market requirements. Given that we expect to continue to pursue expansion opportunities over the next several years, capital resources will continue to include long-term borrowings on our current credit facilities and possibly securing additional sources of capital including debt and/or equity. However, as a result of our ongoing strong earnings performance expected in existing operations, we expect to maintain a capital structure and liquidity profile that supports our strategic objectives and therefore will continue to monitor market requirements and our liquidity and make adjustments to these plans as needed.

Operating Cash Flows

Net cash provided by operating activities increased $54.3 million to $139.2 million in 2008 compared to 2007. This change was driven primarily by a $49.0 million increase in distributions received from equity affiliates, primarily Market Hub. Effective with our 2007 IPO, Market Hub is required to make distributions of its Available Cash to its partners, including us.

Net cash provided by operating activities increased $10.1 million to $84.9 million in 2007 compared to 2006. This change was driven primarily by higher earnings.

Investing Cash Flows

Cash flows used in investing activities totaled $17.3 million in 2008 compared to $205.0 million in 2007. The $187.7 million change was driven primarily by:

• $154.6 million of net purchases of available-for-sale securities in the 2007 period that were held as collateral for the term loan as compared to $123.0 million of net proceeds in 2008 from the liquidation of such securities. As permitted by the terms of the credit facility, proceeds were used for capital and investment expenditures. This $277.6 million decrease in cash used was primarily offset by

• a $60.3 million increase in investment expenditures representing capital contributions to Gulfstream and Market Hub in 2008 used to fund their expansion projects,

• a $4.7 million cash portion of the Saltville acquisition in the 2008 second quarter, and

• proceeds from sales of assets in 2007 of $8.3 million.

Capital and investment expenditures for 2008 totaled $135.6 million and included $124.3 million for expansion projects, primarily at Gulfstream and Market Hub, and $11.3 million for East Tennessee and Saltville maintenance projects. We estimate total 2009 capital and investment expenditures of approximately $75 million, of which $60 million is expected to be used for expansion projects primarily at Gulfstream and Market Hub and $15 million for maintenance and other projects.

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In response to increased Appalachian production activity, East Tennessee held the Greenway Project open season in February 2008 and received strong demand for new capacity. These open season results provide opportunities for multi-year expansion projects. In addition, East Tennessee has smaller project opportunities from this open season that can be completed within the existing right-of-ways, like Greenway/Nora, the first project arising from the Greenway open season. Construction has been completed and commercial service commenced on December 1, 2008. East Tennessee continues to evaluate additional opportunities arising from the Greenway open seasons and is developing plans for a multi-year program.

Given our objective of growth through acquisitions and expansions of existing assets, we anticipate that we will continue to invest significant amounts of capital to grow and acquire assets. Expansion capital expenditures may vary significantly based on investment opportunities.

Expansion capital and investment expenditures in 2008 included the completion of Glade Springs, CNX and Greenway Nora projects, the completion of Market Hub’s Egan Cavern 4 and continued expansion of Egan Cavern 3 and Moss Bluff Cavern 4, and Gulfstream’s Phase III and Phase IV expansions that were placed partially into service in the third quarter of 2008.

Significant 2009 expansion projects, including those of Gulfstream and Market Hub, are expected to include:

• Gulfstream — The Phase IV compression project and the final completion of Phase III are expected to be completed in the first quarter of 2009.

• Egan — Egan Cavern 3 is expected to be placed into initial gas service in the second half of 2009. The expected final working capacity at completion of Egan Cavern 3 is 8.0 Bcf to be in service in 2012.

• Moss Bluff — Moss Bluff Cavern 4 construction will continue, ultimately expected to increase storage working capacity by 6.5 Bcf, as well as upgrade top-side facilities, and expand pipeline interconnects. The cavern is expected to be placed into service in 2011.

• East Tennessee — Preliminary development efforts will continue on the Greenway expansion program.

Net cash flows used in investing activities totaled $205.0 million in 2007 compared to $91.8 million in 2006. This $113.2 million change was driven primarily by:

• $154.6 million of net purchases of available-for-sale securities in the 2007 period that were held as collateral for the term portion of the $500.0 million credit facility, and

• a $28.3 million increase in investment expenditures representing capital contributions to Gulfstream and Market Hub in 2007 used to fund their expansion projects, partially offset by

• a $61.4 million reduction in expansion capital expenditures in 2007, primarily the result of the completion of the Jewell Ridge expansion project in 2006, and

• proceeds on sales of assets in 2007 of $8.3 million.

Financing Cash Flows

Net cash flows used in financing activities in 2008 totaled $105.9 million compared to $135.0 million cash provided in 2007. The $240.9 million change was driven primarily by:

• $300.0 million net issuances of long-term debt and note payable to affiliates in 2007 as compared to a net reduction of $10.0 million in 2008,

• $230.2 million of net cash received in the 2007 period from the issuance of common units to the public in the IPO, and

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• $74.8 million of distributions to partners in 2008, partially offset by

• $362.4 million of net transfers to parent in 2007, which included an initial cash distribution of $345.0 million to Spectra Energy on July 2, 2007, and

• $12.5 million of dividends in 2007 by East Tennessee to its parent prior to the IPO.

Net cash flows provided by financing activities in 2007 totaled $135.0 million compared to $15.6 million in 2006. This $119.4 million increase was driven primarily by:

• $300.0 million net issuances of long-term debt and notes payable to affiliates in 2007, and

• $230.2 million of net cash received in the 2007 period upon the issuance of common units to the public in the IPO, partially offset by

• an initial cash distribution of $345.0 million to Spectra Energy on July 2, 2007 and net transfers to Spectra Energy of $17.4 million compared to net transfers from Spectra Energy of $15.6 million in 2006,

• distributions to partners of $20.3 million in 2007, and

• $12.5 million of dividends in 2007 by East Tennessee to its parent prior to the IPO.

Prior to the completion of the IPO, all of our excess cash flow was distributed as dividends and net transfers to Spectra Energy. As a result, our changes in cash provided by operating activities and cash used in investing activities were offset by cash flows for financing activities.

Available Credit Facility and Restrictive Debt Covenants. Credit markets in the U.S. have recently experienced varying degrees of volatility and contraction that has limited the supply of credit. This volatility has been caused by many factors, including concerns about creditworthiness in the overall market, especially the financial services sector, which has culminated in the failure or consolidation of several large financial and investment institutions. During this credit contraction, we have been able to draw on our committed and available credit facilities in amounts sufficient to fund liquidity needs.

We have an outstanding credit facility with an aggregate of approximately $500 million in bank commitments, of which approximately $31 million ($16.1 million unfunded) were allocated to Lehman Brothers Commercial Bank (Lehman) as of December 31, 2008. As a result of the bankruptcy filing of Lehman’s parent, we consider the unfunded commitment from Lehman to be unavailable. Currently, we are working to identify replacement lenders for the portion of our credit facility currently held by Lehman. We believe that the commitments of the other lenders under our credit facility is sufficient to fund our working capital and short-term requirements, and that a potential default by Lehman would not materially affect our liquidity.

Our obligations under the revolving portion of our credit facility are unsecured and the term borrowings are secured by qualifying investment-grade securities in an amount equal to or greater than the outstanding principal amount of the loan. The terms of the credit facility allow for liquidation of collateral to fund capital expenditures or certain acquisitions provided that an equal amount of term loan is converted to a revolving loan. Investments in marketable securities totaling $31.6 million at December 31, 2008 and $154.6 million at December 31, 2007 were pledged as collateral against the term loan. The revolving credit facility bears interest based on the London InterBank Offering Rate (LIBOR). The credit facility prohibits us from making distributions of Available Cash to unitholders if any default or event of default, as defined, exists. In addition, the credit facility contains covenants, among others, limiting our ability to make other restricted distributions or dividends on account of the purchase, redemption, retirement, acquisition, cancellation or termination of partnership interests, and is also subject to certain financial covenants. These financial covenants include financial leverage and interest coverage ratios. The terms of the credit agreement require us to maintain a ratio of total debt to Adjusted EBITDA, as defined in the credit agreement, of 5.0 or less. As of December 31, 2008, the ratio was 2.8. The terms of the credit agreement also require us to maintain a ratio of Adjusted EBITDA, as defined in the credit agreement, to interest expense of

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2.5 or greater. As of December 31, 2008, the ratio was 10.2. Adjusted EBITDA, as defined in the credit agreement, and therefore these ratios are affected by substantially the same economic and other drivers as those discussed under Results of Operations. We are not aware of any events that would cause us to not comply with such covenants in the near future. The credit facility does not contain material adverse change clauses.

Cash Distributions. The partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our Available Cash, as defined, to unitholders of record on the applicable record date. We have increased the quarterly cash distributions each quarter of 2008 from $0.32 per unit for the fourth quarter of 2007 to $0.36 per unit for the fourth quarter of 2008, or 13%. A cash distribution to our unitholders of $0.36 per unit was declared on January 27, 2009 and was paid on February 13, 2009, which is a $0.01 per unit increase over the cash distribution paid on November 14, 2008.

Off Balance Sheet Arrangements

We do not have any off-balance sheet financing entities or structures with third parties other than our equity investments in Gulfstream and Market Hub, and maintain no debt obligations that contain provisions requiring accelerated payment of the related obligation in the event of specified declines in credit ratings.

Gulfstream has $850 million aggregate principal amount of senior notes outstanding, none of which is included on our consolidated balance sheets.

Contractual Obligations

We enter into contracts that require payment of cash at certain specified periods, based on certain specified minimum quantities and prices. The following table summarizes our contractual cash obligations for each of the periods presented. The table below excludes all amounts classified as Current Liabilities on the Consolidated Balance Sheets other than Current Maturities of Long-Term Debt. It is expected that the majority of current liabilities on the Consolidated Balance Sheets will be paid in cash in 2009.

Contractual Obligations as of December 31, 2008

	Payments Due by Period
	Total		2009		2010 & 2011		2012 & 2013		2014 & Beyond
	(In millions)
Long-term debt(a)	$	441.8	$	13.8	$	27.6	$	400.4	$	—
Note payable — affiliates(a)		52.6		52.6		—		—		—
Operating leases		0.5		0.1		0.2		0.2		—
Purchase obligations
Material/capital purchases		—		—		—		—		—
Other purchase obligations		2.0		2.0		—		—		—
Total contractual cash obligations	$	496.9	$	68.5	$	27.8	$	400.6	$	—

(a) See Note 11 of Notes to Consolidated Financial Statements. Amounts include scheduled interest payments over the life of the debt.

Quantitative and Qualitative Disclosures About Market Risk

We are exposed to market risks associated with interest rate and credit exposure. Management has established comprehensive risk management policies to monitor and manage these market risks. The Chief Financial Officer of Spectra Energy is responsible for the overall governance of managing interest rate risk and credit risk, including monitoring exposure limits.

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Interest Rate Risk

We are exposed to risk resulting from changes in interest rates as a result of our issuance of variable and fixed rate debt and investments in short-term securities. We manage interest rate exposure by limiting variable- rate exposures to percentages of total capitalization and by monitoring the effects of market changes in interest rates. We may also enter into financial derivative instruments, including, but not limited to, interest rate swaps to manage and mitigate interest rate risk exposure.

Based on a sensitivity analysis as of December 31, 2008, it was estimated that if market interest rates average 1% higher (lower) in 2009 than in 2008, interest expense, net of offsetting impacts in interest income, would increase (decrease) by $1.2 million. Comparatively, based on a sensitivity analysis as of December 31, 2007, had interest rates averaged 1% higher (lower) in 2008 than in 2007, it was estimated that interest expense, net of offsetting interest income, would have fluctuated by approximately $2.9 million. These amounts were estimated by considering the effect of the hypothetical interest rates on variable-rate securities outstanding, adjusted for interest rate hedges, investments, and cash and cash equivalents outstanding as of December 31, 2008 and 2007. If interest rates changed significantly, we would likely take action to manage our 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 our financial structure.

Credit Risk

Credit risk represents the loss that we would incur if a counterparty fails to perform under its contractual obligations. Our exposure generally relates to receivables and unbilled revenue for services provided, as well as volumes owed by customers for imbalances or gas loaned by us generally under park and loan services and no-notice services. Our principal customers for natural gas transportation and storage are industrial end-users, marketers, exploration and production companies, local distribution companies and utilities located in the southern and southeastern United States. We have concentrations of receivables from these industry sectors. These concentrations may affect our overall credit risk in that risk factors can negatively affect the credit quality of an entire sector.

Where exposed to credit risk, we analyze the counterparties’ financial condition prior to entering into an agreement, establish credit limits and monitor the appropriateness of these limits on an ongoing basis. We also obtain cash, letters of credit or parental guarantees from customers to provide credit support, where appropriate, based on our financial analysis of the customer and the regulatory or contractual terms and conditions applicable to each transaction. Over 90% of our credit exposures for transportation and storage services are either with customers who have an investment-grade rating (or the equivalent based on an evaluation by Spectra Energy), or are secured by collateral.

We manage cash to maximize value while assuring appropriate amounts of cash are available, as required. We typically invest our available cash in high-quality money market securities. Such money market securities are designed for safety of principal and liquidity, and accordingly, do not include equity-based securities. We do not have any investments in asset-backed commercial paper or auction-rate securities.

Market Hub, our 50% equity investment, also has gas imbalances created primarily by park and loan services. Increases in gas prices and gas price volatility can materially increase Market Hub’s credit risk related to gas loaned to customers. The highest amount of gas loaned out by Market Hub over the past 12 months at any one time to customers has been approximately 3.7 Bcf. The market value of that volume, assuming an average market price of $6.00 per MMBtu, would be $22 million. Market Hub’s credit exposure from gas loans is managed consistent with the program described above, and Market Hub obtains security deposits as necessary from third parties and affiliates to cover any excess exposure.

Based on our policies for managing credit risk, our exposures and our credit and other reserves, we do not anticipate a materially adverse effect on our consolidated results of operations, financial position or cash flows as a result of non-performance by any counterparty.

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OTHER ISSUES

Global Climate Change. Policymakers at regional, federal and international levels continue to evaluate potential legislative and regulatory compliance mechanisms to achieve reductions in global greenhouse gas (GHG) emissions in the effort to address the challenge of climate change. It is likely that our assets and operations in the U.S. are or will become subject to direct and indirect effects of current and possible future global climate change regulatory actions in the jurisdictions in which those assets and operations are located.

In the United States, climate change action is evolving at state, regional and federal levels. We expect a number of our assets and operations could be affected by eventual mandatory GHG programs; however, the timing and specific policy objectives in many jurisdictions, including at the federal level, remain uncertain.

The United States is not a signatory to the United Nations-sponsored Kyoto Protocol, nor has the federal government adopted a mandatory GHG emissions reduction requirement. However, in 2008, the EPA initiated an Advanced Notice of Proposed Rulemaking to examine whether GHG emissions could be effectively regulated under the existing Clean Air Act. In addition, several legislative proposals have been introduced and discussed in the U.S. Congress that would impose GHG emissions constraints, though final legislation has yet to advance.

A number of states in the United States, primarily in the northeast and west, are establishing or considering state or regional programs that would mandate reductions in GHG emissions. These regional programs include the Regional Greenhouse Gas Initiative (RGGI) which applies only to power producers in select northeastern states, the Western Climate Initiative (WCI) which includes a number of western states and Canadian provinces, and the Midwestern Greenhouse Gas Reduction Accord which includes six midwestern states and one Canadian province. We expect a number of our assets and operations could be affected either directly or indirectly by state or regional programs. However, as the key details of future GHG restrictions and compliance mechanisms remain undefined, the likely future effects on our business are highly uncertain.

Due to the speculative outlook regarding any U.S. federal and state policies, we cannot estimate the potential effect of GHG policies on our future consolidated results of operations, financial position or cash flows. We continue to monitor the development of greenhouse gas regulatory policies in the states in which we operate.

Other. For additional information on other issues related to us, see Item 8. Financial Statements and Supplementary Data, Notes 5 and 14 of Notes to Consolidated Financial Statements.

New Accounting Pronouncements

See Note 1 of Notes to Consolidated Financial Statements for discussion.

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

See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Quantitative and Qualitative Disclosures About Market Risk for discussion.

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Item 8. Financial Statements and Supplementary Data.

Management’s Annual Report on Internal Control over Financial Reporting

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

Our management, including our Chief Executive Officer and Chief Financial Officer, has conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2008 based on the framework in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2008.

Our independent registered public accounting firm has audited and issued a report on the effectiveness of our internal control over financial reporting, which is included in its Report of Independent Registered Public Accounting Firm.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Unitholders of

Spectra Energy Partners, LP

Houston, Texas

We have audited the accompanying consolidated balance sheets of Spectra Energy Partners, LP and subsidiaries as of December 31, 2008 and 2007, and the related consolidated statements of operations, partners’ capital/predecessor equity and comprehensive income, and cash flows of Spectra Energy Partners, LP and subsidiaries and Spectra Energy Partners Predecessor for each of the three years in the period ended December 31, 2008 (collectively, Spectra Energy Partners, LP and subsidiaries and Spectra Energy Partners Predecessor are the “Company”). Our audits also included the financial statement schedule listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits. The consolidated financial statements give retroactive effect to the acquisition of 100% of the equity interests of Saltville Gas Storage Company L.L.C. (“Saltville”) and the P-25 pipeline from Spectra Energy Corp by the Company on April 4, 2008, which has been accounted for in a manner similar to a pooling of interests as described in Notes 1 and 2 to the consolidated financial statements.

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 and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

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In our opinion, such consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2008 and 2007, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2008, after giving retroactive effect to the acquisition of Saltville and the P-25 pipeline described in Notes 1 and 2 to the consolidated financial statements, 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. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

As discussed in Note 1 to the consolidated financial statements, on July 2, 2007 the Company completed its initial public offering. For periods prior to the closing of the initial public offering, the financial statements were prepared from the separate records maintained by Spectra Energy Capital, LLC for East Tennessee Natural Gas LLC, Market Hub Partners Holding and Gulfstream Natural Gas System, L.L.C., the entities that were contributed to the Company by Spectra Energy Corp, and are based on the historical ownership percentages of the entities’ operations that were contributed. The financial results of the entities are treated as the historical results of the Company for financial statement purposes and may not necessarily be indicative of the conditions that would have existed or the results of operations if the Company had been operated as an unaffiliated entity. Portions of certain expenses represent allocations made from and are applicable to Spectra Energy Capital, LLC as a whole.

Also as described in Note 1 to the consolidated financial statements, the portion of the accompanying consolidated financial statements attributable to Saltville and the P-25 pipeline have been prepared from the separate records maintained by Spectra Energy Capital, LLC and may not necessarily be indicative of the conditions that would have existed or the results of operations if Saltville and the P-25 pipeline had been operated as unaffiliated entities. Portions of certain expenses represent allocations made from, and are applicable to Spectra Energy Capital, LLC as a whole.

/s/    Deloitte & Touche LLP

Houston, Texas

March 11, 2009

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SPECTRA ENERGY PARTNERS, LP

CONSOLIDATED STATEMENTS OF OPERATIONS

	Years Ended December 31,
	2008			2007			2006
	(In millions, except per-unit amounts)
Operating Revenues
Transportation of natural gas	$	107.0		$	100.6		$	82.9
Storage of natural gas and other		17.9			20.5			18.6
Total operating revenues		124.9			121.1			101.5
Operating Expenses
Operating, maintenance and other		20.2			26.4			14.1
Operating, maintenance and other — affiliates		23.4			3.3			12.7
Depreciation and amortization		26.3			26.4			21.4
Property and other taxes		3.1			4.4			5.4
Total operating expenses		73.0			60.5			53.6
Operating Income		51.9			60.6			47.9
Other Income and Expenses
Equity in earnings of unconsolidated affiliates		61.4			55.6			41.1
Other income and expenses, net		0.9			0.4			2.1
Total other income and expenses		62.3			56.0			43.2
Interest Income		3.5			5.5			—
Interest Expense		17.8			17.1			7.7
Earnings Before Income Taxes		99.9			105.0			83.4
Income Tax Expense (Benefit)(a)		(1.4	)		(97.9	)		15.3
Net Income	$	101.3		$	202.9		$	68.1
Calculation of Limited Partners’ Interest in Net Income:
Net income	$	101.3		$	202.9			n/a	(b)
Less:
Net income attributable to predecessor operations		1.6			156.7			n/a
General partner’s interest in net income		2.5			0.9			n/a
Limited partners’ interest in net income	$	97.2		$	45.3			n/a
Basic and diluted net income per limited partner unit	$	1.40		$	0.68			n/a
Weighted average limited partners units outstanding — basic and diluted		69.4			66.2			n/a

(a) Includes a $2.5 million and a $110.5 million benefit related to the elimination of accumulated deferred income tax liabilities in 2008 and 2007, respectively. See Note 6 for further discussion.

(b) Not applicable

See Notes to Consolidated Financial Statements

59

SPECTRA ENERGY PARTNERS, LP

CONSOLIDATED BALANCE SHEETS

	December 31,
	2008		2007
	(In millions)
ASSETS
Current Assets
Cash and cash equivalents	$	30.9	$	14.9
Receivables, trade (net of allowance for doubtful accounts of $0.5 and $0.3 at December 31, 2008 and 2007, respectively)		11.4		11.5
Receivables — affiliates		0.8		2.2
Natural gas imbalance receivables		2.2		1.3
Natural gas imbalance receivables — affiliates		2.5		1.3
Inventory		3.0		2.7
Fuel tracker		—		2.4
Other		1.5		—
Total current assets		52.3		36.3
Investments and Other Assets
Investments in unconsolidated affiliates		573.3		495.1
Goodwill		118.3		118.3
Other investments		31.6		154.8
Total investments and other assets		723.2		768.2
Property, Plant and Equipment
Cost		969.6		930.0
Less accumulated depreciation and amortization		154.4		133.7
Net property, plant and equipment		815.2		796.3
Regulatory Assets and Deferred Debits		10.8		10.5
Total Assets	$	1,601.5	$	1,611.3

See Notes to Consolidated Financial Statements

60

SPECTRA ENERGY PARTNERS, LP

CONSOLIDATED BALANCE SHEETS

	December 31,
	2008			2007
	(In millions)
LIABILITIES AND PARTNERS’ CAPITAL
Current Liabilities
Accounts payable	$	4.4		$	6.8
Accounts payable — affiliates		7.6			1.2
Taxes accrued		2.4			3.5
Interest accrued		0.8			1.6
Natural gas imbalance payables		3.2			3.1
Note payable — affiliates		50.0			50.0
Fuel tracker		2.8			—
Other		4.7			7.4
Total current liabilities		75.9			73.6
Long-term Debt		390.0			400.0
Deferred Credits and Other Liabilities
Deferred income taxes		8.8			10.7
Other		8.4			3.3
Total deferred credits and other liabilities		17.2			14.0
Commitments and Contingencies
Partners’ Capital
Predecessor equity		—			98.4
Common units (48.9 million and 44.6 million units issued and outstanding at December 31, 2008 and 2007, respectively)		794.5			699.3
Subordinated units (21.6 million units issued and outstanding)		304.7			303.5
General partner units (1.4 million units issued and outstanding)		21.4			19.0
Accumulated other comprehensive income (loss)		(2.2	)		3.5
Total partners’ capital		1,118.4			1,123.7
Total Liabilities and Partners’ Capital	$	1,601.5		$	1,611.3

See Notes to Consolidated Financial Statements

61

SPECTRA ENERGY PARTNERS, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Years Ended December 31,
	2008			2007			2006
	(In millions)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	101.3		$	202.9		$	68.1
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		26.3			26.4			21.4
Deferred income tax expense (benefit)		(2.0	)		(103.6	)		15.2
Equity in earnings of unconsolidated affiliates		(61.4	)		(55.6	)		(41.1	)
Distributions received from unconsolidated affiliates		71.7			22.7			20.3
Decrease (increase) in:
Receivables		3.7			(14.8	)		(0.1	)
Taxes receivable — affiliates		(0.2	)		1.5			—
Other current assets		(1.2	)		1.6			(1.1	)
Increase (decrease) in:
Accounts payable		2.5			8.4			(0.8	)
Taxes accrued		(1.1	)		3.8			(3.3	)
Other current liabilities		(1.4	)		(4.5	)		(8.9	)
Other, assets		1.2			1.6			(9.2	)
Other, liabilities		(0.2	)		(5.5	)		14.3
Net cash provided by operating activities		139.2			84.9			74.8
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(47.0	)		(30.4	)		(91.8	)
Investment expenditures		(88.6	)		(28.3	)		—
Acquisition of Saltville and P-25 pipeline		(4.7	)		—			—
Proceeds from sales of assets		—			8.3			—
Purchases of available-for-sale securities		(1,132.0	)		(1,439.0	)		—
Proceeds from sales and maturities of available-for-sale securities		1,255.0			1,284.4			—
Net cash used in investing activities		(17.3	)		(205.0	)		(91.8	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from issuance of debt under credit facilities		1,785.0			380.0			—
Payments for the redemption of debt under credit facilities		(1,795.0	)		(130.0	)		—
Proceeds from note payable — affiliates		—			50.0			—
Proceeds from issuance of common units		—			230.2			—
Dividends to parent		—			(12.5	)		—
Distributions to partners		(95.1	)		(20.3	)		—
Transfers from (to) parent, net		(0.8	)		(362.4	)		15.6
Net cash provided by (used in) financing activities		(105.9	)		135.0			15.6
Net increase (decrease) in cash and cash equivalents		16.0			14.9			(1.4	)
Cash and cash equivalents at beginning of the period		14.9			—			1.4
Cash and cash equivalents at end of the period	$	30.9		$	14.9		$	—
Supplemental Disclosures
Cash paid for interest, net of amount capitalized	$	14.3		$	10.3		$	8.6
Cash paid for income taxes		0.9			6.5			3.2

See Notes to Consolidated Financial Statements

62

SPECTRA ENERGY PARTNERS, LP

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL/PREDECESSOR

EQUITY AND COMPREHENSIVE INCOME

	Predecessor Equity			Partners’ Capital									Accumulated Other Comprehensive Income (Loss)			Total
				Limited Partners						General Partner
				Common			Subordinated
	(In millions)
December 31, 2005	$	1,001.1		$	—		$	—		$	—		$	4.1		$	1,005.2
Net income		68.1			—			—			—			—			68.1
Reclassification of cash flow hedges into earnings		—			—			—			—			(0.3	)		(0.3	)
Total comprehensive income																	67.8
Net change in parent advances		24.1			—			—			—			—			24.1
December 31, 2006		1,093.3			—			—			—			3.8			1,097.1
Net income attributable to the period January 1, 2007 through July 2, 2007		156.7			—			—			—			—			156.7
Net income attributable to the period July 3, 2007 through December 31, 2007		—			30.5			14.8			0.9			—			46.2
Reclassification of cash flow hedges into earnings		—			—			—			—			(0.3	)		(0.3	)
Total comprehensive income																	202.6
Dividends to parent		(12.5	)		—			—			—			—			(12.5	)
Distributions to partners		—			(13.4	)		(6.5	)		(0.4	)		—			(20.3	)
Net change in parent advances		(373.4	)		—			—			—			—			(373.4	)
Conversion to Spectra Energy Partners, LP		(765.7	)		452.0			295.2			18.5			—			—
Issuance of common units		—			230.2			—			—			—			230.2
December 31, 2007		98.4			699.3			303.5			19.0			3.5			1,123.7
Net income		1.6			66.9			30.3			2.5			—			101.3
Unrealized net loss on cash flow hedges		—			—			—			—			(6.2	)		(6.2	)
Reclassification of cash flow hedges into earnings		—			—			—			—			0.5			0.5
Total comprehensive income																	95.6
Net change in parent advances		(0.8	)		—			—			—			—			(0.8	)
Acquisition of Saltville and P-25 pipeline		(99.2	)		—			—			—			—			(99.2	)
Excess purchase price over net acquired assets		—			(7.6	)		—			(0.2	)		—			(7.8	)
Issuance of units		—			100.2			—			2.1			—			102.3
Attributed deferred tax expense		—			(0.2	)		(0.1	)		—			—			(0.3	)
Distributions to partners		—			(64.1	)		(29.0	)		(2.0	)		—			(95.1	)
December 31, 2008	$	—		$	794.5		$	304.7		$	21.4		$	(2.2	)	$	1,118.4

See Notes to Consolidated Financial Statements

63

SPECTRA ENERGY PARTNERS, LP

Notes to Consolidated Financial Statements

INDEX

		Page
1.	Summary of Operations and Significant Accounting Policies	64
2.	Acquisitions	71
3.	Transactions with Affiliates	77
4.	Business Segments	77
5.	Regulatory Matters	79
6.	Income Taxes	79
7.	Net Income per Limited Partner Unit and Cash Distributions	81
8.	Marketable Securities	82
9.	Investments in Unconsolidated Affiliates	83
10.	Property, Plant and Equipment	84
11.	Debt and Credit Facility	84
12.	Fair Value Measurements	85
13.	Deferred Revenues	86
14.	Commitments and Contingencies	86
15.	Interest Rate Risk, Credit Risk and Financial Instruments	86
16.	Equity-Based Compensation	87
17.	Subsequent Event	88
18.	Quarterly Financial Data (Unaudited)	88

1. Summary of Operations and Significant Accounting Policies

The terms “we,” “our,” “us,” and “Spectra Energy Partners” as used in this report refer collectively to Spectra Energy Partners, LP and its subsidiaries unless the context suggests otherwise. These terms are used for convenience only and are not intended as a precise description of any separate legal entity within Spectra Energy Partners.

Nature of Operations. Spectra Energy Partners, LP, through its subsidiaries and equity affiliates are engaged in the transportation of natural gas through interstate pipeline systems that serve the southeastern United States, and the storage of natural gas in underground facilities that are located in southeast Texas, south central Louisiana and southwest Virginia. We are a Delaware master limited partnership formed on March 19, 2007.

Initial Public Offering. On July 2, 2007, immediately prior to the closing of our initial public offering (IPO), Spectra Energy Corp (Spectra Energy) contributed to us 100% of the ownership of East Tennessee Natural Gas LLC (East Tennessee) less certain working capital balances retained as per the partnership agreements, 50% of the ownership of Market Hub Partners Holding (Market Hub), formerly Market Hub Partners Holding, LLC, and a 24.5% interest in Gulfstream Natural Gas System, L.L.C. (Gulfstream). See Note 3 for further information regarding the working capital transfers. Spectra Energy indirectly owned 100% of our partnership prior to the closing of the IPO.

On July 2, 2007, we completed our IPO. We issued 11.5 million common units to the public, representing 17% of our outstanding equity. Net cash of $230.2 million was received by us upon closing of the IPO. Spectra Energy retained an 83% equity interest in our partnership, including common units, subordinated units and a 2% general partner interest. Approximately $26.0 million of these proceeds were distributed to Spectra Energy, $194.0 million was used to purchase qualifying investment-grade securities, and $10.0 million was retained by us to meet working capital requirements. Also on July 2, 2007, we borrowed $194.0 million in term debt using the investment-grade securities as collateral and borrowed an additional $125.0 million of revolving debt. Proceeds from these borrowings, totaling $319.0 million, were distributed to Spectra Energy.

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Acquisitions. On April 4, 2008, we completed the acquisition of the equity interests of Saltville Gas Storage Company L.L.C. (Saltville) and the P-25 pipeline from Spectra Energy Capital, LLC (collectively, hereafter referred to as the “Saltville acquisition”). The Saltville acquisition represented a transfer of entities under common control. Accordingly, the Consolidated Financial Statements and related information presented herein have been recast to include the historical results of Saltville and the P-25 pipeline for all periods presented. See Note 2 for further discussion.

Basis of Presentation. For periods prior to the closing of the IPO, the combined financial statements were prepared from the separate records maintained by Spectra Energy Capital, LLC for the entities that were originally contributed to us and for the operations included in the Saltville acquisition, and are based on Spectra Energy Capital, LLC’s historical ownership percentages of those operations. The combined financial results of these entities are treated as the historical results of our partnership for financial statement reporting purposes. Both the combined financial statements of East Tennessee, Saltville, Market Hub and Gulfstream, as well as the consolidated financial statements of our partnership for the periods post-IPO, are hereafter referred to as the Consolidated Financial Statements. The historical data for periods prior to the closing of the IPO and for periods prior to the Saltville acquisition may not necessarily be indicative of the actual results of operations had those entities been operated separately during those periods. Because a direct ownership relationship did not exist among entities comprising our partnership prior to July 2, 2007 and prior to the Saltville acquisition on April 4, 2008, the net investment in our partnership is shown as Predecessor Equity in the applicable Consolidated Financial Statements.

We generally account for investments in 20% to 50%-owned affiliates, and investments in less than 20%-owned affiliates where we have the ability to exercise significant influence, under the equity method. Accordingly, the consolidated historical financial statements for our partnership reflect the consolidation of East Tennessee and Saltville, and the investments in Market Hub and Gulfstream using the equity method of accounting. All intercompany balances and transactions have been eliminated in consolidation.

Spectra Energy managed its cash on a centralized basis for the entire Spectra Energy consolidated group, which in the periods up to the completion of our IPO, included the various assets and operations of the companies comprising our partnership. Gulfstream did not participate in the centralized cash management activity of Spectra Energy. The individual cash accounts maintained at the business unit levels (i.e. within our entities) were swept to a Spectra Energy corporate account on a daily basis, creating an Advance Receivable between Spectra Energy (or other affiliates/corporate entities) and the individual entities that now comprise our partnership. Therefore, our financials do not reflect any cash balances prior to the IPO. These net advances did not bear interest and were carried as unsecured, intercompany balances. Spectra Energy and our entities settled the cumulative advance balances through equity distributions or contributions prior to our IPO. Therefore, the consolidated net advances have been reclassified to Predecessor Equity in the Consolidated Balance Sheets.

Our costs of doing business have been reflected in our financial accounting records for the periods presented. These costs include direct charges and allocations from Spectra Energy and its affiliates for business services, such as payroll, accounts payable and facilities management; corporate services, such as finance and accounting, legal, human resources, investor relations, public and regulatory policy, and senior executives; and pension and other post-retirement benefit costs.

Transactions between us and Spectra Energy and its affiliates have been identified in the Consolidated Financial Statements as transactions between affiliates. See Note 3 for further discussion.

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

Fair Value Measurements. Effective January 1, 2008, we adopted the required provisions of Statement of Financial Accounting Standards (SFAS) No. 157, “Fair Value Measurements,” for financial assets and liabilities.

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SFAS No. 157 defines fair value, establishes a consistent framework for measuring fair value and expands disclosure requirements about fair value measurements. SFAS No. 157 requires entities to, among other things, maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.

SFAS No. 157 defines fair value as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date.

SFAS No. 157 specifies a hierarchy of valuation techniques based on whether the inputs to those valuation techniques are observable or unobservable. Observable inputs reflect market data obtained from independent sources, while unobservable inputs reflect our market assumptions. In accordance with SFAS No. 157, these two types of inputs have created the following fair value hierarchy:

• Level 1 — Quoted unadjusted prices for identical instruments in active markets.

• Level 2 — Quoted prices for similar instruments in active markets; quoted prices for identical or similar instruments in markets that are not active; and model-derived valuations in which all significant inputs and significant value drivers are observable in active markets.

• Level 3 — Model derived valuations in which one or more significant inputs or significant value drivers are unobservable.

Cash and Cash Equivalents. Highly liquid investments with original maturities of three months or less at the date of acquisition, except for the investments that are pledged as collateral against long-term debt as discussed in Note 11, are considered cash equivalents.

Inventory. Inventory consists primarily of other materials and supplies and is recorded at cost, using average cost.

Natural Gas Imbalances. The Consolidated Balance Sheets include in-kind balances as a result of differences in gas volumes received and delivered for customers. Since settlement of imbalances is in-kind, changes in these balances do not have an effect on our Consolidated Statements of Cash Flows. Natural gas volumes owed to or by us are valued at natural gas market index prices as of the balance sheet dates.

Investments. We may actively invest a portion of our cash balances in various financial instruments, including taxable or tax-exempt debt securities. In addition, we invest in short-term money market securities, some of which are restricted due to debt collateral requirements. We have classified all investments that are debt securities with maturity dates over one year as available-for-sale under SFAS No. 115, “Accounting For Certain Investments in Debt and Equity Securities,” and they are carried at fair market value. Investments in money-market securities are accounted for at fair value. 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. The cost of securities sold is determined using the specific identification method. Purchases and sales of available-for-sale securities are presented on a gross basis within Cash Flows from Investing Activities in the accompanying Consolidated Statements of Cash Flows.

Goodwill. We evaluate goodwill for potential impairment under the guidance of SFAS No. 142, “Goodwill and Other Intangible Assets.” Under this standard, goodwill is subject to an annual test for impairment. We have designated August 31 as the date we perform the annual review for goodwill impairment. Under the provisions of SFAS No. 142, we perform the annual review for goodwill impairment at the reporting unit level, which we have 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

66

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.

We completed our annual goodwill impairment test as of August 31, 2008 and no impairments were identified. We primarily use a discounted cash flow analysis to determine fair value for our reporting unit. Key assumptions in the determination of fair value include the use of an appropriate discount rate and estimated future cash flows. In estimating cash flows, we incorporate expected long-term growth rates, regulatory stability and the ability to renew contracts, as well as other factors that affect our revenue, expense and capital expenditure projections. We did not record any impairment of goodwill in 2008, 2007 and 2006, and there have been no additions, amortization or other changes in the carrying amount of goodwill during the years then ended. Goodwill of our sole operating segment, Gas Transportation and Storage, was $118.3 million at both December 31, 2008 and 2007.

Property, Plant and Equipment. Property, plant and equipment are stated at historical cost less accumulated depreciation. We capitalize 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 or increase the expected output of property, plant and equipment is also capitalized. The cost of repairs, replacements and major maintenance projects that do not extend the useful life or increase the expected output of property, plant and equipment, is expensed as incurred. Depreciation is generally computed over the asset’s estimated useful life using the straight-line method. The composite weighted-average depreciation rates were 2.8% for 2008, 3.0% for 2007 and 2.6% for 2006. See also “Allowance for Funds Used During Construction (AFUDC)” discussed below.

When we retire our regulated property, plant and equipment, we charge the original cost plus the cost of retirement, less salvage value, to accumulated depreciation and amortization. When we sell entire regulated operating units, or retire or sell 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.

Unamortized Debt Expense. Debt expenses incurred with the issuance of outstanding long-term debt are amortized over the terms of the debt issues. Any call premiums or unamortized expenses associated with refinancing higher-cost debt obligations to finance regulated assets and operations are amortized consistent with regulatory treatment of those items, where appropriate.

Environmental Expenditures. We expense 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. Undiscounted 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. We account for our regulated operations at East Tennessee and Saltville under the provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” 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, we record assets and liabilities that result from the regulated ratemaking process that may not be recorded under GAAP for non-regulated entities. We continually assess whether regulatory assets are probable of future recovery by considering factors such as applicable regulatory changes and recent rate orders applicable to other regulated entities. Based on this continual assessment, we believe the existing regulatory assets are probable of recovery. These regulatory assets are classified in the

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Consolidated Balance Sheets as Regulatory Assets and Deferred Debits. We had no regulatory liabilities as of December 31, 2008 and 2007. We periodically evaluate the applicability of SFAS No. 71, and consider factors such as regulatory changes and the effect of competition. If cost-based regulation ends or competition increases, we may have to reduce certain of our asset balances to reflect a market basis lower than cost and write-off the associated regulatory assets. See Note 5 for further discussion.

Revenue Recognition. Revenues from the transportation and storage of natural gas and the storage of liquefied natural gas (LNG) are recognized when the service is provided. Revenues related to these services provided but not yet billed are estimated each month. These estimates are generally based on contract data, regulatory information 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.

Significant Customers. Customers accounting for 10% or more of consolidated revenues during 2008, 2007 or 2006 are as follows:

	% of Revenues
Customer	2008		2007		2006
Atmos Energy Corporation	14	%	15	%	16	%
KGen Murray I and II, LLC	(a	)	(a	)	11

(a) Percentage less than 10%

Allowance for Funds Used During Construction. AFUDC, which represents the estimated debt and equity costs of capital funds necessary to finance the construction and expansion of new regulated facilities, consists of two components, an equity component and an interest expense component. The equity component is a non-cash item. AFUDC is capitalized as a component of property, plant and equipment, with offsetting credits to the Consolidated Statements of Operations through Other Income and Expenses, Net for the equity component and Interest Expense for the interest expense component. After construction is completed, we are permitted to recover these costs through inclusion in the rate base and in the depreciation provision. The total amount of AFUDC included in the Consolidated Statements of Operations was $1.1 million in 2008 (an equity component of $0.9 million and an interest expense component of $0.2 million), $0.3 million in 2007 (an equity component of $0.2 million and an interest expense component of $0.1 million) and $3.0 million in 2006 (an equity component of $2.1 million and an interest expense component of $0.9 million).

Preliminary Project Costs. Project costs, including expenditures for preliminary surveys, plans, investigations, environmental studies, regulatory applications and other costs incurred for the purpose of determining the feasibility of capital expansion projects, are initially included in operating expenses. If and when it is determined that recovery of such costs through regulated revenues of the completed project is probable, the inception-to-date costs of the project are recognized as Property, Plant and Equipment in accordance with the provisions of SFAS No. 71 and operating expenses are reduced.

Income Taxes. Our Gas Transportation and Storage operations were subject to corporate income tax under tax sharing agreements with Spectra Energy in 2007 and with Duke Energy Corporation (Duke Energy) in 2006 prior to the spin-off of Spectra Energy from Duke Energy on January 2, 2007. During those periods, income taxes were calculated by us on the basis of our separate company income and deductions related to Gas Transportation and Storage in accordance with respective established practices of Spectra Energy and Duke Energy. 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.

Market Hub and Gulfstream are not subject to federal income tax, but rather the taxable income or loss of these entities is reported on the income tax returns of the respective members. Market Hub is subject to Texas income (franchise) taxes under a tax sharing agreement with Spectra Energy.

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We adopted Financial Accounting Standards Board (FASB) Interpretation (FIN) No. 48, “Accounting for Uncertainty in Income Taxes, an Interpretation of FAS 109,” on January 1, 2007. The implementation of FIN 48 had no material impact on the consolidated financial statements.

Segment Reporting. SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information,” establishes standards for a public company to report financial and descriptive information about its reportable operating segments in interim and annual 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 our defined business segment. A description of our reportable segment, consistent with how business results are reported internally to management and the disclosure of segment information in accordance with SFAS No. 131, is presented in Note 4.

Distributions from Unconsolidated Affiliates. We consider distributions received from unconsolidated affiliates which do not exceed cumulative equity in earnings subsequent to the date of investment to be a return on investment and classify these amounts as operating activities within the accompanying Consolidated Statements of Cash Flows. Cumulative distributions received in excess of cumulative equity in earnings subsequent to the date of investment are considered to be a return of investment and are classified as investing activities.

Cash Flow Hedges. We have entered into interest rate swaps which were designated as effective cash flow hedges. Changes in the fair value of a derivative designated and qualified as a cash flow hedge, to the extent effective, are reported as Accumulated Other Comprehensive Income (Loss) (AOCI) until earnings are affected by the hedged transaction.

New Accounting Pronouncements — 2008. The following new accounting pronouncements were adopted during 2008 and the effect of such adoption, if applicable, has been presented in the accompanying Consolidated Financial Statements:

SFAS No. 157, “Fair Value Measurements.” SFAS No. 157, defines fair value, establishes a framework for measuring fair value in GAAP and expands disclosures about fair value measurements. In February 2008, the FASB issued FASB Staff Position (FSP) No. FAS 157-1, “Application of FASB Statement No. 157 to FASB Statement No. 13 and Other Accounting Pronouncements that Address Fair Value Measurements for Purposes of Lease Classification or Measurement under Statement 13.” Also in February 2008, the FASB issued FSP No. FAS 157-2, “Effective Date of FASB Statement No. 157,” which delays the effective date of SFAS No. 157 to fiscal years beginning after November 15, 2008 for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). The adoption of SFAS No. 157 and FSP No. FAS 157-1 effective January 1, 2008 did not have a material impact on our consolidated results of operations, financial position or cash flows. See Note 12 for further discussion. As permitted under FSP No. FAS 157-2, we have elected to defer the adoption of SFAS No. 157 for our goodwill impairment test until January 1, 2009, and do not expect the adoption of FSP No. FAS 157-2 to measure these items will have a material impact on our consolidated results of operations, financial position or cash flows.

In October 2008, the FASB issued FSP No. FAS 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active,” which clarifies the application of SFAS No. 157 in determining the fair value of a financial asset when the market for that financial asset is not active. FSP No. FAS 157-3 was effective upon issuance, including prior periods for which financial statements have not been issued. Revisions in

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fair values resulting from a change in the valuation technique or its application would be accounted for as a change in accounting estimate. The adoption of FSP No. FAS 157-3 had no impact on our consolidated results of operations, financial position or cash flows.

SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities.” In February 2007, the FASB issued SFAS No. 159, which permits entities to choose to measure certain financial instruments at fair value. We have determined to not elect fair value measurements for financial assets and financial liabilities included in the scope of SFAS No. 159.

2006. The following significant accounting pronouncements were adopted during 2006 and the effect of such adoption, if applicable, has been presented in the accompanying Consolidated Financial Statements:

Federal Energy Regulatory Commission Accounting Order. In 2005, the Federal Energy Regulatory Commission (FERC) issued an Order on Accounting for Pipeline Assessment Costs that requires most pipeline inspection and integrity assessment activities to be recognized as expenses as incurred. In the Order, the FERC confirmed that pipeline betterments and replacements, including those resulting from integrity inspections, will continue to be capitalized when appropriate. This FERC Order was effective for pipeline inspection and integrity assessment costs incurred on or subsequent to January 1, 2006 and increased our annual expenses $1.2 million in 2008, $3.2 million in 2007 and $1.9 million in 2006. Pipeline inspection and integrity assessment costs capitalized prior to the effective date of the rule were not affected.

Pending. The following new accounting pronouncements have been issued, but have not yet been adopted as of December 31, 2008:

SFAS No. 141R, “Business Combinations.” In December 2007, the FASB issued SFAS No. 141R which replaces SFAS No. 141, “Business Combinations.” SFAS No. 141R requires the acquiring entity in a business combination to recognize all and only the assets acquired and liabilities assumed in the transaction, establishes the acquisition-date fair value as the measurement objective for all assets acquired and liabilities assumed, and requires the acquirer to disclose to investors and other users all of the information they need to evaluate and understand the nature and financial effect of the business combination. SFAS No. 141R applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008 and cannot be early adopted.

SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133.” In March 2008, the FASB issued SFAS No. 161 which amends and expands the disclosure requirements for SFAS No. 133 with the intent to provide users of financial statements an enhanced understanding of how and why derivative instruments are used, how derivative instruments and related hedged items are accounted for under SFAS No. 133 and its related interpretations and how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. We adopted the provisions of SFAS No. 161 effective January 1, 2009 as required.

EITF 07-4, “Application of the Two-Class Method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships.” In March 2008, the FASB ratified a consensus reached by the Emerging Issues Task Force (EITF) that addresses the application of the two-class method for master limited partnerships (MLPs) when incentive distribution rights (IDRs) are present and entitle the IDR holder to a portion of distributions. The final consensus states that when earnings exceed distributions, the computation of earnings per unit (EPU) should be based on the terms of the partnership agreement. Accordingly, any contractual limitations on the distributions to IDR holders (e.g., limitations that only entitle IDR holders to “available cash”) would need to be determined for each reporting period. The guidance in EITF 07-4 is effective for periods that begin after December 15, 2008, and would be accounted for as a change in accounting principle through retrospective application. Early application is not permitted. As we currently follow the guidance of EITF 03-6, “Participating Securities and the Two-Class Method under FASB Statement No. 128, Earnings Per Share”, no change to our current practice of computing net income per limited partner unit is anticipated. However, because our distributions to IDR holders are limited to available cash, the EPU attributable to IDRs will continue to be limited to our available cash.

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FSP No. FAS 142-3, “Determination of the Useful Life of Intangible Assets.” In April 2008, the FASB issued FSP No. FAS 142-3 which amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142, “Goodwill and Other Intangible Assets.” The adoption of the provisions of FSP No. FAS 142-3 on January 1, 2009 had no impact on our consolidated results of operations, financial position or cash flows.

2. Acquisitions

On April 4, 2008, we completed the Saltville acquisition from Spectra Energy at a purchase price of $107.0 million, which included the issuance of 4,207,641 common units and 85,870 general partner units, and a cash payment of $4.7 million to Spectra Energy. Saltville assets include three separate natural gas storage facilities adjacent to the East Tennessee system in southwest Virginia with approximately 5.5 billion cubic feet of working capacity. The P-25 pipeline, now part of the operations of East Tennessee, is a 72-mile, eight-inch natural gas pipeline with a capacity of 40 million cubic feet per day that runs parallel to the East Tennessee system in Virginia. The Saltville storage assets and the P-25 pipeline are strategically integrated with our East Tennessee system. The completion of the Saltville acquisition allows for a streamlined regulatory structure under the FERC jurisdiction, an enhanced operational flexibility that will benefit both East Tennessee and Saltville customers and a broader array of organic expansion opportunities for our pipeline and storage assets.

Spectra Energy’s ownership of our partnership increased from 83% to 84% as a result of receipt of the new common and general partner units. The $7.8 million excess purchase price over the book value of net assets acquired was recorded as a reduction to Partners’ Capital, and the $102.3 million of common and general partner units issued were recorded as increases to Partners’ Capital.

As discussed in Note 1, the Saltville acquisition represented a transfer of entities under common control, which requires that the assets and liabilities acquired be recorded at historical book value and that our financial statements be presented on a basis similar to the pooling method of accounting, whereby all historical periods are retroactively adjusted to furnish comparative financial information as if the transaction had occurred immediately prior to the earliest period presented.

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Consolidated Statements of Operations. The historical Consolidated Statements of Operations for the years ended December 31, 2007 and 2006 have been recast to retroactively reflect the Saltville acquisition, as presented below.

	Year Ended December 31, 2007											Year Ended December 31, 2006
	Previously Reported			Saltville		Eliminations			As Recast			Previously Reported		Saltville			Eliminations			As Recast
	(In millions)
Operating Revenues
Transportation of natural gas	$	98.2		$	2.7	$	(0.3	)	$	100.6		$	80.6	$	2.4		$	(0.1	)	$	82.9
Storage of natural gas and other		1.9			19.7		(1.1	)		20.5			2.0		19.5			(2.9	)		18.6
Total operating revenues		100.1			22.4		(1.4	)		121.1			82.6		21.9			(3.0	)		101.5
Operating Expenses
Operating, maintenance and other		15.7			10.7		—			26.4			9.0		5.1			—			14.1
Operating, maintenance and other — affiliates		4.3			0.4		(1.4	)		3.3			12.8		2.9			(3.0	)		12.7
Depreciation and amortization		23.2			3.2		—			26.4			19.0		2.4			—			21.4
Property and other taxes		2.8			1.6		—			4.4			4.2		1.2			—			5.4
Total operating expenses		46.0			15.9		(1.4	)		60.5			45.0		11.6			(3.0	)		53.6
Operating Income		54.1			6.5		—			60.6			37.6		10.3			—			47.9
Other Income and Expenses
Equity in earnings of unconsolidated affiliates		55.6			—		—			55.6			41.1		—			—			41.1
Other income and expenses, net		0.3			0.1		—			0.4			1.8		0.3			—			2.1
Total other income and expenses		55.9			0.1		—			56.0			42.9		0.3			—			43.2
Interest Income		5.5			—		—			5.5			—		—			—			—
Interest Expense		17.1			—		—			17.1			8.2		(0.5	)		—			7.7
Earnings Before Income Taxes		98.4			6.6		—			105.0			72.3		11.1			—			83.4
Income Tax Expense (Benefit)		(99.1	)		1.2		—			(97.9	)		10.7		4.6			—			15.3
Net Income	$	197.5		$	5.4	$	—		$	202.9		$	61.6	$	6.5		$	—		$	68.1

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Consolidated Balance Sheet. The historical Consolidated Balance Sheet as of December 31, 2007 has been recast to retroactively reflect the Saltville acquisition, as presented below.

	December 31, 2007
	Previously Reported		Saltville		Eliminations			As Recast
	(In millions)
ASSETS
Current Assets
Cash and cash equivalents	$	14.9	$	—	$	—		$	14.9
Receivables, trade		9.9		1.6		—			11.5
Receivables — affiliates		1.9		—		0.3			2.2
Natural gas imbalance receivables		0.8		0.5		—			1.3
Natural gas imbalance receivables — affiliates		3.9		1.1		(3.7	)		1.3
Inventory		2.6		0.1		—			2.7
Fuel tracker		2.4		—		—			2.4
Total current assets		36.4		3.3		(3.4	)		36.3
Investments and Other Assets
Investments in unconsolidated affiliates		495.1		—		—			495.1
Goodwill		118.3		—		—			118.3
Other investments		154.8		—		—			154.8
Total investments and other assets		768.2		—		—			768.2
Property, Plant and Equipment
Cost		821.4		108.6		—			930.0
Less accumulated depreciation and amortization		128.8		4.9		—			133.7
Net property, plant and equipment		692.6		103.7		—			796.3
Regulatory Assets and Deferred Debits		10.4		0.1		—			10.5
Total Assets	$	1,507.6	$	107.1	$	(3.4	)	$	1,611.3

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	December 31, 2007
	Previously Reported		Saltville		Eliminations			As Recast
	(In millions)
LIABILITIES AND PARTNERS’ CAPITAL
Current Liabilities
Accounts payable	$	6.1	$	0.7	$	—		$	6.8
Accounts payable — affiliates		0.9		—		0.3			1.2
Taxes accrued		2.9		0.6		—			3.5
Interest accrued		1.6		—		—			1.6
Natural gas imbalance payables		0.8		2.3		—			3.1
Natural gas imbalance payables — affiliates		3.2		0.5		(3.7	)		—
Note payable — affiliates		50.0		—		—			50.0
Other		5.8		1.6		—			7.4
Total current liabilities		71.3		5.7		(3.4	)		73.6
Long-term Debt		400.0		—		—			400.0
Deferred Credit and Other Liabilities
Deferred income taxes		8.4		2.3		—			10.7
Other		2.6		0.7		—			3.3
Total deferred credits and other liabilities		11.0		3.0		—			14.0
Partners’ Capital
Predecessor equity		—		98.4		—			98.4
Common units		699.3		—		—			699.3
Subordinated units		303.5		—		—			303.5
General partner units		19.0		—		—			19.0
Accumulated other comprehensive income		3.5		—		—			3.5
Total partners’ capital		1,025.3		98.4		—			1,123.7
Total Liabilities and Partners’ Capital	$	1,507.6	$	107.1	$	(3.4	)	$	1,611.3

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Consolidated Statement of Cash Flows. The historical Consolidated Statements of Cash Flows for the years ended December 31, 2007 and 2006 have been recast to retroactively reflect the Saltville acquisition, as presented below.

	Year Ended December 31, 2007
	Previously Reported			Saltville			Eliminations			As Recast
	(In millions)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	197.5		$	5.4		$	—		$	202.9
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		23.2			3.2			—			26.4
Deferred income tax expense (benefit)		(104.6	)		1.0			—			(103.6	)
Equity in earnings of unconsolidated affiliates		(55.6	)		—			—			(55.6	)
Distributions received from unconsolidated affiliates		22.7			—			—			22.7
Decrease (increase) in:
Receivables		(15.3	)		0.8			(0.3	)		(14.8	)
Taxes receivables — affiliates		1.5			—			—			1.5
Other current assets		—			1.6			—			1.6
Increase (decrease) in:
Accounts payable		7.9			0.2			0.3			8.4
Taxes accrued		3.2			0.6			—			3.8
Other current liabilities		(4.7	)		0.2			—			(4.5	)
Other, assets		0.9			0.7			—			1.6
Other, liabilities		(4.3	)		(1.2	)		—			(5.5	)
Net cash provided by operating activities		72.4			12.5			—			84.9
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(27.0	)		(3.4	)		—			(30.4	)
Investment expenditures		(28.3	)		—			—			(28.3	)
Proceeds from sales of assets		—			8.3			—			8.3
Purchases of available-for-sale securities		(1,439.0	)		—			—			(1,439.0	)
Proceeds from sales and maturities of available-for-sale securities		1,284.4			—			—			1,284.4
Net cash provided by (used in) investing activities		(209.9	)		4.9			—			(205.0	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from issuance of debt under credit facilities		380.0			—			—			380.0
Payments for the redemption of debt under credit facilities		(130.0	)		—			—			(130.0	)
Proceeds from note payable — affiliates		50.0			—			—			50.0
Proceeds from issuance of common units		230.2			—			—			230.2
Dividends to parent		(12.5	)		—			—			(12.5	)
Distributions to partners		(20.3	)		—			—			(20.3	)
Transfers to parent, net		(345.0	)		(17.4	)		—			(362.4	)
Net cash provided by (used in) financing activities		152.4			(17.4	)		—			135.0
Net increase in cash and cash equivalents		14.9			—			—			14.9
Cash and cash equivalents at beginning of period		—			—			—			—
Cash and cash equivalents at end of period	$	14.9		$	—		$	—		$	14.9

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	Year Ended December 31, 2006
	Previously Reported			Saltville			Eliminations			As Recast
	(In millions)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	61.6		$	6.5		$	—		$	68.1
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		19.0			2.4			—			21.4
Deferred income tax expense		12.8			2.4			—			15.2
Equity in earnings of unconsolidated affiliates		(41.1	)		—			—			(41.1	)
Distributions received from unconsolidated affiliates		20.3			—			—			20.3
Decrease (increase) in:
Receivables		0.1			(0.4	)		0.2			(0.1	)
Other current assets		(0.9	)		(0.2	)		—			(1.1	)
Increase (decrease) in:
Accounts payable		(0.8	)		0.2			(0.2	)		(0.8	)
Taxes accrued		(3.3	)		—			—			(3.3	)
Other current liabilities		(8.9	)		—			—			(8.9	)
Other, assets		(9.5	)		0.3			—			(9.2	)
Other, liabilities		13.0			1.3			—			14.3
Net cash provided by operating activities		62.3			12.5			—			74.8
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(85.9	)		(5.9	)		—			(91.8	)
Net cash used in investing activities		(85.9	)		(5.9	)		—			(91.8	)
CASH FLOWS FROM FINANCING ACTIVITIES
Transfers from (to) parent, net		23.6			(8.0	)		—			15.6
Net cash provided by (used in) financing activities		23.6			(8.0	)		—			15.6
Net decrease in cash and cash equivalents		—			(1.4	)		—			(1.4	)
Cash and cash equivalents at beginning of period		—			1.4			—			1.4
Cash and cash equivalents at end of period	$	—		$	—		$	—		$	—

Consolidated Statements of Partners’ Capital/Predecessor Equity. The historical Consolidated Statements of Partners’ Capital/Predecessor Equity for the years ended December 31, 2007 and 2006 have been recast to retroactively reflect the Saltville acquisition, as presented below.

	Previously Reported			Saltville			As Recast
	(In millions)
December 31, 2005	$	895.7		$	109.5		$	1,005.2
Net income		61.6			6.5			68.1
Reclassification of cash flow hedges into earnings		(0.3	)		—			(0.3	)
Net change in parent advances		32.1			(8.0	)		24.1
December 31, 2006	$	989.1		$	108.0		$	1,097.1
Net income		197.5			5.4			202.9
Reclassification of cash flow hedges into earnings		(0.3	)		—			(0.3	)
Dividends to parent		(12.5	)		—			(12.5	)
Net change in parent advances		(378.7	)		(15.0	)		(393.7	)
Issuance of common units		230.2			—			230.2
December 31, 2007	$	1,025.3		$	98.4		$	1,123.7

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3. Transactions with Affiliates

In the normal course of business, we provide natural gas transportation, storage and other services to Spectra Energy and its affiliates.

In addition, pursuant to an agreement with Spectra Energy, Spectra Energy and its affiliates perform centralized corporate functions for us, including legal, accounting, compliance, treasury, information technology and other areas. We reimburse Spectra Energy for the expenses to provide these services as well as other expenses it incurs on our behalf, such as salaries of personnel performing services for our benefit and the cost of employee benefits and general and administrative expenses associated with such personnel, capital expenditures, maintenance and repair costs, taxes and direct expenses, including operating expenses and certain allocated operating expenses associated with the ownership and operation of the contributed assets. Spectra Energy and its affiliates charge such expenses based on the cost of actual services provided or using various allocation methodologies based on our percentage of assets, employees, earnings or other measures, as compared to Spectra Energy’s other affiliates. In 2008, we also entered into interest rate swap agreements with Spectra Energy to mitigate our exposure to variable interest rates.

Transactions with affiliates are summarized in the tables below:

Consolidated Statements of Operations

	2008		2007		2006
	(In millions)
Operating, maintenance and other expenses	$	23.4	$	3.3	$	12.7
Interest expense		1.5		0.6		—

Consolidated Balance Sheets

	December 31,
	2008		2007
	(In millions)
Receivables	$	0.8	$	2.2
Natural gas imbalance receivables		2.5		1.3
Current assets — other		0.5		—
Accounts payable		7.6		1.2
Note payable		50.0		50.0
Deferred credits and other liabilities — other		5.6		—

See also Notes 1, 9, 11, 12 and 15 for discussion of other specific related party transactions.

In accordance with our partnership formation agreements, East Tennessee transferred $13.4 million of certain working capital balances to Spectra Energy immediately prior to the formation of our partnership on July 2, 2007. These balances were primarily comprised of accounts receivable and advances from Spectra Energy totaling $20.5 million, net of tax liabilities retained by Spectra Energy of $7.1 million.

4. Business Segments

Prior to the Saltville acquisition, East Tennessee was considered our sole reportable segment. Effective upon completion of the acquisition, we created a new business segment, Gas Transportation and Storage, that aligns our operations with the chief operating decision maker’s view of the business. All prior periods presented have been recast to conform the business segment disclosures to the new segment structure. Our business segment is considered to be the sole reportable segment under the guidance of SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information.”

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Gas Transportation and Storage includes East Tennessee and Saltville. This segment provides interstate transportation of natural gas and the storage and redelivery of LNG for customers in the southeastern U.S. These operations are primarily subject to the FERC and the Department of Transportation’s (DOT) rules and regulations.

The remainder of our operations is presented as “Other.” While it is not considered a business segment, Other primarily includes our equity investments in Gulfstream and Market Hub, other investments and certain unallocated corporate costs.

Gulfstream provides interstate natural gas pipeline transportation for customers in central and southern Florida. Gulfstream’s operations are subject to the rules and regulations of the FERC and DOT.

Market Hub owns and operates two natural gas storage facilities, Moss Bluff and Egan, which are located in Southeast Texas and South Central Louisiana, respectively. Market Hub’s operations are subject to the rules and regulations of DOT. Moss Bluff is also subject to the rules and regulations of the Texas Railroad Commission. Egan is also subject to the rules and regulations of the FERC.

Management evaluates segment performance primarily based on earnings before interest and taxes from continuing operations (EBIT). On a segment basis, EBIT represents all profits from continuing operations (both operating and non-operating) before deducting interest and taxes.

Business Segment Data

	Total Revenues		Segment EBIT/ Consolidated Earnings Before Income Taxes		Depreciation and Amortization		Capital and Investment Expenditures		Segment/ Total Assets
	(In millions)
2008
Gas Transportation and Storage	$	124.9	$	61.5	$	26.3	$	47.0	$	977.7
Other		—		52.7		—		88.6		623.8
Total		124.9		114.2		26.3		135.6		1,601.5
Interest income		—		3.5		—		—		—
Interest expense		—		17.8		—		—		—
Total consolidated	$	124.9	$	99.9	$	26.3	$	135.6	$	1,601.5
2007
Gas Transportation and Storage	$	121.1	$	64.2	$	26.4	$	30.4	$	968.1
Other		—		52.4		—		28.3		643.2
Total		121.1		116.6		26.4		58.7		1,611.3
Interest income		—		5.5		—		—		—
Interest expense		—		17.1		—		—		—
Total consolidated	$	121.1	$	105.0	$	26.4	$	58.7	$	1,611.3
2006
Gas Transportation and Storage	$	101.5	$	52.7	$	21.4	$	91.8
Other		—		38.4		—		—
Total		101.5		91.1		21.4		91.8
Interest expense		—		7.7		—		—
Total consolidated	$	101.5	$	83.4	$	21.4	$	91.8

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5. Regulatory Matters

Regulatory Assets. Our regulated operations are subject to SFAS No. 71. Accordingly, we record assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for non-regulated entities. See Note 1 for further discussion.

	December 31,				Recovery/Refund Period Ends
	2008		2007
	(In millions)
Regulatory Assets (1)
Regulatory asset related to income taxes	$	8.7	$	8.4	(2)
Vacation accrual (non-current)		1.3		1.2	2009
Total Regulatory Assets	$	10.0	$	9.6

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

(2) Amortized over the life of the related property, plant and equipment.

All regulatory assets are excluded from rate base unless otherwise noted. There were no regulatory liabilities as of December 31, 2008 and 2007.

Rate Related Information

East Tennessee. On November 1, 2005, East Tennessee placed into effect new rates approved by the FERC as a result of a rate settlement with customers. The settlement agreement includes a five-year rate moratorium and certain operational changes.

Saltville. On September 1, 2008, Saltville placed into effect new rates approved by the FERC as a result of a settlement with customers associated with a rate proceeding. This settlement includes a rate moratorium until October 1, 2011.

Gulfstream. In June 2007, the FERC issued an order approving Gulfstream’s Phase III expansion project. That order also required Gulfstream to file a Cost and Revenue Study three years after the Phase III facilities go in service. The projected filing date would be the fall of 2011.

Management believes that the effects of these matters will not have a material adverse effect on our future consolidated results of operations, financial position or cash flows.

6. Income Taxes

Income taxes with respect to our East Tennessee and Saltville operations were calculated by us in 2007 and 2006 on the basis of their separate company income and deductions in accordance with established practices of Spectra Energy.

In conjunction with the contribution by Spectra Energy of the ownership of East Tennessee to us immediately prior to the IPO, $110.5 million of federal income tax liabilities outstanding at June 30, 2007 were eliminated and recorded as a benefit to Income Tax Expense (Benefit) on the Consolidated Statements of Operations. Effective July 2, 2007, as a result of our MLP structure, we are no longer subject to federal income taxes, but are still subject to Tennessee state income tax.

On April 4, 2008, we completed the Saltville acquisition, which was treated as a transfer of entities under common control as discussed in Note 1. Accordingly, the income tax effects associated with Saltville’s operations prior to the acquisition are reflected in the Consolidated Statements of Operations. In addition, in the second quarter of 2008, in connection with the acquisition and the resulting change in tax status of Saltville, $2.5 million of deferred income tax liabilities were eliminated and recorded as a benefit to Income Tax Expense (Benefit).

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Market Hub and Gulfstream are not subject to federal income tax, but rather the taxable income or loss of these entities is reported on the income tax returns of the respective members. Market Hub is subject to Texas income (margin) taxes under a tax sharing agreement with Spectra Energy.

The following details the components of income tax expense (benefit):

	2008			2007			2006
	(In millions)
Current income taxes
Federal(a)	$	0.3		$	5.2		$	0.2
State		0.3			0.5			(0.1	)
Total current income taxes		0.6			5.7			0.1
Deferred income taxes
Federal(b)		(2.0	)		(105.3	)		13.5
State		—			1.7			1.7
Total deferred income taxes		(2.0	)		(103.6	)		15.2
Total income tax expense (benefit)	$	(1.4	)	$	(97.9	)	$	15.3

(a) We were subject to federal income taxes prior to the formation of the MLP on July 2, 2007 and Saltville was subject to federal income taxes prior to the acquisition on April 4, 2008.

(b) Comprised of the $2.5 million and $110.5 million of deferred income tax liabilities in 2008 and 2007, respectively and federal income tax effects prior to the formation of the MLP.

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

	2008			2007			2006
	(In millions)
Income tax expense, computed at the statutory rate of 35%	$	35.0		$	36.7		$	29.2
State income tax, net of federal income tax effect(a)		0.6			1.7			1.0
Entities not subject to income tax		(34.5	)		(25.8	)		(14.4	)
Change in tax status		(2.5	)		(110.5	)		—
Other items, net		—			—			(0.5	)
Total income tax expense (benefit)	$	(1.4	)	$	(97.9	)	$	15.3
Effective tax rate		(b)			(b)			18.3%

(a) Includes federal income tax effects prior to the formation of the MLP.

(b) Not meaningful.

Net Deferred Income Tax Liability Components

	December 31,
	2008			2007
	(In millions)
Deferred credits and other liabilities	$	—		$	—
Net deferred income tax assets		—			—
Accelerated depreciation rates		—			(1.9	)
State deferred income tax, net of federal tax effect		(8.8	)		(8.8	)
Total net deferred income tax liabilities		(8.8	)		(10.7	)
Total net deferred income tax liabilities	$	(8.8	)	$	(10.7	)

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The above deferred tax amounts have been classified in our Consolidated Balance Sheets as Deferred Credits and Other Liabilities.

No material increases or decreases related to uncertain tax benefits were recorded in 2008 and 2007.

7. Net Income Per Limited Partner Unit and Cash Distributions

We calculate net income per limited partner unit in accordance with EITF No. 03-6, “Participating Securities and the Two-Class Method under FASB Statement No. 128.” Undistributed earnings for a period are allocated to a participating security based on the contractual participation rights of the security to share in those earnings as if all of the earnings for the period had been distributed.

Net income per limited partner unit is computed by dividing the limited partners’ interest in net income by the weighted average number of limited partner units outstanding. The limited partners’ interest in net income is determined by first allocating net income to the general partner based upon the general partner’s 2% ownership interest and incentive distribution rights held. In accordance with EITF Issue No. 03-6, net income levels above the incentive distribution level must be allocated to the general partner for purposes of calculating net income per limited partner unit. Diluted net income per limited partner unit reflects the potential dilution that could occur if securities or other agreements to issue common units, such as phantom unit awards, were exercised, settled or converted into common units. The weighted-average number of units used to calculate diluted earnings per limited partner unit includes the effect of 19,731 phantom units in 2007.

The following table presents our net income per limited partner unit calculations.

	Years Ended December 31,
	2008		2007(a)
	(In millions, except per-unit amounts)
Net income	$	101.3	$	202.9
Less:
Net income attributable to predecessor operations		1.6		156.7
General partner’s interest in net income — 2%		2.0		0.9
General partner’s interest in net income attributable to incentive distribution rights		0.5		—
Limited partners’ interest in net income	$	97.2	$	45.3
Net income allocable to common units	$	66.9	$	30.5
Net income allocable to subordinated units		30.3		14.8
Limited partners’ interest in net income	$	97.2	$	45.3
Weighted average limited partner units outstanding — basic and diluted
Common units		47.8		44.6
Subordinated units		21.6		21.6
Total		69.4		66.2
Net income per limited partner unit — basic and diluted
Common units	$	1.40	$	0.68
Subordinated units	$	1.40	$	0.68

(a) Net income per limited partner unit data for 2007 is only presented for the period since our IPO on July 2, 2007.

The partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our Available Cash, as defined, to unitholders of record on the applicable record date.

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Available Cash. Available Cash, for any quarter, consists of all cash on hand at the end of that quarter:

• less the amount of cash reserves established by the general partner to:

• provide for the proper conduct of business,

• comply with applicable law, any debt instrument or other agreement, or

• provide funds for distributions to the unitholders and to the general partner for any one or more of the next four quarters,

• plus, if the general partner so determines, all or a portion of cash on hand on the date of determination of Available Cash for the quarter.

Subordinated Units. All of the subordinated units are held by wholly owned subsidiaries of Spectra Energy. The partnership agreement provides that, during the subordination period, the common unitholders have the right to receive distributions of Available Cash each quarter in an amount equal to $0.30 per common unit (the Minimum Quarterly Distribution), plus any arrearages in the payment of the Minimum Quarterly Distribution on the common units from prior quarters, before any distributions of Available Cash may be made on the subordinated units. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be Available Cash to be distributed on the common units. The subordination period will end, and the subordinated units will convert to common units, on a one-for-one basis, when certain distribution requirements, as defined in the partnership agreement, have been met. It is currently estimated that the subordination period will not end during 2009.

Incentive Distribution Rights. The general partner holds incentive distribution rights in accordance with the partnership agreement as follows:

	Total Quarterly Distribution	Marginal Percentage Interest in Distributions
	Target Per-Unit Amount	Common and Subordinated Unitholders		General Partner
Minimum Quarterly Distribution	$0.30	98	%	2	%
First Target Distribution	up to $0.345	98	%	2	%
Second Target Distribution	above $0.345 up to $0.375	85	%	15	%
Third Target Distribution	above $0.375 up to $0.45	75	%	25	%
Thereafter	above $0.45	50	%	50	%

To the extent these incentive distributions are made to the general partner, there will be more Available Cash proportionately allocated to the general partner than to holders of common and subordinated units.

8. Marketable Securities

We invested a portion of the proceeds from our IPO in 2007 in financial instruments, including money market and debt securities that frequently have stated maturities of 20 years or more. These investments, which totaled $31.6 million as of December 31, 2008 and $154.6 million as of December 31, 2007, are pledged as collateral against our term loan and are classified as Other Investments on the Consolidated Balance Sheets. We purchased $1,132.0 million and received proceeds on sales of $1,255.0 million of these investments in 2008, and purchased $1,439.0 million and received proceeds on sales of $1,284.4 million of these investments in 2007. Purchases and proceeds on sales of long-term investments are classified within Cash Flows from Investing Activities on the Consolidated Statements of Cash Flows.

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The estimated fair values of long-term investments at December 31, 2008 and 2007, classified as available-for-sale, are as follows:

	December 31,
	2008						2007
	Gross Unrealized Holding Gains		Gross Unrealized Holding Losses		Estimated Fair Value		Gross Unrealized Holding Gains		Gross Unrealized Holding Losses		Estimated Fair Value
	(In millions)
Corporate debt securities	$	—	$	—	$	24.7	$	—	$	—	$	125.2
Other		—		—		6.9		—		—		29.4
Total long-term investments	$	—	$	—	$	31.6	$	—	$	—	$	154.6

The average contractual maturity of the above securities was either less than one year at December 31, 2008 and 2007 or the security had been sold as of the date of this report.

9. Investments in Unconsolidated Affiliates

As of December 31, 2008, our investments in unconsolidated affiliates were comprised of the 24.5% interest in Gulfstream and the 50% interest in Market Hub.

We received distributions totaling $28.5 million in 2008, $16.8 million in 2007 and $20.3 million in 2006 from Gulfstream, and $43.2 million in 2008 and $5.9 million in 2007 from Market Hub.

Our share of cumulative undistributed earnings of Market Hub totaled $146.7 million at December 31, 2008. Our share of cumulative undistributed earnings of Gulfstream totaled $5.7 million at December 31, 2008.

As of December 31, 2008 and 2007, the carrying amount of investments in affiliates approximated the amount of underlying equity in net assets.

Investments in Unconsolidated Affiliates

	December 31,
	2008		2007
	(In millions)
Gulfstream	$	253.3	$	211.3
Market Hub		320.0		283.8
Total	$	573.3	$	495.1

Equity in Earnings of Unconsolidated Affiliates

	2008		2007		2006
	(In millions)
Gulfstream	$	27.5	$	23.5	$	16.8
Market Hub		33.9		32.1		24.3
Total	$	61.4	$	55.6	$	41.1

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Summarized Financial Information of Unconsolidated Affiliates

	2008						2007						2006
	Gulfstream		Market Hub		Total		Gulfstream		Market Hub		Total		Gulfstream		Market Hub		Total
	(In millions)
Statements of Operations
Operating revenues	$	206.7	$	98.0	$	304.7	$	185.3	$	91.3	$	276.6	$	180.3	$	78.8	$	259.1
Operating expenses		61.4		30.6		92.0		45.9		32.7		78.6		63.5		38.1		101.6
Operating income		144.7		67.4		212.1		139.4		65.6		205.0		116.9		51.3		168.2
Net income		110.8		69.3		180.1		95.4		64.2		159.6		68.4		48.7		117.1

	December 31, 2008									December 31, 2007
	Gulfstream			Market Hub			Total			Gulfstream			Market Hub			Total
	(In millions)
Balance Sheets
Current assets	$	95.1		$	143.4		$	238.5		$	96.0		$	157.8		$	253.8
Non-current assets		1,849.2			623.6			2,472.8			1,669.1			539.1			2,208.2
Current liabilities		(36.2	)		(125.6	)		(161.8	)		(30.9	)		(127.7	)		(158.6	)
Non-current liabilities		(849.7	)		(1.0	)		(850.7	)		(849.7	)		(1.1	)		(850.8	)
Net assets	$	1,058.4		$	640.4		$	1,698.8		$	884.5		$	568.1		$	1,452.6

10. Property, Plant and Equipment

	Estimated Useful Life	December 31,
		2008			2007
	(Years)	(In millions)
Natural gas transmission	50	$	840.6		$	793.7
Storage	17		113.9			113.8
Equipment	3-10		3.9			3.9
Vehicles	3-5		2.7			2.7
Land	—		2.1			2.1
Construction in process	—		—			6.2
Other	5-50		6.4			7.6
Total property, plant and equipment			969.6			930.0
Total accumulated depreciation			(154.4	)		(133.7	)
Total net property, plant and equipment		$	815.2		$	796.3

11. Debt and Credit Facility

Credit Facility Summary	Expiration Date	Credit Facility Capacity			Outstanding as of December 31, 2008
					Term Loan		Revolving Loan		Total
	(In millions)
Spectra Energy Partners, LP	2012	$	500.0	(a)	$	31.0	$	209.0	$	240.0

(a) Lehman Brothers Commercial Bank (Lehman), a subsidiary of Lehman Brothers Holding, Inc., is a lender in this facility. As Lehman Brothers Holding, Inc. has filed bankruptcy, we consider $16.1 million of unfunded commitment from Lehman to be unavailable.

Effective as of July 2, 2007, we entered into a five-year $500.0 million credit agreement that includes both term and revolving borrowing capacity, of which we borrowed $194.0 million of term borrowings and $125.0 million of revolving borrowings upon the closing of the IPO.

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Our obligations under the revolving portion of our credit facility are unsecured and the term borrowings are secured by qualifying investment-grade securities in an amount equal to or greater than the outstanding principal amount of the loan. The terms of the credit facility allow for liquidation of collateral to fund capital expenditures or certain acquisitions provided that an equal amount of term loan is converted to a revolving loan. Investments in marketable securities totaling $31.6 million at December 31, 2008 and $154.6 million at December 31, 2007 were pledged as collateral against the term loan. The revolving credit facility bears interest based on a one month London InterBank Offering Rate (LIBOR) and was 0.44% at December 31, 2008. The credit facility prohibits us from making distributions of Available Cash to unitholders if any default or event of default, as defined, exists. In addition, the credit facility contains covenants, among others, limiting our ability to make other restricted distributions or dividends on account of the purchase, redemption, retirement, acquisition, cancellation or termination of partnership interests, and is also subject to certain financial covenants. These financial covenants include financial leverage and interest coverage ratios. The terms of the credit agreement require us to maintain a ratio of total debt to Adjusted EBITDA, as defined in the credit agreement, of 5.0 or less. The terms of the credit agreement also require us to maintain a ratio of Adjusted EBITDA, as defined in the credit agreement, to interest expense of 2.5 or greater. Adjusted EBITDA, as defined in the credit agreement, and therefore these ratios are affected by substantially the same economic and other drivers as those discussed under Results of Operations. As of December 31, 2008, we were in compliance with those covenants. The credit facility does not contain material adverse change clauses.

Long-term debt includes East Tennessee’s 5.71% notes payable totaling $150.0 million at both December 31, 2008 and 2007. This debt is due in one installment in 2012. East Tennessee’s debt agreement contains financial covenants which limit the amount of debt that can be outstanding as a percentage of total capital. Failure to maintain the covenants could require East Tennessee to immediately pay down the outstanding balance. As of December 31, 2008, East Tennessee was in compliance with those covenants. In addition, the debt agreement allows 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, if any. The debt agreement does not contain material adverse change clauses.

Effective as of August 15, 2007, we entered into a five-year promissory note with our equity affiliate, Market Hub, to borrow up to $50.0 million. The note matures on August 15, 2012; however, any borrowings under the agreement are payable on demand to Market Hub. The promissory note bears interest based on a one month LIBOR and was 0.44% at December  31, 2008.

12. Fair Value Measurements

The following table presents, for each of the fair value hierarchy levels, assets and liabilities that are measured at fair value on a recurring basis:

Description	Balance Sheet Caption	December 31, 2008
		Total		Level 1		Level 2		Level 3
		(In millions)
Available-for-sale securities	Investments and other assets-other investments	$	31.6	$	6.9	$	24.7	$	—
Total Assets		$	31.6	$	6.9	$	24.7	$	—
Interest rate swap liabilities	Deferred credits and other liabilities — other	$	5.6	$	—	$	5.6	$	—
Total Liabilities		$	5.6	$	—	$	5.6	$	—

Level 2 Valuation Techniques

Fair values of our available-for-sale securities, primarily fixed-income debt instruments and money market funds that are actively traded in the secondary market, are determined based on market-based prices. These valuations may include inputs such as quoted market prices of the exact or similar instruments, broker or dealer quotations, or alternative pricing sources that may include models or matrix pricing tools, with reasonable levels of price transparency.

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13. Deferred Revenues

East Tennessee has a long-term customer contract that began in 2002 with billed amounts that decline annually over the term of the contract. The revenues billed annually over the 20 year term of the contract range from $9.9 million to $6.2 million. The annual amount of revenue recognized is $9.4 million, with the difference deferred in Other within Deferred Credits and Other Liabilities on the accompanying Consolidated Balance Sheets. The deferred revenue for this contract was $2.7 million as of December 31, 2008 and $2.5 million as of December 31, 2007.

14. Commitments and Contingencies

General Insurance

We are insured through Spectra Energy’s master insurance program for insurance coverages consistent with companies engaged in similar commercial operations with similar type properties. Our insurance program includes (1) commercial general and excess liability insurance for liabilities arising to third parties for bodily injury and property damage resulting from our operations; (2) workers’ compensation liability coverage to required statutory limits; (3) automobile liability insurance for all owned, non-owned and hired vehicles covering liabilities to third parties for bodily injury and property damage; (4) insurance policies in support of the indemnification provisions of Spectra Energy’s by-laws and (5) property insurance, including machinery breakdown, on an all risk-replacement valued basis, onshore business interruption and extra expense. All coverages are subject to certain deductibles, terms and conditions common for companies with similar types of operations. The cost of Spectra Energy’s insurance coverages trend the cyclical changes in the insurance market.

Environmental

We are subject to federal, state and local regulations regarding air and water quality, hazardous and solid waste disposal and other environmental matters. Management believes there are no matters outstanding that will have a material adverse effect on our consolidated results of operations, financial position or cash flows.

Litigation

We are involved in legal, tax and regulatory proceedings in various forums, including matters regarding contracts, performance and other matters, arising in the ordinary course of business, some of which involve substantial monetary amounts. We have insurance coverage for certain of these losses should they be incurred. Management believes that the final disposition of these proceedings will not have a material adverse effect on our consolidated results of operations, financial position or cash flows.

Leases

We lease assets in several areas of operations. Rental expense for these leases was $2.0 million in 2008, $2.0 million in 2007 and $1.4 million in 2006. Future minimum rental payments under operating leases are $0.1 million in 2009 through 2013.

15. Interest Rate Risk, Credit Risk and Financial Instruments

Interest Rate Risk. Changes in interest rates expose us to risk as a result of the issuance of variable and fixed-rate debt. We manage our interest rate exposure by limiting our variable-rate exposures to percentages of total capitalization and by monitoring the effects of market changes in interest rates, including consideration of hedging activities, if needed.

In June 2008, we entered into a series of two and three-year interest rate swap agreements with Spectra Energy to mitigate our exposure to variable interest rates on $140 million of loans outstanding under the revolving loan facility. These interest rate swaps were designated as effective cash flow hedges. Through

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December 31, 2008, these hedges resulted in no ineffectiveness, and unrealized net losses on the agreements have been deferred in AOCI in the Consolidated Balance Sheets. It is estimated that $3.4 million of losses reported in AOCI at December 31, 2008 will be reclassified into earnings during the next 12 months.

Credit Risk. Our principal customers for natural gas transportation and storage services are industrial end-users, marketers, exploration and production companies, local distribution companies and utilities located throughout the southern and southeastern United States. We have concentrations of receivables from these industry sectors throughout these regions. These concentrations of customers may affect our overall credit risk in that risk factors can negatively affect the credit quality of the entire sector. Where exposed to credit risk, we analyze the counterparties’ financial condition prior to entering into an agreement, establish credit limits and monitor the appropriateness of those limits on an ongoing basis. We also obtain cash, letters of credit or other acceptable forms of security from customers to provide credit support, where appropriate, based on our financial analysis of the customer and the regulatory or contractual terms and conditions applicable to each transaction.

Financial Instruments. The fair value of financial instruments 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, 2008 and 2007 are not necessarily indicative of the amounts we could have realized in current markets.

	December 31,
	2008				2007
	Book Value		Approximate Fair Value		Book Value		Approximate Fair Value
	(In millions)
Long-term debt	$	390.0	$	381.9	$	400.0	$	401.0
Note payable — affiliates		50.0		50.0		50.0		50.0
Long-term SFAS No. 115 securities		31.6		31.6		154.6		154.6

The fair value of cash and cash equivalents, receivables, and accounts payable are not materially different from their carrying amounts because of the short-term nature of these instruments.

16. Equity-Based Compensation

We account for equity-based awards under the provisions of SFAS No. 123(R), “Share-Based Payment,” which establishes the accounting for equity-based awards exchanged for employee and certain non-employee services.

We awarded 5,000 common phantom units and 120,250 common phantom units to certain employees of Spectra Energy during the years ended December 31, 2008 and 2007, respectively. At December 31, 2008 and 2007, common phantom units of 73,767 and 120,250 were outstanding, respectively. These units were granted under the Long-Term Incentive Plan and will vest over three years. Compensation expense under these grants did not have a material impact on our consolidated results of operations.

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17. Subsequent Event

A cash distribution to unitholders of $0.36 per unit was declared on January 27, 2009 and was paid on February 13, 2009, which is an increase of 3% over the cash distribution of $0.35 per unit paid on November 14, 2008.

18. Quarterly Financial Data (Unaudited)

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Total
	(In millions, except per-unit amounts)
2008
Operating revenues	$	32.5	$	29.7	$	29.5	$	33.2	$	124.9
Operating income		15.7		13.0		10.3		12.9		51.9
Net income		24.1		27.5		24.3		25.4		101.3
Net income per limited partner unit	$	0.33	$	0.38	$	0.34	$	0.35	$	1.40
2007
Operating revenues	$	32.4	$	29.4	$	28.6	$	30.7	$	121.1
Operating income		17.1		20.2		10.2		13.1		60.6
Net income		21.1		23.9		136.2		21.7		202.9
Net income per limited partner unit		n/a		n/a	$	0.35	$	0.33	$	0.68

As discussed in Note 6, we recorded a benefit of $110.5 million in the third quarter of 2007, from the reversal of deferred income tax liabilities as a result of our master limited partnership structure.

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SPECTRA ENERGY PARTNERS, LP

SCHEDULE II — CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

			Additions:
	Balance at Beginning of Period		Charged to Expense		Charged to Other Accounts		Deductions(a)		Balance at End of Period
	(In millions)
December 31, 2008:
Allowance for doubtful accounts	$	0.3	$	0.3	$	—	$	0.1	$	0.5
Other(b)		1.7		—		—		1.7		—
	$	2.0	$	0.3	$	—	$	1.8	$	0.5
December 31, 2007:
Allowance for doubtful accounts	$	0.3	$	0.1	$	—	$	0.1	$	0.3
Other(b)		5.0		—		—		3.3		1.7
	$	5.3	$	0.1	$	—	$	3.4	$	2.0
December 31, 2006:
Allowance for doubtful accounts	$	0.3	$	0.1	$	—	$	0.1	$	0.3
Other(b)		7.5		—		—		2.5		5.0
	$	7.8	$	0.1	$	—	$	2.6	$	5.3

(a) Principally cash payments and reserve reversals.

(b) Principally a right of way dispute, included in Accounts Payable on the Consolidated Balance Sheets at December 31, 2007 and Other Current Liabilities at December 31, 2006.

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

None.

Item 9A. Controls and Procedures.

Disclosure controls and procedures are controls and other procedures that are designed to ensure that information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act of 1934 (Exchange Act) is recorded, processed, summarized, and reported, within the time periods specified by the Securities and Exchange Commission’s (SEC) rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to provide reasonable assurance that information required to be disclosed by us in the reports we file or submit under the Exchange Act is accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

Under the supervision and with the participation of the management of our General Partner, including the Chief Executive Officer and Chief Financial Officer, we have evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act) as of December 31, 2008, and, based upon this evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that these controls and procedures are effective.

Changes in Internal Control over Financial Reporting

As previously reported, the Board of Directors appointed Gregory J. Rizzo to the position of President and Chief Executive Officer of Spectra Energy Partners, effective December 2, 2008. Mr. Rizzo replaced C. Gregory Harper who announced his resignation as President and Chief Executive Officer and member of the Board of Directors of Spectra Energy Partners.

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Under the supervision and with the participation of the management of our General Partner, including the Chief Executive Officer and Chief Financial Officer, we have evaluated changes in internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the fiscal quarter ended December 31, 2008 and found no change that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.

Management’s Annual Report on Internal Control over Financial Reporting

The report of management required under this Item 9A is contained in Item 8. Financial Statements and Supplementary Data, Management’s Annual Report on Internal Control over Financial Reporting.

Attestation Report of Independent Registered Public Accounting Firm

The attestation report required under this Item 9A is contained in Item 8. Financial Statements and Supplementary Data, Report of Independent Registered Public Accounting Firm.

Item 9B. Other Information.

None.

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PART III

Item 10. Directors, Executive Officers and Corporate Governance.

Management of Spectra Energy Partners, LP

We do not have directors or officers, which is commonly the case with publicly traded partnerships. Our operations and activities are managed by our general partner, Spectra Energy Partners (DE) GP, LP, which in turn is managed by its general partner, Spectra Energy Partners GP, LLC, (the General Partner). The General Partner is wholly owned by a subsidiary of Spectra Energy. The officers and directors of the General Partner are responsible for managing us. All of the directors of the General Partner are elected annually by Spectra Energy and all of the officers of the General Partner serve at the discretion of the directors. Unitholders are not entitled to participate, directly or indirectly, in management or operations.

Board of Directors and Officers

The Board of Directors of the General Partner currently has seven members, three of whom are independent as defined under the independence standards established by the New York Stock Exchange (NYSE). The NYSE does not require a listed limited partnership to have a majority of independent directors on its general partner’s Board of Directors or to establish a compensation committee or a nominating committee. However, the Board of Directors of the General Partner has established an audit committee (the Audit Committee) and a conflicts committee (the Conflicts Committee) to address conflict situations, each consisting of Steven D. Arnold, Nora M. Brownell and Stewart A. Bliss.

The Board of Directors of the General Partner annually review the independence of directors and affirmatively makes a determination that each director expected to be independent has no material relationship with the General Partner, either directly or indirectly as a partner, unitholder or officer of an organization that has a relationship with the General Partner. The members of the Audit Committee and Conflicts Committee each meet the independence and experience standards established by the NYSE and the Exchange Act, as amended, to serve on an audit committee of a board of directors.

The officers of the General Partner manage the day-to-day affairs of our business. All of our executive management personnel are employees of Spectra Energy and devote a portion of their time to our business and affairs. We also utilize a significant number of employees of Spectra Energy to operate our business and provide general and administrative services. We reimburse Spectra Energy for allocated expenses of operational personnel who perform services for our benefit and for allocated general and administrative expenses.

The General Partner does not receive any management fee or other compensation for its management of our partnership under the omnibus agreement with Spectra Energy (Omnibus Agreement) or otherwise. Under the terms of the Omnibus Agreement, we reimburse Spectra Energy up to $3.0 million annually for the provision of various general and administrative services for our benefit, which amount is adjusted for inflation until July 2010. We also reimburse Spectra Energy for direct expenses incurred on our behalf and expenses allocated to us as a result of becoming a public entity. The partnership agreement provides that the General Partner will determine the expenses that are allocable to us.

Meeting Attendance and Preparation

Members of the General Partner’s Board of Directors attended at least 75% of regular board meetings and meetings of the committees on which they serve, either in person or telephonically. In addition, directors are expected to be prepared for each meeting of the board by reviewing materials distributed in advance.

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Directors and Executive Officers

The following table shows information regarding the current directors and executive officers of the General Partner. Directors are elected for one-year terms.

Name	Age	Position with Spectra Energy Partners GP, LLC
Gregory J. Rizzo	52	President, Chief Executive Officer and Director
Laura Buss Sayavedra	41	Vice President and Chief Financial Officer
Fred J. Fowler	63	Chairman
Steven D. Arnold	48	Director
Stewart A. Bliss	75	Director
Nora M. Brownell	62	Director
Patrick J. Hester	58	Director
R. Mark Fiedorek	46	Director

Directors of Spectra Energy Partners GP, LLC hold office until the earlier of their death, resignation, removal or disqualification or until their successors have been elected and qualified. Officers serve at the discretion of the Board of Directors. There are no family relationships among any of our directors or executive officers.

Gregory J. Rizzo was elected to the Board of Directors of Spectra Energy Partners GP, LLC in May 2007 and was named President and Chief Executive Officer in December 2008. He also serves as Group Vice President of U.S. Regulatory Affairs for Spectra Energy Corp, which was spun off from Duke Energy Corporation and has done so since January 2007. Mr. Rizzo previously served as Group Vice President for Duke Energy Gas Transmission — Northeast Pipelines from March 2004 until assuming his current position. Prior to then, Mr. Rizzo served as Executive Vice President of Duke Energy Gas Transmission from February 2003 until March 2004; and Senior Vice President Marketing and Capacity Management from March 2002 until February 2003.

Laura Buss Sayavedra was named to her current position in May 2008. Prior to that, she was Vice President, Strategic Development and Analysis for Spectra Energy Corp, which was spun off from Duke Energy Corporation. She previously served at Duke Energy Gas Transmission as General Manager, Strategic Planning and Development from July 2005 to December 2006. Prior to then, she served as Vice President, Operations and Analytics of Duke Energy North America from May 2004 to June 2005 and Senior Director of Energy Marketing from January 2003 to April 2004.

Fred J. Fowler was elected to the Board of Directors of Spectra Energy Partners GP, LLC as its Chairman in December 2008. He retired as President and Chief Executive Officer of Spectra Energy Corp in December 2008, a position he held since its inception in January 2007. Mr. Fowler previously served as Group Executive and President of Duke Energy Gas Transmission from April 2006. Prior to then, he was President and Chief Operating Officer in November 2002 to April 2006.

Steven D. Arnold was elected to the Board of Directors of Spectra Energy Partners GP, LLC in May 2007 and serves on the Audit Committee and on the Conflicts Committee as Chairman. Mr. Arnold is engaged in private investment management and consulting services in Houston, Texas through 3 Lights Management Co., serving as its President since inception in 2000. Mr. Arnold currently serves on the Advisory Boards of Avalon Advisors, LP, in Texas and Alliance Real Estate Value Funds in Colorado.

Stewart A. Bliss was elected to the Board of Directors of Spectra Energy Partners GP, LLC in June 2007 and chairs the Audit Committee and serves on the Conflicts Committee. Mr. Bliss has been an independent financial consultant and senior business advisor in Denver, Colorado for many years, with expertise that also includes mergers and acquisitions. In early 2007, he served as interim director of the Colorado Department of

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Economic Development and International Trade. Mr. Bliss was a senior advisor with Green Manning & Bunch, Ltd., a Denver-based investment banking firm from 2000 until 2007. Until recently, he served as lead director and chair of the audit committee on Kinder Morgan Inc.’s Board of Directors. Mr. Bliss currently serves as a member of the Colorado Commission on Judicial Discipline.

Nora M. Brownell was elected to the Board of Directors of Spectra Energy Partners GP, LLC in May 2007 and serves on our Audit Committee and the Conflicts Committee. In May 2001, Ms. Brownell was confirmed as Commissioner of the Federal Energy Regulatory Commission where she served until the expiration of her term in June 2006. Ms. Brownell also currently serves on the Board of Directors of Comverge, Inc.

Patrick J. Hester was elected to the Board of Directors of Spectra Energy Partners GP, LLC in October 2008. He also serves as interim General Counsel for Spectra Energy Corp and Associate General Counsel for Spectra Energy Corp’s Northeast region. Mr. Hester previously served as Vice President, Project Management and Development for Duke Energy Gas Transmission from 2005 until he assumed his current position. Previously he was General Counsel for Duke Energy Gas Transmission from 2003.

R. Mark Fiedorek was elected to the Board of Directors of Spectra Energy Partners GP, LLC in December 2008. He also serves as Group Vice President of Spectra Energy Corp’s U.S. Transmission and Storage — Southeast. He previously served as Vice President of Asset Optimization and Marketer Services since 2002 until 2007 when he was named to his current position with Spectra Energy Corp.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Exchange Act requires the General Partner’s directors and executive officers, and persons who own more than 10% of any class of our equity securities to file with the SEC and the NYSE initial reports of ownership and reports of changes in ownership of our common units and other equity securities. Spectra Energy prepares and files these reports on behalf of the General Partner’s directors and executive officers. To our knowledge, all Section 16(a) reporting requirements applicable to the General Partner’s directors and executive officers were complied with during 2008.

Audit Committee

The Board of Directors of the General Partner has a standing audit committee composed of Steven D. Arnold, Nora M. Brownell and Stewart A. Bliss, each of whom is able to understand fundamental financial statements and at least one of whom has past experience in accounting or related financial management experience. The Board has determined that each member of the Audit Committee is independent under Section 303A.02 of the NYSE listing standards and Section 10A(m)(3) of the Exchange Act, as amended. In making the independence determination, the Board considered the requirements of the NYSE. The Audit Committee has adopted a charter, which has been ratified and approved by the Board of Directors.

Mr. Bliss has been designated by the Board of Directors as the Audit Committee’s financial expert meeting the requirements promulgated by the SEC based upon his education and employment experience as more fully detailed in Mr. Bliss’s biography set forth above.

The Audit Committee assists the Board of Directors in its oversight of the integrity of our financial statements and compliance with legal and regulatory requirements and corporate policies and controls. The Audit Committee has the sole authority to retain and terminate our independent registered public accounting firm, approve all auditing services and related fees and terms thereof, and pre-approve any non-audit services to be rendered by our independent registered public accounting firm. The Audit Committee is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm has unrestricted access to the Audit Committee.

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Conflicts Committee

The Board of Directors has a standing Conflicts Committee, which is comprised of Steven D. Arnold, Nora M. Brownell and Stewart A. Bliss. The Conflicts Committee reviews specific matters that the Board of Directors believes may involve conflicts of interest. The Conflicts Committee will determine if the resolution of the conflict of interest is in the best interest of our partnership. The members of the Conflicts Committee may not be officers, employees or security holders of the General Partner, or directors, officers or employees of its affiliates. Any matters approved by the Conflicts Committee in good faith will be conclusively deemed to be fair and reasonable to us, approved by all of our partners, and not a breach by the General Partner of any duties it may owe us or our unitholders.

Principles for Corporate Governance and Code of Business Ethics

We have adopted Corporate Governance Guidelines that outline the important policies and practices regarding our governance. We have also adopted a Code of Business Ethics applicable to the persons serving as the General Partner’s directors and Spectra Energy has adopted a Code of Business Ethics applicable to persons serving as the General Partner’s officers, all of whom are employees of Spectra Energy.

Copies of the Corporate Governance Guidelines, the Code of Business Ethics and the Audit Committee Charter are available online at www.spectraenergypartners.com. Copies of these items are also available free of charge in print to any unitholder who sends a request to the office of Investor Relations of our partnership at 5400 Westheimer Court, Houston, Texas 77056, (713) 627-4963.

Communications by Unitholders

Unitholders and other interested parties may communicate with any and all members of the Board of Directors, including nonmanagement directors, by transmitting correspondence by mail or facsimile addressed to one or more directors by name or to the chairman of the Board of Directors or any committee of the Board of Directors at the following address and fax number; Name of the Director(s), c/o President, Spectra Energy Partners, LP, 5400 Westheimer Court, Houston, Texas 77056 fax: (713) 989-1818.

Report of the Audit Committee

The Audit Committee oversees our financial reporting process on behalf of the Board of Directors. Management has the primary responsibility for the financial statements and the reporting process including the systems of internal controls. The Audit Committee operates under a written charter approved by the Board of Directors. The charter, among other things, provides that the Audit Committee has authority to appoint, retain and oversee the independent auditor. In this context, the Audit Committee:

• reviewed and discussed the audited financial statements in this annual report on Form 10-K with management, including a discussion of the quality, not just the acceptability, of the accounting principles, the reasonableness of significant judgments and the clarity of disclosures in the financial statements;

• reviewed with Deloitte & Touche, LLP, our independent auditors, who are responsible for expressing an opinion on the conformity of the audited financial statements with generally accepted accounting principles, their judgments as to the quality and acceptability of our accounting principles and such other matters as are required to be discussed with the Audit Committee under generally accepted auditing standards;

• received the written disclosures and the letter required by standard No. 1 of the independence standards board (independence discussions with audit committees) provided to the Audit Committee by Deloitte & Touche, LLP;

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• discussed with Deloitte & Touche, LLP its independence from management and us and considered the compatibility of the provision of nonaudit service by the independent auditors with the auditors’ independence;

• discussed with Deloitte & Touche, LLP the matters required to be discussed by Statement on Auditing Standards No. 61 (communications with audit committees);

• discussed with Spectra Energy’s internal auditors and Deloitte & Touche, LLP the overall scope and plans for their respective audits. The Audit Committee meets with the internal auditors and Deloitte & Touche, LLP, with and without management present, to discuss the results of their examinations, their evaluations of our internal controls and the overall quality of our financial reporting;

• based on the foregoing reviews and discussions, recommended to the Board of Directors that the audited financial statements be included in the annual report on Form 10-K for the year ended December 31, 2008, for filing with the SEC; and

• approved the selection and appointment of Deloitte & Touche, LLP to serve as our independent auditors.

This report has been furnished by the members of the Audit Committee of the Board of Directors:

Audit Committee

Steven D. Arnold

Nora M. Brownell

Stewart A. Bliss

March 11, 2009

The report of the Audit Committee in this report shall not be deemed incorporated by reference into any other filing by Spectra Energy Partners, LP under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, except to the extent that we specifically incorporate this information by reference, and shall not otherwise be deemed filed under such acts.

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Item 11. Executive Compensation.

COMPENSATION DISCUSSION AND ANALYSIS

References below to “Spectra Energy Partners,” “we,” “our,” “us,” or similar terms refer to Spectra Energy Partners, LP.

The purpose of this Compensation Discussion and Analysis is to provide information about the objectives and policies regarding compensation for the officers of the general partner of our partnership listed in the Summary Compensation Table. We do not directly employ any of the persons responsible for managing our business and we do not have a compensation committee. We are managed by our general partner, the executive officers of which are employees of Spectra Energy. Our reimbursement for the compensation of executive officers is governed by the Omnibus Agreement and is generally based on time allocated to us during a period.

Compensation paid or awarded by us in 2008 to our Chief Executive Officer (our principal executive officer) and our Chief Financial Officer (our principal financial officer, and together with our principal executive officer, our “named executive officers”) reflects the total compensation paid by Spectra Energy, which includes compensation that is allocated to us pursuant to Spectra Energy’s allocation methodology and subject to the terms of the Omnibus Agreement. Prior to our formation, our executive officers devoted their time to Spectra Energy. Currently, our named executive officers devote a portion of their time to our business and affairs and a corresponding amount of the compensation paid by Spectra Energy to our named executive officers is allocated to us. The Compensation Committee of Spectra Energy (Compensation Committee) has ultimate decision making authority with respect to the compensation of our named executive officers other than with respect to awards of equity in our partnership, for which our Board retains control. The elements of compensation discussed below, other than our partnership equity based compensation, and Spectra Energy’s decisions with respect to determinations on payments, was not subject to approvals by the Board of Directors of our general partner. Compensation of our executive officers was approved by the Compensation Committee of the Board of Directors of Spectra Energy or its delegate and ratified by the Board of Directors of our general partner. Awards under our long-term incentive plan are recommended by the Compensation Committee and approved by the Board of Directors of Spectra Energy Partners GP, LLC.

With respect to compensation objectives and decisions regarding our named executive officers for 2008, the Compensation Committee approved the cash compensation, and recommended equity based compensation, of our named executive officers based on its compensation philosophy, which is to reward both continued employment and performance through a combination of short-term bonus incentives and long-term equity compensation. Senior management of Spectra Energy typically utilizes compensation consultants and reviews market data for determining relevant compensation levels and compensation program elements through the review of and, in certain cases, participation in, various relevant compensation surveys. Senior management then submits a proposal to the Compensation Committee for the compensation to be paid or awarded to executives and employees for consideration. Spectra Energy consulted with compensation consultants with respect to determining 2009 compensation for the named executive officers in a manner consistent with its current compensation philosophy. All compensation determinations are discretionary and are, as noted above, subject to Spectra Energy’s decision-making authority.

The elements of Spectra Energy’s compensation program discussed below are intended to provide a compensation package designed to drive performance and reward contributions in support of the business strategies of Spectra Energy and its affiliates at the corporate, partnership and individual levels. Historically, more than half of the compensation provided to Spectra Energy’s executive officers has been provided in the form of short-term and long-term incentives. We expect that compensation for our executive officers in 2009 and the future will be structured in a similar manner.

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Committee Advisors

In 2007, the Compensation Committee engaged ExeQuity, LLP (ExeQuity), an independent consulting firm, to report directly to the Compensation Committee with respect to matters related to executive compensation, best practices and analysis of meeting materials prepared by management. ExeQuity generally confers with the Chair of the Compensation Committee and the Compensation Committee itself and discusses compensation matters with management on a limited basis. ExeQuity performs no other services for Spectra Energy other than its services as independent consultant.

In 2008, ExeQuity reviewed materials provided to the Compensation Committee by management, consulted with the chairman prior to meetings regarding agenda items and attended meetings of the Compensation Committee. ExeQuity also provided consulting services as Spectra Energy conducted a detailed study of the appropriate structure of its long-term incentive program and the appropriate measures that would determine vesting of performance awards.

Elements of the Compensation Program

The objective of Spectra Energy’s compensation program is to link total compensation to both individual and company performance, on both a short and long-term basis, with significant percentages of potential earning opportunities based on the achievement of predetermined performance targets. As such, the compensation program is a valuable tool that assists us in attracting, retaining and motivating well qualified executives.

The following table sets forth the principal components of compensation for our named executive officers:

Component	Description	Rationale
Salary	Compensation paid in cash throughout the year.	Provides compensation for ongoing service.
Short-Term Incentive	Annual cash payment based on the achievement of defined financial and individual performance goals.	Makes significant percentage of cash compensation contingent on specific objectives. These objectives are considered to be appropriate measures of the business imperatives that are necessary to build a solid record of financial success and operational excellence.
Long-Term Incentive	Performance units and phantom awards.	Rewards long-term company performance, establishes economic alignment of executives with unitholders and provides retention incentive.
Retirement	Company sponsored retirement and savings plans.	Provides retention incentives and rewards service through retirement-related payments and provides savings opportunities.
Perquisites	Personal use of company aircraft for business purposes only.	Provides reasonable assistance to the executive conducting business on behalf of the Company.
Severance	Change of control agreements that provide benefits upon termination following a change of control of Spectra Energy.	Achieves management continuity and focus on best results for unitholders in the event of a change of control of the company.

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Factors Considered When Determining Total Compensation

During 2007, the Compensation Committee conducted a detailed review of its compensation philosophies in connection with establishing the 2008 compensation program. While the basic tenets of its philosophy did not change, the 2008 compensation program differed from the 2007 program as follows:

• Scopes of responsibilities and market data were reviewed to make total compensation opportunities reflect Spectra Energy’s position as an independent public entity separate from its former parent.

• Long-term incentives were structured to take into account strategic issues unique to Spectra Energy such as executive retention, capital project execution and ownership.

• Peer benchmarks were identified for measuring long-term financial performance.

Group Comparison. The Compensation Committee sets salaries and short-term and long-term incentive target levels based on what we believe to be the market median of compensation available to our executives in the market. Spectra Energy’s consultants and internal staff gather information from the public filings of the companies listed below that is representative of the companies in its markets that compete with Spectra Energy for executive talent.

Compensation Reference Group

CenterPoint Energy	Dominion Resources	DTE Energy
El Paso Corp.	Enbridge, Inc.	Equitable Resources
National Fuel Gas Co.	NiSource	ONEOK, Inc.
Questar Corp.	Sempra Energy	Southern Union Company
TransCanada Corp.	Williams Companies

The Compensation Committee has decided that the best representation of broader market practice for Spectra Energy’s positions can be extracted from survey data. Specifically, the Compensation Committee has chosen to use the Towers Perrin Compensation Data Base^© General Industry Survey as a source of market information because the Compensation Committee believes that the survey provides a reliable indication of compensation practices in companies that are comparable in size to Spectra Energy and Spectra Energy Partners as measured by revenues. Further, the Compensation Committee is mindful that Duke Energy employed this survey when it was responsible for the compensation of Spectra Energy’s executives, and Spectra Energy believes that it is important to establish a consistent source of survey data over time.

External Market Conditions and Individual Factors. In addition to using benchmark survey data, the Compensation Committee also takes into account external market conditions and individual factors when establishing the total compensation of each named executive officer. Some of these factors include the executive’s level of experience, the executive’s tenure and responsibilities, the executive’s position and the appropriate competitive pressures for that position within the industry. Finally, the Compensation Committee considers internal equity when evaluating the compensation of our named executive officers relative to other executives.

2008 Compensation Opportunities

The base salary, short-term incentive opportunity and long-term incentive opportunity established for each of our named executive officers is intended to provide total target compensation in the range of the market median for individuals in comparable positions and markets in which we compete for executive talent. See — “Factors Considered when Determining Total Compensation.” Consistent with these objectives, an average of 60% of the 2008 compensation opportunity provided to our named executive officers was in the form of short-

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term and long-term incentives, and an average of 35% of named executive officers’ compensation opportunity was in the form of long-term incentives alone.

The following table shows the 2008 target direct pay opportunities for our named executive officers.

2008 Target Pay Opportunity

Name	Salary		Short-Term Incentive Target Opportunity		Long-Term Incentive Target Opportunity		Total Target Pay Opportunity
Gregory J. Rizzo	$	307,500	50	%	100	%	$	768,750
Laura Buss Sayavedra	$	194,272	40	%	50	%	$	369,116
C. Gregory Harper	$	285,500	50	%	80	%	$	656,650
Lon C. Mitchell, Jr.	$	250,000	50	%	75	%	$	562,500

Salary. At the beginning of 2008, the Compensation Committee considered whether adjustments to salaries were appropriate and adjusted salaries of the named executive officers at that time, based upon job responsibilities, level of experience, individual performance, comparisons to the salaries of executives in similar positions obtained from market surveys and internal comparisons. The Compensation Committee approved salary adjustments for Messrs. Rizzo, Harper and Mitchell and the Chief Executive Officer of Spectra Energy and other members of Spectra Energy management approved salary adjustments for Ms. Sayavedra.

Short-Term Incentives. Short-term incentive opportunities, awarded under the Spectra Energy Executive Short-Term Incentive (STI) Plan for 2008, were designed to compensate executives for individual and company performance during the year based on goals set at the beginning of the year. The threshold, target and maximum incentive opportunities for each participant in the STI Plan during 2008 were established as a percentage of base salary. Bonuses were earned based on the achievement of individual, corporate and/or business unit goals as determined by the Compensation Committee. Target STI awards expressed as a percentage of base annual salary for our named executive officers in 2008 are reflected in the ‘2008 Target Pay Opportunity’ table above.

Under guidelines adopted for the 2008 STI program, participants were eligible to receive up to 190% of the amount of their STI target, depending on actual performance. Up to 200% of the target bonus amount contingent on financial or operational measures could be paid if performance at a specified maximum level was achieved. The maximum that could be earned for performance on individual measures was 150% of target. The amount that could be paid for performance at a specified minimum level for any measure was 50% of the target amount. No compensation was to be earned if performance fell below a specified minimum level.

As shown in the following table, STI payments for our named executive officers were based on the achievement of individual goals and financial objectives related to management responsibilities for Spectra Energy and Spectra Energy Partners. The results of Spectra Energy’s ownership interests in DCP Midstream, LLC (DCP Midstream) were not integrated into the objectives of our executives because those executives did not have management responsibilities for Spectra Energy’s investment in DCP Midstream. Therefore, Spectra Energy Transmission, LLC (Spectra Energy Transmission) refers to Spectra Energy Corp excluding consideration of DCP Midstream results. STI payments were based on the achievement of individual goals and financial objectives including Spectra Energy’s Earnings per share (EPS), Spectra Energy Transmission Earnings Before Interest and Taxes (EBIT), Spectra Energy Transmission Return on Capital Employed (ROCE), Spectra Energy Partners Distributable Cash, Spectra Energy Partners ROCE, Spectra Energy Transmission and Spectra Energy Partners Projects and Spectra Energy O&M Cost and Safety Initiative goals. Due to Mr. Harper’s resignation prior to December 31, 2008, he was not eligible for a STI payment, and therefore is excluded from the table below.

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2008 Target Incentive Payment Opportunity

Measures	Mr. Rizzo	Ms. Sayavedra	Mr. Mitchell
Spectra Energy EPS	20%	20%	20%
Spectra Energy Transmission Return on Capital Employed	15%	10%	—
Spectra Energy Transmission Projects — Capital Expenditures	5%	—	—
Spectra Energy Transmission Projects — Rates of Return	5%	—	—
Spectra Energy Transmission EBIT	20%	12.5%	—
Spectra Energy Partners Return on Capital Employed	—	7.5%	15%
Spectra Energy Partners Projects — Capital Expenditures	—	2.5%	5%
Spectra Energy Partners Projects — Rates of Return	—	2.5%	5%
Spectra Energy Partners Distributable Cash	—	10%	20%
O&M Cost & Safety Initiatives	15%	15%	15%
Individual	20%	20%	20%

Ongoing EPS was chosen as a measure because Spectra Energy believes that it is one of the primary measures used by the investment community in valuing Spectra Energy. An EPS target of $1.56 was established as an estimate of the earnings expected for 2008 in the event Spectra Energy’s financial and strategic goals were achieved. The EPS amount corresponding to the payout maximum was set at 15.4% above the target and was judged to be an earnings level that was possible if financial performance was extraordinary. The EPS level corresponding to the payout minimum was set at approximately 10% below the target level and was deemed to be an amount of earnings that warranted consideration for incentive pay.

Spectra Energy Transmission EBIT was chosen as a measure of the effectiveness of Spectra Energy’s business’s ability to generate earnings without considering interest or taxes. Fifty-five percent of the effect of exchange rate fluctuations in Canadian currency and any contributions to earnings by DCP Midstream were excluded from the calculation of EBIT in an attempt to make this measure a clear gauge of the performance of Spectra Energy’s three core business units. Target performance was set at a level that matched Spectra Energy’s corporate forecasts. Maximum payout level was set at a level judged to be superior performance, and a minimum payout was set at a level considered to be the lowest level of performance that would justify a reduced payout.

Spectra Energy Partners Distributable Cash was chosen as a measure because it is a measure of the effectiveness of Spectra Energy Partners’ ability to generate cash for its investors. Target performance was set at a level consistent with corporate forecasts. Similar to other measures, maximum and minimum performance were set, respectively, at levels deemed by the Compensation Committee to be significant challenges or minimally acceptable.

ROCE was chosen as a measure because it reflects efficiency and effectiveness of capital deployment in its core business and also within Spectra Energy Partners. Target performance was set at a level consistent with corporate forecasts. Similar to other measures, maximum and minimum performance were set, respectively, at levels deemed by the Compensation Committee to be significant challenges or minimally acceptable.

O&M Cost and Safety initiatives were chosen as a combined measure to reflect the importance of having a safety culture and wisely spending money on the daily operations and maintenance of our business.

Given the level of capital spending during 2008, Capital Expenditures and Rates of Return for Spectra Energy Transmission and Spectra Energy Partners Projects were chosen as measures to place increased emphasis on the cost effectiveness of projects and attainment of returns that were initially established for the projects.

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A summary of the 2008 individual objectives for each named executive officer and each objective weighting are shown in the following table.

Objective	Mr. Rizzo	Ms. Sayavedra	Mr. Mitchell
Leadership and employee development, diversity and a high performance culture	20%	10%	10%
Enhancement of Spectra Energy Partners’ unit performance and standing in the financial community	—	7%	15%
Project execution	50%	25%	—
Management of strategic initiatives	20%	43%	45%
Improvement of the internal and external communication process	—	8%	15%
Industry leadership	10%	—	—
Enhancement of Spectra Energy Partners’ financial review	—	7%	15%

Determination of 2008 Short-Term Incentive Payments

At the end of the 2008, management prepared a report on the achievement of financial, project and operational goals. These results were reviewed and approved by the Compensation Committee in February 2009 along with a review of the achievement of the named executive officers’ individual goals, including a calculation of the percentage achievement of each for purposes of the STI program. For the named executive officers, performance for each individual objective was calculated and reviewed by the Compensation Committee for Messrs. Rizzo and Mitchell and by members of Spectra Energy’s management for Ms. Sayavedra, which then approved the final performance results and payment of bonuses.

The amounts set forth below show the percentage of target for achieving the threshold, target and maximum levels established for each category as well as the actual result. The corresponding values for the EPS goal, in dollars, and EBIT and Distributable Cash goals, in millions, are also shown in parentheses. We do not publicly disclose our target return on capital employed, project capital expenditures or project rates of return because that information constitutes confidential commercial information, the disclosure of which would cause us competitive harm.

Measures	Threshold	Target	Maximum	Actual
Spectra Energy EPS	50%($1.40)	100%($1.56)	200%($1.80)	200%($1.83)
Spectra Energy Transmission Return on Capital Employed	50%	100%	200%	157%
Spectra Energy Transmission Projects —Capital Expenditures	50%	100%	200%	0%
Spectra Energy Transmission Projects —Rates of Return	50%	100%	200%	75%
Spectra Energy Transmission EBIT	50%	100%	200%	153%($1,558)
Spectra Energy Partners Return on Capital Employed	50%	100%	200%	200%
Spectra Energy Partners Projects —Capital Expenditures	50%	100%	200%	132%
Spectra Energy Partners Projects —Rates of Return	50%	100%	200%	0%
Spectra Energy Partners Distributable Cash	50%	100%	200%	200% ($119)
O&M Cost & Safety Initiatives	50%	100%	200%	129%
Individual	*	*	*	*

* The individual goal results for the named executive officers are summarized in the ‘2008 STI Awards’ table below.

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The following table is a summary of the payments made to each of our named executive officers who were employed as of December 31, 2008:

2008 STI Awards

Name	Short-Term Incentive Award		Actual Individual Award as a Percent of Target Individual Award		Actual Payout as a Percent of Target Short-Term Incentive Award
Gregory J. Rizzo	$	198,842	94	%	129	%
Laura Buss Sayavedra	$	116,607	84	%	146	%
Lon C. Mitchell, Jr.	$	133,981	89	%	153	%

In calculating final bonus amounts, the Compensation Committee applied a reduction in earned amounts for Mr. Rizzo and Ms. Sayavedra due to safety results for Spectra Energy Transmission in 2008.

Long-Term Incentives. Spectra Energy provides long-term incentive opportunities to our executive officers to achieve an alignment of executive and shareholder interests and motivate executives to achieve strategic goals that will maximize shareholder value.

Beginning in 2007, the Compensation Committee undertook an extensive study of the appropriate structure of long-term awards based on its overall philosophy regarding performance-based compensation and executive ownership. Because expected share price growth rates for high dividend paying companies are typically lower than the growth rates for the market in general, we determined that, at this point in time, the use of stock options in our long-term incentive programs would not be the form of award that would most effectively challenge our leadership employees to deliver a competitive return to our shareholders. Further, as we reviewed the nature of long-term incentive structures of other companies with similar businesses, it appeared that those companies had reached similar conclusions. The Compensation Committee therefore decided that, beginning in 2008, the use of stock options would be suspended as an element of our long-term incentive program for a period of time and would be replaced with awards that result in share ownership when certain specific performance goals are achieved. These new performance awards will be used in combination with phantom restricted units that vest over a three-year period. We believe that the combination of these two forms of award will be an effective means of creating a focus on returns to shareholders and retaining our executive talent in a very competitive market.

The performance unit awards comprised 50% of the target value of annual long-term compensation and will be earned based on how Spectra Energy performs relative to a group of energy companies over a three-year period. The long-term incentive peer group of 19 companies is not entirely the same as the compensation reference group discussed above for two reasons:

• In discussions with its consultant, the Compensation Committee decided that the compensation reference group is not large enough to develop a reliable long-term measure of relative corporate performance.

• The groups serve two different purposes. The compensation reference group provides an informal benchmark of compensation practices of companies with which we compete for executive talent, while the long-term incentive peer group provides a measure of our performance compared to companies with which we compete for capital.

The companies in Spectra Energy’s long-term incentive peer group are:

Ameren Corp.	CenterPoint Energy	Consolidated Edison
Dominion Resources	DTE Energy	El Paso Corp.
Enbridge, Inc.	Equitable Resources	NiSource
National Fuel Gas Co.	ONEOK, Inc.	PG&E Corp.
Public Service Enterprise Group	Questar Corp.	Sempra Energy
Southern Union Company	TransCanada Corp.	Williams Companies
Xcel Energy

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The performance unit awards generally vest only to the extent Spectra Energy’s Total Shareholder Return (TSR) is achieved over a three-year measurement period, as compared to the peer group, in accordance with the percentages outlined in the following table:

Relative TSR Performance Results	Percent Payout of Target Performance Units
80th Percentile or Higher	200	%
50th Percentile (Target)	100	%
30th Percentile	50	%
Below 30th Percentile	0	%

The Compensation Committee approved these payout levels after a review of similar plans in place by many of the companies in the peer group, after a review of the historical returns of the peer group and indices that track energy company performance, and after consultations with Spectra Energy’s outside compensation advisors. Once earned, performance units will be converted to shares of Spectra Energy common stock.

Phantom units comprised the remaining 50% of annual long-term compensation grant value. These units will vest at the end of three years at which time they will be converted to shares of Spectra Energy common stock. Dividend equivalents accumulated from the date of grant will be paid in cash on the number of performance units and phantom units at the time that units vest.

The table below shows long-term incentive awards granted to our named executive officers in 2008:

Name	Expected Value of Long-Term Incentive/Equity Grants as a Percentage of Base Salary		Number of Performance Units Granted	Number of Phantom Units Granted
Gregory J. Rizzo	100	%	6,200	5,800
Laura Buss Sayavedra	50	%	2,000	1,900
C. Gregory Harper	80	%	6,100	5,700
Lon C. Mitchell, Jr.	75	%	5,000	4,700

In addition to the awards above, Ms. Sayavedra received a grant of 5,000 Spectra Energy Partners phantom units on October 1, 2008 in recognition of her appointment to her current position. These units ratably vest over three years.

Retirement and Other Benefits. Spectra Energy provides our executives with retirement benefits under the Spectra Energy Retirement Savings Plan, the Spectra Energy Executive Savings Plan, the Spectra Energy Retirement Cash Balance Plan and the Spectra Energy Executive Cash Balance Plan. The Compensation Committee has determined that, based on market surveys, these plans are comparable to the benefits provided by our peers and provide an important tool for the attracting and retaining our executives. Please refer to “Executive Compensation” for disclosure of the amounts paid to our named executive officers under these plans.

The Spectra Energy Retirement Savings Plan, a “401(k) plan,” is generally available to all employees in the United States. The plan is a tax-qualified retirement plan that provides a means for employees to save for retirement on a tax-deferred basis and to receive an employer matching contribution. Earnings on amounts credited to the Spectra Energy Retirement Savings Plan are determined by reference to investment choices (including a Spectra Energy Common Stock Fund) selected by each participant.

The Spectra Energy Executive Savings Plan enables executives to defer compensation, and receive employer matching contributions, in excess of the limits of the Internal Revenue Code of 1986, as amended, that apply to qualified retirement plans such as the Spectra Energy Retirement Savings Plan. Earnings on amounts credited to the Spectra Energy Executive Savings Plan are determined by reference to investment choices similar to those offered under the Spectra Energy Retirement Savings Plan.

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The Spectra Energy Retirement Cash Balance Plan provides a defined benefit for retirement, the amount of which is based on a participant’s cash balance account balance, which grows with monthly pay and interest credits.

The Spectra Energy Executive Cash Balance Plan provides executives with the retirement benefits to which they would be entitled under the Spectra Energy Retirement Cash Balance Plan if the limits contained in the Internal Revenue Code of 1986, as amended, did not exist.

Perquisites and Personal Benefits. In 2008, the Compensation Committee approved a perquisite policy for executive officers. In accordance with this policy, Spectra Energy makes its private aircraft available to our executive officers for business use, and there are limited instances when the named executive officers are permitted to use Spectra Energy’s private aircraft for personal travel or to bring personal guests as passengers on business-related flights. When the executive officer’s use of aircraft or a guest’s travel does not meet the Internal Revenue Service’s (IRS) standard for business use, the cost of that travel is imputed as income to the officer.

Compensation of the Chief Executive Officer

The compensation paid to Mr. Harper in 2008 was established in a similar manner as other executives of Spectra Energy. On December 2, 2008 the Board of Directors announced Mr. Rizzo had been selected to succeed Mr. Harper as President and Chief Executive Officer of Spectra Energy Partners effective December 1, 2008. No changes were made to Mr. Rizzo’s compensation in 2008.

2009 Compensation Program

During 2007, the Compensation Committee conducted a detailed review of Spectra Energy’s compensation philosophies in connection with establishment of our compensation program for 2008. During 2008, the Compensation Committee reviewed the components of the program and believes the overall philosophy and structure of the program will continue to meet the needs of Spectra Energy to attract, retain and motivate executives of high caliber who are expected to create value for its shareholders.

The 2009 compensation opportunities shown in the table below were set for named executive officers based on: 1) a review of market-based information on peer reference group companies and survey data; 2) a review of the mix of individual pay elements; 3) the appointment of Mr. Rizzo as President and Chief Executive Officer and Ms. Sayavedra as Vice President and Chief Financial Officer; 4) individual performance and an assessment of future potential; and 5) the relationship of pay opportunities among executive officers given the relative contributions each is expected to make to our ongoing operation.

Name	Salary		Short-Term Incentive Target Opportunity		Long-Term Incentive Target Opportunity
Gregory J. Rizzo	$	315,188	50	%	100	%
Laura Buss Sayavedra	$	205,000	40	%	50	%

In February 2009, the Board of Directors approved a grant of 10,000 Spectra Energy Partners phantom units to Mr. Rizzo in recognition of his current position. These units cliff vest three years from the grant date.

Compensation Committee Report

The Audit Committee of the Board reviewed and discussed with management the Compensation Discussion and Analysis contained in this Annual Report on Form 10-K and, based on these reviews and discussions, recommended that the Compensation Discussion and Analysis be included in this Annual Report on Form 10-K.

Steven D. Arnold

Nora M. Brownell

Stewart A. Bliss

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EXECUTIVE COMPENSATION

The table below sets forth compensation from Spectra Energy Partners during 2007 and 2008 to Spectra Energy Partners’ named executive officers, which include our former President and Chief Executive Officer and former Chief Financial Officer, both of whom ended their employment with us during 2008.

SUMMARY COMPENSATION TABLE

Name and Principal Position	Year	Salary ($)	Bonus ($)	Stock Awards ($)(1)	Option Awards ($)(2)	Non-Equity Incentive Plan Compensation ($)(3)	Change in Pension Value and Nonqualified Deferred Compensation Earnings ($)(4)	All Other Compensation ($)(5)	Total ($)
Gregory J. Rizzo(6)	2008	307,500	—	237,100	67,844	198,842	78,857	35,014	925,157
President and Chief Executive Officer
Laura Buss Sayavedra(7)	2008	194,272	—	86,251	17,938	116,607	12,915	15,666	443,649
Vice President and Chief Financial Officer
C. Gregory Harper*	2008	267,199	—	318,375	35,876	—	26,629	61,167	709,246
Former Chief Executive Officer	2007	260,832	—	252,194	78,623	245,238	51,970	30,500	919,357
Lon C. Mitchell, Jr.*(8)	2008	166,667	—	102,613	—	133,981	53,137	72,244	528,642
Former Chief Financial Officer	2007	245,263	25,000	318,367	233,230	222,219	55,039	28,986	1,128,104

* Mr. Harper resigned from his position as President and Chief Executive Officer on November 30, 2008 and was succeeded by Mr. Rizzo. Mr. Mitchell retired from his position as Chief Financial Officer on June 30, 2008 and was succeeded by Ms. Sayavedra.

(1) This column reflects the aggregate dollar amount recognized for financial statement reporting purposes for 2007 with respect to outstanding performance share and phantom share awards, and includes amounts attributable to performance share and phantom share awards granted in prior years. The aggregate dollar amount was determined in accordance with the provisions of SFAS No. 123(R), but without regard to any estimate of forfeitures related to service-based vesting conditions. See Note 16 of Notes to Consolidated Financial Statements regarding assumptions underlying the valuation of equity awards. Mr. Mitchell’s remaining option award expense was accelerated as of December 31, 2007 as he was retirement eligible. As a result, no option expense was recorded for Mr. Mitchell for 2008.

(2) This column reflects the aggregate dollar amount recognized for financial statement reporting purposes for 2007 with respect to outstanding stock options, and includes amounts attributable to stock options granted in prior years. The aggregate dollar amount was determined in accordance with the provisions of SFAS No. 123(R). See Note 16 of Notes to Consolidated Financial Statements regarding assumptions underlying the valuation of equity awards.

(3) This column includes amounts payable under the Spectra STI Plan with respect to the 2008 and 2007 performance period. Unless deferred, these amounts were paid, respectively, in March 2009 and March 2008.

(4) This column includes the amounts listed below. During 2007, our pension plan measurement date was changed from September 30 to December 31. Therefore, figures for 2007 represent the change in value during the fifteen month period ending December 31, 2007 whereas figures for 2008 represent the change in value during the twelve month period ending December 31, 2008.

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	Gregory J. Rizzo		Laura Buss Sayavedra		C. Gregory Harper		Lon C. Mitchell, Jr.
Change in actuarial present value of accumulated benefit under the Spectra Energy Retirement Cash Balance Plan for the period beginning on January 1, 2008 and ending on December 31, 2008	$	49,066	$	7,972	$	8,031	$	36,960
Change in actuarial present value of accumulated benefit under the Spectra Energy Executive Cash Balance Plan for the period beginning on January 1, 2008 and ending on December 31, 2008		29,791		4,943		18,598		16,177
Total	$	78,857	$	12,915	$	26,629	$	53,137

(5) All Other Compensation column includes the following for 2008:

	Gregory J. Rizzo		Laura Buss Sayavedra		C. Gregory Harper		Lon C. Mitchell, Jr.
Personal use of airplane	$	—	$	—	$	2,252	$	—
Matching contributions under the Spectra Energy Retirement Savings Plan		13,800		13,800		13,800		13,800
Premiums for life insurance coverage provided under Life Insurance Plans		1,504		366		601		1,551
Make-whole matching contribution credits under the Spectra Energy Executive Savings Plan		19,710		—		15,060		10,073
Charitable contributions made in the name of the Executive under Spectra Energy’s matching gift policy		—		1,500		3,100		—
Lump sum merit		—		—		—		9,000
Accrued vacation upon termination		—		—		26,354		37,820
Total	$	35,014	$	15,666	$	61,167	$	72,244

(6) Mr. Rizzo became President and Chief Executive Officer effective December 1, 2008. Compensation for the entire fiscal year 2008 is disclosed for Mr. Rizzo.

(7) Ms. Sayavedra became Vice President and Chief Financial Officer effective July 1, 2008. Compensation for the entire fiscal year 2008 is disclosed for Ms. Sayavedra.

(8) Mr. Mitchell received a discretionary bonus equal to $25,000 in connection with his efforts relating to the spin-off of Spectra Energy from Duke Energy.

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2008 GRANTS OF PLAN-BASED AWARDS

		Committee Approval Date	Estimated Possible Payouts Under Non-Equity Incentive Plan Awards(1)						Estimated Future Payouts Under Equity Incentive Plan Awards(2)(3)			All Other Stock Awards: Number of Shares of Stock or Units	Grant Date Fair Value of Stock and Option Awards ($)(4)
Name	Grant Date		Threshold		Target		Maximum		Threshold	Target	Maximum
			($)		($)		($)		(#)	(#)	(#)	(#)(2)(3)
Gregory J. Rizzo			$	76,875	$	153,750	$	292,125
Gregory J. Rizzo	2/26/2008	2/25/2008							3,100	6,200	12,400		$	190,216
Gregory J. Rizzo	2/26/2008	2/25/2008										5,800	$	141,114
Laura Buss Sayavedra			$	40,000	$	80,000	$	152,000
Laura Buss Sayavedra	2/26/2008	2/25/2008							1,000	2,000	4,000		$	61,360
Laura Buss Sayavedra	2/26/2008	2/25/2008										1,900	$	46,227
Laura Buss Sayavedra	10/1/2008	8/22/2008										5,000	$	95,000
C. Gregory Harper			$	—	$	—	$	—
C. Gregory Harper	2/26/2008	2/25/2008							3,050	6,100	12,200		$	187,148
C. Gregory Harper	2/26/2008	2/25/2008										5,700	$	138,681
Lon C. Mitchell, Jr.			$	43,575	$	87,150	$	165,585
Lon C. Mitchell, Jr.	2/26/2008	2/25/2008							2,500	5,000	10,000		$	153,400
Lon C. Mitchell, Jr.	2/26/2008	2/25/2008										4,700	$	114,351

(1) The awards reflected in the Estimated Possible Payouts Under Non-Equity Incentive Plan Awards column were granted for the 2008 performance period under the terms of the Spectra Energy Corp Executive STI Plan. The actual amounts payable to each executive under the terms of such plan are disclosed in the Summary Compensation Table. Due to Mr. Harper’s resignation prior to December 31, 2008, he was ineligible for an award. Due to Mr. Mitchell’s retirement prior to December 31, 2008, he was eligible for a pro-rated award based on service during the fiscal year 2008, which is reflected in the table above.

(2) Awards reflected in these columns with a grant date of February 26, 2008 were made in shares of Spectra Energy common stock and were granted under the terms of the Spectra Energy Corp 2007 Long-Term Incentive Plan. Awards reflected in these columns with a grant date of October 1, 2008 were made in units of Spectra Energy Partners and were granted under the terms of the Spectra Energy Partners 2007 Long-Term Incentive Plan.

(3) Awards reflected in these columns for Mr. Harper were later cancelled in accordance with his resignation on December 6, 2008 and for Mr. Mitchell were later reduced in conjunction with his retirement on August 30, 2008. Any awards that remain outstanding for Mr. Mitchell are included in the Outstanding Equity Awards Table.

(4) The per share full grant date fair value of the phantom shares and performance shares granted on February 26, 2008, computed in accordance with SFAS No. 123(R) is $24.33 and $30.68, respectively. The per unit full grant date fair value of the phantom units granted on October 1, 2008, computed in accordance with SFAS No. 123(R) is $19.00.

When Duke Energy spun-off its gas businesses to form Spectra Energy, equitable adjustments were made with respect to outstanding stock options and other forms of equity awards originally denominated in shares of Duke Energy common stock. All such awards were adjusted into two separate awards, one denominated in shares of Duke Energy common stock and one denominated in shares of Spectra Energy common stock. The number of shares of Spectra Energy common stock distributed to award holders was equal to the number of Spectra Energy shares that a shareholder of Duke Energy common stock would have received effective on the January 2, 2007 spin date (i.e., a ratio of 0.5 shares of Spectra Energy common stock for every one share of Duke Energy common stock). With respect to stock options, the per share option exercise price of the original Duke Energy stock option was proportionally allocated between the two types of stock options taking into account the distribution ratio and the relative per share trading prices following the distribution. The resulting Duke Energy and Spectra Energy awards continue to be subject to the vesting schedule under the original Duke Energy award agreement. For purposes of vesting of options and phantom stock and the post-termination exercise periods applicable to the options, continued employment with Spectra Energy is considered to be continued employment with the issuer of the options or shares of phantom stock. The adjustments preserved, but did not increase, the value of the equity awards.

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OUTSTANDING EQUITY AWARDS AT 2008 FISCAL YEAR-END

	Option Awards						Stock Awards
Name	Number of Securities Underlying Unexercised Options (#) Exercisable		Number of Securities Underlying Unexercised Options (#) Unexercisable(1)	Option Exercise Price ($)(2)		Option Expiration Date	Number of Shares or Units of Stock That Have Not Vested (#)(3)(4)		Market Value of Shares or Units of Stock That Have Not Vested ($)		Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested (#)(5)	Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested ($)
Gregory J. Rizzo	SE	3,800		$	36.86	12/20/2010
	DUK	7,600		$	24.39
	SE	3,850		$	32.44	12/19/2011
	DUK	7,700		$	21.47
	SE	1,700		$	32.54	4/1/2012
	DUK	3,400		$	21.54
	SE	1,612		$	11.86	2/25/2013
	DUK	3,225		$	7.85
	SE	512		$	12.52	4/1/2013
	DUK	1,025		$	8.29
	SE	12,734	25,466	$	25.64	2/27/2017
							SE	14,870	$	234,054
							SEP	3,700		73,186
							DUK	4,940		74,149
							Total		$	381,389
							SE				6,200	$	97,588
							SEP				—		—
							DUK				—		—
							Total					$	97,588
Laura Buss Sayavedra(6)	SE	950		$	21.42	12/20/2009
	SE	1,100		$	36.86	12/20/2010
	DUK	2,200		$	24.39
	SE	1,350		$	32.44	12/19/2011
	DUK	2,700		$	21.47
	SE	825		$	11.86	2/25/2013
	SE	3,368	6,732	$	25.64	2/27/2017
							SE	4,197	$	66,061
							SEP	6,000		118,680
							DUK	1,194		17,922
							Total		$	202,663
							SE				2,000	$	31,480
							SEP				—		—
							DUK				—		—
							Total					$	31,480

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	Option Awards						Stock Awards
Name	Number of Securities Underlying Unexercised Options (#) Exercisable		Number of Securities Underlying Unexercised Options (#) Unexercisable(1)	Option Exercise Price ($)(2)		Option Expiration Date	Number of Shares or Units of Stock That Have Not Vested (#)(3)(4)		Market Value of Shares or Units of Stock That Have Not Vested ($)		Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested (#)(5)	Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested ($)
C. Gregory Harper(7)	SE	1,400		$	25.53	2/17/2009
	DUK	2,800		$	16.90
	SE	1,700		$	21.42	3/5/2009
	DUK	3,400		$	14.17
	SE	2,100		$	36.86	3/5/2009
	DUK	4,200		$	24.39
	SE	1,900		$	32.44	3/5/2009
	DUK	3,800		$	21.47
	SE	500		$	33.00	3/5/2009
	DUK	1,000		$	21.84
	SE	625		$	11.86	3/5/2009
	SE	850		$	12.52	3/5/2009
	DUK	350		$	8.29
	SE	6,734		$	25.64	3/5/2009
							SE	—	$	—
							SEP	—		—
							DUK	—		—
							Total		$	—
							SE				—	$	—
							SEP				—		—
							DUK				—		—
							Total					$	—
Lon C. Mitchell, Jr.	SE	2,900		$	36.86	12/20/2010
	DUK	5,800		$	24.39
	SE	6,150		$	32.44	12/19/2011
	DUK	12,300		$	21.47
	SE	6,375		$	11.86	2/25/2013
	SE	10,268	20,532	$	25.64	2/27/2017
							SE	5,707	$	89,828
							SEP	417		8,248
							DUK	3,992		59,920
							Total		$	157,996
							SE				1,111	$	17,487
							SEP				—		—
							DUK				—		—
							Total					$	17,487

(1) On February 27, 2007, Mr. Rizzo, Ms. Sayavedra and Mr. Mitchell received stock options that vest in three equal installments on the first three anniversaries of the date of grant.

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(2) For options granted February 27, 2007, the exercise price is equal to the closing price of Spectra Energy common stock on the date of grant. For options granted prior to December 31, 2006, the exercise price for the original Duke Energy options is equal to the closing price of Duke Energy common stock on the date of grant. In connection with the spin-off of Spectra Energy effective January 2, 2007, all Duke Energy equity awards were adjusted to reflect the change in the price of Duke Energy common stock that occurred as a result of the spin-off, and an additional award denominated in Spectra Energy common shares was granted. The adjustments preserved, but did not increase, the value of the equity awards. The following chart indicates the original and adjusted exercise prices of each Duke Energy stock option. In addition, the chart indicates exercise prices for stock options granted on January 2, 2007 at Spectra Energy associated to each grant date at Duke Energy:

Date of Grant	Duke Energy Original Option Exercise Price		Duke Energy Adjusted Option Exercise Price		Spectra Energy Option Exercise Price Granted on January 2, 2007
February 17, 1999	$	29.66	$	16.90	$	25.53
December 20, 1999	$	24.88	$	14.17	$	21.42
December 20, 2000	$	42.81	$	24.39	$	36.86
December 19, 2001	$	37.68	$	21.47	$	32.44
April 1, 2002	$	37.80	$	21.54	$	32.54
February 25, 2003	$	13.77	$	7.85	$	11.86
April 1, 2003	$	14.54	$	8.29	$	12.52

(3) Mr. Rizzo, Ms. Sayavedra and Mr. Mitchell received Spectra Energy and Duke Energy phantom shares as follows:

a. On February 26, 2008 and on February 27, 2007, Spectra Energy shares were granted which, subject to certain exceptions, vest on the third anniversary of the date of grant.

b. On February 28, 2005 and April 4, 2006, Duke Energy shares were granted which, subject to certain exceptions, vest in equal installments on the first five anniversaries of the date of grant. Outstanding Duke Energy shares and corresponding Spectra Energy shares related to this award are included above.

(4) Mr. Mitchell received Spectra Energy Partners phantom units on July 2, 2007 which, subject to certain exceptions, vest in three equal installments on the first three anniversaries of the date of grant. Mr. Rizzo and Ms. Sayavedra received Spectra Energy Partners phantom units on July 2, 2007 each of which, subject to certain exceptions, vest on the third anniversary of the date of grant.

(5) Mr. Rizzo, Ms. Sayavedra and Mr. Mitchell received performance shares on February 26, 2008 that, subject to certain exceptions, are eligible for vesting on December 31, 2008. Pursuant to Instruction 3 to Item 402(f)(2) of Regulation S-K, performance shares are listed at the target number of shares.

(6) On October 1, 2008, Ms. Sayavedra received a grant in the amount of 5,000 units, which, subject to certain exceptions, vest in equal installments on the first three anniversaries of the date of grant.

(7) Due to his resignation, Mr. Harper’s stock options expired within 3 months of his resignation and all outstanding shares or units were forfeited.

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2008 OPTION EXERCISES AND STOCK VESTED

	Option Awards			Stock Awards
Name	Number of Shares Acquired on Exercise(#)	Value Realized on Exercise ($)(1)		Number of Shares Acquired on Vesting(#)(2)	Value Realized on Vesting($)(3)
Gregory J. Rizzo
Spectra Energy	9,900	$	33,804	4,122	$	69,215
Duke Energy	8,550		36,851	8,245		144,949
Total		$	70,655		$	214,164
Laura Buss Sayavedra
Spectra Energy				3,008	$	62,811
Duke Energy				6,016		107,958
Total					$	170,769
C. Gregory Harper
Spectra Energy	—	$	—	3,107	$	71,879
Spectra Energy Partners				3,333		85,758
Duke Energy	5,000		42,770	6,214		116,320
Total		$	42,770		$	273,957
Lon C. Mitchell, Jr.
Spectra Energy				5,543	$	109,145
Spectra Energy Partners				2,500		64,925
Duke Energy				11,086		197,724
Total					$	371,794

(1) The value realized upon exercise was calculated based on the closing price of a share of Spectra Energy or Duke Energy common stock on the date of option exercise.

(2) Includes performance shares covering the 2006 — 2008 performance period based on Duke Energy’s total shareholder return performance from January 1, 2006 — December 31, 2006 and equally weighted between Duke Energy and Spectra Energy’s total shareholder performance from January 1, 2007 — December 31, 2008.

(3) The value realized upon vesting of stock awards was calculated based on the closing price of a share of common stock for the respective equity on the respective vesting date, and includes a cash payment to Mr. Rizzo, Ms. Sayavedra and Mr. Mitchell for dividend equivalents on earned performance shares in the amount of $24,981, $6,137 and $17,885, respectively. In addition, Messrs. Harper and Mitchell also received a cash payment for distribution equivalents on earned phantom shares in the amount of $3,166 and $2,375, respectively.

Spectra Energy Retirement Cash Balance Plan and Executive Cash Balance Plan

Spectra Energy provides pension benefits that are intended to assist its retirees with their retirement income needs. A more detailed description of the plans that comprise Spectra Energy’s pension program follows.

Each of the Spectra Energy Partners executive officers actively participated in pension plans sponsored by Spectra Energy or an affiliate in 2008. Officers participated in the Spectra Energy Retirement Cash Balance Plan (“RCBP”), which is a noncontributory, defined benefit retirement plan that is intended to satisfy the requirements for qualification under Section 401(a) of the Internal Revenue Code. The RCBP generally covers non-bargaining employees of Spectra Energy and affiliates. The RCBP provides benefits under a “cash balance account” formula.

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Each of the Spectra Energy Partners executive officers who participates in the RCBP has satisfied the eligibility requirements to receive his or her account benefit upon termination of employment. The RCBP benefit is payable in the form of a lump sum in the amount credited to the hypothetical account at the time of benefit commencement. Payment is also available in the form of an annuity based on the actuarial equivalent of the account balance.

The amount credited to the hypothetical account is increased with monthly pay credits equal to (a) for participants with combined age and service of less than 35 points, 4% of eligible monthly compensation, (b) for participants with combined age and service of 35 to 49 points, 5% of eligible monthly compensation, (c) for participants with combined age and service of 50 to 64 points, 6% of eligible monthly compensation, and (d) for participants with combined age and service of 65 or more points, 7% of eligible monthly compensation. If the participant earns more than the Social Security wage base, the account is credited with additional pay credits equal to 4% of eligible compensation above the Social Security wage base. Interest credits are credited monthly, with the interest rate determined quarterly based on the 30-year Treasury rate.

For the RCBP, eligible monthly compensation is equal to Form W-2 wages, plus elective deferrals under a 401(k) or cafeteria plan. Compensation does not include severance pay (including payment for unused vacation), expense reimbursements, allowances, cash or noncash fringe benefits, moving expenses, bonuses for performance periods in excess of one year, transition pay, long-term incentive compensation (including income resulting from any stock-based awards such as stock options, stock appreciation rights, phantom stock or restricted stock) and other compensation items to the extent described as not included for purposes of benefit plans or the RCBP.

The benefit of participants in the RCBP may not be less than determined under certain prior benefit formulas (including optional forms). In addition, the benefit under the RCBP is limited by maximum benefits and compensation limits under the Internal Revenue Code.

Each of the Spectra Energy Partners executive officers was eligible to participate in the Spectra Energy Executive Cash Balance Plan (“ECBP”), which is a noncontributory, defined benefit retirement plan that is not intended to satisfy the requirements for qualification under Section 401(a) of the Internal Revenue Code. Benefits earned under the ECBP are attributable to (a) compensation in excess of the annual compensation limit ($230,000 for 2008) under the Internal Revenue Code that applies to the determination of pay credits under the RCBP, (b) certain deferred compensation that is not recognized by the RCBP, (c) restoration of benefits in excess of a defined benefit plan maximum annual benefit limit ($185,000 for 2008) under the Internal Revenue Code that applies to the RCBP, and (d) supplemental benefits granted to a particular participant. Generally, benefits earned under the RCBP and the ECBP vest upon completion of three years of service, and, with certain exceptions, vested benefits generally become payable upon termination of employment with Spectra Energy.

Spectra Energy has established a grantor trust that is subject to the claims of our creditors into which funds related to the ECBP are deposited. Funds deposited into the trust are managed by an independent trustee subject to guidelines provided by us.

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The following table provides information related to each plan that provides for payments or other benefits at, following or in connection with retirement, determined as of December 31, 2008.

PENSION BENEFITS

Name	Plan Name	Number of Years Credited Service (#)	Present Value of Accumulated Benefit ($)		Payments During Last Fiscal Year ($)
Gregory J. Rizzo	Spectra Energy Retirement Cash Balance Plan	29.34	$	392,924	$	—
Gregory J. Rizzo	Spectra Energy Executive Cash Balance Plan	29.34	$	181,605	$	—
Laura Buss Sayavedra	Spectra Energy Retirement Cash Balance Plan	13.15	$	109,076	$	—
Laura Buss Sayavedra	Spectra Energy Executive Cash Balance Plan	13.15	$	7,064	$	—
C. Gregory Harper	Spectra Energy Retirement Cash Balance Plan	21.62	$	163,624	$	—
C. Gregory Harper	Spectra Energy Executive Cash Balance Plan	21.62	$	78,430	$	—
Lon C. Mitchell, Jr.	Spectra Energy Retirement Cash Balance Plan	8.39	$	—	$	158,017
Lon C. Mitchell, Jr.	Spectra Energy Executive Cash Balance Plan	8.39	$	113,025	$	—

Spectra Energy Executive Savings Plan

Under the Spectra Energy Executive Savings Plan, participants can elect to defer a portion of their base salary, short-term incentive compensation and long-term incentive compensation (other than stock options). Participants also receive a company matching contribution in excess of the contribution limits prescribed by the IRS under the Spectra Energy Corp Retirement Savings Plan. In general, payments are made following termination of employment or death in the form of a lump sum or installments, as selected by the participant. Participants may request an accelerated distribution upon an “unforeseeable emergency.” In general, participants may direct the deemed investment of base salary deferrals, short-term incentive deferrals and matching contributions among investments options available under the Spectra Energy Retirement Savings Plan, including in a Spectra Energy Common Stock Fund. Deferrals of equity awards are credited with earnings and losses based on the performance of the Spectra Energy Common Stock Fund. Spectra Energy has established a grantor trust that is subject to the claims of our creditors into which funds related to the Spectra Energy Executive Savings Plan are deposited. Funds deposited into the trust are managed by an independent trustee subject to guidelines provided by us.

The Spectra Energy Executive Savings Plan and the Spectra Energy Retirement Savings Plan became effective with the spin-off of Spectra Energy. These plans contain the same provisions as the predecessor plans sponsored by Duke Energy, and individual benefit accruals were transferred from the Duke Energy plans to the Spectra Energy plans effective with the spin-off of Spectra Energy. Participants received credit for investment in 0.5 of a share of Spectra Energy common stock for each share of Duke Energy common stock held in the Duke Energy Common Stock Fund.

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NONQUALIFIED DEFERRED COMPENSATION

Name	Executive Contributions in Last FY ($)(1)		Registrant Contributions in Last FY($)(2)		Aggregate Earnings in Last FY ($)(3)			Aggregate Withdrawals/ Distributions ($)			Aggregate Balance at Last FYE ($)
Gregory J. Rizzo Spectra Energy Executive Savings Plan	$	15,060	$	14,492	$	(99,463	)	$	—		$	291,713
Laura Buss Sayavedra Spectra Energy Executive Savings Plan	$	—	$	—	$	—		$	—		$	—
C. Gregory Harper Spectra Energy Executive Savings Plan	$	13,360	$	13,933	$	(25,413	)	$	—		$	59,562
Lon C. Mitchell, Jr Spectra Energy Executive Savings Plan	$	146,243	$	26,658	$	(112,688	)	$	(71,254	)	$	217,763

(1) Executive contributions credited to the plan in 2008 include amounts reported as “Salary” in the Summary Compensation Table as well as “Non-Equity Incentive Plan Compensation” paid in 2008 but reported in the table as compensation earned in 2007.

(2) Reflects make-whole matching contribution credits made in 2008 under the Spectra Energy Executive Savings Plan with respect to elective salary deferrals made by executives during 2007. See footnote 5 to the “Summary Compensation Table” for the amount of make-whole matching contribution credits made to the Spectra Energy Executive Savings Plan in 2009 with respect to elective compensation deferrals made by executives during 2008.

(3) Negative amounts reflect losses incurred during the fiscal year 2008 due to market conditions.

Potential Payments Upon Termination of Employment or Change in Control

Under certain circumstances, each Spectra Energy Partners executive officer would be entitled to compensation in the event his or her employment terminates. The amount of the compensation is contingent upon a variety of factors, including the circumstances under which employment is terminated. The relevant agreements and terms of awards applicable to named executive officers are described below, followed by a table that quantifies the amount that would become payable to each Spectra Energy Partners executive officer as a result of his or her termination of employment. The amounts shown assume that such termination was effective as of December 31, 2008 and are estimates of the amounts that would be paid. The actual amounts that would be paid can only be determined at the time of named executive officer’s termination of employment.

The following table summarizes the consequences under Duke Energy’s long-term incentive award agreements, without giving effect to the change in control agreements described below, that would occur in the event of the termination of employment of a Spectra Energy Partners executive officer.

Event	Consequences
Termination with cause	Phantom Shares and Options — the executive’s right to unvested portion of award terminates immediately
Voluntary termination (not retirement eligible)	Phantom Shares and Options — the executive’s right to unvested portion of award terminates immediately
Involuntary termination without cause (not retirement eligible)	Phantom Shares — prorated portion of award vests
Voluntary termination or involuntary termination without cause (retirement eligible)	Phantom Shares — continue to vest
Involuntary or good reason termination after a Change in Control	Phantom Shares — award vests
Death or Disability	Phantom Shares — prorated portion of award vests

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The following table summarizes the consequences under Spectra Energy and Spectra Energy Partners’ long-term incentive award agreements, without giving effect to the change in control agreements described below, that would occur in the event of the termination of employment of a Spectra Energy Partners executive officer.

Event	Consequences
Termination with cause	Phantom Shares, Performance Shares and Options — the executive’s right to unvested portion of award terminates immediately
Voluntary termination (not retirement eligible)	Phantom Shares, Performance Shares and Options — the executive’s right to unvested portion of award terminates immediately
Involuntary termination without cause (not retirement eligible)	Phantom Shares — prorated portion of award vests Performance Shares — prorated portion of award vests based on actual performance after performance period ends Options — the executive’s right to unvested shares terminates immediately
Voluntary termination or involuntary termination without cause (retirement eligible)	Phantom Shares — prorated portion of award continues to vest Performance Shares — prorated portion of award vests based on actual performance after performance period ends Options — continue to vest
Involuntary or good reason termination after a Change in Control	Phantom Shares — award vests Performance Shares — award vests based on target performance Options — award vests
Death or Disability	Phantom Shares — award vests Performance Shares — award vests based on target performance Options — award vests

Effective with the formation of Spectra Energy, Mr. Rizzo entered into a Change in Control Agreement with Spectra Energy. The agreement has an initial term of two years, after which the agreement automatically extends from the first date of each month for one additional month, unless six months prior written notice is provided.

The Change in Control Agreement provides for payments and benefits to the executive in the event of termination of employment within two years after a “change in control” of Spectra Energy, other than termination: 1) by Spectra Energy for “cause”; 2) by reason of death or disability; or 3) of the executive for other than “good reason” (each such term as defined in the agreements). Payments and benefits include: (1) a lump-sum cash payment equal to a pro-rata amount of the executive’s target bonus for the year in which the termination occurs; (2) a lump-sum cash payment equal to two times the sum of the executive’s annual base salary and target annual bonus opportunity in effect immediately prior to termination or, if higher, in effect immediately prior to the first occurrence of an event or circumstance constituting “good reason”; (3) continued medical, dental and basic life insurance coverage for a two-year period (or a lump sum cash payment of equivalent value); and (4) a lump-sum cash payment representing the amount Spectra Energy would have allocated or contributed to the executive’s qualified and nonqualified defined benefit pension plan and defined contribution savings plan accounts during the two years following the termination date, plus the unvested portion, if any, of the executive’s accounts as of the date of termination that would have vested during such two year period. In addition, under certain circumstances the agreement may provide for continued vesting of certain long-term incentive awards for two additional years.

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Under the Change in Control Agreement, the covered executive is also entitled to reimbursement of up to $50,000 for the cost of certain legal fees incurred in connection with claims under the agreements. In the event that any of the payments or benefits provided for in the Change in Control Agreement otherwise would constitute an “excess parachute payment” (as defined in Section 280G of the Internal Revenue Code), the amount of payments or benefits would be reduced to the maximum level that would not result in excise tax under Section 4999 of the Internal Revenue Code if such reduction would cause the executive to retain an after-tax amount in excess of what would be retained if no reduction were made. In the event a named executive officer becomes entitled to payments and benefits under a change in control agreement, he or she would be subject to a one-year noncompetition and nonsolicitation provision from the date of termination, in addition to certain confidentiality and cooperation provisions.

Due to Mr. Harper’s resignation and Mr. Mitchell’s retirement prior to December 31, 2008, they were not entitled to any benefits other than those disclosed in previous tables. Therefore, they are not included in the table below.

POTENTIAL PAYMENTS UPON TERMINATION OF

EMPLOYMENT OR A CHANGE IN CONTROL (“CIC”)

Name and Triggering Event(1)	Cash Severance Payment ($)(2)	Incremental Retirement Plan Benefit ($)(3)	Welfare and Similar Benefits ($)(4)	Stock Awards ($)(5)(6)	Option Awards ($)(7)	Total Payments ($)
Gregory J. Rizzo
Voluntary termination or involuntary termination with cause	—	—	11,827	—	—	11,827
Involuntary termination without cause	—	—	11,827	177,814	—	189,641
Involuntary or good reason termination after a CIC	922,500	97,052	34,271	504,497	—	1,558,320
Death	—	—	11,827	427,267	—	439,094
Disability	—	—	11,827	427,267	—	439,094
Laura Buss Sayavedra
Voluntary termination or involuntary termination with cause	—	—	3,846	—	—	3,846
Involuntary termination without cause	—	—	3,846	56,128	—	59,974
Involuntary or good reason termination after a CIC	—	—	3,846	243,134	—	246,980
Death	—	—	3,846	224,429	—	228,275
Disability	—	—	3,846	224,429	—	228,275

(1) Amounts in the above table represent obligations of Spectra Energy under agreements currently in place at Spectra Energy, and valued as of December 31, 2008.

(2) Amounts listed under “Cash Severance Payment” are payable under the terms of Mr. Rizzo’s change in control agreement. The severance benefits set forth above do not include accrued salary and bonus payments earned through December 31, 2008; however, such amounts are reflected in the Summary Compensation Table above.

(3) Pursuant to Mr. Rizzo’s Change in Control Agreement, amounts listed under “Incremental Retirement Plan Benefit” represent the additional amounts that would be credited in respect of the Spectra Energy Retirement Cash Balance Plan, Spectra Energy Executive Cash Balance Plan, Spectra Energy Retirement Savings Plan and the Spectra Energy Executive Savings Plan in the event he continued to be employed by Spectra Energy, at his rate of base salary as in effect on December 31, 2008, for two additional years.

(4) Amounts listed under “Welfare and Other Benefits” include accrued vacation and the amount that would be paid to Mr. Rizzo who has entered into a Change in Control Agreement in lieu of providing continued welfare benefits for 24 months.

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(5) The amount listed under “Stock Awards” do not include amounts attributable to the performance shares that vested on December 31, 2008; such amounts are included in the Option Exercises and Stock Vested Table above.

(6) The amounts listed under “Stock Awards” do not include amounts attributable to performance shares that, upon applicable termination events, are prorated based on service from the grant date to December 31, 2008 and vest subject to a performance determination at the end of the performance period. The amounts listed would be the result of the acceleration of the vesting of previously awarded stock as a result of a change in control.

(7) The number of shares of common stock underlying options for which (a) vesting is accelerated upon the applicable termination event or (b) vesting continues after the applicable termination event (i.e., due to the executives being retirement eligible) for Mr. Rizzo and Ms. Sayavedra were 25,466 and 6,732, respectively. The exercise price for these options is higher than the price of Spectra Energy common stock on December 31, 2007 and therefore, the amounts listed under “Option Awards” is zero.

The amounts listed in the preceding table have been determined based on a variety of assumptions, and the actual amounts to be paid out can only be determined at the time of each Spectra Energy Partners executive officer’s termination of employment. The amounts described in the table do not include compensation to which each Spectra Energy Partners executive officer would be entitled without regard to his or her termination of employment, including (a) base salary and short-term incentives that have been earned but not yet paid, and (b) amounts that have been earned, but not yet paid, under the terms of the plans listed under the “Pension Benefits” and “Nonqualified Deferred Compensation” tables.

With respect to Mr. Rizzo, the amounts shown above do not reflect the fact that if, in the event that payments to the executive in connection with a change in control otherwise would result in an excise tax under Section 4999 of the Internal Revenue Code of 1986, as amended, such payments may be reduced to the extent necessary so that the excise tax does not apply.

The amounts shown above with respect to outstanding Spectra Energy, Spectra Energy Partners and Duke Energy stock awards and option awards were calculated based on a variety of assumptions, including the following: (a) the Spectra Energy Partners executive officer terminated employment on the last day of 2008; (b) as price for Spectra Energy common stock of $15.74, for Spectra Energy Partners units of $19.78 and for Duke Energy common stock of $15.01, all of which were the closing prices on December 31, 2008; (c) the continuation of Spectra Energy’s and Duke Energy’s dividend and Spectra Energy Partners’ distribution at the rate in effect on December 31, 2008; and (d) performance at the target level with respect to performance shares.

If a change in control of Spectra Energy occurred on December 31, 2008, the outstanding performance shares awards would be paid out on a prorated basis assuming target performance. As of December 31, 2008, the prorated performance shares that would be paid as a result of these accelerated vesting provisions would have had a value of $102,114 and $32,940 for Mr. Rizzo and Ms. Sayavedra, respectively.

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Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.

The following table sets forth the beneficial ownership of Spectra Energy Partners’ units and the related transactions and held by:

• each person who then will beneficially own 5% or more of the then outstanding units;

• all of the directors of the General Partner;

• each named executive officer of the General Partner; and

• all directors and officers of the General Partner as a group.

Name of Beneficial Owner(1)	Common Units Beneficially Owned	Percentage of Common Units Beneficially Owned		Subordinated Units Beneficially Owned	Percentage of Subordinated Units Beneficially Owned		Percentage of Total Common and Subordinated Units Beneficially Owned
Spectra Energy Corp(2)	37,337,521	76.4	%	21,638,730	100.0	%	83.7	%
Spectra Energy Transmission LLC	11,920,493	24.4	%	5,037,637	23.3	%	24.1	%
Spectra Energy Southeast Pipeline Corp.	25,417,028	52.0	%	16,601,093	76.7	%	59.6	%
Fred J. Fowler	9,400	*		—	—		*
R. Mark Fiedorek	11,500	*		—	—		*
Patrick J. Hester	—	*		—	—		*
Gregory J. Rizzo	5,000	*		—	—		*
Laura Buss Sayavedra	250	*		—	—		*
Steven D. Arnold	30,449	*		—	—		*
Nora M. Brownell	1,218	*		—	—		*
Stewart A. Bliss	3,949	*		—	—		*
All directors and executive officers as a group (eight persons)	61,766	*		—	—		*

(*) Less than 1% of units outstanding.

(1) Unless otherwise indicated, the address for all beneficial owners in this table is 5400 Westheimer Court, Houston, TX 77056.

(2) Spectra Energy is the ultimate parent company of each of Spectra Energy Transmission, Spectra Energy Southeast Pipeline Corp. and Spectra Energy Partners (DE) GP, LP and may, therefore, be deemed to beneficially own the units held by each of these entities.

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Equity Compensation Plan Information

The following table summarizes information about Spectra Energy Partners’ equity compensation plan as of December 31, 2008.

	Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights(1) (a)	Weighted -Average Exercise Price of Outstanding Options, Warrants and Rights (b)	Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column(a)) (c)
Equity compensation plans approved by unitholders	—	n/a	—
Equity compensation plans not approved by unitholders	—	n/a	810,275
Total	—	n/a	810,275

(1) The long-term incentive plan currently permits the grant of awards covering an aggregate of 900,000 units.

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Item 13. Certain Relationships and Related Transactions, and Director Independence.

Spectra Energy and its affiliates own 37,337,521 common units and 21,638,730 subordinated units, representing an aggregate 84% limited partner interest in Spectra Energy Partners. In addition, the General Partner owns a 2% general partner interest in Spectra Energy Partners and all of the incentive distribution rights.

Distributions and Payments to The General Partner and its Affiliates

The following table summarizes the distributions and payments made or to be made by Spectra Energy Partners to the General Partner and its affiliates in connection with the ongoing operation and any liquidation of Spectra Energy Partners. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm’s-length negotiations.

Operational Stage

Distributions of Available Cash to the General Partner and its affiliates Spectra Energy Partners generally makes cash distributions 98% to its unitholders pro rata, including the General Partner and its affiliates, as the holders of an aggregate 37,337,521 common units, 21,638,730 subordinated units, and 2% to the General Partner. In addition, if distributions exceed the minimum quarterly distribution and other higher target distribution levels, the General Partner will be entitled to increasing percentages of the distributions, up to 50% of the distributions above the highest target distribution level.

Payments to the General Partner and its affiliates Spectra Energy Partners reimburses Spectra Energy and its affiliates for the payment of certain operating expenses and for the provision of various general and administrative services for the benefit of Spectra Energy Partners.

Withdrawal or removal the General Partner If the General Partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests.

Liquidation Stage

Liquidation Upon Spectra Energy Partners’ liquidation, the partners, including the General Partner, will be entitled to receive liquidating distributions according to their respective capital account balances.

Omnibus Agreement

In connection with its IPO, Spectra Energy Partners entered into an omnibus agreement with Spectra Energy, its general partner and others that addresses the following matters:

• Spectra Energy Partners’ obligation to reimburse Spectra Energy for the payment of direct operating expenses it incurs on Spectra Energy Partners’ behalf in connection with Spectra Energy Partners’ business and operations;

• Spectra Energy Partners’ obligation to reimburse Spectra Energy for providing it allocated corporate, general and administrative services, which reimbursement is capped at $3.0 million per year, subject to

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adjustment for inflation and increases in connection with expansions of operations through the acquisition or construction of new assets or businesses with the concurrence of Spectra Energy Partners’ Conflicts Committee; and

• Spectra Energy’s obligation to indemnify Spectra Energy Partners’ for certain liabilities and Spectra Energy Partners’ obligation to indemnify Spectra Energy for certain liabilities.

The General Partner and its affiliates also receive payments from Spectra Energy Partners pursuant to the contractual arrangements described below under the caption “Contracts with Affiliates.”

Any or all of the provisions of the Omnibus Agreement, other than the indemnification provisions described below, is terminable by Spectra Energy at its option if the General Partner is removed without cause and units held by the General Partner and its affiliates are not voted in favor of that removal. The Omnibus Agreement (other than the indemnification provisions) will also terminate in the event of a change of control of Spectra Energy Partners, its general partner or the general partner of its general partner.

Reimbursement of Operating and General and Administrative Expense

Under the Omnibus Agreement, Spectra Energy Partners reimburses Spectra Energy for the payment of certain operating expenses and for the provision of various corporate, general and administrative services (which corporate, general and administrative expenses are capped at $3.0 million annually, subject to increases as described above) for Spectra Energy Partners’ benefit.

Pursuant to these arrangements, Spectra Energy performs centralized corporate functions for Spectra Energy Partners, including legal, accounting, compliance, treasury, insurance, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit and tax. Spectra Energy Partners reimburses Spectra Energy for the expenses to provide these services as well as other expenses it incurs on Spectra Energy Partners’ behalf, such as salaries of personnel performing services for Spectra Energy Partners’ benefit and the cost of Spectra Energy employee benefits and general and administrative expenses associated with such personnel; capital expenditures; maintenance and repair costs; taxes; and direct expenses, including operating expenses and certain allocated operating expenses, associated with the ownership and operation of the contributed assets.

Competition

Neither Spectra Energy or any of its affiliates is restricted, under either Spectra Energy Partners’ partnership agreement or the Omnibus Agreement, from competing with Spectra Energy Partners. Spectra Energy and any of its affiliates may acquire, construct or dispose of additional transportation and storage or other assets in the future without any obligation to offer Spectra Energy Partners the opportunity to purchase or construct those assets.

Indemnification

Under the Omnibus Agreement, Spectra Energy agreed to indemnify Spectra Energy Partners for three years after the closing of the IPO against certain potential environmental and toxic tort claims, losses and expenses associated with the operation of the assets and occurring before July 2, 2007, the closing date of the IPO. The maximum liability of Spectra Energy for this indemnification obligation will not exceed $15.0 million and Spectra Energy will not have any obligation under this indemnification until aggregate losses exceed $250,000. Spectra Energy has no indemnification obligations with respect to environmental claims made as a result of additions to or modifications of environmental laws relating to pollution or protection of the environment or natural resources promulgated after July 2, 2007. Spectra Energy Partners has agreed to indemnify Spectra Energy against environmental liabilities related to Spectra Energy Partners’ assets to the extent Spectra Energy is not required to indemnify Spectra Energy Partners.

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Additionally, Spectra Energy will indemnify Spectra Energy Partners for losses attributable to title defects, failures to obtain consents or permits necessary for the transfer of the contributed assets, retained assets and liabilities (including preclosing litigation relating to contributed assets) and income taxes attributable to pre-closing operations. Spectra Energy Partners will indemnify Spectra Energy for all losses attributable to the postclosing operations of the assets contributed to Spectra Energy Partners, to the extent not subject to Spectra Energy’s indemnification obligations.

Acquisition from Affiliates

On April 4, 2008, we completed the Saltville acquisition from Spectra Energy at a purchase price of $107.0 million, which included the issuance of 4,207,641 common units and 85,870 general partner units, and a cash payment of $4.7 million to Spectra Energy. The transaction received regulatory approval from the FERC.

The Conflicts Committee of the General Partner’s Board of Directors recommended approval of the transaction. The Conflicts Committee retained independent legal and financial advisors to assist it in evaluating and negotiating the transaction. In recommending approval of the transaction, the Conflicts Committee based its decision in part on an opinion from the independent financial advisor that the consideration to be paid by Spectra Energy Partners is fair, from a financial point of view, to Spectra Energy Partners and its unitholders (other than the General Partner and any unitholder affiliated with the General Partner).

Contracts with Affiliates

Gulfstream Limited Liability Company Agreement

In connection with the closing of the IPO, Spectra Energy contributed to Spectra Energy Partners 49.0% of its 50.0% interest in Gulfstream. Currently, Spectra Energy Partners owns a 24.5% interest in Gulfstream, Spectra Energy owns a 25.5% interest and The Williams Companies, Inc. (Williams) own a 50.0% interest. Gulfstream’s second amended and restated limited liability company agreement governs the ownership and management of Gulfstream and provides for quarterly distributions equal to 100% of its available cash, which is defined to include Gulfstream’s cash and cash equivalents on hand at the end of the quarter less any reserves that may be deemed appropriate by the Gulfstream management committee for the operation of its business (including reserves for its future maintenance capital expenditures and for its anticipated future credit needs) or for its compliance with laws or other agreements.

The management committee representatives of Spectra Energy and Williams jointly make the determinations related to Gulfstream’s available cash. In addition, because Spectra Energy Partners holds less than a 25% interest in Gulfstream, under the terms of the limited liability company agreement, Spectra Energy and Williams are able to collectively make all decisions with respect to the operation of Gulfstream without Spectra Energy Partners’ approval, other than those decisions relating to (1) a dissolution of Gulfstream, (2) Gulfstream’s entrance into bankruptcy proceedings, (3) Gulfstream’s conducting any activity or business that may generate income for federal income tax purposes that may not be “qualifying income,” or (4) an amendment of Gulfstream’s limited liability company agreement or its certificate of formation.

Under the Gulfstream limited liability company agreement, each member’s interest is subject to transfer restrictions, including a right of first offer in favor of the other members except in the case of certain transfers to affiliates. Accordingly, if a member identifies a potential third-party purchaser for all or a portion of its interest, that member must first offer the other members the opportunity to acquire the interest that it proposes to sell on the same terms and conditions as proposed by such potential purchaser.

Market Hub General Partnership Agreement

In connection with the closing of the IPO, Spectra Energy contributed to Spectra Energy Partners 50.0% of its interest in Market Hub. Currently, Spectra Energy Partners owns a 50.0% interest in Market Hub and Spectra Energy owns a 50.0% interest. A partnership agreement governs the ownership and management of Market Hub and provides for quarterly distributions equal to 100% of its available cash, which is defined to include Market Hub’s cash and cash equivalents on hand at the end of the quarter less any reserves that may be deemed

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appropriate by the Market Hub management committee for the operation of its business (including reserves for its future maintenance capital expenditures and for its anticipated future credit needs) or for its compliance with law or other agreements.

A management committee comprised of an equal number of representatives of Spectra Energy and Spectra Energy Partners jointly make the determinations related to Market Hub’s available cash.

Storage and Transportation Related Arrangements

Spectra Energy Partners charges transportation and storage fees to Spectra Energy and its respective affiliates. Management anticipates continuing to provide these services to Spectra Energy and its respective affiliates in the ordinary course of business.

East Tennessee. East Tennessee is a party under a pipeline balancing agreement with Texas Eastern Transmission, LP (Texas Eastern), a Spectra Energy affiliate. The agreement was entered into in accordance with East Tennessee’s FERC gas tariff and provides for the monthly balancing of natural gas at receipt and delivery points with Texas Eastern interconnecting with East Tennessee’s pipeline system.

Market Hub. Texas Eastern has entered into a variety of storage service agreements with Moss Bluff and Egan. At Egan, interruptible service agreements were made under a FERC approved gas tariff, using rates negotiated at arms-length between the parties. At Moss Bluff, interruptible and firm storage service agreements are subject to the Statement of Operating Conditions on file with the FERC. Storage service agreements between Moss Bluff and Texas Eastern include rates negotiated at arms-length between the parties. In addition, each of Moss Bluff and Egan have entered into agreements with Texas Eastern as an interconnecting pipeline to provide for monthly gas balancing at receipt and delivery points between the parties.

Director Independence

See Item 10. Directors, Executive Officers and Corporate Governance for information about the independence of the General Partner’s board of directors and its committees.

Item 14. Principal Accounting Fees and Services.

The following table presents fees for professional services rendered by Deloitte & Touche LLP, and the member firms of Deloitte Touche Tohmatsu and their respective affiliates (collectively, Deloitte) for us for 2008 and 2007:

Type of Fees	2008		2007
	(In millions)
Audit Fees(a)	$	0.8	$	1.4
Audit-Related Fees(b)		0.3		—
Total Fees:	$	1.1	$	1.4

(a) Audit Fees are fees billed or expected to be billed by Deloitte for professional services for the audit of our Consolidated Financial Statements included in our annual report on Form 10-K and review of financial statements included in our quarterly reports on Form 10-Q, services that are normally provided by Deloitte in connection with statutory, regulatory or other filings or engagements or any other service performed by Deloitte to comply with generally accepted auditing standards. Audit Fees also includes fees billed or expected to be billed by Deloitte for professional services for the audit of our internal controls under the requirements of Section 404 of the Sarbanes-Oxley Act of 2002 and related regulations. 2007 Audit Fees include $0.8 million for the audits of our Combined Financial Statements for the 2004, 2005 and 2006 periods and for the 2007 first quarter review, all of which were included in the 2007 Registration Statement on Form S-1.

123

(b) Audit-Related Fees are fees billed by Deloitte for assurance and related services that are reasonably related to the performance of an audit or review of our financial statements, including assistance with acquisitions and divestitures and internal control reviews.

To safeguard the continued independence of the independent auditor, the Audit Committee adopted a policy that prevents our independent auditor from providing services to us that are prohibited under Section 10A(g) of the Exchange Act, as amended. This policy also provides that independent auditors are only permitted to provide services to us and our subsidiaries that have been pre-approved by the Audit Committee. Pursuant to the policy, all audit services require advance approval by the Audit Committee. All other services by the independent auditor that fall within certain designated dollar thresholds, both per engagement as well as annual aggregate, have been pre-approved under the policy. Different dollar thresholds apply to the three categories of pre-approved services specified in the policy (Audit-Related services, Tax services and Other services). All services that exceed the dollar thresholds must be approved in advance by the Audit Committee. For services prior to July 2, 2007 (the date of our IPO), such services were approved by the Audit Committee of Spectra Energy under a similar policy. Pursuant to applicable provisions of the Exchange Act, as amended, the Audit Committee has delegated approval authority to the Chairman of the Audit Committee. The Chairman has presented all approval decisions to the full Audit Committee. All engagements performed by the independent auditor since July 2, 2007 were approved by the Audit Committee pursuant to its pre-approval policy.

124

PART IV

Item 15. Exhibits, Financial Statement Schedules.

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

Spectra Energy Partners, LP:

Report of Independent Registered Public Accounting Firm

Consolidated Statements of Operations for the Years Ended December 31, 2008, 2007 and 2006

Consolidated Balance Sheets as of December 31, 2008 and 2007

Consolidated Statements of Cash Flows for the Years Ended December 31, 2008, 2007 and 2006

Consolidated Statements of Partners’ Capital / Predecessor Equity and Comprehensive Income for the Years Ended December 31, 2008, 2007 and 2006

Notes to Consolidated Financial Statements

Schedule II — Consolidated Valuation and Qualifying Accounts and Reserves for the Years Ended December 31, 2008, 2007 and 2006

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

Gulfstream Natural Gas System, L.L.C.:

Independent Auditors’ Report

Statements of Operations for the Years Ended December 31, 2008, 2007 and 2006

Balance Sheets as of December 31, 2008 and 2007

Statements of Cash Flows for the Years Ended December 31, 2008, 2007 and 2006

Statements of Members’ Equity and Comprehensive Income for the Years Ended December 31, 2008, 2007 and 2006

Notes to Financial Statements

Market Hub Partners Holding:

Independent Auditors’ Report

Consolidated Statements of Operations for the Years Ended December 31, 2008, 2007 and 2006

Consolidated Balance Sheets as of December 31, 2008 and 2007

Consolidated Statements of Cash Flows for the Years Ended December 31, 2008, 2007 and 2006

Consolidated Statements of Partners’ Capital for the Years Ended December 31, 2008, 2007 and 2006

Notes to Consolidated Financial Statements

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

(c) Exhibits — See Exhibit Index at the end of this Annual Report on Form 10-K.

125

SIGNATURES

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

	SPECTRA ENERGY PARTNERS, LP
	By:	Spectra Energy Partners (DE) GP, LP, its general partner
	By:	Spectra Energy Partners GP, LLC, its general partner
Date: May 14, 2009		/S/    GREGORY J. RIZZO
		Gregory J. Rizzo President and Chief Executive Officer Spectra Energy Partners GP, LLC
Date: May 14, 2009		/S/    LAURA BUSS SAYAVEDRA
		Laura Buss Sayavedra Vice President and Chief Financial Officer Spectra Energy Partners GP, LLC

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

/S/    GREGORY J. RIZZO         (i)    Gregory J. Rizzo	President and Chief Executive Officer (Principal Executive Officer and Director)
/S/    LAURA BUSS SAYAVEDRA         (ii)    Laura Buss Sayavedra	Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)
* (iii)    Fred J. Fowler	Chairman of the Board of Directors
* Steven D. Arnold	Director
* Stewart A. Bliss	Director
* Nora M. Brownell	Director
* Patrick J. Hester	Director
* R. Mark Fiedorek	Director

Date: May 14, 2009

Gregory J. Rizzo, by signing his name hereto, does hereby sign this document on behalf of the registrant and on behalf of each of the above-named persons previously indicated by asterisk pursuant to a power of attorney duly executed by the registrant and such persons, filed with the Securities and Exchange Commission as an exhibit hereto.

By:	/s/    GREGORY J. RIZZO
	Gregory J. Rizzo Attorney-In-Fact

126

FINANCIAL STATEMENTS OF

GULFSTREAM NATURAL GAS SYSTEM, L.L.C.

INDEX TO FINANCIAL STATEMENTS

	Page
Financial Statements:
Independent Auditors’ Report	F-2
Statements of Operations for the years ended December 31, 2008, 2007 and 2006	F-3
Balance Sheets as of December 31, 2008 and 2007	F-4
Statements of Cash Flows for the years ended December 31, 2008, 2007 and 2006	F-5
Statements of Members’ Equity and Comprehensive Income for the years ended December 31, 2008, 2007 and 2006	F-6
Notes to Financial Statements	F-7

F-1

INDEPENDENT AUDITORS’ REPORT

To the Members of Gulfstream Natural Gas System, L.L.C.

Houston, Texas

We have audited the accompanying balance sheets of Gulfstream Natural Gas System, L.L.C., (the “Company”), as of December 31, 2008 and 2007, and the related statements of operations, members’ equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2008. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, such financial statements present fairly, in all material respects, the financial position of Gulfstream Natural Gas System, L.L.C. as of December 31, 2008 and 2007, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2008 in conformity with accounting principles generally accepted in the United States of America.

/s/    Deloitte & Touche LLP

Houston, Texas

March 11, 2009

F-2

GULFSTREAM NATURAL GAS SYSTEM, L.L.C.

STATEMENTS OF OPERATIONS

	Years Ended December 31,
	2008			2007		2006
	(In millions)
Operating Revenues
Transportation of natural gas	$	204.4		$	183.7	$	178.8
Other		2.3			1.6		1.5
Total operating revenues		206.7			185.3		180.3
Operating Expenses
Operating, maintenance and other		5.7			1.0		7.2
Operating, maintenance and other — affiliates		12.6			9.2		8.0
Depreciation and amortization		30.3			30.0		30.4
Property and other taxes		12.8			5.7		17.9
Total operating expenses		61.4			45.9		63.5
Gain (Loss) on Sale of Assets		(0.6	)		—		0.1
Operating Income		144.7			139.4		116.9
Other Income and Expenses		11.1			3.9		0.3
Interest Expense		45.0			47.9		48.8
Net Income	$	110.8		$	95.4	$	68.4

See Notes to Financials Statements

F-3

GULFSTREAM NATURAL GAS SYSTEM, L.L.C.

BALANCE SHEETS

	December 31,
	2008		2007
	(In millions)
ASSETS
Current Assets
Cash and cash equivalents	$	63.0	$	73.7
Receivables (net of allowance for doubtful accounts of $0.3 million at December 31, 2008)		22.1		16.2
Inventory		7.9		1.7
Other		2.1		4.4
Total current assets		95.1		96.0
Property, Plant and Equipment
Cost		1,996.1		1,786.3
Less accumulated depreciation and amortization		178.1		147.8
Net property, plant and equipment		1,818.0		1,638.5
Regulatory Assets and Deferred Debits
Regulatory tax asset — allowance for funds used during construction		24.3		22.9
Unamortized debt expense		6.6		7.2
Other		0.3		0.5
Total regulatory assets and deferred debits		31.2		30.6
Total Assets	$	1,944.3	$	1,765.1
LIABILITIES AND MEMBERS’ EQUITY
Current Liabilities
Accounts payable	$	20.3	$	4.4
Accounts payable — affiliates		1.4		1.0
Taxes accrued		3.1		5.8
Interest accrued		8.2		8.2
Accrued liabilities		0.5		6.0
Fuel tracker liabilities		—		3.1
Natural gas imbalance payables		2.7		2.4
Total current liabilities		36.2		30.9
Long-term Debt		849.6		849.6
Other Long-term Liabilities		0.1		0.1
Commitments and Contingencies
Members’ Equity
Members’ equity		1,045.5		870.3
Accumulated other comprehensive income		12.9		14.2
Total members’ equity		1,058.4		884.5
Total Liabilities and Members’ Equity	$	1,944.3	$	1,765.1

See Notes to Financial Statements

F-4

GULFSTREAM NATURAL GAS SYSTEM, L.L.C.

STATEMENTS OF CASH FLOWS

	Years Ended December 31,
	2008			2007			2006
	(In millions)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	110.8		$	95.4		$	68.4
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		31.0			30.6			31.1
Loss (gain) on sale of assets		0.6			—			(0.1	)
Allowance for funds used during construction — equity		(7.8	)		(1.8	)		(0.2	)
Reclassification adjustments from accumulated other comprehensive income into net income		(1.3	)		(1.3	)		(1.3	)
Decrease (increase) in:
Receivables		(5.8	)		(1.2	)		3.8
Other current assets		(6.7	)		(4.7	)		(0.5	)
Increase (decrease) in:
Accounts payable		2.2			1.1			1.0
Taxes accrued		(2.7	)		(8.2	)		8.1
Interest accrued		—			—			(0.7	)
Accrued liabilities		(5.5	)		—			(0.9	)
Fuel tracker liabilities		(0.1	)		—			(2.3	)
Other current liabilities		—			1.0			3.2
Other, assets		1.6			(3.0	)		2.8
Other, liabilities		—			(0.2	)		(5.3	)
Net cash provided by operating activities		116.3			107.7			107.1
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(191.4	)		(71.2	)		(21.7	)
Proceeds on sale of assets		1.4			—			—
Net cash used in investing activities		(190.0	)		(71.2	)		(21.7	)
CASH FLOWS FROM FINANCING ACTIVITIES
Capital contributions from members		179.4			76.4			—
Distributions to members		(116.4	)		(68.6	)		(83.0	)
Payments for debt issuance costs		—			—			(0.3	)
Net cash provided by (used in) financing activities		63.0			7.8			(83.3	)
Net increase (decrease) in cash and cash equivalents		(10.7	)		44.3			2.1
Cash and cash equivalents at beginning of period		73.7			29.4			27.3
Cash and cash equivalents at end of period	$	63.0		$	73.7		$	29.4
Supplemental Disclosures
Cash paid for interest, net of amount capitalized	$	49.5		$	49.0		$	49.4
Significant non-cash transaction:
Property, plant and equipment accruals	$	19.8		$	5.6		$	2.6

See Notes to Financial Statements

F-5

GULFSTREAM NATURAL GAS SYSTEM, L.L.C.

STATEMENTS OF MEMBERS’ EQUITY AND COMPREHENSIVE INCOME

	Spectra Energy Corp			Spectra Energy Partners, LP			The Williams Companies, Inc.			Total
	(In millions)
Balance December 31, 2005	$	399.2		$	—		$	399.1		$	798.3
Net income		34.2			—			34.2			68.4
Other comprehensive income
Reclassification of cash flow hedges into earnings		(0.7	)		—			(0.6	)		(1.3	)
Total comprehensive income											67.1
Distributions to members		(41.5	)		—			(41.5	)		(83.0	)
Attributed deferred tax expense		(0.2	)		—			(0.1	)		(0.3	)
Balance December 31, 2006		391.0			—			391.1			782.1
Net income attributable to the period January 1, 2007 through July 2, 2007		17.3			—			17.2			34.5
Net income attributable to the period July 3, 2007 through December 31, 2007		15.5			14.9			30.5			60.9
Other comprehensive income
Reclassification of cash flow hedges into earnings attributable to the period January 1, 2007 through July 2, 2007		(0.3	)		—			(0.3	)		(0.6	)
Reclassification of cash flow hedges into earnings attributable to the period July 3, 2007 through December 31, 2007		(0.2	)		(0.2	)		(0.3	)		(0.7	)
Total comprehensive income											94.1
Ownership change		(197.1	)		197.1			—			—
Capital contributions from members		20.3			17.9			38.2			76.4
Distributions to members		(21.2	)		(13.1	)		(34.3	)		(68.6	)
Attributed deferred tax benefit		0.2			0.1			0.2			0.5
Balance December 31, 2007		225.5			216.7			442.3			884.5
Net income		28.3			27.1			55.4			110.8
Other comprehensive income
Reclassification of cash flow hedges into earnings		(0.3	)		(0.3	)		(0.7	)		(1.3	)
Total comprehensive income											109.5
Capital contributions from members		45.7			44.0			89.7			179.4
Distributions to members		(29.7	)		(28.5	)		(58.2	)		(116.4	)
Attributed deferred tax benefit		0.4			0.3			0.7			1.4
Balance December 31, 2008	$	269.9		$	259.3		$	529.2		$	1,058.4

See Notes to Financial Statements

F-6

GULFSTREAM NATURAL GAS SYSTEM, L.L.C.

Notes to Financial Statements

1.    Summary of Operations and Significant Accounting Policies

Nature of Operations. Gulfstream Natural Gas System, L.L.C. (collectively, “we”, “our”, and “us”) owns an approximate 745-mile interstate natural gas pipeline system and is owned 25.5% by a subsidiary of Spectra Energy Corp (Spectra Energy), 24.5% by Spectra Energy Partners, LP (Spectra Energy Partners) and 50% by a subsidiary of The Williams Companies, Inc. (Williams). We are operated under joint management by Spectra Energy, which provides the business functions, and Williams, which provides the technical functions. We transport natural gas from Mississippi and Alabama, crossing the Gulf of Mexico to markets in central and southern Florida. Our interstate natural gas transmission operations are subject to the rules and regulations of the Federal Energy Regulatory Commission (FERC). We were formed on May 17, 1999 as a Delaware limited liability company.

On July 2, 2007, immediately prior to the closing of Spectra Energy Partners’ initial public offering (IPO), Spectra Energy contributed to Spectra Energy Partners a 24.5% interest in us. Spectra Energy indirectly owned 100% of Spectra Energy Partners prior to the closing of the IPO.

Basis of Presentation. The financial statements reflect the results of operations, financial position and cash flows of our company. The financial statements do not include any of the assets, liabilities, revenues or expenses of the members.

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

Fair Value Measurements. Effective January 1, 2008, we adopted the required provisions of Statement of Financial Accounting Standards (SFAS) No. 157, “Fair Value Measurements,” for financial assets and liabilities. SFAS No. 157 defines fair value, establishes a consistent framework for measuring fair value and expands disclosure requirements about fair value measurements. SFAS No. 157 requires entities to, among other things, maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.

SFAS No. 157 defines fair value as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date.

SFAS No. 157 specifies a hierarchy of valuation techniques based on whether the inputs to those valuation techniques are observable or unobservable. Observable inputs reflect market data obtained from independent sources, while unobservable inputs reflect our market assumptions. In accordance with SFAS No. 157, these two types of inputs have created the following fair value hierarchy:

• Level 1—Quoted unadjusted prices for identical instruments in active markets.

• Level 2—Quoted prices for similar instruments in active markets; quoted prices for identical or similar instruments in markets that are not active; and model-derived valuations in which all significant inputs and significant value drivers are observable in active markets.

• Level 3—Model derived valuations in which one or more significant inputs or significant value drivers are unobservable.

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

F-7

Inventory. Inventory consists primarily of other materials and supplies and is recorded at cost, using average cost.

Natural Gas Imbalances. The Balance Sheets include in-kind balances as a result of differences in gas volumes received and delivered for customers. Since settlement of imbalances is in-kind, changes in these balances do not have an effect on our Statements of Cash Flows. Natural gas volumes owed to or by us are valued at natural gas market index prices as of the balance sheet dates.

Cash Flow Hedges. In 2005, we entered into derivative transactions that are hedges of the future cash flows of forecasted transactions (cash flow hedges). For all hedge contracts, we provide documentation of the hedge in accordance with Statement of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended and assess whether the hedge contract is highly effective in offsetting changes in cash flows. We document hedging activity by transaction type (i.e. swaps) and risk management strategy (i.e. 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 Statements of Members’ Equity and Comprehensive Income as Accumulated Other Comprehensive Income (AOCI) until earnings are affected by the hedged transaction. We discontinue hedge accounting prospectively when it is 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. All derivatives designated and accounted for as hedges are classified in the same category as the item being hedged in the Statements of Cash Flows. In addition, all components of each derivative gain or loss are included in the assessment of hedge effectiveness.

When available, quoted market prices or prices obtained through external sources are used to measure a contract’s fair value.

Property, Plant and Equipment. Property, plant and equipment are stated at historical cost less accumulated depreciation. We capitalize 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 or increase the expected output of property, plant and equipment is also capitalized. The cost of repairs, replacements and major maintenance projects that do not extend the useful life or increase the expected output of property, plant and equipment, is expensed as incurred. Depreciation is generally computed over the asset’s estimated useful life using the straight-line method. The composite weighted-average depreciation rates were 1.7% for 2008 and 1.8% for both 2007 and 2006. See also “Allowance for Funds Used During Construction (AFUDC)” discussed below.

When we retire our regulated property, plant and equipment, we charge the original cost plus the cost of retirement, less salvage value, to accumulated depreciation and amortization. When we sell entire regulated operating units, or retire or sell 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 FERC.

Unamortized Debt Expense. Debt expenses incurred with the issuance of outstanding long-term debt are amortized over the terms of the debt issues. Any call premiums or unamortized expenses associated with refinancing higher-cost debt obligations to finance regulated assets and operations are amortized consistent with regulatory treatment of those items, where appropriate.

F-8

Cost-Based Regulation. We account for our operations under the provisions of SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation.” 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 may be recorded by an unregulated enterprise. Accordingly, we record assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for non-regulated entities. We continually assess whether regulatory assets are probable of future recovery by considering factors such as applicable regulatory changes and recent rate orders applicable to other regulated entities. Based on this continual assessment, we believe the existing regulatory assets are probable of recovery. These regulatory assets are primarily classified in the Balance Sheets as Regulatory Assets and Deferred Debits. We have no regulatory liabilities as of December 31, 2008 and 2007. We periodically evaluate the applicability of SFAS No. 71, and consider factors such as regulatory changes and the effect of competition. If cost-based regulation ends or competition increases, we may have to reduce certain of our asset balances to reflect a market basis less than cost and write-off the associated regulatory assets. See Note 3 for further discussion.

Revenue Recognition. Revenues from the transportation of natural gas are recognized when the service is provided. Revenues related to these services provided but not yet billed are estimated each month. These estimates are generally based on contract data, regulatory information 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.

Significant Customers. Customers accounting for 10% or more of revenues during 2008, 2007 and 2006 are as follows:

	% of Revenues
Customer	2008		2007		2006
Florida Power & Light Company	49	%	50	%	51	%
Florida Power Corporation	25		22		22
Tampa Electric Company and affiliates	10		10		10

Allowance for Funds Used During Construction. AFUDC, which represents the estimated debt and equity costs of capital funds necessary to finance the construction and expansion 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, with offsetting credits to the Statements of Operations. After construction is completed, we are permitted to recover these costs through inclusion in the rate base and in the depreciation provision. The total amount of AFUDC included in the Statements of Operations was $11.6 million in 2008 (an equity component of $7.8 million and an interest expense component of $3.8 million), $2.7 million in 2007 (an equity component of $1.7 million and an interest expense component of $1.0 million) and $0.4 million in 2006 (an equity component of $0.3 million and an interest expense component of $0.1 million).

Preliminary Project Costs. Project costs, including expenditures for preliminary surveys, plans, investigations, environmental studies, regulatory applications and other costs incurred for the purpose of determining the feasibility of capital expansion projects, are initially included in operating expenses. If and when it is determined that recovery of such costs through regulated revenues of the completed project is probable, the inception-to-date costs of the project are recognized as Property, Plant and Equipment in accordance with the provisions of SFAS No. 71 and operating expenses are reduced.

Income Taxes. We are not subject to income tax, but rather our taxable income or loss is reported on the respective income tax returns of our members. Accordingly, there is no federal tax provision in these financial statements. Since we are not responsible for the attributed income taxes, amounts related to the tax gross-up of

F-9

AFUDC equity are carried in the individual capital accounts of our members. The deferred income tax effect of the AFUDC equity gross up of $24.3 million at December 31, 2008 and $22.9 million at December 31, 2007 is classified in the Balance Sheets as Regulatory Assets and Deferred Debits.

New Accounting Pronouncements — 2008. The following new accounting pronouncements were adopted during 2008 and the effect of such adoption, if applicable, has been presented in the accompanying Financial Statements:

SFAS No. 157, “Fair Value Measurements.” SFAS No. 157, defines fair value, establishes a framework for measuring fair value in GAAP and expands disclosures about fair value measurements. In February 2008, the Financial Accounting Standards Board (FASB) issued FASB Staff Position (FSP) No. FAS 157-1, “Application of FASB Statement No. 157 to FASB Statement No. 13 and Other Accounting Pronouncements That Address Fair Value Measurements for Purposes of Lease Classification or Measurement under Statement 13.” Also in February 2008, the FASB issued FSP No. 157-2, “Effective Date of FASB Statement No. 157,” which delays the effective date of SFAS No. 157 to fiscal years beginning after November 15, 2008 for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). The adoption of SFAS No. 157 and FSP No. FAS 157-1 effective January 1, 2008 did not have a material impact on our consolidated results of operations, financial position or cash flows.

In October 2008, the FASB issued FSP No. FAS 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active,” which clarifies the application of SFAS No. 157 in determining the fair value of a financial asset when the market for that financial asset is not active. FSP No. FAS 157-3 was effective upon issuance, including prior periods for which financial statements have not been issued. Revisions in fair values resulting from a change in the valuation technique or its application would be accounted for as a change in accounting estimate. The adoption of FSP No. FAS 157-3 had no impact on our consolidated results of operations, financial position or cash flows.

SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities.” In February 2007, the FASB issued SFAS No. 159, which permits entities to choose to measure certain financial instruments at fair value. We have determined to not elect fair value measurements for financial assets and financial liabilities included in the scope of SFAS No. 159.

Pending. The following new accounting pronouncements have been issued, but have not yet been adopted as of December 31, 2008:

SFAS No. 141R, “Business Combinations.” In December 2007, the FASB issued SFAS No. 141R which replaces SFAS No. 141, “Business Combinations.” SFAS No. 141R requires the acquiring entity in a business combination to recognize all and only the assets acquired and liabilities assumed in the transaction, establishes the acquisition-date fair value as the measurement objective for all assets acquired and liabilities assumed, and requires the acquirer to disclose to investors and other users all of the information they need to evaluate and understand the nature and financial effect of the business combination. SFAS No. 141R applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008 and cannot be early adopted.

FSP No. FAS 142-3, “Determination of the Useful Life of Intangible Assets.” In April 2008, the FASB issued FSP No. FAS 142-3 which amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142, “Goodwill and Other Intangible Assets.” The adoption of the provisions of FSP No. FAS 142-3 on January 1, 2009 had no impact on our consolidated results of operations, financial position or cash flows.

F-10

2.    Transactions with Affiliates

Gulfstream Management & Operating Services, L.L.C. (GMOS), owned 50% by an affiliate of Spectra Energy and 50% by an affiliate of Williams, provides management, construction and operating services pursuant to agreements entered into with us and with affiliates of Spectra Energy and Williams. GMOS bills us for services rendered including labor and benefit costs, employee expenses, overhead costs and in some cases, third-party costs. Such amounts are reflected in the Statements of Operations as Operating, Maintenance and Other-Affiliates or in the Balance Sheets as Property, Plant and Equipment, as appropriate.

Transactions with affiliates are summarized in the tables below:

Statements of Operations

	2008		2007		2006
	(In millions)
Operating, maintenance and other expenses	$	12.6	$	9.2	$	8.0

Balance Sheets

	December 31,
	2008		2007
	(In millions)
Property, plant and equipment(a)	$	10.9	$	5.2
Accounts payable		1.4		1.0

(a) Reflects additions to Property, Plant and Equipment billed from an affiliate in the respective year.

3.    Regulatory Matters

Regulatory Assets. Our operations are subject to SFAS No. 71. Accordingly, we record assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for non-regulated entities. See Note 1 for further discussion.

	December 31,				Recovery/Refund Period Ends
	2008		2007
	(In millions)
Regulatory Assets(1)
Regulatory asset related to income taxes	$	24.3	$	22.9	(2	)

(1) Included in Regulatory Assets and Deferred Debits on the Balance Sheets.

(2) Amortized over the life of the related property, plant and equipment.

All regulatory assets are excluded from rate base unless otherwise noted. There were no regulatory liabilities as of December 31, 2008 and 2007.

Rate Related Information. In June 2007, the FERC issued an order approving our Phase III expansion project. That order also required us to file a Cost and Revenue Study three years after our Phase III facilities go in service. The projected filing date would be the fall of 2011.

F-11

4.    Property, Plant and Equipment

	Estimated Useful Life	December 31,
		2008			2007
	(years)	(In millions)
Natural gas transmission	60	$	1,844.7		$	1,645.6
Land	—		16.0			18.0
Construction in process	—		88.7			81.2
Other	5-20		46.7			41.5
Total property, plant and equipment			1,996.1			1,786.3
Total accumulated depreciation			(178.1	)		(147.8	)
Total net property, plant and equipment		$	1,818.0		$	1,638.5

5.    Debt

Summary of Debt and Related Terms

	Year Due	December 31,
		2008			2007
	(In millions)
Unsecured note payable, 5.56%	2015	$	500.0		$	500.0
Unsecured note payable, 6.19%	2025		350.0			350.0
Unamortized debt discount			(0.4	)		(0.4	)
Total long-term debt		$	849.6		$	849.6

6.    Fair Value Measurements

The following table presents, for each of the fair value hierarchy levels, assets that are measured at fair value on a recurring basis:

		December 31, 2008
Description	Balance Sheet Caption	Total		Level 1		Level 2		Level 3
		(In millions)
Short-term money market securities	Cash and cash equivalents	$	46.5	$	46.5	$	—	$	—
Total Assets		$	46.5	$	46.5	$	—	$	—

7.    Hedging Activities, Financial Instruments and Credit Risk

Interest Rate Cash Flow Hedges. We are exposed to the impact of market fluctuations in interest rates. To protect from increasing interest rates and the resulting higher cost of the debt that was issued in 2005, we locked in existing interest rates by using financial derivatives (swaps) for hedge strategies. The total amount of the debt issued was $850.0 million of which $500.0 million was hedged. The associated interest rate swaps were terminated on October 12, 2005, prior to the issuance of the related debt. These derivatives were initially recorded on the Balance Sheets at their fair value as AOCI. Deferred gains of $12.9 million in AOCI as of December 31, 2008 will continue to be amortized to interest expense over the term of the debt issued (November 2015.)

Financial Instruments. The fair value of outstanding financial instruments 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, 2008 and 2007 are not necessarily indicative of the amounts we could have realized in current markets.

F-12

Financial Instruments

	December 31,
	2008				2007
	Book Value		Approximate Fair Value		Book Value		Approximate Fair Value
	(In millions)
Long-term debt	$	849.6	$	748.1	$	849.6	$	847.9

The fair value of cash and cash equivalents, accounts receivable and accounts payable are not materially different from their carrying amounts because of the short-term nature of these instruments.

Credit Risk. Our principal customers for natural gas transportation are utilities located throughout the state of Florida. We have concentrations of receivables from utilities throughout Florida. These concentrations of customers may affect our overall credit risk in that risk factors can negatively impact the credit quality of the entire sector. Where exposed to credit risk, we analyze the counterparties’ financial condition prior to entering into an agreement, establish credit limits and monitor the appropriateness of those limits on an ongoing basis. We also obtain parental guarantees, cash or letters of credit from customers to provide credit support, where appropriate, based on our financial analysis of the customer and the regulatory or contractual terms and conditions applicable to each transaction.

8.    Commitments and Contingencies

General Insurance. We carry, either independently or through our owners, insurance consistent with companies engaged in similar commercial operations with similar type properties. Our insurance includes: (1) liability insurance covering our liabilities arising from bodily injury or property damage to third parties resulting from our operations including liabilities arising from the use of owned, non-owned and hired vehicles and (2) property insurance on an all-risk basis covering loss or damage to real and personal property owned or leased by our company. We also carry onshore business interruption insurance. All coverages are subject to certain deductibles, terms and conditions common for companies with similar types of operations. The cost of our general insurance will continue to fluctuate reflecting changing conditions of the insurance markets.

Environmental. We are subject to federal, state and local regulations regarding air and water quality, hazardous and solid waste disposals and other environmental matters. We believe there are no matters outstanding that, when resolved, will have a material adverse effect on our results of operations, financial position or cash flows.

Litigation. We are involved in legal, tax and regulatory proceedings in various forums, including matters regarding contracts, performance and other matters, arising in the ordinary course of business, some of which may involve substantial monetary amounts. We have insurance coverage for certain of these losses should they be incurred. We believe that the final disposition of these proceedings will not have a material adverse effect on our results of operations, financial position or cash flows.

9.    Subsequent Event

A distribution to members of $32.3 million was declared and paid on January 21, 2009.

F-13

CONSOLIDATED FINANCIAL STATEMENTS OF

MARKET HUB PARTNERS HOLDING

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	Page
Consolidated Financial Statements:
Independent Auditors’ Report	F-15
Consolidated Statements of Operations for the years ended December 31, 2008, 2007 and 2006	F-16
Consolidated Balance Sheets as of December 31, 2008 and 2007	F-17
Consolidated Statements of Cash Flows for the years ended December 31, 2008, 2007 and 2006	F-18
Consolidated Statements of Partners’ Capital for the years ended December 31, 2008, 2007 and 2006	F-19
Notes to Consolidated Financial Statements	F-20

F-14

INDEPENDENT AUDITORS’ REPORT

To the Partners of Market Hub Partners Holding

Houston, Texas

We have audited the accompanying consolidated balance sheets of Market Hub Partners Holding and subsidiaries (the “Company”) as of December 31, 2008 and 2007, and the related consolidated statements of operations, partners’ capital, and cash flows for each of the three years in the period ended December 31, 2008. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Market Hub Partners Holding and subsidiaries as of December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008 in conformity with accounting principles generally accepted in the United States of America.

/s/    Deloitte & Touche LLP

Houston, Texas

March 11, 2009

F-15

MARKET HUB PARTNERS HOLDING

CONSOLIDATED STATEMENTS OF OPERATIONS

	Years Ended December 31,
	2008		2007		2006
	(In millions)
Operating Revenues
Salt cavern storage	$	82.6	$	71.0	$	66.7
Salt cavern storage — affiliates		3.6		3.6		1.9
Hub services and other		5.6		9.9		3.9
Hub services and other — affiliates		6.2		6.8		6.3
Total operating revenues		98.0		91.3		78.8
Operating Expenses
Operating, maintenance and other		6.5		18.8		14.2
Operating, maintenance and other — affiliates		10.4		2.5		12.1
Depreciation and amortization		10.6		9.1		7.8
Property and other taxes		3.1		2.3		4.0
Total operating expenses		30.6		32.7		38.1
Gains on Sales of Other Assets		—		7.0		10.6
Operating Income		67.4		65.6		51.3
Other Income and Expenses		0.2		—		—
Interest Income		0.2		—		—
Interest Income — Affiliates		2.9		2.3		—
Interest Expense — Affiliates		1.0		3.6		2.6
Earnings Before Income Taxes		69.7		64.3		48.7
Income Tax Expense		0.4		0.1		—
Net Income	$	69.3	$	64.2	$	48.7

See Notes to Consolidated Financial Statements

F-16

MARKET HUB PARTNERS HOLDING

CONSOLIDATED BALANCE SHEETS

	December 31,
	2008		2007
	(In millions)
ASSETS
Current Assets
Cash and cash equivalents	$	18.3	$	21.7
Receivables		8.2		7.5
Receivables — affiliates		1.7		—
Natural gas imbalance receivables		3.8		13.7
Natural gas imbalance receivables — affiliates		10.3		14.5
Notes receivable — affiliates		100.0		100.0
Other		1.1		0.4
Total current assets		143.4		157.8
Other Assets
Goodwill		200.5		200.5
Other assets		0.1		0.1
Total other assets		200.6		200.6
Property, Plant and Equipment
Cost		501.9		408.4
Less accumulated depreciation and amortization		78.9		69.9
Net property, plant and equipment		423.0		338.5
Total Assets	$	767.0	$	696.9
LIABILITIES AND PARTNERS’ CAPITAL
Current Liabilities
Accounts payable	$	7.6	$	4.1
Accounts payable — affiliates		9.4		1.3
Taxes accrued		2.0		1.8
Interest accrued — affiliates		7.0		6.0
Natural gas imbalance payables		13.8		29.2
Natural gas imbalance payables — affiliates		1.3		—
Collateral liabilities		2.7		2.2
Collateral liabilities — affiliates		80.0		80.0
Other		1.8		3.1
Total current liabilities		125.6		127.7
Deferred Credits and Other Liabilities
Advances payable — affiliates		1.0		1.1
Total deferred credits and other liabilities		1.0		1.1
Commitments and Contingencies
Partners’ Capital		640.4		568.1
Total Liabilities and Partners’ Capital	$	767.0	$	696.9

See Notes to Consolidated Financial Statements

F-17

MARKET HUB PARTNERS HOLDING

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Years Ended December 31,
	2008			2007			2006
	(In millions)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	69.3		$	64.2		$	48.7
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		10.6			9.1			7.8
Gains on sales of other assets		—			(7.0	)		(10.6	)
Decrease (increase) in:
Receivables		(0.7	)		2.9			5.9
Receivables — affiliates		0.8			—			—
Other current assets		(0.7	)		0.5			6.1
Other, assets		0.1			4.5			6.2
Increase (decrease) in:
Accounts payable		(2.6	)		5.1			5.3
Accounts payable — affiliates		5.6			1.3			(0.5	)
Taxes accrued		0.2			(2.2	)		0.4
Collateral liabilities — current		0.5			(1.4	)		1.3
Collateral liabilities — affiliates — current		—			—			55.0
Other current liabilities		(0.3	)		1.0			2.6
Collateral liabilities — affiliates — noncurrent		—			—			25.0
Net cash provided by operating activities		82.8			78.0			153.2
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(89.1	)		(49.7	)		(54.1	)
Net decrease (increase) in advances receivable — affiliates		—			75.5			(94.2	)
Net increase (decrease) in advances payable — affiliates		(0.1	)		1.1			(20.5	)
Net increase in notes receivable — affiliates		—			(100.0	)		—
Net proceeds from insurance claim — affiliates		—			9.2			15.6
Net cash used in investing activities		(89.2	)		(63.9	)		(153.2	)
CASH FLOWS FROM FINANCING ACTIVITIES
Distributions to partners		(86.3	)		(11.7	)		—
Capital contributions from partners		89.3			19.3			—
Net cash provided by financing activities		3.0			7.6			—
Net increase (decrease) in cash and cash equivalents		(3.4	)		21.7			—
Cash and cash equivalents at beginning of period		21.7			—			—
Cash and cash equivalents at end of period	$	18.3		$	21.7		$	—
Supplemental Disclosures
Significant non-cash transactions:
Transfers of assets to parent	$	—		$	19.6		$	—
Property, plant and equipment accruals		7.3			1.0			4.9
Intercompany property, plant and equipment transfers		—			4.7			—

See Notes to Consolidated Financial Statements

F-18

MARKET HUB PARTNERS HOLDING

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

	Spectra Energy Corp			Spectra Energy Partners, LP			Total
	(In millions)
Balance December 31, 2005	$	467.2		$	—		$	467.2
Net income		48.7			—			48.7
Balance December 31, 2006		515.9			—			515.9
Net income attributable to the period January 1, 2007 through July 2, 2007		29.1			—			29.1
Transfers of assets to parent		(19.6	)		—			(19.6	)
Ownership change		(262.7	)		262.7			—
Net income attributable to the period July 3, 2007 through December 31, 2007		17.5			17.6			35.1
Capital contributions from partners		9.6			9.7			19.3
Distributions to partners		(5.8	)		(5.9	)		(11.7	)
Balance December 31, 2007		284.0			284.1			568.1
Net income		34.7			34.6			69.3
Capital contributions from partners		44.6			44.7			89.3
Distributions to partners		(43.1	)		(43.2	)		(86.3	)
Balance December 31, 2008	$	320.2		$	320.2		$	640.4

See Notes to Consolidated Financial Statements

F-19

MARKET HUB PARTNERS HOLDING

Notes to Consolidated Financial Statements

1.    Summary of Operations and Significant Accounting Policies

Nature of Operations. Market Hub Partners Holding (collectively, “we”, “our”, and “us”), owns and operates two natural gas storage facilities: Moss Bluff, located near Houston, Texas and Egan, located in Acadia Parish, Louisiana. Our facilities provide producers, end-users, local distribution companies, pipelines and energy marketers with high deliverability storage services, as well as hub services, such as park and loan services, wheeling and title transfer. Our Egan facilities are subject to the rules and regulations of the Federal Energy Regulatory Commission (FERC). Moss Bluff is regulated by the Texas Railroad Commission as an intrastate storage company. Moss Bluff, as a Hinshaw pipeline, must also comply with certain requirements under the FERC regulations.

Until July 2, 2007, we were a Delaware limited liability company that was wholly owned by Spectra Energy Corp (Spectra Energy). On July 2, 2007, immediately prior to the closing of Spectra Energy Partners, LP (Spectra Energy Partners) initial public offering (IPO), we were converted to a Delaware general partnership and Spectra Energy contributed 50% of its 100% ownership of us to Spectra Energy Partners.

Basis of Presentation. The financial statements reflect the consolidated results of operations, financial position and cash flows of us and our subsidiaries. The financial statements do not include any of the assets, liabilities, revenues or expenses of our partners.

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

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

Natural Gas Imbalances. The Balance Sheets include in-kind balances as a result of differences in gas volumes received and delivered for customers. Since settlement of imbalances is in-kind, changes in these balances do not have an effect on our Statements of Cash Flows. Natural gas volumes owed to or by us are valued at natural gas market index prices as of the balance sheet dates.

Goodwill. We evaluate goodwill for potential impairment under the guidance of Statement of Financial Accounting Standards (SFAS) No. 142, “Goodwill and Other Intangible Assets.” Under this standard, goodwill is subject to an annual test for impairment. We have designated August 31 as the date we perform the annual review for goodwill impairment.

Impairment testing of goodwill consists of a two-step process. The first step involves a comparison of the implied fair value of our partnership with our carrying amount. If the carrying amount exceeds our fair value, the second step of the process involves a comparison of the fair value and the carrying value of the goodwill. If the carrying value of the goodwill 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 our fair value is below our carrying amount.

We completed our annual goodwill impairment test as of August 31, 2008 and no impairments were identified. We primarily use 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 and estimated future cash flows. In estimating cash flows, we incorporate expected long-term growth rates, regulatory stability and the ability to

F-20

renew contracts, as well as other factors that affect revenue, expense and capital expenditure projections. We did not record any impairment of our goodwill in 2008, 2007 or 2006, and there have been no additions, amortization or other changes in the carrying amount of goodwill during those years.

Property, Plant and Equipment. Property, plant and equipment are stated at historical cost less accumulated depreciation. We capitalize 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 or increase the expected output of property, plant and equipment is also capitalized. The cost of repairs, replacements and major maintenance projects that do not extend the useful life or increase the expected output of property, plant and equipment, is expensed as incurred. Depreciation is generally computed over the asset’s estimated useful life using the straight-line method. The composite weighted-average depreciation rates were 3.0% for 2008, 2.9% for 2007 and 3.0% for 2006.

Revenue Recognition. Revenues from the storage of natural gas and related hub services are recognized when the service is provided. Revenues related to these services provided but not yet billed are estimated each month. These estimates are generally based on contract data, regulatory information and preliminary storage 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.

Significant Customers. Customers accounting for 10% or more of consolidated revenues during 2008, 2007 or 2006 are as follows:

	% of Consolidated Revenues
Customer	2008		2007		2006
Northern Indiana Public Service Company	(a	)	(a	)	11	%
Spectra Energy	10	%	11	%	(a	)

(a) Percentage below 10%

Income Taxes. We are not subject to federal income tax, but rather our taxable income or loss is reported on the respective income tax returns of the partners. Accordingly, there is no income tax provision recorded for our partnership except Texas margin tax.

New Accounting Pronouncements — 2008. The following new accounting pronouncements were adopted during 2008 and the effect of such adoption, if applicable, has been presented in the accompanying Consolidated Financial Statements:

SFAS No. 157, “Fair Value Measurements.” SFAS No. 157, defines fair value, establishes a framework for measuring fair value in GAAP and expands disclosures about fair value measurements. In February 2008, the Financial Accounting Standards Board (FASB) issued FASB Staff Position (FSP) No. FAS 157-1, “Application of FASB Statement No. 157 to FASB Statement No. 13 and Other Accounting Pronouncements that Address Fair Value Measurements for Purposes of Lease Classification or Measurement under Statement 13.” Also in February 2008, the FASB issued FSP No. FAS 157-2, “Effective Date of FASB Statement No. 157,” which delays the effective date of SFAS No. 157 to fiscal years beginning after November 15, 2008 for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). The adoption of SFAS No. 157 and FSP No. FAS 157-1 effective January 1, 2008 did not have a material impact on our consolidated results of operations, financial position or cash flows. As permitted under FSP No. FAS 157-2, we have elected to defer the adoption of SFAS No. 157 for our goodwill impairment test and the measurement of asset retirement obligations until January 1, 2009, and do not expect the adoption of FSP No. FAS 157-2 to measure these items will have a material impact on our consolidated results of operations, financial position or cash flows.

F-21

In October 2008, the FASB issued FSP No. FAS 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active,” which clarifies the application of SFAS No. 157 in determining the fair value of a financial asset when the market for that financial asset is not active. FSP No. FAS 157-3 was effective upon issuance, including prior periods for which financial statements have not been issued. Revisions in fair values resulting from a change in the valuation technique or its application would be accounted for as a change in accounting estimate. The adoption of FSP No. FAS 157-3 had no impact on our consolidated results of operations, financial position or cash flows.

SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities.” In February 2007, the FASB issued SFAS No. 159, which permits entities to choose to measure certain financial instruments at fair value. We have determined not to elect fair value measurements for financial assets and financial liabilities included in the scope of SFAS No. 159.

Pending. The following new accounting pronouncements have been issued, but have not yet been adopted as of December 31, 2008:

SFAS No. 141R, “Business Combinations.” In December 2007, the FASB issued SFAS No. 141R which replaces SFAS No. 141, “Business Combinations.” SFAS No. 141R requires the acquiring entity in a business combination to recognize all and only the assets acquired and liabilities assumed in the transaction, establishes the acquisition-date fair value as the measurement objective for all assets acquired and liabilities assumed, and requires the acquirer to disclose to investors and other users all of the information they need to evaluate and understand the nature and financial effect of the business combination. SFAS No. 141R applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008 and cannot be early adopted.

FSP No. FAS 142-3, “Determination of the Useful Life of Intangible Assets.” In April 2008, the FASB issued FSP No. FAS 142-3 which amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142, “Goodwill and Other Intangible Assets.” The adoption of the provisions of FSP No. FAS 142-3 on January 1, 2009 had no impact on our consolidated results of operations, financial position or cash flows.

2.    Transactions with Affiliates

In the normal course of business, we provide storage and other services to Spectra Energy and its affiliates.

Operating, maintenance and other expenses include reimbursement of costs incurred by affiliates on behalf of us and allocations from Spectra Energy affiliates for various services and other costs. Affiliates charge such expenses based on the cost of actual services provided or using various allocation methodologies based on our percentage of assets, employees, earnings or other measures as compared to other affiliates.

Advances receivable from or payable to affiliates do not bear interest. Advances are carried as unsecured, open accounts and are not segregated between current and non-current amounts. Increases and decreases in advances generally result from the movement of funds to provide for our operations and capital expenditures.

Transactions with affiliates are summarized in the tables below:

F-22

Statements of Operations

	2008		2007		2006
	(In millions)
Salt cavern storage — affiliates	$	3.6	$	3.6	$	1.9
Hub services and other — affiliates		6.2		6.8		6.3
Operating, maintenance and other — affiliates		10.4		2.5		12.1
Gains on Sales of Other Assets		—		7.0		10.6
Interest Income — Affiliates		2.9		2.3		—
Interest Expense — Affiliates		1.0		3.6		2.6

Balance Sheets

	December 31,
	2008		2007
	(In millions)
Receivables — affiliates	$	1.7	$	—
Natural gas imbalance receivables — affiliates		10.3		14.5
Notes receivable — affiliates		100.0		100.0
Current assets — other		0.8		—
Accounts payable — affiliates		9.4		1.3
Interest accrued — affiliates		7.0		6.0
Natural gas imbalance payables — affiliates		1.3		—
Collateral liabilities — affiliates		80.0		80.0
Advances payable — affiliates		1.0		1.1

During 2007 and 2006, we recorded $7.0 million and $10.6 million, respectively, of Gains on Sales of Other Assets within the Consolidated Statements of Operations, primarily reflecting property insurance proceeds received from affiliates associated with a 2004 cavern well-head fire at Moss Bluff. In addition, we received $1.9 million in 2006 of business interruption insurance proceeds related to the cavern well-head fire that were recorded as Operating Revenues — Hub Services and Other — Affiliates in the Consolidated Statements of Operations. We also received insurance proceeds from affiliates of $14.1 million in 2006, included in Net Cash Provided by Operating Activities in the Consolidated Statements of Cash Flows, related to reimbursements of customer and working gas and additional operating expenses incurred as a result of the fire.

During 2006, in accordance with our credit policies, we received an $80.0 million security deposit from an affiliate for a gas loan contract with that affiliate. We are required to pay a market rate of interest on the security deposit. The gas loan contract will terminate in April 2009. The security deposit was $80.0 million at December 31, 2008 and 2007 and is classified in the Consolidated Balance Sheets as Current Liabilities.

Effective as of August 15, 2007, we received payment of advances receivable of $80.0 million and entered into five-year promissory notes with Spectra Energy Partners and Spectra Energy Capital, LLC, (Spectra Capital), a wholly owned subsidiary of Spectra Energy, to loan them up to $50.0 million each. The notes mature on August 15, 2012, however, any borrowings under the agreement are payable on demand and therefore have been classified within Current Assets in the Consolidated Balance Sheet. The promissory notes bear interest based on a one month London InterBank Offering Rate (LIBOR), and was 0.44% at December 31, 2008. As of December 31, 2008 and 2007, Spectra Energy Partners and Spectra Capital each had $50.0 million of borrowings outstanding under the notes.

We received capital contributions of $89.3 million and $19.3 million from our partners and made distributions of $86.3 million and $11.7 million in 2008 and 2007, respectively.

F-23

In accordance with the partnership formation agreements, we transferred certain balances to Spectra Energy on July 2, 2007. These balances were primarily comprised of accounts receivable and advances from Spectra Energy totaling $19.6 million. These assets are classified in the Consolidated Statements of Partners’ Capital as Transfers of Assets to Parent. This transaction was classified as non-cash for purposes of the Consolidated Statements of Cash Flows.

3.    Property, Plant and Equipment

	Estimated Useful Life	December 31,
		2008			2007
	(Years)	(In millions)
Salt cavern storage facilities	15-40	$	408.5		$	378.6
Land	—		12.4			12.4
Construction in process	—		80.3			16.5
Other	5-40		0.7			0.9
Total property, plant and equipment			501.9			408.4
Total accumulated depreciation			(78.9	)		(69.9	)
Total net property, plant and equipment		$	423.0		$	338.5

4.    Credit Risk and Financial Instruments

Credit Risk. Our principal customers for high deliverability natural gas storage services and hub services are pipelines, local distribution companies, producers, end-users, power generators and energy marketers. We have concentrations of receivables from these industry sectors and locations. These concentrations of customers may affect our overall credit risk in that risk factors can negatively impact the credit quality of the entire sector. Where exposed to credit risk, we analyze the counterparties’ financial condition prior to entering into an agreement, establish credit limits and monitor the appropriateness of those limits on an ongoing basis. We also obtain cash, letters of credit or other acceptable forms of security from customers to provide credit support, where appropriate, based on our financial analysis of the customer and the regulatory or contractual terms and conditions applicable to each transaction.

Financial Instruments. The fair value of cash and cash equivalents, accounts receivable, accounts payable and notes receivables are not materially different from their carrying amounts because of the short-term nature of these instruments.

5.    Commitments and Contingencies

General Insurance. We are insured through Spectra Energy’s master insurance program for insurance coverages consistent with companies engaged in similar commercial operations with similar type properties. Our insurance program includes (1) commercial general and excess liability insurance for liabilities arising to third parties for bodily injury and property damage resulting from our operations; (2) workers’ compensation liability coverage to required statutory limits; (3) automobile liability insurance for all owned, non-owned and hired vehicles covering liabilities to third parties for bodily injury and property damage; (4) insurance policies in support of the indemnification provisions of Spectra Energy’s by-laws and (5) property insurance, including machinery breakdown, on an all risk replacement valued basis, onshore business interruption and extra expense. All coverages are subject to certain deductibles, terms and conditions common for companies with similar types of operations. The cost of Spectra Energy’s insurance coverages trend the cyclical changes in the insurance market.

Environmental. We are subject to federal, state and local regulations regarding air and water quality, hazardous and solid waste disposal, and other environmental matters. We believe there are no matters outstanding that, when resolved, will have a material adverse effect on our consolidated results of operations, financial position or cash flows.

F-24

Litigation. We are involved in legal, tax and regulatory proceedings in various forums including matters regarding contracts, performance and other matters, arising in the ordinary course of business, some of which may involve substantial monetary amounts. We have insurance coverage for certain of these losses should they be incurred. We believe that the final disposition of these proceedings will not have a material adverse effect on our consolidated results of operations, financial position or cash flows.

6.    Subsequent Event

A distribution to partners of $17.6 million was declared and paid on January 23, 2009.

F-25

Exhibit Index

Exhibit No.	Exhibit Description
2.1	Asset Purchase Agreement, dated December 13, 2007, between Spectra Energy Virginia Pipeline Company and East Tennessee Natural Gas, LLC (filed as Exhibit 10.2 to Spectra Energy Partners, LP’s Form 8-K dated December 14, 2007).
3.1	First Amended and Restated Agreement of Limited Partnership of Spectra Energy Partners, LP (filed as Exhibit 3.1 to Spectra Energy Partners, LP’s Form 8-K dated July 9, 2007).
3.2	Amendment No. 1 to First Amended and Restated Agreement of Limited Partnership of Spectra Energy Partners, LP, dated April 11, 2008 (filed as Exhibit 10.1 to Spectra Energy Partners, LP’s Form 10-Q on May 14, 2008).
3.3	Certificate of Limited Partnership of Spectra Energy Partners, LP (filed as Exhibit 3.1 to Spectra Energy Partners, LP’s Form S-1 on March 30, 2007, file no. 333-141687).
3.4	First Amended and Restated Agreement of Limited Partnership Agreement of Spectra Energy Partners (DE) GP, LP (filed as Exhibit 3.2 to Spectra Energy Partners, LP’s Form 8-K dated July 9, 2007).
3.5	Certificate of Limited Partnership of Spectra Energy Partners (DE) GP, LP (filed as Exhibit 3.3 to Spectra Energy Partners, LP’s Form S-1 on March 30, 2007, file no. 333-141687).
3.6	First Amended and Restated Limited Liability Agreement of Spectra Energy Partners GP, LLC (filed as Exhibit 3.3 to Spectra Energy Partners, LP’s Form 8-K dated July 9, 2007).
3.7	Certificate of Formation of Spectra Energy Partners GP, LLC (filed as Exhibit 3.5 to Spectra Energy Partners, LP’s Form S-1 on March 30, 2007, file no. 333-141687).
10.1	Contribution, Conveyance and Assumption Agreement, dated July 2, 2007, by and among Spectra Energy Partners, LP, Spectra Energy Partners OLP, LP, Spectra Energy Partners GP, LLC, Spectra Energy Partners OLP GP, LLC, Spectra Energy Partners (DE) GP, LP, Spectra Energy Transmission, LLC, Spectra Energy Southeast Pipeline Corporation, East Tennessee Natural Gas, LLC, Egan Hub Storage, LLC, Moss Bluff Hub, LLC and Market Hub Partners Holding, LLC (filed as Exhibit 10.1 to Spectra Energy Partners, LP’s Form 8-K dated July 9, 2007).
10.2	Omnibus Agreement, dated July 2, 2007, by and among Spectra Energy Partners, LP, Spectra Energy Partners (DE) GP, LP, Spectra Energy Partners GP, LLC and Spectra Energy Corp (filed as Exhibit 10.2 to Spectra Energy Partners, LP’s Form 8-K dated July 9, 2007).
+10.3	Long Term Incentive Plan of Spectra Energy Partners, LP (filed as Exhibit 10.3 to Spectra Energy Partners, LP’s Form 8-K dated July 9, 2007).
+10.4	Form of Phantom Unit Award Agreement under the Spectra Energy Partners, LP Long-Term Incentive Plan (filed as Exhibit 4.3 to Spectra Energy Partners, LP’s Form S-8 on July 2, 2007).
10.5	General Partnership Agreement of Market Hub Partners Holding (filed as Exhibit 10.4 to Spectra Energy Partners, LP’s Form 8-K dated July 9, 2007).
*10.6	Credit Agreement, dated as of May 24, 2007 among Spectra Energy Partners OLP, LP, as the Borrower, Spectra Energy Partners, LP, as Parent Guarantor and Wachovia Bank, National Association, as Administrative Agent, Citibank, N.A., as Syndication Agent, and the other lenders party thereto.
10.7	First Amendment to Credit Agreement, dated as of September 30, 2007, by and among Spectra Energy Partners OLP, LP, as the Borrower, Spectra Energy Partners, LP, as Parent Guarantor and Wachovia Bank, National Association, as Administrative Agent, and the other lenders party thereto (filed as Exhibit 10.1 to Spectra Energy Partners, LP’s Form 8-K dated October 11, 2007).
*10.8	Contribution Agreement, dated December 13, 2007, by and among Spectra Energy Transmission, LLC, Spectra Energy Partners (DE) GP, LP and Spectra Energy Partners, LP.

Exhibit No.	Exhibit Description
10.9	Gulfstream Natural Gas System, L.L.C. Indenture dated October 26, 2005 relating to $500,000,000 of its 5.56% Senior Notes due 2015 and $350,000,000 of its 6.19% Senior Notes due 2025 (filed as Exhibit 10.4 to Spectra Energy Partners, LP’s Form S-1/A on June 13, 2007, file no. 333-141687).
10.10	Second Amended and Restated Limited Liability Company Agreement of Gulfstream Natural Gas System, L.L.C. (filed as Exhibit 10.6 to Spectra Energy Partners, LP’s Form S-1/A on June 4, 2007, file no. 333-141687).
*10.11	East Tennessee Natural Gas, LLC Note Purchase Agreement dated December 15, 2002 relating to $150,000,000 of its 5.71% Senior Notes due 2012.
12.1	Ratios of Earnings to Fixed Charges (filed as Exhibit 12.1 to Spectra Energy Partners, LP’s Form 10-K on March 11, 2009).
21.1	Subsidiaries of the Registrant (filed as Exhibit 12.1 to Spectra Energy Partners, LP’s Form 10-K on March 11, 2009).
*23.1	Consent of Deloitte & Touche LLP.
*23.2	Consent of Deloitte & Touche LLP.
*23.3	Consent of Deloitte & Touche LLP.
24.1	Power of Attorney (filed as Exhibit 12.1 to Spectra Energy Partners, LP’s Form 10-K on March 11, 2009).
*31.1	Certification of the Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*31.2	Certification of the Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*32.1	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*32.2	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

* Filed herewith.

+ Denotes management contract or compensatory plan or arrangement.