Spectra Energy Partners, LP (Form: S-1, Received: 03/30/2007 11:40:03)

Proposed Maximum

Amount of

Title of Each Class of

Aggregate Offering

Registration

Securities to be Registered

Price(1)(2)

Common units representing limited partner interests

$277,725,000

As filed with the Securities and Exchange Commission on March 30, 2007

Registration No. 333-

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

SPECTRA ENERGY PARTNERS, LP

(Exact Name of Registrant as Specified in Its Charter)


Delaware	4922	41-2232463
(State or Other Jurisdiction of Incorporation or Organization)	(Primary Standard Industrial Classification Code Number)	(I.R.S. Employer Identification Number)

5400 Westheimer Court

Houston, Texas 77056

(713) 627-5400

(Address, Including Zip Code, and Telephone Number,

Including Area Code, of Registrant’s Principal Executive Offices)

C. Gregory Harper

President and Chief Executive Officer

5400 Westheimer Court

Houston, Texas 77056

(713) 627-5400

(Name, Address, Including Zip Code, and Telephone Number,

Including Area Code, of Agent for Service)

Copies to:


David P. Oelman Vinson & Elkins L.L.P. 1001 Fannin Street, Suite 2500 Houston, Texas 77002 (713) 758-2222		Joshua Davidson Kelly B. Rose Baker Botts L.L.P. 910 Louisiana Street Houston, Texas 77002 (713) 229-1234

Approximate date of commencement of proposed sale to the public: As soon as practicable after this Registration Statement becomes effective.

If any of the securities being registered on this form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box. o

If this form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

If this form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

If this form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

If delivery of the prospectus is expected to be made pursuant to Rule 434, please check the following box. o


(1)		Includes common units issuable upon exercise of the underwriters’ option to purchase additional common units.

(2)		Estimated solely for the purpose of calculating the registration fee pursuant to Rule 475(o).

The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the registration statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

The information in this preliminary prospectus is not complete and may be changed. These securities may not be sold until the registration statement filed with the Securities and Exchange Commission is effective. This preliminary prospectus is not an offer to sell nor does it seek an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.

SUBJECT TO COMPLETION DATED MARCH 30, 2007

PROSPECTUS

11,500,000 Common Units

Representing Limited Partner Interests

Spectra Energy Partners, LP is a limited partnership recently formed by Spectra Energy Corp. This is the initial public offering of our common units. We currently estimate that the initial public offering price will be between $ and $ per common unit. Prior to this offering, there has been no public market for our common units. We intend to apply to list our common units on the New York Stock Exchange under the symbol “SEP.”

Investing in our common units involves risks. Please read “Risk Factors” beginning on page 22.

These risks include the following:


	•	We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner, to enable us to make cash distributions to holders of our common units and subordinated units at the initial distribution rate under our cash distribution policy.

	•	Two of our three primary assets are controlled by Spectra Energy Corp and other third parties who are responsible for their management and operations. As a result we cannot control the amount of cash we will receive from them and we may be required to contribute significant cash to fund their operations.

	•	Our natural gas transportation and storage operations are subject to regulation by the Federal Energy Regulatory Commission, which could have an adverse impact 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 to you.

	•	Spectra Energy Corp 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 Corp, have conflicts of interest with us and limited fiduciary duties, and they may favor their own interests to your detriment.

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

	•	If you are not an (1) individual or entity subject to U.S. federal income taxation on the income generated by us or (2) entity not subject to U.S. federal taxation on the income generated by us, but all of whose owners are subject to such taxation, you will not be entitled to receive distributions or allocations of income or loss on your common units and your common units will be subject to redemption.

	•	Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors.

	•	You will experience immediate and substantial dilution of $6.43 in tangible net book value per common unit.

	•	You may be required to pay taxes on income from us even if you do not receive any cash distributions from us.


	Per Common Unit	Total

Initial public offering price	$	$
Underwriting discount(1)	$	$
Proceeds to Spectra Energy Partners, LP (before expenses)	$	$


(1)		Excludes an aggregate structuring fee equal to 0.25% of the gross proceeds of this offering payable to Citigroup Global Markets Inc. and Lehman Brothers Inc.

We have granted the underwriters a 30-day option to purchase up to an additional 1,725,000 common units from us on the same terms and conditions as set forth above if the underwriters sell more than 11,500,000 common units in this offering.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.

The underwriters expect to deliver the common units through the facilities of The Depository Trust Company on or about , 2007.


Citigroup	Lehman Brothers

, 2007


INDEX TO FINANCIAL STATEMENTS			F-1
APPENDIX A — FORM OF FIRST AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF SPECTRA ENERGY PARTNERS, LP			A-1
APPENDIX B — APPLICATION FOR TRANSFER OF COMMON UNITS			B-1
APPENDIX C — CERTIFICATION FORM FOR NON-INDIVIDUAL INVESTORS			C-1
APPENDIX D — GLOSSARY OF TERMS			D-1
Certificate of Limited Partnership - Spectra Energy Partners, LP
Certificate of Limited Partnership - Spectra Energy Partners (DE) GP, LP
Certifcate of Formation of Spectra Energy Partners GP, LLC
Consent of Deloitte & Touche LLP
Consent of Deloitte & Touche LLP
Consent of Deloitte & Touche LLP

You should rely only on the information contained in this prospectus. We have not, and the underwriters have not, authorized anyone to provide you with different information. If anyone provides you with different or inconsistent information, you should not rely on it. We are not, and the underwriters are not, making an offer to sell these securities in any jurisdiction where an offer or sale is not permitted. You should assume that the information appearing in this prospectus is accurate as of the date on the front cover of this prospectus. Our business, financial condition, results of operations and prospects may have changed since that date.

Until , 2007 (25 days after the date of this prospectus), all dealers that buy, sell or trade our common units, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

SUMMARY

This summary provides a brief overview of information contained elsewhere in this prospectus. You should read the entire prospectus carefully, including “Risk Factors” beginning on page 22 and the historical and pro forma financial statements. Unless indicated otherwise, the information presented in this prospectus assumes (1) an initial public offering price of $20.00 per unit and (2) that the underwriters do not exercise their option to purchase additional units. We include a glossary of some of the terms used in this prospectus as Appendix D. References in this prospectus to “Spectra Energy Partners, LP,” “we,” “our,” “us” or like terms when used in a historical context refer to the businesses that Spectra Energy Corp is contributing to Spectra Energy Partners, LP in connection with this offering. When used in the present tense or prospectively, those terms refer to Spectra Energy Partners, LP and its subsidiaries. References to our “general partner” refer to Spectra Energy Partners (DE) GP, LP and/or Spectra Energy Partners GP, LLC, the general partner of Spectra Energy Partners (DE) GP, LP, as appropriate. References to “Spectra Energy” when used with respect to periods prior to January 1, 2007 refer to Spectra Energy Capital, LLC and when used with respect to periods after that date or prospectively refer to Spectra Energy Corp, the ultimate parent company of our general partner. References to “East Tennessee,” “Gulfstream” or “Market Hub” refer to East Tennessee Natural Gas, LLC, Gulfstream Natural Gas System, L.L.C. or Market Hub Partners Holding, LLC, respectively.

Spectra Energy Partners, LP

Overview

We are a growth-oriented Delaware limited partnership recently formed by Spectra Energy to own and operate natural gas transportation and storage assets. Our initial assets consist of interests in two interstate natural gas pipeline systems located in the southeastern United States with over 2,100 miles of pipelines, interests in two natural gas storage facilities in Texas and Louisiana with aggregate working gas storage capacity of approximately 35 Bcf and a liquefied natural gas, or LNG, storage facility in Tennessee.

We intend to utilize the significant experience of Spectra Energy’s management team to execute our growth strategy, including the acquisition and construction of additional energy assets. Spectra Energy, which is comprised of the former natural gas businesses of Duke Energy Corporation, became a stand-alone publicly traded company in January 2007 and is one of the largest operators of natural gas pipelines and storage facilities in North America. At December 31, 2006, Spectra Energy had approximately 17,500 miles of natural gas transportation pipelines and approximately 265 Bcf of natural gas storage capacity (including the assets to be contributed to us).

Our Assets

East Tennessee System. We own and operate 100% of the approximately 1,400-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 growing energy demands of the Southeast and Mid-Atlantic regions of the United States through its connection to 19 receipt points and more than 175 delivery points and its market delivery capability of approximately 1.3 Bcf/d of natural gas. East Tennessee also owns and operates an LNG storage facility in Kingsport, Tennessee with working gas storage capacity of approximately 1.0 Bcf and regasification capability of 150 MMcf/d.

Gulfstream System. We own a 24.5% interest in the approximately 690-mile Gulfstream interstate natural gas transportation system, which extends from Pascagoula, Mississippi and Mobile, Alabama across the Gulf of Mexico and into Florida. Gulfstream supports the fast growing south and central Florida markets through its connection to seven receipt points and 19 delivery points and its market delivery capability of approximately 1.1 Bcf/d of natural gas. Subsidiaries of Spectra Energy and The Williams Companies, Inc., respectively, own the remaining 25.5% and 50.0% interests in Gulfstream and jointly operate the system.

Market Hub System. We own a 50.0% interest in Market Hub, which owns and operates two high-deliverability salt cavern natural gas storage facilities located in Acadia Parish, Louisiana and Liberty County, Texas. These two facilities have aggregate working gas storage capacity of approximately 35 Bcf and interconnect with 12 major natural gas pipeline systems. Market Hub’s storage facilities offer access to natural gas supplies from Texas, Louisiana and growing imports of LNG to the Gulf Coast, and each facility interconnects with Spectra Energy’s Texas Eastern System. A subsidiary of Spectra Energy owns the remaining 50.0% interest in Market Hub and operates the system.

Our Operations

We transport and store natural gas for a broad mix of customers, including local gas distribution companies, or LDCs, municipal utilities, interstate and intrastate pipelines, direct industrial users, electric power generators and natural gas 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 Federal Energy Regulatory Commission, or FERC, rate-making policies, and, in the case of our storage facility in Texas, by the Texas Railroad Commission, or TRC.

We provide a significant portion of our transportation and storage services through firm contracts that obligate our customers to pay us monthly capacity reservation fees, which are fixed charges owed to us regardless of the actual pipeline or storage capacity utilized by a customer. When a customer utilizes the capacity it has reserved under these contracts, we also collect a variable fee based on the volume of natural gas actually transported or stored. This enables us to recover our variable costs. These fees are typically a small percentage of the total fees we receive from our firm contracts. We also derive a smaller portion of our revenues through interruptible contracts under which our customers pay fees based on their actual utilization of our assets for transportation and storage services and other related services. Customers who have executed interruptible contracts are not assured capacity in our pipeline and storage facilities. 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 sets forth certain information regarding our assets, our contracts and our revenues, as of and for the year ended December 31, 2006:


																Weighted
				Revenue Composition %									% of Physical			Average
				Firm Contracts									Capacity			Remaining
				Capacity									Subscribed			Contract
	Our Ownership			Reservation			Variable			Interruptible			Under Firm			Life (in
Asset	Interest			Fees			Fees			Contracts			Contracts			years)(1)

East Tennessee		100.0	%		97.7	%		1.7	%		0.6	%		89.7	%		9.3
Gulfstream		24.5	%		85.6	%		2.9	%		11.5	%		68.8	%		20.2
Market Hub		50.0	%		90.0	%		0.0	%		10.0	%		100.0	%		2.4


(1)		The average life of each contract is calculated based on the average annual contract revenue for such contract’s remaining life.

The high percentage of our earnings derived from capacity reservation fees mitigates the risk to us of earnings fluctuations caused by changing supply and demand conditions. For additional information about our contracts, please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — How We Evaluate Our Operations” and “Business — Regulation.”

Our Organic Growth Initiatives

Each of our systems has recently been expanded, is undergoing current expansion or presents additional organic growth opportunities for future expansion. We have budgeted approximately $110 million for all of

our planned growth capital expenditures through 2008, including our related capital contributions to Gulfstream and Market Hub. Examples of our organic expansion projects include:


	•	East Tennessee System Expansions. Since acquiring East Tennessee in 2000 we have completed expansions that have doubled its market delivery capability from 668 MMcf/d to 1.3 Bcf/d. Our recently completed, approximately $300 million Patriot Extension contributed approximately 400 MMcf/d of capacity to this total and for the first time linked East Tennessee with markets in North Carolina and the broader Mid-Atlantic region. The addition of this new market has allowed East Tennessee to pursue additional greenfield expansions such as the approximately $60 million Jewell Ridge Lateral, which added capacity of up to 228 MMcf/d for delivery of additional Appalachian production to East Tennessee customers. Spectra Energy is currently evaluating additional storage projects at its Saltville storage facility to provide supply flexibility to the markets served on each end of the East Tennessee system. We believe the East Tennessee expansion projects will offer additional organic growth opportunities as those assets are further expanded.

	•	Gulfstream System Expansions. Two fully-contracted expansion projects are currently being pursued for Gulfstream to increase its utilization and total system capacity. The estimated $135 million Phase III project will extend the pipeline to a new market, enabling us to fully subscribe Gulfstream’s existing mainline capacity. The estimated $117 million Phase IV project will add compression and extend the pipeline to a new market, increasing Gulfstream’s mainline capacity from 1.1 Bcf/d to 1.25 Bcf/d by early 2009. Both of these expansions are fully-supported by customer contracts with 23-year initial terms and have applications pending with FERC for approval. Our 24.5% share of the remaining expansion costs for both Phase III and Phase IV is expected to be approximately $51.3 million.

	•	Market Hub System Expansions. Expansion projects are currently being pursued at Market Hub’s Egan, Louisiana storage facility to increase its aggregate working gas storage capacity from its current capacity of 20 Bcf to 24 Bcf by 2008. An application is currently pending with FERC for approval to further expand Egan to 32 Bcf by 2012. An expansion is also underway to increase the natural gas injection capability of Egan. This estimated $50 million expansion will be placed into service during the summer of 2007, adding approximately 22,800 horsepower of compression and increasing Egan’s injection capacity by approximately 0.5 Bcf/d to approximately 1.3 Bcf/d. Our 50% share of the remaining expansion costs for all of these projects is expected to be approximately $73.8 million. In addition, since acquiring Market Hub in 2000, Spectra Energy has expanded the storage capacity at Moss Bluff by approximately 4 Bcf and is currently considering additional capacity expansions.

We intend to finance our expansion projects with an appropriate combination of equity and debt. In addition, any refusal by FERC to issue certificate authorization for one or more of these projects may mean that we cannot pursue these projects or that they are constructed in a manner and with capacities that we do not currently anticipate.

Business Strategies

Our primary business objective is to increase our cash distributions per unit over time by executing the following strategies:


	•	pursuing economically attractive organic expansion opportunities and greenfield construction projects;

	•	increasing contracted capacity for natural gas transportation and storage on our systems by further expanding our customer base and diverse sources of natural gas supply;

	•	optimizing our existing assets and achieving additional operating efficiencies; and

	•	growing through strategic and accretive acquisitions of assets from third parties, Spectra Energy or both.

Competitive Strengths

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


	•	our ability to grow through organic expansion opportunities, greenfield construction projects and acquisitions, along with access to other business development opportunities, is enhanced by our affiliation with Spectra Energy;

	•	our natural gas transportation assets are strategically located to transport natural gas from a number of diverse supply regions to high-demand end-use markets;

	•	our storage assets are strategically positioned to capitalize on expected increased demand for natural gas storage;

	•	our cash flow is relatively stable due to the high percentage of our revenues obtained from capacity reservation fees and the long-term nature of our contracts;

	•	our management team has significant experience in the natural gas transportation and storage and energy industries; and

	•	our high-quality assets have been well maintained.

Our Relationship with Spectra Energy

One of our principal attributes is our relationship with Spectra Energy, which will own our general partner and a significant interest in us following this offering. Spectra Energy is comprised of the former natural gas businesses of Duke Energy Corporation and became a stand-alone publicly traded company in January 2007. Spectra Energy owns and operates a large and diversified portfolio of complementary natural gas-related energy assets and is one of North America’s leading midstream natural gas companies. Spectra Energy, which trades on the New York Stock Exchange under the symbol “SE,” serves three key links in the natural gas value chain: gathering and processing, transportation and storage and distribution. Through its interests in five U.S. pipeline systems (including East Tennessee and Gulfstream) and three Canadian pipeline systems, Spectra Energy owns and operates one of the largest long-haul natural gas pipeline networks in North America consisting of approximately 17,500 miles of transportation pipelines. In addition, Spectra Energy is one of the largest operators of natural gas storage in North America with eleven storage facilities with total working gas capacity of approximately 265 Bcf (including East Tennessee’s LNG facility and Market Hub), and owns a 50.0% interest in DCP Midstream, LLC (previously known as Duke Energy Field Services, LLC), which is the largest natural gas liquids producer in North America. DCP Midstream, LLC owns the general partner interest and a 40.7% limited partner interest in DCP Midstream Partners, LP, which is a midstream master limited partnership.

Upon the completion of this offering, Spectra Energy will own our 2% general partner interest, all of our incentive distribution rights and a 79.6% limited partner interest in us. We will enter into an omnibus agreement with Spectra Energy, our general partner and certain of their affiliates that will govern our relationship with them regarding certain reimbursement and indemnification matters. Please read “Certain Relationships and Related Party Transactions — Omnibus Agreement.” While our relationship with Spectra Energy and its subsidiaries is a significant attribute, it may also be a source of conflicts. For example, neither Spectra Energy nor any of its affiliates are prohibited from competing with us. Spectra Energy and its affiliates may acquire, construct or dispose of assets in the future without any obligation to offer us the opportunity to purchase or construct those assets. Please read “Conflicts of Interest and Fiduciary Duties.”

Summary of Risk Factors

An investment in our common units involves risks. The following list of risk factors is not exhaustive. Please read carefully these and other risks described under “Risk Factors.”

Risks Related to Our Business


	•	We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner, to enable us to make cash distributions to holders of our common units and subordinated units at the initial distribution rate under our cash distribution policy.

	•	On a pro forma basis we would not have had sufficient cash available for distribution to pay the full minimum quarterly distribution on all units for the year ended December 31, 2006. Please read “Our Cash Distribution Policy and Restrictions on Distributions.”

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

	•	Our natural gas transportation and storage operations are subject to regulation by FERC, which could have an adverse impact 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 to you.

	•	Certain of our transportation services are subject to long-term, fixed-price “negotiated rate” contracts that are not subject to adjustment, even if our cost to perform such services exceeds the revenues received from such contracts.

	•	The assumptions underlying the minimum estimated cash available for distribution we include in “Our Cash Distribution Policy and Restrictions on Distributions” are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those estimated.

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

	•	Any significant decrease in supplies of natural gas in our areas of operation could adversely affect our business and operating results.

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

	•	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 to you.

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. Spectra Energy has conflicts of interest, and it may favor its own interests to your detriment.

	•	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 our commercial activities or our ability to acquire additional assets or businesses.


	•	If you are not an (1) individual or entity subject to U.S. federal income taxation on the income generated by us or (2) entity not subject to U.S. federal taxation on the income generated by us, but all of whose owners are subject to such taxation, you will not be entitled to receive distributions or allocations of income or loss on your common units and your common units will be subject to redemption.

	•	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 to you.

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

Tax Risks to Common Unitholders


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

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

	•	You may be required to pay taxes on income from us even if you do not receive any cash distributions from us.

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

Formation Transactions and Partnership Structure

General

At the closing of this offering the following transactions will occur:


	•	Spectra Energy or its subsidiaries will contribute certain of their assets to us or our subsidiaries;

	•	we will issue to a subsidiary of Spectra Energy 29,812,011 common units and 20,030,066 subordinated units, representing an aggregate 79.6% limited partner interest in us;

	•	we will issue to Spectra Energy Partners (DE) GP, LP, a subsidiary of Spectra Energy, a 2% general partner interest in us and all of our incentive distribution rights, which will entitle our general partner to increasing percentages of the cash we distribute in excess of $0.3738 per unit per quarter (115% of the minimum quarterly distribution);

	•	we will issue 11,500,000 common units to the public in this offering, representing an 18.4% limited partner interest in us, and will use the proceeds as described in “Use of Proceeds”;

	•	we will enter into a new $500 million credit facility under which we expect to borrow $50 million in term debt and $125 million in revolving debt; and

	•	we will enter into an omnibus agreement with Spectra Energy, our general partner and certain of their affiliates pursuant to which:


	—	we will reimburse Spectra Energy for the payment of certain operating expenses and for providing various general and administrative services; and

	—	Spectra Energy will indemnify us for certain environmental and tax liabilities and title and right-of-way defects.

Management of Spectra Energy Partners, LP

Spectra Energy Partners (DE) GP, LP, our general partner, has sole responsibility for conducting our business and for managing our operations. Because our general partner is a limited partnership, its general partner, Spectra Energy Partners GP, LLC, will conduct our business and operations, and the board of directors and officers of Spectra Energy Partners GP, LLC will make decisions on our behalf. Spectra Energy will elect all members to the board of directors of Spectra Energy Partners GP, LLC, with at least three directors meeting the independence standards established by the New York Stock Exchange. For more information about these individuals, please read “Management — Directors and Executive Officers.”

As is common with publicly traded limited partnerships and in order to maximize operational flexibility, we will conduct our operations through subsidiaries. We will have one direct operating subsidiary initially, Spectra Energy Partners OLP, LP, a limited partnership that will conduct business through itself and its subsidiaries.

Principal Executive Offices and Internet Address

Our principal executive offices are located at 5400 Westheimer Court, Houston, Texas 77056 and our telephone number is (713) 627-5400. Our website is located at www.spectraenergypartners.com. We expect to make our periodic reports and other information filed with or furnished to the Securities and Exchange Commission, which we refer to as the SEC, available, free of charge, through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

Summary of Conflicts of Interest and Fiduciary Duties

General. Our general partner has a legal duty to manage us in a manner beneficial to holders of our common units and subordinated units. This legal duty originates in statutes and judicial decisions and is commonly referred to as a “fiduciary duty.” However, because our general partner is owned by Spectra Energy, the officers and directors of our general partner also have fiduciary duties to manage our general partner in a manner beneficial to Spectra Energy. As a result of this relationship, conflicts of interest may arise in the future between us and holders of our common units and subordinated units, on the one hand, and our general partner and its affiliates on the other hand.

Partnership Agreement Modifications to Fiduciary Duties. Our partnership agreement limits the liability and reduces the fiduciary duties of our general partner to holders of our common units and subordinated units. Our partnership agreement also restricts the remedies available to holders of our common units and subordinated units for actions that might otherwise constitute a breach of our general partner’s fiduciary duties owed to holders of our common units and subordinated units. Our partnership agreement also provides that affiliates of our general partner, including Spectra Energy and its affiliates, are not restricted from competing with us. By purchasing a common unit, the purchaser agrees to be bound by the terms of our partnership agreement and, pursuant to the terms of our partnership agreement, each holder of common units consents to various actions contemplated in the partnership agreement and conflicts of interest that might otherwise be considered a breach of fiduciary or other duties under applicable state law.

For a more detailed description of the conflicts of interest and fiduciary duties of our general partner, please read “Conflicts of Interest and Fiduciary Duties.”

The Offering


Common units offered to the public		11,500,000 common units.

Common units subject to the underwriters’ option to purchase additional common units		If the underwriters exercise their option to purchase additional units in full, we will issue 1,725,000 additional common units to the public and redeem the same number of common units from a subsidiary of Spectra Energy, who may be deemed to be a selling unitholder in this offering. Please read “Selling Unitholder”.

Units outstanding after this offering		41,312,011 common units and 20,030,066 subordinated units, representing 66% and 32%, respectively, limited partner interests in us. The general partner will own 1,251,879 general partner units.

Use of proceeds		We intend to use the net proceeds of approximately $215.6 million from this offering, after deducting underwriting discounts and structuring fees but before paying offering expenses to:

		• purchase approximately $50.0 million of United States Treasury and other qualifying securities, which will be assigned as collateral to secure the term loan portion of our credit facility;

		• pay approximately $6.9 million of expenses associated with the offering and related formation transactions;

		• distribute approximately $150.0 million in cash to subsidiaries of Spectra Energy as reimbursement for capital expenditures incurred by subsidiaries of Spectra Energy prior to this offering related to the assets to be contributed to us upon the closing of this offering, which distribution will be made in partial consideration of the assets contributed to us upon the closing of this offering; and

		• use the remaining amount of approximately $8.7 million to fund working capital.

		We also anticipate that we will borrow approximately $50 million in term debt and approximately $125 million in revolving debt upon the closing of this offering, and we will distribute the aggregate amount of the proceeds of such borrowings to subsidiaries of Spectra Energy, which distribution will be made in partial consideration of the assets contributed to us upon the closing of this offering.

		If the underwriters’ option to purchase additional common units is exercised in full, we will (1) use the net proceeds of $32.3 million to purchase an equivalent amount of United States Treasury and other qualifying securities, which will be assigned as collateral to secure the additional term loan borrowings described below and (2) borrow an additional amount under the term loan portion of our credit facility equal to the net proceeds to be received from the exercise of the underwriters’ option. The proceeds of the additional term loan borrowings will be used to redeem from a subsidiary of Spectra Energy a number of common units equal to the number of common units issued upon exercise of the underwriters’ option, at a price per


		common unit equal to the proceeds per common unit before expenses but after underwriting discounts and a structuring fee.

Cash distributions		We will make an initial quarterly distribution of $0.325 per common unit ($1.30 per common unit on an annualized basis) to the extent we have sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates. Our ability to pay cash distributions at this initial distribution rate is subject to various restrictions and other factors described in more detail under the caption “Our Cash Distribution Policy and Restrictions on Distributions.”

		We will pay investors in this offering a prorated distribution for the first quarter during which we are a publicly traded partnership. Such distribution will cover the period from the closing date of this offering to and including September 30, 2007. We expect to pay this cash distribution on or about November 15, 2007.

		Our partnership agreement requires us to distribute all of our cash on hand at the end of each quarter, less reserves established by our general partner. We refer to this cash as “available cash,” and we define its meaning in our partnership agreement and in the glossary of terms attached as Appendix D. Our partnership agreement also requires that we distribute all of our available cash from operating surplus each quarter in the following manner:

		• first , 98% to the holders of common units and 2% to our general partner, until each common unit has received a minimum quarterly distribution of $0.325 plus any arrearages from prior quarters;

		• second , 98% to the holders of subordinated units and 2% to our general partner, until each subordinated unit has received a minimum quarterly distribution of $0.325; and

		• third , 98% to all unitholders, pro rata, and 2% to our general partner, until each unit has received a distribution of $0.3738.

		If cash distributions to our unitholders exceed $0.3738 per common unit in any quarter, our general partner will receive, in addition to distributions on its 2% general partner interest, increasing percentages, up to 48%, of the cash we distribute in excess of that amount. We refer to these distributions as “incentive distributions.” Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions.”

		The amount of pro forma available cash generated during the year ended December 31, 2006 would have been sufficient to allow us to pay the full minimum quarterly distribution on all of our common units but only approximately 47% of the minimum quarterly distribution on our subordinated units during that period. For a calculation of our ability to make distributions to unitholders based on our pro forma results for 2006, please read “Our Cash Distribution Policy and Restrictions on Distributions — Unaudited Pro Forma Cash Available for Distribution for the Year Ended December 31, 2006.”


		We believe that, based on the estimates contained and the assumptions listed under the caption “Our Cash Distribution Policy and Restrictions on Distributions — Minimum Estimated Cash Available for Distribution for the Twelve-Month Period Ending June 30, 2008,” we will have sufficient cash available for distribution to make cash distributions for the four quarters ending June 30, 2008 at the initial distribution rate of $0.325 per common unit per quarter ($1.30 per common unit on an annualized basis) on all common units and subordinated units.

Subordinated units		A subsidiary of Spectra Energy will initially own all of our subordinated units. The principal difference between our common units and subordinated units is that in any quarter during the subordination period, holders of the subordinated units are entitled to receive the minimum quarterly distribution of $0.325 per unit only after the common units have received the minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Subordinated units will not accrue arrearages. The subordination period will end on the first business day after we have earned and paid at least $0.325 on each outstanding limited partner unit and general partner unit for any three consecutive, non-overlapping four quarter periods ending on or after June 30, 2010. The subordination period also will end upon the removal of our general partner other than for cause if the units held by our general partner and its affiliates are not voted in favor of such 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. Please read “Provisions of Our Partnership Agreement Related to Cash Distributions — Subordination Period.”

Early conversion of subordinated units		Alternatively, the subordination period will end on the first business day after we have earned and paid at least $1.95 (150% of the annualized minimum quarterly distribution) on each outstanding limited partner unit and general partner unit for any four quarter period ending on or after June 30, 2008. Please read “Provisions of Our Partnership Agreement Related to Cash Distributions — Subordination Period.”

General Partner’s right to reset the target distribution levels		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 the same percentage increases above the reset minimum quarterly distribution amount as in our current target distribution levels.

		In connection with resetting these target distribution levels, our general partner will be entitled to receive 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. For a more detailed description of our general partner’s right to reset the target distribution levels upon which the incentive distribution payments are based and the concurrent right of our general partner to receive Class B units in connection with this reset, please see “Provisions of Our Partnership Agreement Related to Cash Distributions — General Partner’s Right to Reset Incentive Distribution Levels.”

Issuance of additional units		We can issue an unlimited number of units without the consent of our unitholders. Please read “Units Eligible for Future Sale” and “The Partnership Agreement — Issuance of Additional Securities.”

Limited voting rights		Our general partner will manage and operate us. Unlike the holders of common stock in a corporation, you will have only limited voting rights on matters affecting our business. You will have no right to elect our general partner or the directors of its general partner on an annual or other continuing basis. Our general partner may not be removed except by a vote of the holders of at least 66 2 / 3 % of the outstanding units, including any units owned by our general partner and its affiliates, voting together as a single class. Upon consummation of this offering, our general partner and its affiliates will own an aggregate of approximately 81.3% of our common and subordinated units. This will give Spectra Energy the ability to prevent our general partner’s involuntary removal. Please read “The Partnership Agreement — Voting Rights.”

Limited call right		If at any time our general partner and its affiliates own more than 80% of the outstanding common units, our general partner has the right, but not the obligation, to purchase all of the remaining common units at a price not less than the then-current market price of the common units.

Eligible Holders and redemption		Only Eligible Holders will be entitled to receive distributions or be allocated income or loss from us. 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 taxation on the income generated by us, so long as all of the entity’s owners are subject to such taxation.


		We have the right, which we may assign to any of our affiliates, but not the obligation, to redeem all of the common and subordinated units of any holder that is not an Eligible Holder or that has failed to certify or has falsely certified that such holder is an Eligible Holder. The purchase price for such redemption would be equal to the lower of the holder’s purchase price and the then-current market price of the units. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner.

		Please read “Description of the Common Units — Transfer of Common Units” and “The Partnership Agreement — Non-Taxpaying Assignees; Redemption.”

Estimated ratio of taxable income to distributions		We estimate that if you own the common units you purchase in this offering through the record date for distributions for the period ending December 31, 2010, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be % or less of the cash distributed to you with respect to that period. For example, if you receive an annual distribution of $1.30 per unit, we estimate that your average allocable federal taxable income per year will be no more than $ per unit. Please read “Material Tax Consequences — Tax Consequences of Unit Ownership — Ratio of Taxable Income to Distributions.”

Material tax consequences		For a discussion of other material federal income tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States, please read “Material Tax Consequences.”

Exchange listing		We intend to apply to list our common units on the New York Stock Exchange under the symbol “SEP.”

Summary Historical and Pro forma Financial and Operating Data

The following table shows (i) summary historical financial and operating data of Spectra Energy Partners Predecessor, (ii) summary pro forma financial data of Spectra Energy Partners and (iii) summary historical financial and operating data of Gulfstream and Market Hub for the periods and as of the dates indicated. The summary historical financial data of Spectra Energy Partners Predecessor as of and for the years ended December 31, 2004, 2005 and 2006 are derived from the historical audited combined financial statements of Spectra Energy Partners Predecessor, appearing elsewhere in this prospectus. The table should also be read together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

The summary historical financial data of Gulfstream and Market Hub as of and for the years ended December 31, 2004, 2005 and 2006 are derived from the audited financial statements of Gulfstream and Market Hub, respectively, appearing elsewhere in this prospectus.

The summary pro forma financial data of Spectra Energy Partners as of and for the year ended December 31, 2006 are derived from the unaudited pro forma combined financial statements of Spectra Energy Partners included elsewhere in this prospectus. The pro forma adjustments have been prepared as if certain transactions to be effected at the closing of this offering had taken place on December 31, 2006 in the case of the pro forma balance sheet, or as of January 1, 2006, in the case of the pro forma statement of operations. These transactions include:


	•	East Tennessee’s and Market Hub’s distribution of accounts receivable of $9.1 million and $12.1 million ($6.0 million, net to our interest), respectively, to Spectra Energy;

	•	Spectra Energy Partners’ receipt of $230 million in gross proceeds from the issuance and sale of 11,500,000 common units to the public;

	•	Spectra Energy Partners’ borrowings under its new $500 million credit facility of $50 million in term debt and $125 million in revolving debt; and

	•	Spectra Energy Partners’ use of proceeds and borrowings to pay transaction expenses and underwriting commissions, reimburse Spectra Energy for certain capital expenditures, replenish working capital and invest in U.S. Treasury and other qualifying securities.

The following table includes the following non-generally accepted accounting principles (GAAP) financial measures:


	•	Our historical and pro forma Adjusted EBITDA;

	•	Adjusted EBITDA for both our 24.5% ownership interest in Gulfstream and our 50.0% ownership interest in Market Hub;

	•	Our historical and pro forma cash available for distribution; and

	•	Cash available for distribution for both our 24.5% ownership interest in Gulfstream and our 50.0% ownership interest in Market Hub.

These measures are presented because such information is relevant to, and will be used by, management, industry analysts, investors, lenders and rating agencies to assess the financial performance and operating results of our fundamental business activities. Our 24.5% ownership interest in Gulfstream and our 50.0% ownership interest in Market Hub are not consolidated in our pro forma financial results, but are accounted for using the equity method of accounting. In order to evaluate our Adjusted EBITDA for the cash impact of our investments in Gulfstream and Market Hub on our results, we calculate Adjusted EBITDA and cash available for distribution separately for us and our ownership interests in Gulfstream and Market Hub. We expect distributions we receive from Gulfstream and Market Hub to represent a significant portion of the cash we distribute to our unitholders. The limited liability company agreements for each of Gulfstream and Market Hub provide for quarterly distributions of available cash to their members. Please read “How We Make Cash Distributions — General — Limitations on Cash Distributions and Our

Ability to Change Our Cash Distribution Policy” for more information on the manner in which Gulfstream and Market Hub distribute cash to their members.

For Gulfstream and Market Hub, we define Adjusted EBITDA as net income plus interest expense, income taxes and depreciation and amortization less other income, net, which primarily consists of non-cash AFUDC and certain other items such as insurance recoveries. Our equity share of Gulfstream’s Adjusted EBITDA is 24.5%, and our equity share of Market Hub’s Adjusted EBITDA is 50.0%.

We define our cash available for distribution as our Adjusted EBITDA plus cash available for distribution from Gulfstream and Market Hub, less net cash paid for interest expense and maintenance capital expenditures. Our cash available for distribution does not reflect changes in working capital balances. Our pro forma cash available for distribution for the year ended December 31, 2006 includes our anticipated incremental general and administrative expense of being a publicly traded partnership.

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

For a reconciliation of these measures to their most directly comparable financial measures calculated and presented in accordance with GAAP, please read “— Non-GAAP Financial Measures.”


							Spectra Energy
							Partners, LP
							Pro Forma
	Spectra Energy Partners Predecessor						Year Ended
	Year Ended December 31,						December 31,
	2004		2005		2006		2006
	(In thousands, except per unit and operating data)
Statement of Operations Data:
Total operating revenues	$	81,716	$	80,003	$	82,609	$	82,609
Operating expenses:
Operations, maintenance, and other		26,081		24,648		21,831		21,831
Depreciation and amortization		21,492		23,640		18,986		18,986
Property and other taxes		518		5,264		4,177		4,177

Total operating expenses		48,091		53,552		44,994		44,994

Operating income		33,625		26,451		37,615		37,615

Equity in earnings of unconsolidated affiliates		35,495		46,287		41,105		41,105
Other income (expenses), net		1,491		552		1,780		1,780
Interest expense (income), net		8,258		8,506		8,151		15,976
Income tax expense		9,202		7,834		10,741		453

Net income	$	53,151	$	56,950	$	61,608	$	64,071

Pro forma net income per common unit							$	1.02
Pro forma net income per subordinated unit							$	1.02


Balance Sheet Data (at period end):

Total assets	$	1,302,974	$	1,202,772	$	1,284,582	$	1,323,465
Property, plant and equipment, net		602,226		616,316		691,820		691,820
Investment in unconsolidated affiliates		553,731		422,340		442,793		431,081
Long-term debt		150,000		150,000		150,000		325,000
Total parent net equity		1,024,754		895,696		989,125		967,400


							Spectra Energy
							Partners, LP
							Pro Forma
	Spectra Energy Partners Predecessor						Year Ended
	Year Ended December 31,						December 31,
	2004		2005		2006		2006
	(In thousands, except per unit and operating data)

Other Financial Data:

Spectra Energy Partners
Net cash provided by operating activities	$	83,987		93,272	$	62,278	$	64,741
Adjusted EBITDA		55,117		50,091		56,601		56,601
Incremental general and administrative expense of being a publicly-traded partnership		—		—		—		5,500	(b)
Net cash paid for interest expense		12,955		8,566		8,591		16,216
Maintenance capital expenditures		6,679		8,232		10,933		10,933
Cash available for distribution(a)		73,784		77,526		80,377		67,252
Expansion capital expenditures		27,590		51,083		74,977		74,977
Gulfstream — our 24.5%
Net cash provided by operating activities		18,771		24,999		24,712
Adjusted EBITDA		18,699		29,583		36,060
Net cash paid for interest expense		1,555		3,869		12,109
Maintenance capital expenditures		47		234		151
Cash available for distribution(a)		17,097		25,480		23,800
Expansion capital expenditures		30,356		15,000		5,149
Market Hub — our 50.0%
Net cash provided by operating activities		21,452		31,139		84,386
Adjusted EBITDA		27,027		32,552		24,286
Net cash paid for interest expense		—		—		22
Maintenance capital expenditures		5,823		13,799		4,763
Cash available for distribution(a)		21,204		18,753		19,500
Expansion capital expenditures		2,677		5,195		22,279

Operating Data:
East Tennessee
Transportation capacity (Bcf/d)		1.263		1.280		1.319
Contracted firm capacity (Bcf/d)		1.147		1.114		1.183
Transported volumes (Bcf)		121.7		133.1		143.7
Gulfstream — 100% basis
Transportation capacity (Bcf/d)		1.063		1.063		1.063
Contracted firm capacity (Bcf/d)		0.296		0.731		0.731
Transported volumes (Bcf)		110.7		179.7		251.3
Market Hub — 100% basis
Storage capacity (Bcf)		28.7		29.8		34.8


(a)		Cash available for distribution of Spectra Energy Partners includes cash available for distribution from Gulfstream and Market Hub.

(b)		Upon completion of this offering, we anticipate incurring incremental general and administrative expense of approximately $5.5 million per year as a result of being a publicly-traded limited partnership. The unaudited pro forma combined financial statements do not reflect these expenses.

Non-GAAP Financial Measures

Adjusted EBITDA and cash available for distribution are used as supplemental financial measures by management and by external users of our financial statements, such as investors and commercial banks, to assess:


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

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

	•	our 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 their financing methods and capital structure.

Adjusted EBITDA and cash available for distribution should not be considered alternatives to net income, operating income, net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Adjusted EBITDA and cash available for distribution exclude some, but not all, items that affect net income and operating income and these measures may vary among other companies. Therefore, Adjusted EBITDA and cash available for distribution as presented may not be comparable to similarly titled measures of other companies. Furthermore, while cash available for distribution is a measure we use to assess our ability to make distributions to our unitholders, cash available for distribution should not be viewed as indicative of the actual amount of cash that we have available for distributions or that we plan to distribute for a given period.

The following tables present reconciliations of the non-GAAP financial measures of Adjusted EBITDA and cash available for distribution for each of us, Gulfstream and Market Hub to their respective GAAP financial measures of net income and net cash provided (used) by operating activities on a historical basis and on a pro forma basis as adjusted for this offering.


										Spectra Energy
										Partners, LP
										Pro Forma
	Spectra Energy Partners Predecessor									Year Ended
	Year Ended December 31,									December 31,
	2004			2005			2006			2006
	(In thousands)

Spectra Energy Partners
Reconciliation of Non-GAAP “Adjusted EBITDA” and “Cash Available for Distribution” to GAAP “Net Income”
Net income	$	53,151		$	56,950		$	61,608		$	64,071
Add:
Interest expense (income), net		8,258			8,506			8,151			15,976
Income tax expense		9,202			7,834			10,741			453
Depreciation and amortization		21,492			23,640			18,986			18,986
Less:
Equity in earnings of Gulfstream		11,081			16,611			16,763			16,763
Equity in earnings of Market Hub		24,414			29,676			24,342			24,342
Other income (expenses), net		1,491			552			1,780			1,780

Adjusted EBITDA	$	55,117		$	50,091		$	56,601		$	56,601

Add:
Cash available for distribution from Gulfstream		17,097			25,480			23,800			23,800
Cash available for distribution from Market Hub		21,204			18,753			19,500			19,500
Less:
Incremental general and administrative expense of being a public company		—			—			—			5,500
Net cash paid for interest expense (income), net		12,955			8,566			8,591			16,216
Maintenance capital expenditures		6,679			8,232			10,933			10,933

Cash available for distribution	$	73,784		$	77,526		$	80,377		$	67,252


Reconciliation of Non-GAAP “Adjusted EBITDA” and “Cash Available for Distribution” to GAAP “Net cash provided by operating activities”
Net cash provided by operating activities	$	83,987		$	93,272		$	62,278		$	64,741
Interest expense (income), net		8,258			8,506			8,151			15,976
Income taxes		(21,964	)		3,465			(2,072	)		(12,360	)
Distributions received from Market Hub		—			—			—			—
Distributions received from Gulfstream		(13,720	)		(29,645	)		(20,335	)		(20,335	)
Other		(6	)		12			299			299
Changes in operating working capital:
Accounts receivable		848			(934	)		(49	)		(49	)
Other current assets		6,294			(6,189	)		878			878
Accounts payable		4,787			(1,687	)		798			798
Taxes accrued		(17,694	)		(7,527	)		3,345			3,345
Other current liabilities		3,197			(1,617	)		8,927			8,927
Other, including changes in noncurrent assets and liabilities		1,130			(7,565	)		(5,619	)		(5,619	)

Adjusted EBITDA	$	55,117		$	50,091		$	56,601		$	56,601

Add:
Cash available for distribution from Gulfstream		17,097			25,480			23,800			23,800
Cash available for distribution from Market Hub		21,204			18,753			19,500			19,500
Less:
Incremental general and administrative expense of being a public company		—			—			—			5,500
Net cash paid for interest expense (income), net		12,955			8,566			8,591			16,216
Maintenance capital expenditures		6,679			8,232			10,933			10,933

Cash available for distribution	$	73,784		$	77,526		$	80,377		$	67,252


	Gulfstream
	Year Ended December 31,
	2004			2005			2006
	(In thousands)

Gulfstream
Reconciliation of non-GAAP “Adjusted EBITDA” and “Cash Available for Distribution” to GAAP “Net Income”
Net income	$	45,228		$	67,800		$	68,422
Add:
Interest expense		9,092			25,540			48,787
Depreciation and amortization		25,354			29,190			30,406
Less:
Other income (expenses), net		3,353			1,783			431

Adjusted EBITDA — 100%	$	76,321		$	120,747		$	147,184

Adjusted EBITDA — our 24.5%	$	18,699		$	29,583		$	36,060

Less:
Net cash paid for interest expense		6,349			15,794			49,423
Maintenance capital expenditures		190			955			617

Cash available for distribution — 100%	$	69,782		$	103,998		$	97,144

Cash available for distribution — our 24.5%	$	17,097		$	25,480		$	23,800


Reconciliation of Non-GAAP “Adjusted EBITDA” and “Cash Available for Distribution” to GAAP “Net cash provided by operating activities”
Net cash provided by operating activities	$	76,617		$	111,858		$	107,083
Interest expense (income), net		9,092			25,540			48,787
Other		(5,571	)		(4,962	)		493
Changes in operating working capital:
Accounts receivable		(420	)		9,698			(3,772	)
Other current assets		(3,575	)		143			545
Accounts payable		(102	)		2,066			(994	)
Accrued taxes		1,264			(4,861	)		(8,050	)
Accrued interest		(1,573	)		(6,709	)		687
Accrued liabilities		172			(5,830	)		875
Fuel tracker liabilities		—			(2,962	)		2,260
Other current liabilities		(223	)		(2,940	)		(3,197	)
Other, including changes in noncurrent assets and liabilities		640			(294	)		2,467

Adjusted EBITDA — 100%	$	76,321		$	120,747		$	147,184

Adjusted EBITDA — our 24.5%	$	18,699		$	29,583		$	36,060

Less:
Net cash paid for interest expense		6,349			15,794			49,423
Maintenance capital expenditures		190			955			617

Cash available for distribution — 100%	$	69,782		$	103,998		$	97,144

Cash available for distribution — our 24.5%	$	17,097		$	25,480		$	23,800


	Market Hub
	Year ended December 31,
	2004			2005			2006
	(In thousands)

Market Hub
Reconciliation of Non-GAAP “Adjusted EBITDA” and “Cash Available for Distribution” to GAAP “Net Income”
Net income	$	48,829		$	59,353		$	48,684
Add:
Interest expense		—			—			2,625
Depreciation and amortization		6,788			6,938			7,815
Less:
Other income (expenses), net		1,533			1,146			10,553
Interest income		30			41			—

Adjusted EBITDA — 100%	$	54,054		$	65,104		$	48,571

Adjusted EBITDA — our 50.0%	$	27,027		$	32,552		$	24,286

Less:
Net cash paid for interest expense		—			—			43
Maintenance capital expenditures		11,646			27,599			9,528

Cash available for distribution — 100%	$	42,408		$	37,505		$	39,000

Cash available for distribution — our 50.0%	$	21,204		$	18,753		$	19,500


Reconciliation of Non-GAAP “Adjusted EBITDA” and “Cash Available for Distribution” to GAAP “Net cash provided by operating activities”
Net cash provided by operating activities	$	42,904		$	62,278		$	168,771
Interest expense (income), net		(30	)		(41	)		2,625
Other		6			(10	)		—
Changes in operating working capital:
Accounts receivable		36,682			(16,306	)		(5,944	)
Inventory		808			3,137			(6,113	)
Other current assets		(260	)		—			—
Accounts payable		(1,593	)		363			(4,804	)
Accrued taxes		214			506			(379	)
Collateral liabilities		(1,799	)		(491	)		(56,341	)
Other accrued liabilities		(22,852	)		14,587			(2,638	)
Other, including changes in noncurrent assets and liabilities		(26	)		1,081			(46,606	)

Adjusted EBITDA — 100%	$	54,054		$	65,104		$	48,571

Adjusted EBITDA — our 50.0%	$	27,027		$	32,552		$	24,286

Less:
Net cash paid for interest expense		—			—			43
Maintenance capital expenditures		11,646			27,599			9,528

Cash available for distribution — 100%	$	42,408		$	37,505		$	39,000

Cash available for distribution — our 50.0%	$	21,204		$	18,753		$	19,500

RISK FACTORS

Limited partner interests are inherently different from capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in similar businesses. You should consider carefully the following risk factors together with all of the other information included in this prospectus in evaluating an investment in our common units.

If any of the following risks were actually to occur, our business, financial condition, results of operations and cash flows could be materially adversely affected. In that case, we might not be able to make distributions on our common units, the trading price of our common units could decline and you could lose all or part of your investment.

Risks Related to Our Business

We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner, to enable us to make cash distributions to holders of our common units and subordinated units at the initial distribution rate under our cash distribution policy.

In order to make cash distributions at our initial distribution rate of $0.325 per common unit per complete quarter, or $1.30 per unit per year, we will require available cash of approximately $20.3 million per quarter, or $81.4 million per year, based on the number of common units and subordinated units outstanding immediately after completion of this offering, whether or not the underwriters exercise their option to purchase additional common units. We may not have sufficient available cash from operating surplus each quarter to enable us to make cash distributions at the initial distribution rate under our cash distribution policy. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate based on, among other things:


	•	the rates we charge for our transportation and storage services and the volumes of natural gas our customers transport and store;

	•	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, how we contract for services, our existing contracts, our operating costs and our 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 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 our operating and maintenance and general and administrative costs.

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


	•	the level of capital expenditures we make to complete construction projects;

	•	our debt service requirements and other liabilities;

	•	fluctuations in our working capital needs;

	•	our ability to borrow funds and access capital markets;


	•	restrictions on distributions contained in our debt agreements; and

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

For a description of additional restrictions and factors that may affect our ability to make cash distributions, please read “Our Cash Distribution Policy and Restrictions on Distributions.”

On a pro forma basis we would not have had sufficient cash available for distribution to pay the full minimum quarterly distribution on all units for the year ended December 31, 2006.

The amount of available cash we need to pay the minimum quarterly distribution for four quarters on all of our units to be outstanding immediately after this offering is approximately $81.4 million. The amount of our pro forma available cash generated during the year ended December 31, 2006 would have been sufficient to allow us to pay the full minimum quarterly distribution on our common units but only 47% of the minimum quarterly distribution on our subordinated units during that period. For a calculation of our ability to make distributions to unitholders based on our pro forma results for 2006, please read “Our Cash Distribution Policy and Restrictions on Distributions.”

The assumptions underlying our minimum estimated cash available for distribution we include in “Our Cash Distribution Policy and Restrictions on Distributions” are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those estimated.

Our estimate of cash available for distribution set forth in “Our Cash Distribution Policy and Restrictions on Distributions” has been prepared by management and we have not received an opinion or report on it from our or any other independent auditor. The assumptions underlying this estimate are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those assumed. If we do not achieve our anticipated results, we may not be able to pay the full minimum quarterly distribution or any amount on our common units or subordinated units, in which event the market price of our common units may decline materially.

Gulfstream and Market Hub are controlled by Spectra Energy and other third parties who are responsible for their management and operations. As a result we cannot control the amount of cash we will receive 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 half of the cash we distribute to you and our performance is substantially dependant on their distributions to us. Spectra Energy will operate Market Hub and the operation of Gulfstream is shared between Spectra Energy and The Williams Companies. 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. More specifically:


	•	We have limited ability to influence decisions with respect to the operation of Market Hub and Gulfstream, including decisions with respect to incurrence of expenses and distributions to us;

	•	Gulfstream and Market Hub may establish reserves for working capital and maintenance capital expenditures which would reduce cash otherwise available for distribution to us;

	•	Gulfstream and Market Hub may incur additional indebtedness, and related principal and interest payments that reduce cash otherwise available for distribution to us;

	•	Market Hub and Gulfstream may require us to make additional capital contributions to fund working and maintenance capital expenditures, as well as to fund expansion capital expenditures, our funding of which would reduce the amount of cash otherwise available for distribution to you.

Our lack of control over the operation of Market Hub and Gulfstream may mean that we do not receive the amount of cash we expect to be distributed to us and may require us to provide additional

capital, and these contributions may be material. This lack of control may significantly and adversely affect our ability to distribute cash to you. For a more complete description of the agreements governing the management and operation of Market Hub and Gulfstream, please see “Certain Relationships and Related Party Transactions”.

Our natural gas transportation and storage operations are subject to regulation by FERC, which could have an adverse impact 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 to you.

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 FERC. The federal regulation extends to such matters as:


	•	rates, operating terms and conditions of service;

	•	the types of services we may offer to our customers;

	•	construction of new facilities;

	•	acquisition, extension or abandonment of services or facilities;

	•	accounts and records; and

	•	relationships with affiliated companies involved in certain aspects of the natural gas business.

Under the Natural Gas Act (“NGA”), FERC has authority to regulate natural gas companies that provide natural gas pipeline transportation services in interstate commerce. Its authority to regulate those 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. Natural gas companies may not charge rates that have been determined not to be just and reasonable by FERC. In addition, FERC prohibits natural gas companies from unduly preferring or unreasonably discriminating against any person with respect to pipeline rates or terms and conditions of service.

The rates and terms and conditions for our interstate pipeline and storage services are set forth in FERC-approved tariffs. Pursuant to FERC’s jurisdiction over rates, existing rates may be challenged by complaint and proposed rate increases may be challenged by protest. Any successful complaint or protest against our rates, or the loss of our market-based rate authority for our storage facilities, could have an adverse impact on our revenues associated with providing transportation and storage services.

Prior to commencing construction of expansions of interstate pipeline and storage facilities, a natural gas company must obtain certificate authorization from FERC. Applications are pending before FERC for certificate authorization for Gulfstream’s Phase III and Phase IV projects and for Market Hub’s expansion project designed to increase working gas storage capacity at the Egan storage facility from 24 Bcf to 32 Bcf. Any refusal by FERC to issue certificate authorization for one or more of these projects may mean that we cannot pursue these projects or that that they are constructed in a manner and with capacities that we do not currently anticipate. Such refusal or modification could materially and negatively impact the additional revenues expected from these projects.

Should we fail to comply with all applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines. Under the Energy Policy Act of 2005, FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1,000,000 per day for each violation. See “Business — Regulation — FERC Regulation — Energy Policy Act of 2005.”

Finally, 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 ability to make distributions to you.

Our partnership status may be a disadvantage to us in calculating our cost of service for rate-making purposes.

In May 2005, FERC issued a policy statement permitting the inclusion of an income tax allowance in the cost of service-based rates of a pipeline organized as a tax pass through partnership entity to reflect actual or potential income tax liability on public utility income, if the pipeline proves that the ultimate owner of its interests has an actual or potential income tax liability on such income. The policy statement also provides that whether a pipeline’s owners have such actual or potential income tax liability will be reviewed by FERC on a case-by-case basis. In August 2005, FERC dismissed requests for rehearing of its new policy statement. On December 16, 2005, FERC issued its first significant case-specific review of the income tax allowance issue in another pipeline partnership’s rate case. FERC reaffirmed its new income tax allowance policy and directed the subject pipeline to provide certain evidence necessary for the pipeline to determine its income tax allowance. The new tax allowance policy and the December 16, 2005 order have been appealed to the United States Court of Appeals for the District of Columbia Circuit.

On December 8, 2006, FERC issued a new order addressing rates on another pipeline. In the new order, FERC refined its income tax allowance policy, and notably raised a new issue regarding the implication of the policy statement for publicly traded partnerships. It noted that the tax deferral features of a publicly traded partnership may cause some investors to receive, for some indeterminate duration, cash distributions in excess of their taxable income, which FERC characterized as a “tax savings.” FERC stated that it is concerned that this created an opportunity for those investors to earn an additional return, funded by ratepayers. Responding to this concern, FERC chose to adjust the pipeline’s equity rate of return downward based on the percentage by which the publicly traded partnership’s cash flow exceeded taxable income. On February 7, 2007, the pipeline asked FERC to reconsider this ruling.

The ultimate outcome of these proceedings is not certain and could result in changes to FERC’s treatment of income tax allowances in cost of service. Depending upon how the policy statement on income tax allowances is applied in practice to pipelines organized as pass through entities, and whether it is ultimately upheld or modified on judicial review, these decisions might adversely affect us.

Under FERC’s current income tax allowance policy, if any of our FERC-regulated pipelines and storage facilities were to file a rate case, we would be required to establish that the inclusion of an income tax allowance in our cost of service is just and reasonable. While we have established the Eligible Holder certification requirement, we can provide no assurance that such certification will be effective to establish that our unitholders, or our unitholders’ owners, are subject to United States federal income taxation on the income generated by us. If we are unable to do so, FERC could disallow a substantial portion of our interstate pipelines’ income tax allowances, and the level of the affected facility’s maximum lawful rates could decrease from current levels.

Certain of our transportation services are subject to long-term, fixed-price “negotiated rate” contracts that are not subject to adjustment, even if our cost to perform such services exceeds the revenues received from such contracts.

Under 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 service. For the fiscal year ended December 31, 2006, all of Gulfstream’s firm revenues were derived from such “negotiated rate” contracts and approximately 30% of East Tennessee’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 and East Tennessee’s costs to perform services under these “negotiated rate” contracts will exceed the negotiated rates. If this occurs, it could decrease cash flow from Gulfstream and East Tennessee. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — How We Evaluate Our Operations — Contract Mix.”

Market Hub’s right to charge “market-based rates” at certain 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 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 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 FERC if circumstances change relating to Market Hub’s market power. In the event there were 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 impact 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. 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, 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 impact 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 to you.

Any significant decrease in supplies of natural gas in our areas of operation could adversely affect our business and operating results.

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 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 levels 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 to you.

The failure of LNG import terminals to be successfully developed in the Gulf Coast region or the successful development of LNG import terminals outside our areas of operations could reduce the demand for our services.

Imported LNG is expected to be a significant component of future natural gas supply to the United States. Much of this increase in LNG supplies is expected to be imported through new LNG facilities to be developed over the next decade, and the Gulf Coast region is expected to be the region that will attract a majority of these projects. According to FERC’s Office of Energy Policy, as of February 2007, there were two LNG terminals operating on the Gulf Coast, and 14 out of a total of 15 additional LNG terminals proposed for construction in the Gulf Coast region had been approved. We cannot predict which, if any, of these projects will be constructed. We may not realize expected increases in future natural gas supply available for transportation and storage on our systems due to factors including;


	•	new projects may fail to be developed;

	•	new projects may not be developed at their announced capacity;

	•	development of new projects may be significantly delayed;

	•	new projects may be built in locations that are not connected to our systems; or


	• new projects may not influence sources of supply on our systems.

Similarly, the development of new, or expansion of existing, LNG facilities outside our areas of operations could reduce the need for customers to transport natural gas from the Gulf Coast and Appalachian regions, as well as other supply basins connected to our pipelines. This could reduce the amount of natural gas transported by our pipelines and the demand for our storage facilities.

If the expected increase in natural gas supply from imported LNG is not realized in our areas of operation, the future overall volume of natural gas transported and stored on our systems could decline, which could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions to you.

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 2006 is attributable to firm capacity reservation fees that are set to expire on or prior to December 31, 2010. For Gulfstream, East Tennessee and Market Hub those portions were 0%, 44%, and 66%, 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.

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 to you.

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 to you.

We rely on a limited number of customers for a significant portion of revenues. For the year ended December 31, 2006, the three largest customers for East Tennessee were Atmos Energy Corporation, KGen Partners, and AGL Resources, 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 Northern Indiana Public Service Company, Conectiv, Inc. and Fortis Energy Marketing and Trading. These customers accounted for approximately 41%, 82% and 30% of the operating revenues for East Tennessee, Gulfstream and Market Hub, respectively, for the year ended December 31, 2006. 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 to you, unless we are able to contract for comparable volumes from other customers at favorable rates.

If third-party pipelines and other facilities interconnected to our pipelines and facilities become unavailable to transport natural gas, our revenues and cash available to make distributions to you 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. For example, our East Tennessee pipeline can receive over 950,000 Mcf/d from a major pipeline connection with Spectra Energy’s Texas Eastern pipeline near Hartsville and Mount Pleasant, Tennessee, and can deliver approximately 700,000 Mcf/d to an interconnect with the Transco pipeline near Eden, North Carolina, while the Gulfstream pipeline can deliver approximately 500,000 Mcf/d to two interconnects with Florida Gas Transmission within the Florida peninsula. Similarly, both of the Market Hub storage facilities have interconnections with the Texas Eastern pipeline and many others. 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 our revenues. Any temporary or permanent interruption at any key pipeline interconnect which caused a material reduction in volumes transported on our pipelines or stored at our facilities could have a material adverse effect on our business, results of operations, financial condition and ability to make distributions to you.

Neither Gulfstream nor Market Hub is prohibited from incurring indebtedness, which may affect our ability to make distributions to you.

Neither of Gulfstream or Market Hub is prohibited by the terms of their respective limited liability company agreements from incurring indebtedness. As of the date of this offering, Gulfstream has $850 million in outstanding senior notes, none of which indebtedness is consolidated on our balance sheet. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Investing Activities”. If Gulfstream were to incur significant additional indebtedness, or if Market Hub were to incur significant indebtedness, it could inhibit their respective abilities to make distributions to us. An inability by either of Gulfstream or Market Hub to make distributions to us would materially and adversely affect our ability to make distributions to you because we expect distributions we receive from each of them to represent a substantial portion of the cash we distribute to our unitholders.

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 from operations per unit. We may be unable to complete successful, accretive expansion projects or acquisitions for any of the following reasons:


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

	•	we are unable to obtain necessary rights of way or government approvals;

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

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

Any expansion project or acquisition involves potential risks, including, among other things:


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

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

	•	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 or materials, accidents, weather conditions or an inability to obtain necessary permits;

	•	the assumption of unknown liabilities for which we are not indemnified or for which our indemnity is inadequate;

	•	mistaken assumptions about the overall costs of equity or debt;

	•	the diversion of management’s and employees’ attention from other business concerns;

	•	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 or key employee losses at the acquired business.

If any expansion projects or acquisitions we ultimately complete are not accretive to our distributable cash flow per unit, our ability to make distributions to you may be reduced.

The amount of cash we have available for distribution to holders of our common units and subordinated units depends primarily on our cash flow and not solely on profitability.

You should be aware that the amount of cash we have 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 net losses 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 throughput on our systems and adversely affecting our revenues and cash available to make distributions to you 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 throughput 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 to you.

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. For instance, we may be required to obtain and maintain permits and other approvals issued by various federal, state and local governmental authorities; limit or prevent releases of materials from our operations in accordance with these permits and approvals; install pollution control equipment; and incur potentially substantial liabilities for any pollution or contamination that may result from our operations. 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 impacts of our 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 to you. Please read “Business — Environmental Regulation” for more information.

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 United States Department of Transportation, or 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 impact a high consequence area;

	•	improve data collection, integration and analysis;

	•	repair and remediate the pipeline as necessary; and

	•	implement preventive and mitigating actions.

We currently estimate that we will incur costs of approximately $44.2 million between 2007 and 2012 to implement pipeline integrity management program testing along certain segments of the East Tennessee pipeline and at the Market Hub facilities. These estimates do not include the costs, if any, of repairs, remediation or preventative or mitigating actions that may be determined to be necessary as a result of the testing program, which could be substantial. Additionally, our actual implementation costs may be materially higher than we estimate if the increased industry-wide demand for the associated contractors and service providers causes their rates to materially increase. Should we fail to comply with DOT regulations, we could be subject to penalties and fines. Please read “Business — Safety and Maintenance” for more information.

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 to you.

Our operations are subject to operational hazards and unforeseen interruptions.

Our operations are subject to many hazards inherent in the storage and transportation 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 and Rita, as well as damage from vessels;

	•	risks related to pipeline traversing 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 and 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 and Rita 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 to you.

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

At the closing of this offering, we expect to enter into up to a $500 million credit facility, under which we expect to borrow $50 million in term debt and $125 million in revolving debt. Following this offering, we will continue to have the ability to incur additional debt, subject to limitations in our credit facility. Our level of debt could have important consequences to us, 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 operation, 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 generally.

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 our debt, or seeking additional equity capital. We may not be able to effect any of these actions on satisfactory terms, or at all.

Restrictions in our credit facility may interrupt distributions to us from our subsidiaries, which will limit our ability to make distributions to you 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 the distribution of that cash to us in order to meet our obligations and to allow us to make distributions to our unitholders. The operating and financial restrictions and covenants in our credit agreement and any future financing agreements could restrict our ability to finance future operations or capital needs or to expand or pursue our business activities. For example, we anticipate that our credit agreement will restrict or limit our ability to:


	•	make distributions if any default or event of default occurs;


	•	incur additional indebtedness or guarantee other indebtedness;

	•	grant liens or make certain negative pledges;

	•	make certain loans or investments;


	•	make any material change to the nature of our business, including consolidations, liquidations and dissolutions; or

	•	enter into a merger, consolidation, sale and leaseback transaction or sale of assets.

Furthermore, our credit facility will contain covenants requiring us to maintain certain financial ratios and tests. Our ability to comply with the covenants and restrictions contained in our credit agreement 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 agreement, a significant portion of our indebtedness may become immediately due and payable, our lenders’ commitment to make further loans to us may terminate, and our operating partnership will be prohibited from making any distribution to us and, ultimately, to you. 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. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Requirements.” Any interruption of distributions to us from our subsidiaries may limit our ability to satisfy our obligations and to make distributions to you.

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 and 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 seek 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 such as Standard & Poor’s Ratings Services and Moody’s Investors Service 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 to unitholders.

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 impact our results of operations.

The long-term impact 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 United States government has issued warnings that energy assets, including our nation’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 to our business. 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.

If we fail to develop or maintain an effective system of internal controls, we may not be able to report our financial results accurately, or prevent fraud which could have an adverse effect on our business and would likely have a negative effect on the trading price of our common units.

Prior to this offering, our subsidiaries and equity investees were wholly- or partially-owned by Spectra Energy and we have not previously filed reports with the SEC. We will become subject to the public reporting requirements of the Securities Exchange Act of 1934 upon the completion of this offering. We produce our combined financial statements in accordance with the requirements of GAAP, but our internal accounting controls may not currently meet all standards applicable to companies with publicly traded securities. Effective internal controls are necessary for us to provide reliable financial reports to prevent fraud and to operate successfully as a publicly traded partnership. Our efforts to develop and maintain our internal controls may not be successful, and we may be unable to maintain adequate controls over our financial processes and reporting in the future, including compliance with the obligations under Section 404 of the Sarbanes-Oxley Act of 2002, which we refer to as Section 404. For example, Section 404 will require us, among other things, annually to review and report on, and our independent registered public accounting firm annually to attest to, our internal control over financial reporting. Any failure to develop or maintain effective controls, or difficulties encountered in their implementation or other effective improvement of our internal controls could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls subject us to regulatory scrutiny and a loss of confidence in our reported financial information, which could have an adverse effect on our business and would likely have a negative effect on the trading price of our common units.

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 your detriment.

Following this offering, Spectra Energy will own and control 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 us 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. Please read “— 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. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions”;


	•	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;

	•	our general partner determines the amount and timing of asset purchases and sales, borrowings, issuance 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 its 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.

Please read “Conflicts of Interest and Fiduciary Duties.”

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 our 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 will prohibit 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 impact our results of operations and cash available for distribution. Please read “Conflicts of Interest and Fiduciary Duties.”

If you are not an Eligible Holder, you will not be entitled to receive distributions or allocations of income or loss on your common units and your common units will be subject to redemption.

In order to comply with certain FERC rate-making policies applicable to entities that pass through their 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. Please see “Description of the Common Units — Transfer of Common Units.” If you are not a person who fits the requirements to be an Eligible Holder, you will not receive distributions or allocations of income and loss on your units and you run the risk of having your units redeemed by us at the lower of your 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 to you.

Pursuant to an omnibus agreement we will enter into with Spectra Energy, our general partner and certain of their affiliates upon the closing of this offering, 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 to us, 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 to unitholders. Please read “Certain Relationships and Related Party Transactions — Omnibus Agreement.” In addition, under Delaware partnership law, our general partner has unlimited liability for our obligations, such as our debts and environmental liabilities, except for our 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 cash otherwise available for distribution to our unitholders.

Our partnership agreement limits our general partner’s fiduciary duties to holders of our common units and subordinated units and restricts the remedies available to holders of our common units 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. Examples include the exercise of its limited call right, the exercise of its rights to transfer or vote the units it owns, the exercise of its registration rights and its determination whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement;

	•	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 and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us;

	•	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 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.

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. Please read “Conflicts of Interest and Fiduciary Duties — Fiduciary Duties.”

Our general partner may elect to cause us to issue Class B units to it in connection with a resetting of the target distribution levels related to our general partner’s incentive distribution rights without the approval of the conflicts committee of our 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.

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. Please read “Provisions of Our Partnership Agreement Related to Cash Distributions — General Partner Interest and 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 its 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 our general partner, they will have little ability to remove our 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 our general partner and its affiliates will own sufficient units upon completion of this offering 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 the general partner. Following the closing of this offering, our general partner and its affiliates will own 81.3% of our aggregate outstanding common and subordinated 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 our 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 our general partner’s performance in managing our partnership 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 our operations and own our operating assets, which may affect our ability to make distributions to you.

We are a partnership holding company and our operating subsidiaries conduct all of our operations and own all of our 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 our 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 FERC policies.

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 our 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.

You will experience immediate and substantial dilution of $6.43 in tangible net book value per common unit.

The estimated initial public offering price of $20.00 per unit exceeds our pro forma net tangible book value of $13.57 per unit. Based on the initial public offering price of $20.00 per unit, you will incur immediate and substantial dilution of $6.43 per common unit. This dilution results primarily because the assets contributed by our general partner and its affiliates are recorded at their historical cost, and not their fair value, in accordance with GAAP. Please read “Dilution.”

Increases in interest rates could adversely impact 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. If the overall economy strengthens, it is possible that monetary policy will tighten, resulting in higher interest rates to counter possible inflation risk. 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 impacted by the level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank related yield-oriented securities for investment decision-making purposes. 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 impact on our unit price and our ability to issue additional equity to make acquisitions, to incur debt or for other purposes.

We may issue additional units without your approval, which would dilute your existing 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. In addition, our partnership agreement does not prohibit the issuance by our subsidiaries of equity securities which may effectively rank senior to the common units. 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 impact on the trading price of the common units.

After the sale of the common units offered hereby, Spectra Energy and its affiliates will hold an aggregate of 29,812,011 common units and 20,030,066 subordinated units. All of the subordinated units will convert into common units at the end of the subordination period, which could occur as early as the first business day after June 30, 2010, and all of the subordinated units may convert into common units by June 30, 2008 if additional tests are satisfied. The sale of any of these units in the public or private markets could have an adverse impact 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 you to sell your 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-current market price. As a result, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your units. At the completion of this offering and assuming no exercise of the underwriters’ option to purchase additional common units, our general partner and its affiliates will own approximately 72.2% of our outstanding common units. At the end of the subordination period, assuming no additional issuances of common units, our general partner and its affiliates will own approximately 81.3% of our aggregate outstanding units. For additional information about this right, please read “The Partnership Agreement — Limited Call Right.”

Your 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. Our partnership is 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 other states in which we do business. You could be liable for any and all of our obligations as if you 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

	•	your 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 constitute “control” of our business.

For a discussion of the implications of the limitations of liability on a unitholder, please read “The Partnership Agreement — Limited Liability.”

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 you 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.

There is no existing market for our common units, and a trading market that will provide you with adequate liquidity may not develop. The price of our common units may fluctuate significantly, and you could lose all or part of your investment.

Prior to the offering, there has been no public market for the common units. After the offering, there will be only 11,500,000 publicly traded common units, assuming no exercise of the underwriters’ option to purchase additional units. We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. You may not be able to resell your common units at or above the initial public offering price. Additionally, the lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the common units and limit the number of investors who are able to buy the common units.

The initial public offering price for the common units will be determined by negotiations between us and the representatives of the underwriters and may not be indicative of the market price of the common units that will prevail in the trading market. The market price of our common units may decline below the initial public offering price. The market price of our common units may also be influenced by many factors, some of which are beyond our control, including:


	•	our quarterly distributions;

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

	•	loss of a large customer;

	•	regulatory action on our rates or the services we provide;

	•	the adoption of new laws or regulations affecting us or adverse interpretation and application of existing laws or regulations affecting us;

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

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

	•	general economic conditions;

	•	the failure of securities analysts to cover our common units after this offering or changes in financial estimates by analysts;

	•	future sales of our common units; and

	•	other factors described in these “Risk Factors.”

We will incur increased costs as a result of being a publicly-traded partnership.

We have no history operating as a publicly-traded partnership. As a publicly-traded partnership, we will incur significant legal, accounting and other expenses. In addition, the Sarbanes-Oxley Act of 2002, as well as new rules subsequently implemented by the SEC and the New York Stock Exchange, have required changes in corporate governance practices of publicly-traded entities. We expect these new rules and regulations to increase our legal and financial compliance costs and to make activities more time-consuming and costly. For example, as a result of becoming a publicly-traded partnership, we are required to have at least three independent directors, create additional board committees and adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal controls over financial reporting. In addition, we will incur additional costs associated with our publicly-traded company reporting requirements. We also expect these new rules and regulations to make it more difficult and more expensive for our general partner to obtain director and officer liability insurance and it may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. As a result, it may be more difficult for our general partner to attract and retain

qualified persons to serve on its board of directors or as executive officers. We will incur approximately $5.5 million of estimated incremental costs associated with being a publicly-traded partnership for purposes of our Statement of Minimum Estimated Cash Available for Distribution included elsewhere in this prospectus; however, it is possible that our actual incremental costs of being a publicly-traded partnership will be higher than we currently estimate.

Tax Risks to Common Unitholders

In addition to reading the following risk factors, you should read “Material Tax Consequences” for a more complete discussion of the expected material federal income tax consequences of owning and disposing of common units.

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service 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 to our unitholders.

The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the Internal Revenue Service, which we refer to as 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 to you would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you 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 the unitholders, 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. We will, for example, be subject to a new entity-level tax on the portion of our income that is generated in Texas. Specifically, the Texas margin tax will be imposed at a maximum effective rate of 0.7% of our gross income apportioned to Texas. The imposition of such a tax on us by Texas, or any other state, will reduce the cash available for distribution to you.

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 impact of that law on us.

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 to our unitholders.

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 affecting us. The IRS may adopt positions that differ from the conclusions of our counsel expressed in this prospectus or from the positions we take. 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 counsel’s conclusions or positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.

You may be required to pay taxes on your share of our income even if you do not receive any cash distributions from us.

Because our unitholders will be treated as partners to whom we will allocate taxable income which could be different in amount than the cash we distribute, you will be required to pay any federal income taxes and, in some cases, state and local income taxes on your share of our taxable income even if you receive no cash distributions from us. You may not receive cash distributions from us equal to your share of our 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 you sell your common units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those common units. Because distributions in excess of your allocable share of our net taxable income decrease your tax basis in your common units, the amount, if any, of such prior excess distributions with respect to the common units you sell will, in effect, become taxable income to you if you sell such common units at a price greater than your tax basis, even if the price you receive is less than your 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 your share of our nonrecourse liabilities, if you sell your units, you may incur a tax liability in excess of the amount of cash you receive from the sale. Please read “Material Tax Consequences — Disposition of Common Units — Recognition of Gain or Loss” for a further discussion of the foregoing.

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 (known as 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 you are a tax-exempt entity or a foreign person, you should consult your 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 you. It also could affect the timing of these tax benefits or the amount of gain from your sale of our common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns. For a further discussion of the effect of the depreciation and amortization positions we will adopt, please read “Material Tax Consequences — Tax Consequences of Unit Ownership — Section 754 Election.”

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 our partnership for federal income tax purposes.

We will be considered to have terminated our 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 our taxable year for all unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable

income. Please read “Material Tax Consequences — Disposition of Common Units — Constructive Termination” for a discussion of the consequences of our termination for federal income tax purposes.

You will likely be subject to state and local taxes and return filing requirements in states where you do not live as a result of investing in our common units.

In addition to federal income taxes, you 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 you do not live in any of those jurisdictions. You 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, you may be subject to penalties for failure to comply with those requirements. We will initially own assets and do business in the States of 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 your 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.

USE OF PROCEEDS

We expect to receive net proceeds from this offering of approximately $215.6 million (based on an assumed initial public offering price of $20.00 per common unit) after deducting underwriting discounts but before paying expenses associated with the offering and related formation transactions. We anticipate using the aggregate net proceeds of this offering to:


	•	purchase $50.0 million of United States Treasury and other qualifying securities, which will be assigned as collateral to secure the term loan portion of our credit facility;

	•	pay approximately $6.9 million of expenses associated with the offering and related formation transactions;

	•	distribute approximately $150.0 million in cash to subsidiaries of Spectra Energy as reimbursement for capital expenditures incurred by subsidiaries of Spectra Energy prior to this offering related to the assets to be contributed to us upon the closing of this offering, which distribution will be made in partial consideration of the assets contributed to us upon the closing of this offering; and

	•	use the remaining proceeds of approximately $8.7 million to fund working capital.

We will enter into a new $500 million credit facility in connection with the closing of this offering, under which we expect to borrow approximately $50 million in term debt and approximately $125 million in revolving debt. We will distribute the aggregate amount of the proceeds of such borrowings to subsidiaries of Spectra Energy, which distribution will be made in partial consideration of the assets contributed to us upon the closing of this offering. Please see “Certain Relationships and Related Party Transactions — Distributions and Payments to our General Partner and its Affiliates.”

The United States Treasury and other qualifying securities we will purchase will be assigned as collateral to secure the term loan borrowings. The interest we receive from our ownership of these United States Treasury and other qualifying securities will partially offset our cost of borrowings under the term loan facility. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Requirements — Description of Credit Agreement.”

If the underwriters’ option to purchase additional common units is exercised in full, we will (1) use the net proceeds of $32.3 million from the sale of these additional securities to purchase an equivalent amount of United States Treasury and other qualifying securities and (2) borrow an additional amount of term debt equal to the net proceeds to be received from the exercise of the underwriters’ option. The United States Treasury and other qualifying securities purchased will be assigned as collateral to secure such additional term loan borrowings. The proceeds of the additional term loan borrowings will be used to redeem from a subsidiary of Spectra Energy a number of common units equal to the number of common units issued upon exercise of the underwriters’ option, at a price per common unit equal to the proceeds per common unit before expenses but after underwriting discounts and a structuring fee.

CAPITALIZATION

The following table shows:


	•	our cash and long-term investments and capitalization as of December 31, 2006; and

	•	our pro forma cash and long-term investments and capitalization as of December 31, 2006, as adjusted to reflect this offering, the other transactions described under “Summary — Formation Transactions and Partnership Structure — General” and the application of the net proceeds from this offering as described under “Use of Proceeds.”

We derived this table from, and it should be read in conjunction with and is qualified in its entirety by reference to, our historical and pro forma financial statements and the accompanying notes included elsewhere in this prospectus. You should also read this table in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” This table does not reflect any indebtedness associated with our equity investment in Gulfstream, which amount is included in the historical financial statements and the accompanying notes of Gulfstream included elsewhere in this prospectus.


	As of December 31, 2006
	Historical		Pro Forma
	(In thousands)

Cash	$	—	$	8,693
Long-term investments		—		50,000

Total cash and long-term investments	$	—	$	58,693

Long-term debt:
Revolving borrowings	$	—	$	125,000
Term borrowings		—		50,000
East Tennessee		150,000		150,000

Total long-term debt	$	150,000	$	325,000

Partners’ capital/parent net investment:
Net parent equity	$	985,333	$	—
Common units — public		—		209,693
Common units — sponsor		—		439,890
Subordinated units — sponsor		—		295,553
General partner interest		—		18,472

Total partners’ capital/parent net investment		985,333		963,608

Total capitalization	$	1,135,333	$	1,288,608

DILUTION

Dilution is the amount by which the offering price paid by the purchasers of common units sold in this offering will exceed the pro forma net tangible book value per unit after the offering. Assuming an initial public offering price of $20.00 per common unit, on a pro forma basis as of December 31, 2006, after giving effect to the offering of common units and the application of the related net proceeds, our net tangible book value was $849.1 million, or $13.57 per common unit. Net tangible book value excludes $118.3 million of goodwill. Purchasers of common units in this offering will experience substantial and immediate dilution in net tangible book value per common unit for financial accounting purposes, as illustrated in the following table:


Assumed initial public offering price per common unit				$	20.00
Net tangible book value per common unit before the offering(a)	$	17.04
Decrease in net tangible book value per common unit attributable to purchasers in the offering		(3.47	)

Less: Pro forma net tangible book value per common unit after the offering(b)					13.57

Immediate dilution in tangible net book value per common unit to purchasers in the offering				$	(6.43	)


(a)		Determined by dividing the number of units and general partner units (29,812,011 common units, 20,030,066 subordinated units and 1,251,879 general partner units) to be issued to a subsidiary of Spectra Energy for its contribution of assets and liabilities to Spectra Energy Partners, LP into the net tangible book value of the contributed assets and liabilities.

(b)		Determined by dividing the total number of units and general partner units to be outstanding after the offering (41,312,011 common units, 20,030,066 subordinated units and 1,251,879 general partner units) and the application of the related net proceeds into our pro forma net tangible book value, after giving effect to the application of the expected net proceeds of the offering.

The following table sets forth the number of units that we will issue and the total consideration contributed to us by our general partner and its affiliates and by the purchasers of common units in this offering:


	Units Acquired					Total Consideration
	Number		Percent			Amount		Percent
						(In thousands)

General partner and affiliates(a)(b)		51,093,956		81.6	%	$	753,915		76.6	%
New investors		11,500,000		18.4	%		230,000		23.4	%

Total		62,593,956		100.0	%	$	983,915		100.0	%


(a)		The common and subordinated units and general partner units acquired by our general partner and its affiliates consist of 29,812,011 common units and 20,030,066 subordinated units and 1,251,879 general partner units.

(b)		The assets contributed by our general partner and its affiliates were recorded at historical cost in accordance with GAAP. Book value of the consideration provided by our general partner and its affiliates,

OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

You should read the following discussion of our cash distribution policy in conjunction with specific assumptions included in this section. For more detailed information regarding the factors and assumptions upon which our cash distribution policy is based, please read “Assumptions and Considerations” below. In addition, you should read “Forward-Looking Statements” and “Risk Factors” for information regarding statements that do not relate strictly to historical or current facts and certain risks inherent in our business.

For additional information regarding our historical and pro forma operating results, you should refer to our historical combined financial statements for the years ended December 31, 2004, 2005 and 2006, and our unaudited pro forma condensed combined financial statements for the year ended December 31, 2006 included elsewhere in this prospectus.

General

Rationale for Our Cash Distribution Policy. Our cash distribution policy reflects a basic judgment that our unitholders will be better served by our distributing our cash available after expenses and reserves rather than retaining it. Because we believe we will generally finance any capital investments from external financing sources, we believe that our investors are best served by our distributing all of our available cash. Because we are not subject to an entity-level federal income tax, we have more cash to distribute to you than would be the case were we subject to tax. Our cash distribution policy is consistent with the terms of our partnership agreement, which requires that we distribute all of our available cash quarterly.

Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy. There is no guarantee that unitholders will receive quarterly distributions from us. Our distribution policy may be changed at any time and is subject to certain restrictions, including:


	•	Our cash distribution policy is subject to restrictions on distributions under our new credit facility. Specifically, the agreement related to our credit facility contains material financial tests and covenants that we must satisfy. These financial tests and covenants are described in this prospectus under the caption “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Requirements — Description of Credit Agreement.” Should we be unable to satisfy these restrictions under our credit facility or if we are otherwise in default under our credit facility, we would be prohibited from making cash distributions to you notwithstanding our stated cash distribution policy.

	•	Our board of directors will have the authority to establish reserves for the prudent conduct of our business and for future cash distributions to our unitholders, and the establishment of those reserves could result in a reduction in cash distributions to you from the levels we currently anticipate pursuant to our stated distribution policy.

	•	While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including provisions requiring us to make cash distributions contained therein, may be amended. Although during the subordination period, with certain exceptions, our partnership agreement may not be amended without the approval of the public common unitholders, our partnership agreement can be amended with the approval of a majority of the outstanding common units and any Class B units issued upon the reset of incentive distribution rights, if any, voting as a class (including common units held by affiliates of Spectra Energy) after the subordination period has ended. At the closing of this offering, a subsidiary of Spectra Energy will own our general partner and approximately 81.3% of our outstanding common units and subordinated units.

	•	Even if our cash distribution policy is not modified or revoked, the amount of distributions we pay under our cash distribution policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement.


	•	Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets.

	•	We may lack sufficient cash to pay distributions to our unitholders due to increases in our operating or general and administrative expenses, principal and interest payments on our outstanding debt, tax expenses, working capital requirements and anticipated cash needs.

	•	We own a 24.5% interest in Gulfstream, a subsidiary of Spectra Energy owns a 25.5% interest and a subsidiary of The Williams Companies owns the remaining 50.0% interest. Gulfstream is required by the terms of its limited liability company agreement to make quarterly cash 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 Gulfstream’s 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. The management committee representative of Spectra Energy and The Williams Companies will jointly make the determinations related to Gulfstream’s available cash. The limited liability company agreement of Gulfstream may not be amended without the approval of Spectra Energy, The Williams Companies and us. Please read “Certain Relationships and Related Party Transactions — Contracts with Affiliates — Gulfstream Limited Liability Company Agreement.”

	•	We own a 50.0% interest in Market Hub and a subsidiary of Spectra Energy owns the other 50.0% interest. Market Hub is required by the terms of its limited liability company agreement to make quarterly cash 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 appropriate by the Market Hub management committee for the operation of Market Hub’s 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. The management committee representative of Spectra Energy and us will jointly make the determinations related to Market Hub’s available cash. The limited liability company agreement of Market Hub may not be amended without the approval of Spectra Energy and us. Please read “Certain Relationships and Related Party Transactions — Contracts with Affiliates — Market Hub Limited Liability Company Agreement.”

Our Ability to Grow is Dependent on Our Ability to Access External Expansion Capital. We will distribute all of our available cash to our unitholders on a quarterly basis. As a result, we expect that we will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. To the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow. In addition, because we distribute all of our available cash, our growth may not be as fast as businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level, which in turn may impact the available cash that we have to distribute on each unit. There are no limitations in our partnership agreement or our credit facility on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which in turn may impact the available cash that we have to distribute to our unitholders.

Our Initial Distribution Rate

Upon completion of this offering, the board of directors of our general partner will adopt a policy pursuant to which we will declare an initial quarterly distribution of $0.325 per unit per complete quarter, or $1.30 per unit per year, to be paid no later than 45 days after the end of each fiscal quarter (beginning with

the quarter ending September 30, 2007) through the quarter ending June 30, 2008. This equates to an aggregate cash distribution of $20.3 million per quarter or $81.4 million per year, in each case based on the number of common units, subordinated units and general partner units outstanding immediately after completion of this offering. If the underwriters’ option to purchase additional common units is exercised, an equivalent number of common units will be redeemed. Accordingly, the exercise of the underwriters’ option will not affect the total amount of units outstanding or the amount of cash needed to pay the initial distribution rate on all units. Our ability to make cash distributions at the initial distribution rate pursuant to this policy will be subject to the factors described above under the caption “— Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy.”

The table below sets forth the assumed number of outstanding common units, subordinated units and general partner units upon the closing of this offering and the aggregate distribution amounts payable on such units during the year following the closing of this offering at our initial distribution rate of $0.325 per common unit per quarter ($1.30 per common unit on an annualized basis).


			Distributions
	Number of Units		One Quarter		Four Quarters

Publicly held common units		11,500,000	$	3,737,500	$	14,950,000
Common units held by Spectra Energy		29,812,011		9,688,904		38,755,614
Subordinated units held by Spectra Energy		20,030,066		6,509,771		26,039,086
General partner units held by Spectra Energy		1,251,879		406,861		1,627,443

Total		62,593,956	$	20,343,036	$	81,372,143

As of the date of this offering, our general partner will be entitled to 2% of all distributions that we make prior to our liquidation. The general partner’s initial 2% interest in these distributions may be reduced if we issue additional units in the future and our general partner does not elect to contribute a proportionate amount of capital to us to maintain its initial 2% general partner interest.

The subordination period will generally end if we have earned and paid at least $1.30 (the minimum quarterly distribution on an annualized basis) on each outstanding limited partner unit and general partner unit for any three consecutive, non-overlapping four-quarter periods ending on or after June 30, 2010. Alternatively, if we have earned and paid at least $0.4875 per quarter (150% of the minimum quarterly distribution, which is $1.95 on an annualized basis) on each outstanding limited partner unit and general partner unit for any four-quarter periods ending on or after June 30, 2008, the subordination period will terminate automatically. In addition, the subordination period will end if our general partner is removed without cause and the units held by our general partner and its affiliates are not voted in favor of such removal. When the subordination period ends, all remaining subordinated units will convert into an equal number of common units, and the common units will no longer be entitled to arrearages.

If distributions on our common units are not paid with respect to any fiscal quarter at the initial distribution rate, our unitholders will not be entitled to receive such payments in the future except that during the subordination period, to the extent we have available cash in any future quarter in excess of the amount necessary to make cash distributions to holders of our common units at the initial distribution rate, we will use this excess available cash to pay these deficiencies related to prior quarters before any cash distribution is made to holders of subordinated units. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions — Subordination Period.”

We do not have a legal obligation to pay distributions at our initial distribution rate or at any other rate except as provided in our partnership agreement. Our distribution policy is consistent with the terms of our partnership agreement, which requires that we distribute all of our available cash quarterly. Under our partnership agreement, available cash is defined to generally mean, for each fiscal quarter, cash generated from our business in excess of the amount of reserves our general partner determines is necessary or appropriate to provide for the conduct of our business, to comply with applicable law, any of our debt instruments or other agreements or to provide for future distributions to our unitholders for any one or more of the upcoming four quarters.

Our partnership agreement provides that any determination made by our general partner in its capacity as our general partner must be made in good faith and that any such determination will not be subject to any other standard imposed by our partnership agreement, the Delaware limited partnership statute or any other law, rule or regulation or at equity. Holders of our common units may pursue judicial action to enforce provisions of our partnership agreement, including those related to requirements to make cash distributions as described above; however, our partnership agreement provides that our general partner is entitled to make the determinations described above without regard to any standard other than the requirements to act in good faith. Our partnership agreement provides that, in order for a determination by our general partner to be made in “good faith,” our general partner must believe that the determination is in our best interests. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions.”

Our cash distribution policy, as expressed in our partnership agreement, may not be modified or repealed without amending our partnership agreement; however, the actual amount of our cash distributions for any quarter is subject to fluctuations based on the amount of cash we generate from our business and the amount of reserves our general partner establishes in accordance with our partnership agreement as described above. Our partnership agreement may be amended with the approval of our general partner and holders of a majority of our outstanding common units and any Class B units issued upon the reset of the incentive distribution rights, voting together as a class.

We will pay our distributions on or about the 15th day of each of February, May, August and November to holders of record on or about the 1st day of each such month. If the distribution date does not fall on a business day, we will make the distribution on the business day immediately preceding the indicated distribution date. We will adjust the quarterly distribution for the period from the closing of this offering through September 30, 2007 based on the actual length of the period.

In the sections that follow, we present in detail the basis for our belief that we will be able to fully fund our initial distribution rate of $0.325 per unit each quarter through the quarter ending June 30, 2008. In those sections, we present two tables, consisting of:


	•	“Unaudited Pro Forma Cash Available for Distribution,” in which we present the amount of cash we would have had available for distribution for our fiscal year ended December 31, 2006 derived from our unaudited pro forma financial statements that are included in this prospectus, which unaudited pro forma financial statements are based on the audited historical combined financial statements of Spectra Energy Partners Predecessor for the year ended December 31, 2006, as adjusted to give pro forma effect to:


	—	the transactions to be completed as of the closing of this offering, including our incurrence of approximately $50 million of term borrowings and $125 million of revolving borrowings under our new $500 million credit facility; and

	—	this offering and the application of the net proceeds as described under “Use of Proceeds.”


	•	“Statement of Minimum Estimated Cash Available for Distribution,” in which we demonstrate our anticipated ability to generate the minimum estimated cash available for distribution necessary for us to pay distributions at the initial distribution rate on all units for the twelve months ending June 30, 2008.

Unaudited Pro Forma Cash Available for Distribution for the Year Ended December 31, 2006

If we had completed the transactions contemplated in this prospectus on January 1, 2006, pro forma cash available for distribution for the year ended December 31, 2006 would have been approximately $67.3 million. This amount would have been sufficient to make a cash distribution for 2006 at the initial rate of $0.325 per unit per quarter (or $1.30 per unit on an annualized basis) on all of the common units but only 47% of the subordinated units.

Unaudited pro forma cash available for distribution from operating surplus includes incremental general and administrative expense we will incur as a result of being a publicly traded limited partnership, including

compensation and benefit expenses of our executive management personnel, costs associated with annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, independent auditor fees, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs and director compensation. We expect our incremental general and administrative expense of being a publicly-traded partnership to total approximately $5.5 million per year. Our incremental general and administrative expense is not reflected in our historical or pro forma net income for 2006. Corporate general and administrative costs that would have been allocated to us by Spectra Energy’s predecessor company totaled $2.7 million in 2006 and are already reflected in our historical results for 2006.

The following table illustrates, on a pro forma basis, for the year ended December 31, 2006 the amount of available cash that would have been available for distributions to our unitholders, assuming in each case that this offering had been consummated at the beginning of such period. Each of the pro forma adjustments presented below is explained in the footnotes to such adjustments.

We based the pro forma adjustments upon currently available information and specific estimates and assumptions. The pro forma amounts below do not purport to present our results of operations had the transactions contemplated in this prospectus actually been completed as of the dates indicated. In addition, cash available to pay distributions is primarily a cash accounting concept, while our pro forma financial statements have been prepared on an accrual basis. As a result, you should view the amount of pro forma cash available for distribution only as a general indication of the amount of cash available to pay distributions that we might have generated had we been formed in earlier periods.

SPECTRA ENERGY PARTNERS, LP

UNAUDITED PRO FORMA CASH AVAILABLE FOR DISTRIBUTION


	Year Ended
	December 31, 2006
	(In thousands, except
	per unit data)

Pro Forma Net Income(a)	$	64,071
Add:
Interest expense (income), net(b)		15,976
Income tax expense(b)		453
Depreciation and amortization(b)		18,986
Less:
Equity in earnings of Gulfstream(c)		16,763
Equity in earnings of Market Hub(c)		24,342
Other income (expense), net(b)		1,780

Pro forma Adjusted EBITDA(d)	$	56,601

Add:
Pro forma cash available for distribution from Gulfstream(e)		23,800
Pro forma cash available for distribution from Market Hub(f)		19,500
Less:
Incremental general and administrative expense of being a public company(g)		5,500
Pro forma net cash paid for interest expense(h)		16,216
Maintenance capital expenditures(i)		10,933

Pro forma cash available for distribution	$	67,252

Pro forma cash distributions:
Distributions per unit(j)	$	1.30
Distributions to public common unitholders(j)		14,950
Distributions to Spectra Energy(j)		66,422

Total distributions(j)	$	81,372

Excess (shortfall)	$	(14,120	)


(a)		Reflects net income of Spectra Energy Partners Predecessor derived from its historical combined financial statements for the periods indicated giving pro forma effect to the offering and the related transactions.

(b)		Reflects adjustments to reconcile pro forma net income to pro forma Adjusted EBITDA.

(c)		Reflects an adjustment to our Adjusted EBITDA for the elimination of Gulfstream and Market Hub’s equity earnings.

(d)		Our Adjusted EBITDA is defined as net income plus interest, income taxes, depreciation and amortization less our equity earnings in Gulfstream and Market Hub and other income (expenses), net, which primarily consists of a non-cash allowance for funds used during construction, or AFUDC, and certain other items such as insurance recoveries. We have provided Adjusted EBITDA in this prospectus because we believe it provides investors with additional information to measure our financial performance and liquidity. 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 different companies in our industry, our definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies. Adjusted EBITDA has important limitations as an analytical tool, and you should not consider it in isolation, or as a substitute for analysis of our results as reported under GAAP. Please read “Summary — Summary Historical and Pro Forma Financial and Operating Data — Non-GAAP Financial Measures.”

(e)		Pro forma cash available for distribution from Gulfstream for the year ended December 31, 2006 is calculated as follows:


	Year Ended
Gulfstream	December 31, 2006
	(In thousands)

Net income	$	68,422
Add:
Interest expense		48,787
Depreciation and amortization		30,406
Less:
Other income (expenses), net		431

Adjusted EBITDA	$	147,184

Less:
Net cash paid for interest expense		49,423
Maintenance capital expenditures		617

Pro forma cash available for distribution — 100%	$	97,144

Pro forma cash available for distribution — our 24.5%	$	23,800


(f)		Pro forma cash available for distribution from Market Hub for the year ended December 31, 2006 is calculated as follows:


	Year Ended
Market Hub	December 31, 2006
	(In thousands)

Net income	$	48,684
Add:
Interest expense		2,625
Depreciation and amortization		7,815
Less:
Other income (expenses), net		10,553

Adjusted EBITDA	$	48,571

Less:
Net cash paid for interest expense		43
Maintenance capital expenditures		9,528

Pro forma cash available for distribution — 100%	$	39,000

Pro forma cash available for distribution — our 50.0%	$	19,500


(g)		Reflects an adjustment to our adjusted EBITDA for an estimated incremental cash expense associated with being a publicly traded limited partnership, including compensation and benefit expenses of our executive management personnel, costs associated with annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, independent auditor fees, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs and director compensation.

(h)		Reflects on a net basis the interest expense related to borrowings under our credit facility made in connection with this offering and the interest income related to the long-term investments we intend to purchase with a portion of the proceeds from this offering.

		In connection with the closing of this offering, we will enter into a $500 million credit agreement under which we expect to borrow $50 million in term debt and $125 million in revolving debt. We expect that the credit agreement will prohibit us from making distributions of available cash to unitholders in any default or event of default (as defined in the credit agreement) exists. In addition, we expect the credit agreement will contain other various covenants. If an event of default exists under the credit agreement, we expect that the lenders will be able to accelerate the maturity of the credit agreement and exercise other rights and remedies. The credit agreement is subject to a number of conditions, including the negotiation, execution and delivery of definitive documentation.

(i)		Maintenance capital expenditures are capital expenditures made to replace partially or fully depreciated assets, to maintain the existing operating capacity of our assets and to extend their useful lives, or other capital expenditures that are incurred in maintaining existing system volumes and related cash flows.

		In addition, we made expansion capital expenditures of $75.0 million for the year ended December 31, 2006. Expansion capital expenditures are made to acquire additional assets to grow our business, to expand and upgrade our systems and facilities and to construct or acquire similar systems or facilities. These expenditures were assumed to be funded by cash contributions from our parent, Spectra Energy, and are not included in our pro forma cash available for distribution calculation.

(j)		The table below sets forth the assumed number of outstanding common units, subordinated units and general partner units upon the closing of this offering and the estimated per unit and aggregate distribution amounts payable on our common units, subordinated units and general partner units for four quarters at our initial distribution rate of $0.325 per common unit per quarter ($1.30 per common unit on an annualized basis).


			Distribution for
	Number of		Four Quarters
	Units		Per Unit		Aggregate

Pro forma distributions on publicly held common units		11,500,000	$	1.30	$	14,950,000
Pro forma distributions on common units held by Spectra Energy		29,812,011		1.30		38,755,614
Pro forma distribution on subordinated units held by Spectra Energy		20,030,066		1.30		26,039,086
Pro forma distribution on general partner units		1,251,879		1.30		1,627,443

Total		62,593,956	$	1.30	$	81,372,143

Minimum Estimated Cash Available for Distribution for the Twelve-Month Period Ending June 30, 2008

Set forth below is a Statement of Minimum Estimated Cash Available for Distribution that reflects our ability to generate sufficient cash flows to make the minimum quarterly distribution on all of our outstanding units for the twelve months ending June 30, 2008, based on assumptions we believe to be reasonable. These assumptions include adjustments to reflect this offering, the other transactions described under “Summary — Formation Transactions and Partnership Structure — General” and the application of the net proceeds from this offering as described under “Use of Proceeds.” Cash available for distribution is defined as net income plus interest expense, income taxes and depreciation and amortization, less our equity earnings in Gulfstream and Market Hub and plus distributions received from Gulfstream and Market Hub and other income, net, which primarily consists of non-cash AFUDC and certain other items such as insurance recoveries.

Our minimum estimated cash available for distribution reflects our judgment as of the date of this prospectus of conditions we expect to exist and the course of action we expect to take during the twelve months ending June 30, 2008. The assumptions disclosed below under “Assumptions and Considerations” are those that we believe are significant to our ability to generate our minimum estimated cash available for distribution. We believe our actual results of operations and cash flows will be sufficient to generate our minimum estimated cash available for distribution; however, we can give you no assurance that our minimum estimated cash available for distribution will be achieved. There will likely be differences between our minimum estimated cash available for distribution and our actual results and those differences could be material. If we fail to generate the minimum estimated cash available for distribution, we may not be able to pay cash distributions on our common units at the initial distribution rate stated in our cash distribution policy. In order to fund distributions to our unitholders at our initial rate of $1.30 per common unit for the twelve months ending June 30, 2008, our Adjusted EBITDA for the twelve months ending June 30, 2008 must be at least $54.7 million and our cash distributions from Gulfstream and Market Hub must be at least $56.7 million in the aggregate. As set forth in the table below and as further explained under “— Assumptions & Considerations,” we believe our operations will produce minimum estimated cash available for distribution of $81.4 million for the twelve months ending June 30, 2008.

We do not as a matter of course make public projections as to future operations, earnings, or other results. However, management has prepared the minimum estimated cash available for distribution and assumptions set forth below to substantiate our belief that we will have sufficient cash available to make the minimum quarterly distribution to our unitholders for twelve months ending June 30, 2008. The accompanying prospective financial information was not prepared with a view toward complying with the guidelines established by the American Institute of Certified Public Accountants with respect to prospective financial information, but, in the view of our management, was prepared on a reasonable basis, reflects the best currently available estimates and judgments, and presents, to the best of management’s knowledge and belief, the assumptions on which we base our belief that we can generate the minimum estimated cash available for distribution necessary for us to have sufficient cash available for distribution to pay the minimum quarterly distribution to all of our unitholders. However, this information is not fact and should

not be relied upon as being necessarily indicative of future results, and readers of this prospectus are cautioned not to place undue reliance on the prospective financial information.

Neither our independent auditors, nor any other independent accountants, have compiled, examined, or performed any procedures with respect to the prospective financial information contained herein, nor have they expressed any opinion or any other form of assurance on such information or its achievability, and assume no responsibility for, and disclaim any association with, the prospective financial information.

When considering our minimum estimated cash available for distribution you should keep in mind the risk factors and other cautionary statements under “Risk Factors.” Any of the risks discussed in this prospectus could cause our actual results of operations to vary significantly from those supporting our minimum estimated available cash.

We are providing our minimum estimated cash available for distribution and related assumptions to supplement our pro forma and historical financial statements in support of our belief that we will have sufficient available cash to allow us to pay cash distributions on all of our outstanding common and subordinated units for each quarter in the twelve month period ending June 30, 2008 at our stated initial distribution rate. Please read below under “Assumptions and Considerations” for further information as to the assumptions we have made for the preparation of our minimum estimated cash available for distribution.

Actual payments of distributions on common units, subordinated units and the general partner units are expected to be $81.4 million for the twelve month period ending June 30, 2008. This is the expected aggregate amount of cash distributions of $20.3 million per quarter for the period. Quarterly distributions will be paid within 45 days after the close of each quarter.

We do not undertake any obligation to release publicly the results of any future revisions we may make to the assumptions used in generating our minimum estimated cash available for distribution or to update those assumptions to reflect events or circumstances after the date of this prospectus. Therefore, you are cautioned not to place undue reliance on this information.

SPECTRA ENERGY PARTNERS, LP

STATEMENT OF

MINIMUM ESTIMATED CASH AVAILABLE FOR DISTRIBUTION


	Twelve months
	ending June 30,
	2008
	(In thousands,
	except per
	unit data)

Operating revenues	$	103,078
Operating expenses:
Operations, maintenance and other		36,924
Depreciation and amortization		21,548
Property and other taxes		7,294

Total operating expenses		65,766

Operating income		37,312

Add:
Equity earnings of Gulfstream		22,114
Equity earnings of Market Hub		31,535
Less:
Interest expense (income), net(a)		18,344

Net income		72,617

Adjustments to reconcile net income to Adjusted EBITDA:
Add:
Depreciation and amortization		21,548
Interest expense (income), net(a)		18,344
Less:
Equity earnings in Gulfstream		22,114
Equity earnings in Market Hub		31,535
Cash reserve(b)		4,069

Adjusted EBITDA		54,791

Add:
Estimated cash available for distribution from Gulfstream(c)		23,806
Estimated cash available for distribution from Market Hub(d)		32,886
Less:
Cash interest expense (income), net		18,344
Maintenance capital expenditures		11,767

Minimum estimated cash available for distribution	$	81,372

Per unit minimum annual distribution	$	1.30
Annual distributions to:
Public common unitholders		14,950
Spectra Energy		66,422

Total distributions to our unitholders and general partner at the initial distribution rate	$	81,372


(a)		Reflects on a net basis the interest expense related to borrowings under our credit facility made in connection with this offering and the interest income related to the long-term investments we intend to purchase with a portion of the proceeds from this offering.

In connection with the closing of this offering, we expect to enter into a $500 million credit agreement under which we expect to borrow $50 million in term debt and $125 million in revolving debt. We expect that the credit agreement will prohibit us from making distributions of available cash to unitholders in any default or event of default (as defined in the credit agreement) exists. In addition, we expect the credit agreement will contain other various covenants. If an event of default exists under the credit agreement, we expect that the lenders will be able to accelerate the maturity of the credit agreement and exercise other rights and remedies. The credit agreement is subject to a number of conditions, including the negotiation, execution and delivery of definitive documentation.


(b)		Represents a discretionary reserve to be used for reinvestment and other general partnership purposes.

(c)		Gulfstream’s estimated cash available for distribution for the twelve months ending June 30, 2008 is calculated as follows:


	Twelve months
	ending
Gulfstream	June 30, 2008
	(In thousands)

Net income	$	90,263
Add:
Depreciation and amortization expense		30,309
Interest expense, net		32,536
Less:
Other income (expenses), net		4,798

Adjusted EBITDA		148,310
Less:
Cash interest expense, net		49,307
Maintenance capital expenditures		1,834

Estimated cash available for distribution from Gulfstream — 100%	$	97,169

Estimated cash available for distribution from Gulfstream — our 24.5%	$	23,806


(d)		Market Hub’s estimated cash available for distribution for the twelve months ending June 30, 2008 is calculated as follows:


	Twelve months
	ending
Market Hub	June 30, 2008
	(In thousands)

Net income	$	63,071
Add:
Depreciation and amortization expense		8,344
Less:
Other income (expenses), net		2,641

Adjusted EBITDA		68,774
Less:
Maintenance capital expenditures		2,946
Cash paid for taxes		57

Estimated cash available for distribution from Market Hub — 100%	$	65,771

Estimated cash available for distribution from Market Hub — our 50.0%	$	32,886

Please read accompanying summary of the assumptions and considerations underlying these estimates.

Assumptions and Considerations

General

We believe that our estimated minimum cash available for distribution for the twelve months ending June 30, 2008 will not be less than $81.4 million. This amount of estimated minimum cash available for distribution is approximately $14.1 million more than the pro forma cash available for distribution we generated for the year ended December 31, 2006. As we discuss in further detail below, we believe that increased revenue primarily from firm transportation and storage agreements partially offset by increased operating and administrative expenses, will result in our generating higher cash available for distribution for the twelve months ending June 30, 2008. Our expected minimum revenue of $103.1 million, offset by the maximum operating expense, excluding depreciation and amortization, of approximately $36.9 million, taxes other than income taxes of $7.3 million less cash reserve of $4.1 million, plus cash distributions of $23.8 million and $32.9 million from Gulfstream and Market Hub, respectively, less cash interest expense of $18.3 million and maintenance capital expenditures of $11.8 million, results in our estimated minimum cash available for distribution of $81.4 million. We believe the assumptions and estimates we have made to support our ability to generate minimum estimated cash available for distribution, which are set forth below, are reasonable.

Spectra Energy Partners

Our Operating Revenue


	•	We estimate that we will generate at least $103.1 million in revenues for the twelve months ending June 30, 2008. Substantially all of these revenues will be generated from services provided under firm transportation and LNG storage agreements and capacity reservation charges relating to the East Tennessee system. We estimate less than $2.0 million of these revenues will be charges based on actual utilization and interruptible transportation service. We generated $80.0 million and $82.6 million in revenues for the years ended December 31, 2005 and 2006, respectively.

	•	The expected $20.5 million increase in our revenues from the year ended December 31, 2006 compared to the twelve months ending June 30, 2008 is primarily due to increased revenues associated with the Jewell Ridge Lateral, placed in service in 2006, as well as increased revenues associated with the Patriot Extension, which was placed into service in 2005.

Our Expenses


	•	We estimate operating and maintenance expenses will not be more than $36.9 million for the twelve months ending June 30, 2008, which include certain scheduled pipeline integrity expenditures that do not occur annually, as compared to $22.9 million and $19.1 million, respectively, for the years ended December 31, 2005 and 2006.

	•	We estimate our total general and administrative expense will not be more than $8.5 million, a portion of which will be capped pursuant to the terms of the omnibus agreement. Our general and administrative expenses will consist of corporate general and administrative expense allocated from Spectra Energy as well as additional general and administrative costs that result from our being a publicly traded limited partnership. Our estimated general and administrative expense of $8.5 million includes approximately $ million of non-cash expense related to awards to be granted under our Long-Term Incentive Plan. General and administrative expense allocated from Spectra Energy was $2.7 million for the calendar year ended December 31, 2006. Please read “Certain Relationships and Related Party Transactions — Omnibus Agreement.”

	•	We estimate depreciation and amortization expense for the twelve months ending June 30, 2008 for the East Tennessee system will be $21.5 million as compared to $23.6 million and $19.0 million of depreciation and amortization expense for the years ended December 31, 2005 and 2006, respectively. Estimated depreciation and amortization expense reflects management’s estimates, which are


		based on consistent average depreciable asset lives and depreciation methodologies, taking into account estimated capital expenditures.


	•	We estimate property and other taxes for the twelve months ending June 30, 2008 will be $7.3 million as compared to $5.3 million and $4.2 million for the years ended December 31, 2005 and 2006, respectively.

Our Capital Expenditures


	•	We estimate that East Tennessee’s maintenance capital expenditures will not exceed $11.8 million for the twelve months ending June 30, 2008 as compared to $8.2 million and $10.9 million for the years ended December 31, 2005 and 2006, respectively.

	•	We estimate that East Tennessee’s expansion capital expenditures will not exceed $11.8 million for the twelve months ending June 30, 2008. Expansion capital expenditures for East Tennessee were approximately $51.1 million and $75.0 million for the years ended December 31, 2005 and 2006, respectively, and consisted of expansions associated with the Jewell Ridge Lateral and other projects. The increased revenue from these projects is reflected in the twelve months ending June 30, 2008. Organic growth opportunities associated with the Jewell Ridge Lateral constitute the majority of the expansion capital expenditures planned for the twelve months ending June 30, 2008.

Our Financing


	•	We estimate that at closing of this offering we will enter into a new $500 million credit facility and borrow $125 million in revolving debt and $50 million in term debt. We estimate that the revolving borrowings will bear a variable average interest rate of 6.0%.

	•	We estimate that our term debt borrowings, net of interest earned on the $50 million in U.S. Treasury and other qualifying securities pledged to secure the loan, will bear an interest expense of 0.25%.

	•	We estimate that East Tennessee’s $150 million senior notes will remain outstanding and continue to bear interest at 5.71%.

	•	We estimate our capital expenditures and capital contribution requirements will total approximately $81 million and will be funded through borrowings under our new $500 million credit facility at a variable average interest rate of 6.0%.

	•	We estimate that we will remain in compliance with the financial covenants in our existing and future debt agreements during the twelve months ending June 30, 2008.

Our Regulatory, Industry and Economic Factors


	•	We estimate there will not be any new federal, state or local regulations of portions of the energy industry in which we operate, or any new interpretations of existing regulations, that will be materially adverse to our business during the twelve months ending June 30, 2008.

	•	We estimate there will not be any major adverse changes in the portions of the energy industry in which we operate or in general economic conditions during the twelve months ending June 30, 2008.

	•	We estimate that industry, insurance and overall economic conditions will not change substantially during the twelve months ending June 30, 2008.

Our Cash Distributions from Gulfstream and Market Hub


	•	Our estimate reflects cash distributions relating to our 24.5% interest in Gulfstream and our 50.0% interest in Market Hub. Under the terms of their limited liability company agreements, each of Gulfstream and Market Hub must distribute to their members on a quarterly basis 100% of their available cash, which is generally defined as cash on hand at the end of the applicable quarter, less


		any reserves taken by the management committee. As a result, we estimate that we will receive 24.5% and 50.0% of the available cash of Gulfstream and Market Hub, respectively, during the twelve months ending June 30, 2008. Based on our assumptions regarding the revenues, expenses and other capital requirements discussed below, we estimate receiving cash distributions of approximately $23.8 million from Gulfstream and approximately $32.9 million from Market Hub during the twelve months ending June 30, 2008.

Gulfstream System

Although we account for our 24.5% interest in Gulfstream under the equity-method for financial reporting purposes, we have assumed that Gulfstream’s cash distributions to us will be based on the following estimates.

Gulfstream Operating Revenue


	•	We estimate that Gulfstream will generate at least $155.3 million in firm service revenues for the twelve months ending June 30, 2008 related to services provided under firm transportation agreements. Gulfstream generated $121.5 million and $157.9 million in revenues related to these agreements for the years ended December 31, 2005 and 2006, respectively. We do not anticipate that Gulfstream will receive any revenues from its Phase III and Phase IV expansions during the twelve months ending June 30, 2008.

	•	We estimate that Gulfstream will generate revenues for the twelve months ending June 30, 2008 of at least $27.1 million related to interruptible transportation and park and loan service on estimated throughput of 48 Bcf. Gulfstream generated $23.6 million and $22.2 million in revenues related to interruptible transportation and park and loan services on throughput of 32 Bcf and 35 Bcf for the years ended December 31, 2005 and 2006, respectively. This increase in Gulfstream’s interruptible transportation and park and loan services revenue is primarily attributable to currently identified increased customer demand.

Gulfstream Expenses


	•	We estimate Gulfstream’s direct operating and maintenance expense will not be more than $16.3 million for the twelve months ending June 30, 2008, and includes certain scheduled asset integrity expenditures which do not occur annually, as compared to $9.3 million and $15.2 million for the calendar years ended December 31, 2005 and 2006, respectively. Operating expenses exclude capital expenditure provisions on development projects.

	•	We estimate Gulfstream’s depreciation and amortization expense will be no more than $30.3 million for the twelve months ending June 30, 2008. This expense was $29.2 million and $30.4 million for the calendar years ended December 31, 2005 and 2006, respectively. Estimated depreciation and amortization expense reflects management’s estimates, which are based on consistent average depreciable asset lives and depreciation methodologies, taking into account estimated capital expenditures as described below.

	•	We estimate property and other taxes for the twelve months ending June 30, 2008 will be $17.8 million as compared to $15.1 million and $17.9 million for the years ended December 31, 2005 and 2006, respectively.

Gulfstream Capital Expenditures


	•	We estimate that Gulfstream’s maintenance capital expenditures will not exceed $1.8 million for the twelve months ending June 30, 2008 as compared to $1.0 million and $0.6 million for the years ended December 31, 2005 and 2006, respectively.

	•	We estimate that Gulfstream’s net cash expansion capital expenditures will not exceed $152.2 million for the twelve months ending June 30, 2008 as compared to $61.2 million and $21.0 million for the


		years ended December 31, 2005 and 2006, respectively. Our 24.5% share of Gulfstream’s net cash expansion capital expenditures for the twelve months ending June 30, 2008 will be $37.3 million.


	•	The majority of Gulfstream’s expansion capital expenditures for the twelve months ending June 30, 2008 will be associated with its estimated $134.9 million Phase III project and its estimated $117.1 million Phase IV Project. These projects are expected to be phased in beginning in summer 2008 and completed in early 2009, and have applications pending with FERC for approval. The capital expenditures associated with Phase III and IV totaled $12.0 million through December 31, 2006. Both of these expansions are fully-supported by customer contracts with 23-year initial terms. These two projects will significantly increase Gulfstream’s firm transportation service contracts and will significantly decrease Gulfstream’s reliance on seasonal, interruptible transportation service.

Market Hub System

Although we account for our 50.0% interest in Market Hub under the equity-method for financial reporting purposes, we have assumed that Market Hub’s cash distributions to us will be based on the following estimates.

Market Hub Operating Revenue


	•	We estimate that Market Hub will generate at least $84.9 million in total revenues related to services provided under firm and interruptible storage agreements for the twelve months ending June 30, 2008. Market Hub generated $77.9 million and $78.8 million in revenues related to those services for the years ended December 31, 2005 and 2006, respectively. This increase in revenues is primarily attributable to higher average storage rates.

	•	Included in the storage service revenues above, we estimated that Market Hub will generate revenues of $9.4 million related to interruptible storage services for the twelve months ending June 30, 2008. Market Hub generated $14.3 million and $10.2 million in revenues related to these services for the years ended December 31, 2005 and 2006, respectively.

Market Hub Expenses


	•	We estimate that Market Hub’s operating and maintenance expenses will not be more than $11.7 million for the twelve months ending June 30, 2008, which includes certain scheduled asset integrity expenditures that will not occur annually, as compared to $9.5 million and $26.3 million for the years ended December 31, 2005 and 2006, respectively. The increase in operating and maintenance expenses from $9.5 million in 2005 to $26.3 million in 2006 was attributable to a natural gas inventory adjustment as well as expenses associated with two unit overhauls and an information technology upgrade.

	•	We estimate that Market Hub’s depreciation and amortization expense will be no more than $8.3 million as compared to $6.9 and $7.8 million of depreciation and amortization expense for the years ended December 31, 2005 and 2006, respectively. Estimated depreciation and amortization expense reflects management’s estimates, which are based on consistent average depreciable asset lives and depreciation methodologies, taking into account estimated capital expenditures as described below.

	•	We estimate property and other taxes for the twelve months ending June 30, 2008 will be $4.4 million as compared to $3.4 million and $4.0 million for the years ended December 31, 2005 and 2006, respectively.

Market Hub Capital Expenditures


	•	We estimate that Market Hub’s maintenance capital expenditures will not exceed $2.9 million for the twelve months ending June 30, 2008, as compared to $27.6 million and $9.5 million for the years


		ended December 31, 2005 and 2006, respectively. This decrease is primarily attributable to the substantial completion of repairs at Moss Bluff following a fire at a cavern well-head in 2004.


	•	As a result of ongoing expansion projects, we estimate that Market Hub’s expansion capital expenditures will increase to approximately $68.2 million for the twelve months ending June 30, 2008, as compared to $10.4 million and $44.6 million for the years ended December 31, 2005 and 2006, respectively. Expansion projects are currently being pursued at Market Hub’s Egan, Louisiana storage facility to increase its aggregate working gas storage capacity from its current capacity of 20 Bcf to 24 Bcf by 2008. An application is currently pending with FERC for approval to further expand Egan to 32 Bcf by 2012. Our 50.0% share of Market Hub’s net cash expansion capital expenditures for the twelve months ending June 30, 2008 will be $34.1 million.

Payments of Distributions on Common Units, Subordinated Units and the General Partner Units

Distributions on common units, subordinated units and general partner units for the twelve months ending June 30, 2008 are estimated to be $81.4 million in the aggregate. Quarterly distributions will be paid within 45 days after the close of each quarter.

While we believe that these assumptions are reasonable based upon management’s current expectations concerning future events, they are inherently uncertain and are subject to significant business, economic, regulatory and competitive risks and uncertainties, including those described in “Risk Factors,” that could cause actual results to differ materially from those we anticipate. If our assumptions are not realized, the actual cash available for distribution that we generate could be substantially less than that currently expected and could, therefore, be insufficient to permit us to make the full minimum quarterly distribution on all units, in which event the market price of the common units may decline materially.

PROVISIONS OF OUR PARTNERSHIP AGREEMENT
RELATING TO CASH DISTRIBUTIONS

Set forth below is a summary of the significant provisions of our partnership agreement that relate to cash distributions.

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 to unitholders of record on the applicable record date.

Definition of 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 our general partner to:


	•	provide for the proper conduct of our business;

	•	comply with applicable law, any of our debt instruments or other agreements; or

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


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

Intent to Distribute the Minimum Quarterly Distribution. We intend to distribute to the holders of common units and subordinated units on a quarterly basis at least the minimum quarterly distribution of $0.325 per unit, or $1.30 per year, to the extent we have sufficient cash from our operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner. However, there is no guarantee 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 our 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. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Requirements — Description of Credit Agreement” for a discussion of the restrictions to be included in our credit agreement that may restrict our ability to make distributions.

General Partner Interest and Incentive Distribution Rights. Initially, our general partner will be entitled to 2% of all quarterly distributions since inception that we make prior to our liquidation. This general partner interest will be represented by 1,251,879 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 us to maintain its 2% general partner interest.

Our 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 (as defined below) in excess of $0.3738 per unit per quarter. The maximum distribution of 50% includes distributions paid to our general partner on its 2% general partner interest and assumes that our general partner maintains its general partner interest at 2%. The maximum distribution of 50% does not include any distributions that our general partner may receive on units that it owns. Please read “— General Partner Interest and Incentive Distribution Rights” for additional information.

Operating Surplus and Capital Surplus

General. All cash distributed to unitholders will be characterized as either “operating surplus” or “capital surplus.” Our partnership agreement requires that we distribute available cash from operating surplus differently than available cash from capital surplus.

Operating Surplus. We define operating surplus in the partnership agreement and for any period it generally means:


	•	an amount equal to two times the amount needed for any one quarter for us to pay a distribution on all of our units (including the general partner units) and the incentive distribution rights at the same per-unit amount as was distributed in the immediately preceding quarter; plus

	•	all of our cash receipts after the closing of this offering, excluding cash from interim capital transactions, as defined below under “— Capital Surplus”; less

	•	all of our operating expenditures after the closing of this offering, excluding the repayment of borrowings, but including maintenance capital expenditures (including capital contributions to Gulfstream and Market Hub to be used by them for maintenance capital expenditures); less

	•	the amount of cash reserves established by our general partner to provide funds for future operating expenditures.

We define operating expenditures in the partnership agreement, and it generally means all of our expenditures, including, but not limited to, taxes, payments to our general partner, reimbursement of expenses incurred by our 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, provided that operating expenditures will not include:


	•	payments of principal of and premium on indebtedness;

	•	expansion capital expenditures;

	•	payment of transaction expenses (including taxes) related to interim capital transactions;

	•	distributions to our partners; and

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

Maintenance capital expenditures represent capital expenditures made to replace partially or fully depreciated assets, to maintain the existing operating capacity of our assets and to extend their useful lives, or other capital expenditures that are incurred in maintaining existing system volumes and related earnings. Expansion capital expenditures represent capital expenditures made to increase the long-term operating capacity or earnings of our assets, whether through construction or acquisition. Expansion capital expenditures include contributions made to Gulfstream and Market Hub to be used by them for expansion capital expenditures. Costs for repairs and minor renewals to maintain facilities in operating condition and that do not extend the useful life of existing assets will be treated as operations and maintenance expenses as we incur them. Our partnership agreement provides that our general partner, with the concurrence of the conflicts committee, determines how to allocate a capital expenditure for the acquisition or expansion of our assets between maintenance capital expenditures and expansion capital expenditures.

Capital Surplus. We also define capital surplus in the partnership agreement and in “— Characterization of Cash Distributions” below, and it will generally be generated only by the following, which we call “interim capital transactions”:


	•	borrowings;

	•	sales of our equity and debt securities; and


	•	sales or other dispositions of assets for cash, other than inventory, accounts receivable and other current assets sold in the ordinary course of business or as part of normal retirement or replacement of assets.

	•	the termination of interest rate swap agreements or commodity hedge contracts prior to the termination date specified therein;

	•	capital contributions received; and

	•	corporate reorganizations or restructurings.

Characterization of Cash Distributions. Our partnership agreement requires that we treat all available cash distributed as coming from operating surplus until the sum of all available cash distributed since the closing of this offering equals the operating surplus as of the most recent date of determination of available cash. Our partnership agreement requires that we treat any amount distributed in excess of operating surplus, regardless of its source, as capital surplus. As reflected above, operating surplus includes an amount equal to two times the amount needed for any one quarter for us to pay a distribution on all of our units (including the general partner units) and the incentive distribution rights at the same per-unit amount as was distributed in the immediately preceding quarter. This amount, which initially equals $20.3 million, does not reflect actual cash on hand that is available for distribution to our unitholders. Rather, it is a provision that will enable us, if we choose, to distribute as operating surplus up to this amount of cash we receive in the future from interim capital transactions, that would otherwise be distributed as capital surplus. We do not anticipate that we will make any distributions from capital surplus. The characterization of cash distributions as operating surplus versus capital surplus does not result in a different impact to unitholders for federal tax purposes. Please read “Material Tax Consequences — Tax Consequences of Unit Ownership — Treatment of Distributions” for a discussion of the tax treatment of cash distributions.

Subordination Period

General. Our partnership agreement provides that, during the subordination period (which we define below and in Appendix D), the common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $0.325 per common unit, which amount is defined in our partnership agreement as 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 from operating surplus 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.

Subordination Period. The subordination period will extend until the first business day of any quarter beginning after June 30, 2010 that each of the following tests are met:


	•	distributions of available cash from operating surplus on each of the outstanding common units, subordinated units and general partner units equaled or exceeded the minimum quarterly distribution for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;

	•	the “adjusted operating surplus” (as defined below) 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

	•	there are no arrearages in payment of the minimum quarterly distribution on the common units.

Expiration of the Subordination Period. When the subordination period expires, each outstanding subordinated unit will convert into one common unit and will then participate pro rata with the other common units in distributions of available cash. In addition, if the unitholders remove our general partner

other than for cause and units held by the general partner and its affiliates are not voted in favor of such removal:


	•	the subordination period will end and each subordinated unit will immediately convert into one common unit;

	•	any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and

	•	the general partner will have the right to convert its general partner units and its incentive distribution rights into common units or to receive cash in exchange for those interests.

Early Conversion of Subordinated Units. The subordination period will automatically terminate and all of the subordinated units will convert into common units on a one-for-one basis on the first business day following the distribution of available cash to partners in respect of any quarter ending on or after June 30, 2008 that each of the following occurs:


	•	distributions of available cash from operating surplus on each outstanding common unit, subordinated unit and general partner unit equaled or exceeded $0.4875 per quarter (150% of the annualized minimum quarterly distribution) for the four-quarter period immediately preceding the date;

	•	the “adjusted operating surplus” (as defined below) generated during the four-quarter period immediately preceding the date equaled or exceeded the sum of the distribution of $0.4875 (150% of the minimum quarterly distribution) on all of the outstanding common units, subordinated units and general partner units during that period on a fully diluted basis; and

	•	there are no arrearages in payment of the minimum quarterly distribution on the common units.

Adjusted Operating Surplus. Adjusted operating surplus is intended to reflect the cash generated from operations during a particular period and therefore excludes the two-quarter operating surplus “basket” and net drawdowns of reserves of cash generated in prior periods. We define adjusted operating surplus in the partnership agreement and for any period it generally means:


	•	operating surplus generated with respect to that period; plus

	•	any net decrease made in subsequent periods in cash reserves for operating expenditures initially established with respect to that period to the extent such decrease results in a reduction in adjusted operating surplus in subsequent periods pursuant to the following bullet point; less

	•	any net decrease in cash reserves for operating expenditures with respect to that period not relating to an operating expenditure made with respect to that period; plus

	•	any net increase in cash reserves for operating expenditures with respect to that period required by any debt instrument for the repayment of principal, interest or premium.

Distributions of Available Cash from Operating Surplus during the Subordination Period

Our partnership agreement requires that we make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner:


	•	first , 98% to the common unitholders, pro rata, and 2% to the general partner, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter;

	•	second , 98% to the common unitholders, pro rata, and 2% to the general partner, until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period;

	•	third , 98% to the subordinated unitholders, pro rata, and 2% to the general partner, until we distribute for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and


	•	thereafter , in the manner described in “General Partner Interest and Incentive Distribution Rights” below.

The preceding discussion is based on the assumptions that our general partner maintains its 2% general partner interest and that we do not issue additional classes of equity securities.

Distributions of Available Cash from Operating Surplus after the Subordination Period

Our partnership agreement requires that we make distributions of available cash from operating surplus for any quarter after the subordination period in the following manner:


	•	first , 98% to all unitholders, pro rata, and 2% to the general partner, until we distribute for each outstanding unit an amount equal to the minimum quarterly distribution for that quarter; and

	•	thereafter , in the manner described in “General Partner Interest and Incentive Distribution Rights” below.

The preceding discussion is based on the assumptions that our general partner maintains its 2% general partner interest and that we do not issue additional classes of equity securities.

General Partner Interest and Incentive Distribution Rights

Our partnership agreement provides that our general partner initially will be entitled to 2% of all distributions that we make prior to our liquidation. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its 2% general partner interest if we issue additional units. Our general partner’s 2% interest, and the percentage of our cash distributions to which it is entitled, will be proportionately reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us in order to maintain its 2% general partner interest. Our general partner will be entitled to make a capital contribution in order to maintain its 2% general partner interest in the form of the contribution to us of common units based on the current market value of the contributed common units.

Incentive distribution rights represent the right to receive an increasing percentage (13%, 23% and 48%) of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. Our general partner currently holds the incentive distribution rights, but may transfer these rights separately from its general partner interest, subject to restrictions in the partnership agreement.

The following discussion assumes that the general partner maintains its 2% general partner interest and continues to own the incentive distribution rights.

If for any quarter:


	•	we have distributed available cash from operating surplus to the common and subordinated unitholders in an amount equal to the minimum quarterly distribution; and

	•	we have distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution;

then, our partnership agreement requires that we distribute any additional available cash from operating surplus for that quarter among the unitholders and the general partner in the following manner:


	•	first , 98% to all unitholders, pro rata, and 2% to the general partner, until each unitholder receives a total of $0.3738 per unit for that quarter (the “first target distribution”);

	•	second , 85% to all unitholders, pro rata, and 15% to the general partner, until each unitholder receives a total of $0.4063 per unit for that quarter (the “second target distribution”);


	•	third , 75% to all unitholders, pro rata, and 25% to the general partner, until each unitholder receives a total of $0.4875 per unit for that quarter (the “third target distribution”); and

	•	thereafter , 50% to all unitholders, pro rata, and 50% to the general partner.

Percentage Allocations of Available Cash from Operating Surplus

The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and our general partner based on the specified target distribution levels. The amounts set forth under “Marginal Percentage Interest in Distributions” are the percentage interests of our general partner and the unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution Per Unit,” until available cash from operating surplus we distribute reaches the next target distribution level, if any. The percentage interests shown for the unitholders and the general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our general partner include its 2% general partner interest and assume our general partner has contributed any additional capital to maintain its 2% general partner interest and has not transferred its incentive distribution rights.


		Marginal Percentage
	Total Quarterly	Interest in Distribution
	Distribution per Unit				General
	Target Amount	Unitholders			Partner

Minimum Quarterly Distribution	$0.325		98	%		2	%
First Target Distribution	Up to $0.3738		98	%		2	%
Second Target Distribution	above $0.3738 up to $0.4063		85	%		15	%
Third Target Distribution	above $0.4063 up to $0.4875		75	%		25	%
Thereafter	above $0.4875		50	%		50	%

General Partner’s Right to Reset Incentive Distribution Levels

Our general partner, as the holder of our incentive distribution rights, has the right under our partnership agreement to elect to relinquish the right to receive incentive distribution payments based on the initial cash target distribution levels and to reset, at higher levels, the minimum quarterly distribution amount and cash target distribution levels upon which the incentive distribution payments to our general partner would be set. Our general partner’s right to reset the minimum quarterly distribution amount and the target distribution levels upon which the incentive distributions payable to our general partner are based may be exercised, without approval of our unitholders or the conflicts committee of our general partner, at any time when there are no subordinated units outstanding and we have made cash distributions to the holders of the incentive distribution rights at the highest level of incentive distribution for each of the prior four consecutive fiscal quarters. The reset minimum quarterly distribution amount and target distribution levels will be higher than the minimum quarterly distribution amount and the target distribution levels prior to the reset such that our general partner will not receive any incentive distributions under the reset target distribution levels until cash distributions per unit following this event increase as described below. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would otherwise not be sufficiently accretive to cash distributions per common unit, taking into account the existing levels of incentive distribution payments being made to our general partner.

In connection with the resetting of the minimum quarterly distribution amount and the target distribution levels and the corresponding relinquishment by our general partner of incentive distribution payments based on the target cash distributions prior to the reset, our general partner will be entitled to receive a number of newly issued Class B units based on a predetermined formula described below that takes into account the “cash parity” value of the average cash distributions related to the incentive distribution rights received by our general partner for the two quarters prior to the reset event as compared

to the average cash distributions per common unit during this period. We will also issue an additional amount of general partner units in order to maintain the general partner’s ownership interest in us relative to the issuance of the Class B units.

The number of Class B units that our general partner would be entitled to receive from us in connection with a resetting of the minimum quarterly distribution amount and the target distribution levels then in effect would be equal to (x) the average amount of cash distributions received by our general partner in respect of its incentive distribution rights during the two consecutive fiscal quarters ended immediately prior to the date of such reset election divided by (y) the average of the amount of cash distributed per common unit during each of these two quarters. Each Class B unit will be convertible into one common unit at the election of the holder of the Class B unit at any time following the first anniversary of the issuance of these Class B units The issuance of Class B units will be conditioned upon approval of the listing or admission for trading of the common units into which the Class B units are convertible by the national securities exchange on which the common units are then listed or admitted for trading. Each Class B unit will receive the same level of distribution as a common unit on a pari passu basis with other unitholders.

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 be correspondingly higher such that we would distribute all of our available cash from operating surplus for each quarter thereafter as follows:


	•	first, 98% to all unitholders, pro rata, and 2% to the general partner, until each unitholder receives an amount equal to 115% of the reset minimum quarter distribution for that quarter;

	•	second, 85% to all unitholders, pro rata, and 15% to the general partner, until each unitholder receives an amount per unit equal to 125% of the reset minimum quarterly distribution for that quarter;

	•	third, 75% to all unitholders, pro rata, and 25% to the general partner, until each unitholder receives an amount per unit equal to 150% of the reset minimum quarterly distribution for that quarter; and

	•	thereafter, 50% to all unitholders, pro rata, and 50% to the general partner.

The following table illustrates the percentage allocation of available cash from operating surplus between the unitholders and our general partner at various levels of cash distribution levels pursuant to the cash distribution provision of our partnership agreement in effect at the closing of this offering as well as following a hypothetical reset of the minimum quarterly distribution and target distribution levels based on the assumption that the average quarterly cash distribution amount per common unit during the two fiscal quarters immediately preceding the reset election was $0.60.


		Marginal Percentage
	Quarterly Distribution	Interest in Distribution						Quarterly Distribution
	per Unit				General			per Unit following
	Prior to Reset	Unitholders			Partner			Hypothetical Reset

Minimum Quarterly Distribution	$0.325		98	%		2	%	$0.60
First Target Distribution	Up to $0.3738		98	%		2	%	Up to $0.69(1)
Second Target Distribution	above $0.3738 up to $0.4063		85	%		15	%	above $0.69 up to $0.75(2)
Third Target Distribution	above $0.4063 up to $0.4875		75	%		25	%	above $0.75 up to $0.90(3)
Thereafter	above $0.4875		50	%		50	%	above $0.90(3)


(1)		This amount is 115% of the hypothetical reset minimum quarterly distribution.

(2)		This amount is 125% of the hypothetical reset minimum quarterly distribution.

(3)		This amount is 150% of the hypothetical reset minimum quarterly distribution.

The following table illustrates the total amount of available cash from operating surplus that would be distributed to the unitholders and the general partner, including in respect of incentive distribution rights, or IDRs, based on an average of the amounts distributed per quarter for the two quarters immediately prior to the reset. The table assumes that there are 61,342,077 common units and 1,251,879 general partner units, representing a 2% general partner interest, outstanding, and that the average distribution to each common unit is $0.60 for the two quarters prior to the reset. The assumed number of outstanding units assumes the conversion of all subordinated units into common units and no additional unit issuances.


	Quarterly	Common		General Partner Cash Distributions Prior to Reset
	Distribution	Unitholders Cash				2% General
	per Unit	Distributions		Class B		Partner						Total
	Prior to Reset	Prior to Reset		Units		Interest		IDRs		Total		Distributions

Minimum Quarterly Distribution	$0.325	$	19,936,175	$	0	$	406,861	$	0	$	406,861	$	20,343,036
First Target Distribution	up to $0.3738		2,993,493		0		61,092		0		61,092		3,054,585
Second Target Distribution	above $0.3738 up to $0.4063		1,993,617		0		46,909		304,906		351,815		2,345,432
Third Target Distribution	above $0.4063 up to $0.4875		4,980,977		0		132,826		1,527,500		1,660,326		6,641,303
Thereafter	above $0.4875		6,900,984		0		276,039		6,624,944		6,900,984		13,801,967

		$	36,805,246	$	0	$	923,727	$	8,457,350	$	9,381,078	$	46,186,323

The following table illustrates the total amount of available cash from operating surplus that would be distributed to the unitholders and the general partner with respect to the quarter in which the reset occurs. The table reflects that as a result of the reset there are 61,342,077 common units, 14,095,583 Class B units and 1,539,545 general partner units, outstanding, and that the average distribution to each common unit is $0.60. The number of Class B units was calculated by dividing (x) $8,457,350 as the average of the amounts received by the general partner in respect of its incentive distribution rights, or IDRs, for the two quarters prior to the reset as shown in the table above by (y) the $0.60 of available cash from operating surplus distributed to each common unit as the average distributed per common unit for the two quarters prior to the reset.


				General Partner Cash Distributions
	Quarterly	Common		After Reset
	Distribution	Unitholders Cash				2% General
	per	Distributions		Class B		Partner						Total
	Unit After Reset	After Reset		Units		Interest		IDRs		Total		Distributions

Minimum Quarterly Distribution	$0.60	$	36,805,246	$	8,457,350	$	923,727	$	0	$	9,381,077	$	46,186,323
First Target Distribution	up to $0.69		—		—		—		—		—		—
Second Target Distribution	above $0.69 up to $0.75		—		—		—		—		—		—
Third Target Distribution	above $0.75 up to $0.90		—		—		—		—		—		—

Thereafter	above $0.90	$	36,805,246	$	8,457,350	$	923,727	$	0	$	9,381,077	$	46,186,323

Our general partner will be entitled to cause the minimum quarterly distribution amount and the target distribution levels to be reset on more than one occasion, provided that it may not make a reset election except at a time when it has received incentive distributions for the prior four consecutive fiscal quarters based on the highest level of incentive distributions that it is entitled to receive under our partnership agreement.

Distributions from Capital Surplus

How Distributions from Capital Surplus Will Be Made. Our partnership agreement requires that we make distributions of available cash from capital surplus, if any, in the following manner:


	•	first , 98% to all unitholders, pro rata, and 2% to the general partner, until we distribute for each common unit that was issued in this offering an amount of available cash from capital surplus equal to the initial public offering price;


	•	second , 98% to the common unitholders, pro rata, and 2% to the general partner, until we distribute for each common unit an amount of available cash from capital surplus equal to any unpaid arrearages in payment of the minimum quarterly distribution on the common units; and

	•	thereafter , we will make all distributions of available cash from capital surplus as if they were from operating surplus.

Effect of a Distribution from Capital Surplus. Our partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from this initial public offering, which is a return of capital. The initial public offering price less any distributions of capital surplus per unit is referred to as the “unrecovered initial unit price.” Each time a distribution of capital surplus is made, the minimum quarterly distribution and the target distribution levels will be reduced in the same proportion as the corresponding reduction in the unrecovered initial unit price. Because distributions of capital surplus will reduce the minimum quarterly distribution, after any of these distributions are made, it may be easier for the general partner to receive incentive distributions and for the subordinated units to convert into common units. However, any distribution of capital surplus before the unrecovered initial unit price is reduced to zero cannot be applied to the payment of the minimum quarterly distribution or any arrearages.

Once we distribute capital surplus on a unit issued in this offering in an amount equal to the initial unit price, our partnership agreement specifies that the minimum quarterly distribution and the target distribution levels will be reduced to zero. Our partnership agreement specifies that we then make all future distributions from operating surplus, with 50% being paid to the holders of units and 50% to the general partner. The percentage interests shown for our general partner include its 2% general partner interest and assume the general partner has not transferred the incentive distribution rights.

Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

In addition to adjusting the minimum quarterly distribution and target distribution levels to reflect a distribution of capital surplus, if we combine our units into fewer units or subdivide our units into a greater number of units, our partnership agreement specifies that the following items will be proportionately adjusted:


	•	the minimum quarterly distribution;

	•	target distribution levels;

	•	the unrecovered initial unit price; and

	•	the number of common units into which a subordinated unit is convertible.

For example, if a two-for-one split of the common units should occur, the minimum quarterly distribution, the target distribution levels and the unrecovered initial unit price would each be reduced to 50% of its initial level and each subordinated unit would be convertible into two common units. Our partnership agreement provides that we not make any adjustment by reason of the issuance of additional units for cash or property.

In addition, if legislation is enacted or if existing law is modified or interpreted by a governmental taxing authority, so that we become taxable as a corporation or otherwise subject to taxation as an entity for federal, state or local income tax purposes, our partnership agreement specifies that the general partner may reduce the minimum quarterly distribution and the target distribution levels for each quarter by multiplying each distribution level by a fraction, the numerator of which is available cash for that quarter and the denominator of which is the sum of available cash for that quarter plus the general partner’s estimate of our aggregate liability for the quarter for such income taxes payable by reason of such legislation or interpretation. To the extent that the actual tax liability differs from the estimated tax liability for any quarter, the difference will be accounted for in subsequent quarters.

Distributions of Cash Upon Liquidation

General. If we dissolve in accordance with the partnership agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any remaining proceeds to the unitholders and the general partner, in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.

The allocations of gain and loss upon liquidation are intended, to the extent possible, to entitle the holders of outstanding common units to a preference over the holders of outstanding subordinated units upon our liquidation, to the extent required to permit common unitholders to receive their unrecovered initial unit price plus the minimum quarterly distribution for the quarter during which liquidation occurs plus any unpaid arrearages in payment of the minimum quarterly distribution on the common units. However, there may not be sufficient gain upon our liquidation to enable the holders of common units to fully recover all of these amounts, even though there may be cash available for distribution to the holders of subordinated units. Any further net gain recognized upon liquidation will be allocated in a manner that takes into account the incentive distribution rights of the general partner.

Manner of Adjustments for Gain. The manner of the adjustment for gain is set forth in the partnership agreement. If our liquidation occurs before the end of the subordination period, we will allocate any gain to the partners in the following manner:


	•	first, to the general partner and the holders of units who have negative balances in their capital accounts to the extent of and in proportion to those negative balances;

	•	second, 98% to the common unitholders, pro rata, and 2% to the general partner, until the capital account for each common unit is equal to the sum of: (1) the unrecovered initial unit price; (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs; and (3) any unpaid arrearages in payment of the minimum quarterly distribution;

	•	third, 98% to the subordinated unitholders, pro rata, and 2% to the general partner until the capital account for each subordinated unit is equal to the sum of: (1) the unrecovered initial unit price; and (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs;

	•	fourth, 98% to all unitholders, pro rata, and 2% to the general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the first target distribution per unit over the minimum quarterly distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the minimum quarterly distribution per unit that we distributed 98% to the unitholders, pro rata, and 2% to the general partner, for each quarter of our existence;

	•	fifth, 85% to all unitholders, pro rata, and 15% to the general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the second target distribution per unit over the first target distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the first target distribution per unit that we distributed 85% to the unitholders, pro rata, and 15% to the general partner for each quarter of our existence;

	•	sixth, 75% to all unitholders, pro rata, and 25% to the general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the third target distribution per unit over the second target distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the second target distribution per unit that we distributed 75% to the unitholders, pro rata, and 25% to the general partner for each quarter of our existence; and

	•	thereafter, 50% to all unitholders, pro rata, and 50% to the general partner.

The percentage interests set forth above for our general partner include its 2% general partner interest and assume the general partner has not transferred the incentive distribution rights.

If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that clause (3) of the second bullet point above and all of the third bullet point above will no longer be applicable.

Manner of Adjustments for Losses. If our liquidation occurs before the end of the subordination period, we will generally allocate any loss to the general partner and the unitholders in the following manner:


	•	first, 98% to holders of subordinated units in proportion to the positive balances in their capital accounts and 2% to the general partner, until the capital accounts of the subordinated unitholders have been reduced to zero;

	•	second, 98% to the holders of common units in proportion to the positive balances in their capital accounts and 2% to the general partner, until the capital accounts of the common unitholders have been reduced to zero; and

	•	thereafter, 100% to the general partner.

If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that all of the first bullet point above will no longer be applicable.

Adjustments to Capital Accounts. Our partnership agreement requires that we make adjustments to capital accounts upon the issuance of additional units. In this regard, our partnership agreement specifies that we allocate any unrealized and, for tax purposes, unrecognized gain or loss resulting from the adjustments to the unitholders and the general partner in the same manner as we allocate gain or loss upon liquidation. In the event that we make positive adjustments to the capital accounts upon the issuance of additional units, our partnership agreement requires that we allocate any later negative adjustments to the capital accounts resulting from the issuance of additional units or upon our liquidation in a manner which results, to the extent possible, in the general partner’s capital account balances equaling the amount which they would have been if no earlier positive adjustments to the capital accounts had been made.

SELECTED HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA

The following table shows (i) selected historical financial and operating data of Spectra Energy Partners Predecessor, (ii) selected pro forma financial data of Spectra Energy Partners and (iii) selected historical financial and operating data of Gulfstream and Market Hub for the periods and as of the dates indicated. The selected historical financial data of Spectra Energy Partners Predecessor as of and for the years ended December 31, 2004, 2005 and 2006 are derived from the historical audited combined financial statements of Spectra Energy Partners Predecessor, appearing elsewhere in this prospectus. The historical financial data of Spectra Energy Partners Predecessor as of and for the years ended December 31, 2002 and 2003 are derived from the unaudited combined financial statements of Spectra Energy Partners Predecessor. The table should also be read together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

The selected historical financial data of Gulfstream and Market Hub as of and for the years ended December 31, 2004, 2005 and 2006 are derived from the audited financial statements of Gulfstream and Market Hub, respectively, appearing elsewhere in this prospectus. All other historical financial data for Gulfstream and Market Hub are derived from our financial records.

The pro forma financial data of Spectra Energy Partners as of and for the year ended December 31, 2006 are derived from the unaudited pro forma combined financial statements of Spectra Energy Partners included elsewhere in this prospectus. The pro forma adjustments have been prepared as if certain transactions to be effected at the closing of this offering had taken place on December 31, 2006 in the case of the pro forma balance sheet, or as of January 1, 2006, in the case of the pro forma statement of operations. These transactions include:


	•	East Tennessee’s and Market Hub’s distribution of accounts receivable of $9.1 million and $12.1 million ($6.0 million, net to our interest), respectively, Spectra Energy Corp;

	•	The proceeds to Spectra Energy Partners, LP from the issuance and sale of 11.5 million common units at an initial offering price of $20.00 per unit;

	•	Spectra Energy Partner, LP’s borrowings under a new $500 million credit facility of $50 million in term debt and $125 million in revolving debt; and

	•	The use of proceeds and borrowings to pay transaction expenses and underwriting commissions, reimburse Spectra Energy for certain capital expenditures, replenish working capital, and invest in U.S. Treasury and other qualifying securities.

The following table includes the following non-GAAP financial measures:


	•	Our historical and pro forma Adjusted EBITDA;

	•	Adjusted EBITDA for both our 24.5% ownership interest in Gulfstream and our 50.0% ownership interest in Market Hub;

	•	Our historical and pro forma cash available for distribution; and

	•	Cash available for distribution for both our 24.5% ownership interest in Gulfstream and our 50.0% ownership interest in Market Hub.

These measures are presented because such information is relevant to, and is expected to be used by, management, industry analysts, investors, lenders and rating agencies to assess the financial performance and operating results of our fundamental business activities. Our 24.5% ownership interest in Gulfstream and our 50.0% ownership interest in Market Hub are not consolidated in our pro forma financial results, but are accounted for using the equity method of accounting. In order to evaluate our Adjusted EBITDA for the cash impact of our investments in Gulfstream and Market Hub on our results, we calculate Adjusted EBITDA and cash available for distribution separately for us and our ownership interests in Gulfstream and Market Hub. We expect distributions we receive from Gulfstream and Market Hub to represent a significant portion of the cash we distribute to our unitholders. The limited liability company agreements for

each of Gulfstream and Market Hub provide for quarterly distributions of available cash to their members. Please read “How We Make Cash Distributions — General — Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy” for more information on the manner in which Gulfstream and Market Hub distribute cash to their members.

We define our cash available for distribution as Adjusted EBITDA plus cash available for distribution from Gulfstream and Market Hub, less net cash paid for interest expense and maintenance capital expenditures. Our cash available for distribution does not reflect changes in working capital balances. Our pro forma cash available for distribution for the year ended December 31, 2006 includes our anticipated incremental general and administrative expense of being a publicly traded partnership.

For a reconciliation of these measures to their most directly comparable financial measures calculated and presented in accordance with GAAP, please read “— Non-GAAP Financial Measures.”


												Spectra Energy
												Partners, LP
												Pro Forma
	Spectra Energy Partners Predecessor											Year Ended
	Year Ended December 31,											December 31,
	2002		2003			2004		2005		2006		2006
	(In thousands except per unit and operating data)

Statement of Operations:
Total operating revenues	$	58,442	$	65,865		$	81,716	$	80,003	$	82,609	$	82,609
Operating expenses:
Operations, maintenance, and other		11,613		19,032			26,081		24,648		21,831		21,831
Depreciation and amortization		14,577		15,804			21,492		23,640		18,986		18,986
Property and other taxes		3,661		4,318			518		5,264		4,177		4,177

Total operating and expenses		29,851		39,154			48,091		53,552		44,994		44,994

Gain on sale of other assets, net		—		(161	)		—		—		—		—

Operating income		28,591		26,550			33,625		26,451		37,615		37,615

Equity in earnings of unconsolidated affiliates		35,428		28,367			35,495		46,287		41,105		41,105
Other income (expense), net		20,774		7,994			1,491		552		1,780		1,780
Interest expense (income), net		17,839		6,203			8,258		8,506		8,151		15,976
Income tax expense		11,539		6,048			9,202		7,834		10,741		453

Net income	$	55,415	$	50,660		$	53,151	$	56,950	$	61,608	$	64,071

Pro forma net income per common unit												$	1.02
Pro forma net income per subordinated unit												$	1.02
Balance Sheet Data (at period end):
Total assets	$	1,081,254	$	1,258,141		$	1,302,974	$	1,202,772	$	1,284,582	$	1,323,465
Property, plant and equipment, net		433,244		566,697			602,226		616,316		691,820		691,820
Investment in unconsolidated affiliates		511,240		531,956			553,731		422,340		442,793		431,081
Long-term debt		150,000		150,000			150,000		150,000		150,000		325,000
Total parent net equity		878,203		1,021,321			1,024,754		895,696		989,125		967,400


							Spectra Energy
							Partners, LP
	Spectra Energy						Pro Forma
	Partners Predecessor						Year Ended
	Year Ended December 31,						December 31,
	2004		2005		2006		2006
	(In thousands except per unit and operating data)

Other Financial Data:
Spectra Energy Partners
Net cash provided by operating activities	$	83,987	$	93,272	$	62,278	$	64,741
Adjusted EBITDA		55,117		50,091		56,601		56,601
Incremental general and administrative expense of being a publicly-traded partnership		—		—		—		5,500	(b)
Net cash paid for interest expense		12,955		8,566		8,591		16,216
Maintenance capital expenditures		6,679		8,232		10,933		10,933
Cash available for distribution(a)		73,784		77,526		80,377		67,252
Expansion capital expenditures		27,590		51,083		74,977		74,977
Gulfstream — our 24.5%
Net cash provided by operating activities	$	18,771	$	24,999	$	24,712
Adjusted EBITDA		18,699		29,583		36,060
Net cash paid for interest expense		1,555		3,869		12,109
Maintenance capital expenditures		47		234		151
Cash available for distribution(a)		17,097		25,480		23,800
Expansion capital expenditures		30,356		15,000		5,149
Market Hub — our 50.0%
Net cash provided by operating activities	$	21,452	$	31,139	$	84,386
Adjusted EBITDA		27,027		32,552		24,286
Net cash paid for interest expense		—		—		22
Maintenance capital expenditures		5,823		13,799		4,763
Cash available for distribution(a)		21,204		18,753		19,500
Expansion capital expenditures		2,677		5,195		22,279

Operating Data:
East Tennessee
Transportation capacity (Bcf/d)		1.263		1.280		1.319
Contracted firm capacity (Bcf/d)		1.147		1.114		1.183
Transported volumes (Bcf)		121.7		133.1		140.8
Gulfstream — 100% basis
Transportation capacity (Bcf/d)		1.063		1.063		1.063
Contracted firm capacity (Bcf/d)		0.296		0.731		0.731
Transported volumes (Bcf)		110.7		179.7		251.3
Market Hub — 100% basis
Storage capacity (Bcf)		28.7		29.8		34.8


(a)		Cash available for distribution of Spectra Energy Partners includes the cash available for distribution from Gulfstream and Market Hub.

(b)		Upon completion of this offering, we anticipate incurring incremental general and administrative expense of approximately $5.5 million per year as a result of being a publicly-traded limited partnership. The unaudited pro forma combined financial statements do not reflect these expenses.

Non-GAAP Financial Measures


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

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

	•	our 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 their financing methods and capital structure.


										Spectra Energy
										Partners, LP
										Pro Forma
	Spectra Energy Partners Predecessor									Year Ended
	Year Ended December 31,									December 31,
	2004			2005			2006			2006
	(In thousands)

Spectra Energy Partners
Reconciliation of Non-GAAP “Adjusted EBITDA” and “Cash Available for Distribution” to GAAP “Net Income”
Net income	$	53,151		$	56,950		$	61,608		$	64,071
Add:
Interest expense (income), net		8,258			8,506			8,151			15,976
Income tax expense		9,202			7,834			10,741			453
Depreciation and amortization		21,492			23,640			18,986			18,986
Less:
Equity in earnings of Gulfstream		11,081			16,611			16,763			16,763
Equity in earnings of Market Hub		24,414			29,676			24,342			24,342
Other income, net		1,491			552			1,780			1,780

Adjusted EBITDA	$	55,117		$	50,091		$	56,601		$	56,601

Add:
Cash available for distribution from Gulfstream		17,097			25,480			23,800			23,800
Cash available for distribution from Market Hub		21,204			18,753			19,500			19,500
Less:
Incremental general and administrative expense of being a public company		—			—			—			5,500
Net cash paid for interest expense (income), net		12,955			8,566			8,591			16,216
Maintenance capital expenditures		6,679			8,232			10,933			10,933

Cash available for distribution	$	73,784		$	77,526		$	80,377		$	67,252

Reconciliation of Non-GAAP “Adjusted EBITDA” and “Cash Available for Distribution” to GAAP “Net cash provided by operating activities”
Net cash provided by operating activities	$	83,987		$	93,272		$	62,278		$	64,741
Interest expense (income), net		8,258			8,506			8,151			15,976
Income taxes		(21,964	)		3,465			(2,072	)		(12,360	)
Distributions received from Market Hub		—			—			—			—
Distributions received from Gulfstream		(13,720	)		(29,645	)		(20,335	)		(20,335	)
Other		(6	)		12			299			299
Changes in operating working capital:
Accounts receivable		848			(934	)		(49	)		(49	)
Other current assets		6,294			(6,189	)		878			878
Accounts payable		4,787			(1,687	)		798			798
Taxes accrued		(17,694	)		(7,527	)		3,345			3,345
Other current liabilities		3,197			(1,617	)		8,927			8,927
Other, including changes in noncurrent assets and liabilities		1,130			(7,565	)		(5,619	)		(5,619	)

Adjusted EBITDA	$	55,117		$	50,091		$	56,601		$	56,601

Add:
Cash available for distribution from Gulfstream		17,097			25,480			23,800			23,800
Cash available for distribution from Market Hub		21,204			18,753			19,500			19,500
Less:
Incremental general and administrative expense of being a public company		—			—			—			5,500
Net cash paid for interest expense (income), net		12,955			8,566			8,591			16,216
Maintenance capital expenditures		6,679			8,232			10,933			10,933

Cash available for distribution	$	73,784		$	77,526		$	80,377		$	67,252


	Gulfstream
	Year Ended December 31,
	2004			2005			2006
	(In thousands)

Gulfstream
Reconciliation of non-GAAP “Adjusted EBITDA” and “Cash Available for Distribution” to GAAP “Net Income”
Net income	$	45,228		$	67,800		$	68,422
Add:
Interest expense		9,092			25,540			48,787
Depreciation and amortization		25,354			29,190			30,406
Less:
Other income, net		3,353			1,783			431

Adjusted EBITDA — 100%	$	76,321		$	120,747		$	147,184

Adjusted EBITDA — our 24.5%	$	18,699		$	29,583		$	36,060

Less:
Net cash paid for interest expense		6,349			15,794			49,423
Maintenance capital expenditures		190			955			617

Cash available for distribution — 100%	$	69,782		$	103,998		$	97,144

Cash available for distribution — our 24.5%	$	17,097		$	25,480		$	23,800


Reconciliation of Non-GAAP “Adjusted EBITDA” and “Cash Available for Distribution” to GAAP “Net cash provided by operating activities”
Net cash provided by operating activities	$	76,617		$	111,858		$	107,083
Interest expense (income), net		9,092			25,540			48,787
Other		(5,571	)		(4,962	)		493
Changes in operating working capital:
Accounts receivable		(420	)		9,698			(3,772	)
Other current assets		(3,575	)		143			545
Accounts payable		(102	)		2,066			(994	)
Accrued taxes		1,264			(4,861	)		(8,050	)
Accrued interest		(1,573	)		(6,709	)		687
Accrued liabilities		172			(5,830	)		875
Fuel tracker liabilities		—			(2,962	)		2,260
Other current liabilities		(223	)		(2,940	)		(3,197	)
Other, including changes in noncurrent assets and liabilities		640			(294	)		2,467

Adjusted EBITDA — 100%	$	76,321		$	120,747		$	147,184

Adjusted EBITDA — our 24.5%	$	18,699		$	29,583		$	36,060

Less:
Net cash paid for interest expense		6,349			15,794			49,423
Maintenance capital expenditures		190			955			617

Cash available for distribution — 100%	$	69,782		$	103,998		$	97,144

Cash available for distribution — our 24.5%	$	17,097		$	25,480		$	23,800


	Market Hub
	Year ended December 31,
	2004			2005			2006
	(In thousands)

Market Hub
Reconciliation of Non-GAAP “Adjusted EBITDA” and “Cash Available for Distribution” to GAAP “Net Income”
Net income	$	48,829		$	59,353		$	48,684
Add:
Interest expense		—			—			2,625
Depreciation and amortization		6,788			6,938			7,815
Less:
Other income, net		1,533			1,146			10,553
Interest income		30			41			—

Adjusted EBITDA — 100%	$	54,054		$	65,104		$	48,571

Adjusted EBITDA — our 50.0%	$	27,027		$	32,552		$	24,286

Less:
Net cash paid for interest expense		—			—			43
Maintenance capital expenditures		11,646			27,599			9,528

Cash available for distribution — 100%	$	42,408		$	37,505		$	39,000

Cash available for distribution — our 50.0%	$	21,204		$	18,753		$	19,500


Reconciliation of Non-GAAP “Adjusted EBITDA” and “Cash Available for Distribution” to GAAP “Net cash provided by operating activities”
Net cash provided by operating activities	$	42,904		$	62,278		$	168,771
Interest expense (income), net		(30	)		(41	)		2,625
Other		6			(10	)		—
Changes in operating working capital:
Accounts receivable		36,682			(16,306	)		(5,944	)
Inventory		808			3,137			(6,113	)
Other current assets		(260	)		—			—
Accounts payable		(1,593	)		363			(4,804	)
Accrued taxes		214			506			(379	)
Collateral liabilities		(1,799	)		(491	)		(56,341	)
Other accrued liabilities		(22,852	)		14,587			(2,638	)
Other, including changes in noncurrent assets and liabilities		(26	)		1,081			(46,606	)

Adjusted EBITDA — 100%	$	54,054		$	65,104		$	48,571

Adjusted EBITDA — our 50.0%	$	27,027		$	32,552		$	24,286

Less:
Net cash paid for interest expense		—			—			43
Maintenance capital expenditures		11,646			27,599			9,528

Cash available for distribution — 100%	$	42,408		$	37,505		$	39,000

Cash available for distribution — our 50.0%	$	21,204		$	18,753		$	19,500

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

You should read the following discussion of our financial condition and results of operations in conjunction with our historical consolidated financial statements and notes and our pro forma financial statements included elsewhere in this prospectus. Because of the significance of our investments in Gulfstream and Market Hub, we include separate historical financial statements and notes of Gulfstream and Market Hub in this prospectus as well as additional discussion of their financial condition and results of operations presented below. You should read this analysis in conjunction with the historical financial statements of Gulfstream and Market Hub and the notes to those financial statements found elsewhere in this prospectus.

Overview

We are a Delaware limited partnership recently formed by Spectra Energy to own and operate natural gas transportation and storage assets. Our initial assets consist of the following:


	•	*East Tennessee System.* We own and operate 100% of the approximately 1,400-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 also owns and operates an LNG storage facility in Kingsport, Tennessee with working gas storage capacity of approximately 1.0 Bcf and regasification capability of 150 MMcf/d.

	•	*Gulfstream System.* We own a 24.5% interest in the approximately 690-mile Gulfstream interstate natural gas transportation system, which extends from Pascagoula, Mississippi and Mobile, Alabama across the Gulf of Mexico and into central Florida.

	•	*Market Hub System.* We own a 50.0% interest in Market Hub, which owns and operates two high-deliverability salt cavern natural gas storage facilities located in Louisiana and Texas with aggregate working gas storage capacity of approximately 35 Bcf.

Factors that Impact our Business

The high percentage of our business derived from capacity reservation fees mitigates the risk to us of revenue fluctuations due to near-term changes in supply and demand conditions. However, all of our businesses can be negatively affected 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. In addition, the demand for our services under short-term contracts and interruptible service arrangements, while not a significant revenue component, can be impacted to varying degrees by natural gas price volatility and other factors beyond our control.

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, discussed in more detail below, play an important role in how we evaluate our operations and implement our long-term strategies.

Supply and Demand Dynamics

To effectively manage our business, we monitor our market areas for both short-term and long-term shifts in natural gas supply and demand. Our natural gas transportation business links sources of natural gas supply to customers in market demand areas, and our storage services allow our customers to manage volatility in natural gas supply and demand, as well as price, throughout our markets. A shift in the supply of natural gas or the demand for natural gas in a particular market impacts the demand for our services in that market. 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 imported LNG, affect the demand for our services from both producers and consumers. 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. The types of customers that we serve and the terms on which we provide our services largely depend on the dynamics of natural gas supply and demand in our areas of operation. Changes in demand based on commodity price volatility will typically have a greater near-term impact on our interruptible services than on our firm services provided under longer-term contracts, while the longer-term trends in supply and demand in our markets have a larger impact on our overall customer and contract mix.

Customers

We transport and store natural gas for a broad mix of customers, including LDCs, utilities, direct industrial users, electric power generators, marketers, producers or other suppliers, and interstate and intrastate pipelines. 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 customers use our transportation and storage services for a variety of reasons. LDCs and electric power generators typically require a secure and reliable supply of natural gas over a sustained period of time to meet the needs of their customers. Frequently, these types of customers will enter into long-term firm transportation and storage contracts to ensure both a ready supply of natural gas and sufficient transportation capacity over the life of the contract. Producers of natural gas require the ability to deliver their product to market. Producers frequently enter into firm transportation contracts to ensure that they will have sufficient capacity available to deliver their product to delivery points with greater market liquidity. Marketers that generate income from buying and selling natural gas use our storage and transportation services to capitalize on price differentials over time or between markets. Generally demand for our storage services from marketers increases with natural gas price volatility. Our customer mix can vary over time and largely depends on the natural gas supply and demand dynamics in our markets.

Regulation

Government regulation of natural gas transportation and storage has a significant impact on our business. Our rates are regulated under FERC rate-making policies, and, in the case of our storage facility in Texas, by the TRC. 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 FERC. From time to time, certain revenues collected may be subject to possible refunds upon final FERC orders. For more information see “— Critical Accounting Policies and Estimates — Cost-Based Regulation” and “Business — Regulation — FERC Regulation.” Accordingly, estimates of rate refund reserves are recorded considering regulatory proceedings, advice of counsel and our evaluation of the net cumulative effect of all undecided regulatory matters, as well as other risks. The operations and maintenance of our assets are also governed by other federal and state regulatory agencies, including the Department of Transportation. For more information see “Business — Regulation” and “Business — Safety and Maintenance.”

How We Evaluate Our Operations

We evaluate our business on the basis of the following key measures:


	•	our contract mix and percentage of physical capacity sold, particularly the component of services that we provide under firm and interruptible contracts;

	•	our operating, general and administrative expenses;

	•	our Adjusted EBITDA; and

	•	our estimated cash available for distribution.

Contract Mix and Percentage of Physical Capacity Sold

We compete for transportation and storage customers based on the specific type of service a customer needs, operating flexibility, available capacity and price. We provide a significant portion of our transportation and storage services through firm contracts and derive a smaller portion of our revenues through interruptible contracts. We seek to maximize the portion of our 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 sets forth certain information regarding our assets, our contracts and our revenues, as of and for the year ended December 31, 2006:


													% of Physical
				Revenue Composition %									Capacity
				Firm Contracts									Subscribed			Weighted Average
				Capacity			Variable			Interruptible			Under Firm			Remaining Contract
Asset	Our Ownership %			Reservation Fees			Fees			Contracts			Contracts			Life (in years)(1)

East Tennessee		100.0	%		97.7	%		1.7	%		0.6	%		89.7	%		9.3
Gulfstream		24.5	%		85.6	%		2.9	%		11.5	%		68.7	%		20.2
Market Hub		50.0	%		90.0	%		0.0	%		10.0	%		100.0	%		2.4


(1)		The average life of each contract is calculated based on the average annual contract revenue for such contract’s remaining life.

Firm transportation service requires us to reserve pipeline capacity for a customer between certain receipt and delivery points. Firm customers generally pay a “demand” or “capacity reservation” fee based on the amount of capacity being reserved regardless of whether the capacity is used, plus a usage fee. Firm storage customers also reserve a specific amount of storage capacity, including injection and withdrawal rights, and generally pay a capacity reservation charge based on the amount of capacity being reserved plus an injection and/or withdrawal fee. Annual capacity reservation revenues derived from firm service generally remain constant over the life of the contract because the revenues are generated based upon the capacity reserved and not whether the capacity is actually used. The high percentage of our business derived from capacity reservation fees mitigates the risk to us of revenue fluctuations due to changes in near-term supply and demand conditions, and our ability to maintain or increase the amount of firm service we provide is key to assuring a consistent revenue stream.

Interruptible transportation and storage service is typically short term in nature and is generally used by customers that either do not need firm service or have been unable to contract for firm service. These customers pay only for the volume of gas actually transported or stored. Our obligation to provide this service is limited to available capacity not otherwise used by our firm customers, and customers receiving services under interruptible contracts are not assured capacity in our pipeline or storage facilities. We provide our interruptible service at competitive prices in order to position ourselves to capture short term market opportunities as they occur. We view interruptible service as an important part of our strategy to optimize revenues from our assets.

Operating, General and Administrative Expenses

Our operating, general and administrative expenses typically do not vary significantly based upon the amount of gas we transport or store. We obtain in-kind fuel reimbursements from shippers in accordance with each individual tariff or applicable contract terms. While expenses may not materially vary with throughput, our expenses can vary significantly from period to period. The timing of our expenditures during a year generally fluctuate with customer demands as we typically schedule planned maintenance during off-peak periods. Additionally, fluctuations in project development costs are impacted by the level of project development activity during a period and the timing of project approval. Changes in regulation can also impact our maintenance requirements and affect the timing and amount of our costs and expenditures. As an example, the Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006 set new standards for pipelines in assessing the safety and reliability of the pipeline infrastructure and we have incurred and will continue to incur additional costs,

as have other pipelines, to meet these standards. For more information see “Business — Safety and Maintenance.”

Adjusted EBITDA

We define our Adjusted EBITDA as net income plus interest expense, income taxes and depreciation and amortization less our equity in earnings of Gulfstream and Market Hub and other income (expenses), net, which primarily consists of non-cash allowance for funds used during construction, or AFUDC, and certain other items such as insurance recoveries. 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 different 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 such as investors, commercial banks and others, to assess:


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

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

	•	our 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 their financing methods and capital structure.

Cash Available for Distribution

We define our cash available for distribution as our Adjusted EBITDA plus cash available for distribution from Gulfstream and Market Hub, less net cash paid for interest expense and maintenance capital expenditures. Our cash available for distribution does not reflect changes in working capital balances. Our pro forma cash available for distribution for the year ended December 31, 2006 also includes our incremental general and administrative expense of being a publicly-traded partnership.

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

Adjusted EBITDA and cash available for distribution should not be considered alternatives to net income, operating income, cash from operations or any other measure of financial performance or liquidity presented in accordance with GAAP. Adjusted EBITDA and cash available for distribution exclude some, but not all, items that affect net income and operating income and these measures may vary among other companies. Therefore, Adjusted EBITDA and cash available for distribution as presented may not be comparable to similarly titled measures of other companies. For a reconciliation of these measures to their most directly comparable financial measure calculated and presented in accordance with GAAP, please see “Selected Historical and Pro Forma Financial and Operating Data — Non-GAAP Financial Measures.”

Results of Operations — Combined Overview

The following table and discussion is a summary of our combined results of operations for the years ended December 31, 2004, 2005 and 2006. The results of operations for Gulfstream and Market Hub are discussed in further detail following this combined overview discussion.


	Year Ended December 31,
	2004		2005		2006
			(In thousands)

Operating Revenues
Transportation of natural gas	$	78,594	$	77,703	$	80,577
Other		3,122		2,300		2,032

Total operating revenues		81,716		80,003		82,609

Operating Expenses
Operations, maintenance and other		26,081		24,648		21,831
Depreciation and amortization		21,492		23,640		18,986
Property and other taxes		518		5,264		4,177

Total operating expenses		48,091		53,552		44,994

Operating Income		33,625		26,451		37,615
Other Income and Expenses
Equity in earnings of unconsolidated affiliates		35,495		46,287		41,105
Other income and (expenses), net		1,491		552		1,780

Total other income and expenses		36,986		46,839		42,885

Interest Expense		8,258		8,506		8,151

Earnings before Income Taxes		62,353		64,784		72,349
Income Tax Expense		9,202		7,834		10,741

Net Income	$	53,151	$	56,950	$	61,608

Adjusted EBITDA(a)(b)	$	55,117	$	50,091	$	56,601
Cash Available for Distribution(b)(c)	$	73,784	$	77,526	$	80,378


(a)		We define Adjusted EBITDA as net income plus interest expense, income taxes and depreciation and amortization less our equity in earnings of Gulfstream and Market Hub and other income (expenses), net, which primarily includes non-cash AFUDC and certain other items such as insurance recoveries.

(b)		For a reconciliation of this measure to its most directly comparable financial measures calculated and presented in accordance with GAAP, please see “Selected Historical and Pro Forma Financial and Operating Data — Non-GAAP Financial Measures.”

(c)		We define cash available for distribution as our Adjusted EBITDA plus cash available for distribution from Gulfstream and Market Hub, less net cash paid for interest expense and maintenance capital expenditures. Our cash available for distribution does not reflect changes in working capital balances.

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

Operating Revenues — Combined operating revenues increased slightly by $2.6 million in 2006 compared to 2005. The increase was primarily due to a $2.6 million net increase from new firm transportation contracts.

Operating Expenses — Combined operating expenses decreased by $8.6 million or 16% in 2006 compared to 2005. The decrease was primarily due to the following factors:


	•	the capitalization in 2006 of $11.4 million in development costs related to the Jewell Ridge project, approximately $5.6 million of which was incurred and recognized as operating expense in prior periods;

	•	a decrease of $5.0 million in depreciation expense due to an increase in the estimated useful lives of certain assets, as agreed to in a negotiated rate settlement with customers of East Tennessee and approved by FERC; partially offset by:


	—	a $4.8 million increase in operations costs due to overhauls of two compressor units and a $1.2 million increase in insurance costs as a result of higher insurance market rates; and

	—	$3.0 million in increased non-recurring allocations from Spectra Energy Capital, LLC, or Spectra Energy Capital, related to financial re-engineering and other project costs.

Other Income and Expenses

Equity in Earnings of Unconsolidated Affiliates — Combined equity in earnings of unconsolidated affiliates decreased $5.2 million or 11% in 2006 compared to 2005. The decrease is attributable to decreased equity in earnings of $5.2 million from Market Hub, while equity in earnings from Gulfstream did not change from 2006 to 2005. For the factors impacting Gulfstream’s and Market Hub’s earnings, see the discussion included below of the results of operations of Gulfstream and Market Hub.

Other Income and (Expenses), Net — Combined other income and (expenses), net increased by $1.2 million in 2006 compared to 2005. This increase was primarily due to an increase in the equity component of allowance for funds used during construction (AFUDC) in 2006 as a result of the 2006 construction activity on the Jewell Ridge Lateral project.

Income Tax Expense — Combined income tax expense increased by $2.9 million or 37% in 2006 compared to 2005. This increase was primarily attributable to increased taxable income at East Tennessee.

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

Operating Revenues — Combined operating revenues decreased slightly by $1.7 million in 2005 compared to 2004. The decrease was due to the elimination of facility rentals and the elimination of a Gas Research Institute surcharge as well as reduced rates associated with the East Tennessee rate settlement.

Operating Expenses — Combined operating expenses increased by $5.5 million or 11% in 2005 compared to 2004. The increase was due to the following factors:


	•	a $6.0 million increase in project development costs, mostly related to the Jewell Ridge project;

	•	a $4.8 million increase in property and other taxes primarily due to an adjustment of tax reserves in 2004 associated with the resolution of outstanding ad valorem tax matters;

	•	a higher depreciation expense of $1.8 million related to the Patriot Extension project that was placed into service; partially offset by:

	•	a $5.2 million net increase of in-kind fuel recoveries from customers in 2004 in excess of the cost of compressor fuel used; and

	•	a $2.5 million decrease due to increased capitalized cost due to a higher level of construction activity.

Other Income and Expense

Equity in Earnings of Unconsolidated Affiliates — Combined equity in earnings of unconsolidated affiliates increased $10.8 million or 30% in 2005 compared to 2004. The increase is attributable to increased equity in earnings of $5.5 million from Gulfstream and increased equity in earnings from Market Hub of $5.3 million in 2005 compared to 2004. For the factors impacting Gulfstream and Market Hub’s earnings see the discussion included below of the results of operations of Gulfstream and Market Hub.

Other Income and (expenses), net — Combined other income and (expenses), net decreased by $0.9 million in 2005 compared to 2004, as a result of higher equity AFUDC in 2004 related to construction of the Patriot project.

Income Tax Expense — Combined income tax expense decreased by $1.4 million or 15% in 2005 compared to 2004. This net decrease was attributable to a decrease in the taxable income at East Tennessee.

Results of Operations — Unconsolidated Affiliates

We account for Gulfstream and Market Hub using the equity method of accounting. As such, our 24.5% interest in Gulfstream’s net operating results and our 50.0% interest in Market Hub’s net operating results are reflected as equity in earnings of unconsolidated affiliates in our Consolidated Statement of Operations. Due to the significance of Gulfstream’s and Market Hub’s equity in earnings to our results of operations, the following discussion addresses in greater detail the results of operations for 100% of Gulfstream and 100% of Market Hub.


	Years Ended December 31,
Gulfstream	2004		2005		2006
			(In thousands)

Operating Revenue	$	93,615	$	145,104	$	180,257
Operating Expenses		42,648		53,547		63,479
Other Income and Expenses		3,353		1,783		431
Interest Expense		9,092		25,540		48,787

Net Income	$	45,228	$	67,800	$	68,422

Our 24.5% share	$	11,081	$	16,611	$	16,763

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

Gulfstream’s net income increased slightly by $0.6 million to $68.4 million in 2006 from $67.8 million in 2005. The increase was primarily due to the following factors:


	•	a $38.5 million increase in natural gas transportation revenues primarily due to a significant new firm transportation contract; offset by

	•	a $3.3 million decrease in other revenue due to lower interruptible services;

	•	a $9.9 million increase in operating and maintenance expenses primarily due to $2.9 million of increased development costs for Phase III and Phase IV expansion projects, and $2.8 million of higher property and liability premiums due to increased insurance rates for wind-storm insurance coverage, and $2.7 million increase in Florida property taxes; and

	•	a $23.2 million increase in interest expense primarily as a result of $850 million in project financing entered into in October 2005.

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

Gulfstream’s net income increased by $22.6 million or 50% in 2005 compared to 2004. This increase was principally due to the following factors:


	•	a $49.9 million increase in natural gas transportation revenues primarily due to Phase II firm transportation contracts that began in February 2005 when these facilities were placed into service, and new interruptible transportation contracts; partially offset by:

	•	$3.8 million increase in depreciation and amortization expenses due to the placement of Phase II in-service in February 2005;

	•	$7.2 million increase in property and other taxes due to ad valorem tax on Phase II assets placed into service in February 2005; and

	•	$16.4 million increase in interest expense due to debt at Gulfstream issued in 2005, described above.

Market Hub


	Years Ended December 31,
	2004		2005		2006
			(In thousands)

Operating Revenue	$	65,843	$	77,929	$	78,804
Operating Expenses		18,577		19,763		38,048
Other Income and Expenses		1,533		1,146		10,553
Interest (Expense)/Income		30		41		(2,625	)

Net Income	$	48,829	$	59,353	$	48,684

Our 50% share	$	24,415	$	29,677	$	24,342

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

Market Hub’s net income decreased by $10.7 million or 18% in 2006 compared to 2005. The decrease was primarily due to the following factors:


	•	an $18.3 million increase in operating expenses primarily attributable to a $10.0 million increase in net in-kind fuel costs incurred over reimbursements from customers, $3.8 million in higher operations costs due to compressor overhauls and general maintenance and a $1.2 million increase in corporate cost allocations; partially offset by:

	•	a $9.4 million net increase in gains from asset dispositions, principally due to the recognition of a $9.8 million gain from the involuntary conversion of an asset arising from the property insurance settlement related to the 2004 cavern well-head fire at Moss Bluff; and

	•	a $0.9 million increase in operating revenues, primarily due to a $9.1 million increase in firm storage revenues due to expanded storage capacity and higher rates and a $2.8 million increase in interruptible storage revenues partially offset by a $6.2 million net reduction in business interruption insurance proceeds associated with lost revenue related to the 2004 cavern well-head fire at Moss Bluff and a $4.2 million decrease in net in-kind fuel recoveries over incurred fuel cost.

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

Market Hub’s net income increased by $10.5 million or 22% in 2005 compared to 2004. This increase was principally due to the following factors:


	•	a $12.1 million increase in operating revenues, due to the receipt of $8.0 million from a business interruption insurance claim in 2005 to reimburse Moss Bluff for revenue lost in 2004 due to the cavern well-head fire in 2004, described above and $4.2 million for net in-kind fuel recoveries over incurred fuel costs in 2005 compared to 2004; and

	•	a $1.2 million increase in operating expenses, primarily due to a $1.1 million increase in corporate cost allocations.

Future Trends and Outlook

We expect our business to continue to be affected by the following key trends. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about or interpretations of available information prove to be incorrect, our actual results may vary materially from our expected results. Please see “Risk Factors.”

Benefits from System Expansions. We expect that our results of operations for the year ending December 31, 2007 and thereafter will benefit from increased revenues associated with expansion projects recently completed or currently planned. For example, East Tennessee’s Jewell Ridge Lateral project completed in the fourth quarter of 2006 and its Patriot Extension project initially placed in service in 2003 are now generating increased revenues following significant capital expenditures during their development. Two fully-contracted expansion projects are currently being pursued for Gulfstream that will extend the system into South Florida and will increase its market delivery capability from 1.1 Bcf/d to 1.25 Bcf/d by early 2009, subject to Gulfstream’s receipt of approval for its pending applications with FERC. In addition, expansion projects are being pursued at Market Hub’s Egan storage facility, to increase its aggregate working gas storage capacity from a current capacity of 20 Bcf to 24 Bcf by 2008. An application is currently pending with FERC to further expand Egan to 32 Bcf by 2012. An expansion is also underway to increase the natural gas injection capability at Egan. This expansion will be placed into service during the summer of 2007, adding 22,800 horsepower of compression and increasing Egan’s injection capability by 0.5 Bcf/d to approximately 1.3 Bcf/d.

Growing Markets. According to the EIA, overall demand for natural gas consumption in the markets we serve is expected to grow by approximately 2.1% per year for the period from 2006-2012. We believe this growth will be driven by the construction of new natural gas fired electric generation plants in Florida and elsewhere to meet both a growing population base and a growing per capita demand for electricity. With the recent trend towards natural gas fired electric generation, demand for natural gas during the summer months to satisfy cooling requirements is now increasing. For example, according to the Florida Reliability Coordinating Council, natural gas used for electric generation in the Florida market is expected to grow by approximately 7.1% per year for the period from 2006-2015, from 556 Bcf in 2006 to 1,033 Bcf in 2015. Please see “Business — Natural Gas Industry Overview.”

Diversity of Supply Sources. Domestic gas production in the United States is not expected to keep pace with domestic consumption. According to the EIA, production in the lower 48 states is estimated to grow 0.7% per year, from 50.1 Bcf/d in 2006 to 54.3 Bcf/d in 2012, while U.S. natural gas demand in 2012 is estimated to be 67.3 Bcf/d. While supply in some areas in which we operate is increasing due to new discoveries and increased production, traditional supply in other areas in which we operate is beginning to decline. As supply from these areas declines, or becomes less attractive because of vulnerability to hurricanes and other disruptions, the national supply profile is shifting to new, and, in some cases, to non-conventional sources of gas, including basins in the Mid-Continent and Appalachia. A significant portion of the supply shortfall is expected to be met through LNG imports, which are expected to be delivered predominately through terminals along the Gulf Coast.

Influence of LNG Imports. LNG is expected to become an important part of the U.S. energy market. According to the EIA, LNG’s share of total U.S. gas supply could be as high as 17% by 2025. Unlike domestic production, however, LNG supply does not provide a steady stream of supply because deliveries are driven by spot prices that fluctuate with market dynamics. Given the extensive pipeline infrastructure and available gas processing capability in and around the region, the Gulf Coast is the target for approximately 15 of the 40 proposed U.S. onshore LNG terminals. LNG projects for this area are, on average, larger than those planned for other U.S. locations. In addition, due to the large existing industrial base located in the region and less anticipated resistance from the local population, many of these projects

may obtain the necessary regulatory approvals and be developed more expeditiously than proposed projects located in other areas of the country. Please see “Business — Natural Gas Industry Overview.”

Growth of Natural Gas Storage Facilities. Natural gas storage is becoming an increasingly important factor in the natural gas transportation marketplace, and will play a significant role in handling the increased deliveries of LNG expected in the coming years. As a consequence, a substantial number of natural gas storage projects have been announced and are under development, especially in the Texas and Louisiana areas. According to an October 2006 EIA report, as of July 2006, there were 38 underground storage projects underway in the United States with expected in-service dates between 2006 and 2008, of which 15 are new facilities and 23 are expansions. These projects, assuming full implementation, would increase the working gas capacity in the U.S. by 5% by the end of 2008, and include 16 storage projects underway in the Southwest (including Texas and Louisiana). The Southwestern region of the United States has the highest number of high-deliverability, salt-cavern storage facilities, and the demand for this type of storage is expected to continue to grow. Although an increased supply of storage competing with Market Hub’s storage facilities could negatively impact our operations, we believe our facilities are well positioned to take advantage of future growth opportunities.

Liquidity and Capital Resources

Our ability to finance operations, including to fund capital expenditures and acquisitions, to meet our indebtedness obligations, to refinance our indebtedness or to meet collateral requirements will depend on our ability to generate cash in the future. Our ability to generate cash is subject to a number of factors, some of which are beyond our control, including the impact of regulators on our ability to establish transportation and storage rates. Please see “Risk Factors.”

Historically, our sources of liquidity included cash generated from operations, cash received from Gulfstream and Market Hub, external debt and funding from Spectra Energy Capital. As mentioned previously, Market Hub was formerly a wholly owned subsidiary of Spectra Energy Capital and did not make distributions to its members. Market Hub will be required to make distributions of its available cash to its members following this offering. Please see “Certain Relationships and Related Party Transactions — Contracts with Affiliates — Market Hub.” Our cash receipts were historically deposited in Spectra Energy Capital’s bank accounts and cash disbursements were made from those accounts. Consequently, our historical financial statements have reflected no cash balances. Cash transactions processed on our behalf by Spectra Energy Capital were reflected in parent net investment as intercompany advances between us and Spectra Energy Capital. Following this offering, we plan to maintain our own bank accounts but will continue to rely on Spectra Energy personnel to manage our cash and investments through our management arrangements with Spectra Energy.

Subsequent to this offering, we expect our sources of liquidity to include:


	•	the retention of a portion of the proceeds from our initial public offering, as described below;

	•	cash generated from operations;

	•	cash distributions received from Market Hub and Gulfstream;

	•	borrowings under our $500 million credit facility;

	•	cash realized from the liquidation of United States Treasury and other qualifying securities that will be pledged under our credit facility;

	•	issuances of additional partnership units; and,

	•	debt offerings.

We expect to use the retained $8.7 million to fund working capital. We believe that cash generated from these sources will be sufficient to meet our short-term working capital requirements, long-term capital expenditure requirements and quarterly cash distributions.

Working Capital

Working capital is the amount by which current assets exceed current liabilities. Our working capital requirements will be primarily driven by changes in accounts receivable and accounts payable. These changes are primarily impacted by such factors as credit and the timing of collections from customers and the level of spending for maintenance and expansion activity.

We had working capital deficiencies of ($4.8) million and ($20.2) million at December 31, 2006 and 2005, respectively. This negative working capital was created by the historical treasury management arrangements with Spectra Energy Capital described above.

Changes in the terms of our transportation and storage arrangements have a direct impact on our generation and use of cash from operations due to their impact on net income, along with the resulting changes in working capital. A material adverse change in operations or available financing may impact our ability to fund our requirements for liquidity and capital resources.

Spectra Energy Partners Predecessor Combined Cash Flow

Combined net cash provided by operating activities, combined net cash (used in) provided by investing activities and combined net cash provided by (used in) financing activities for the years ended December 31, 2004, 2005 and 2006 were as follows:


	For the Years Ended December 31,
	2004			2005			2006
				(In thousands)

Net cash provided by operating activities	$	83,987		$	93,272		$	62,278
Net cash (used in) provided by investing activities		(34,269	)		92,827			(85,910	)
Net cash provided by (used in) financing activities		(49,718	)		(186,099	)		23,632

The investing and financing activities for our combined cash flows in 2005 were impacted by debt financing at Gulfstream. In October 2005, Gulfstream issued $500 million aggregate principal amount of 5.56% Senior Notes due 2015 and $350 million aggregate principal amount of 6.19% Senior Notes due 2025. The proceeds were used by Gulfstream to pay off a construction loan and the balance of the proceeds, net of transaction costs, of approximately $620 million was distributed to the partners based upon their ownership percentages. Our 24.5% share of this special distribution was $152.1 million, which was a return of capital that we had invested in Gulfstream during the construction period and which was recorded as a cash inflow from investing activities. We then distributed this cash to Spectra Energy, which was reflected as a $152.1 million cash outflow from financing activities. This distribution was in addition to a distribution of $29.6 million included in 2005 cash provided from operating activities.

Operating Activities — Combined net cash provided by operating activities decreased $31.0 million in 2006 compared to 2005, primarily due to $9.3 million in decreased distributions from Gulfstream and higher cash utilized for working capital of $33.8 million partially offset by lower current tax expense of $5.5 million, lower operations and maintenance expenses of $2.8 million, higher revenues of $2.6 million and other items of $1.2 million. The cash utilized for working capital increase of $33.8 million was comprised of $10.9 million of increased cash utilized for accrued taxes, $10.5 million for other current liabilities, $7.1 million for other current assets, $2.5 million for accounts payable and $2.8 million for other various working capital accounts. For 2005 compared to 2004, combined net cash provided by operating activities increased $9.3 million as a result of $15.9 million in increased distributions received from Gulfstream and reduced working capital requirements of $24.1 million partially offset by higher current tax expense of $25.4 million, higher property taxes of $4.7 million and other items of $0.6 million. The reduced working capital requirements of $24.1 million were comprised of $12.5 million of reduced working capital for other current assets, $10.9 million for other liabilities, $6.5 million for accounts payable, $4.8 million for other current liabilities, partially offset by $10.2 million of additional working capital for accrued taxes and $0.4 million for other accounts.

Investing Activities — Most of the year-over-year fluctuations in investing activities was the result of the one time distribution of $152.1 million from Gulfstream in 2005. Other year-over-year variances in net cash (used in) provided by investing activities were:


	•	For 2006 compared to 2005, an increase in cash used of approximately $26.6 million for capital expenditures primarily related to the Jewell Ridge Lateral expansion project of East Tennessee; and

	•	For 2005 compared to 2004, an increase in cash used of approximately $25.0 million for capital expenditures primarily related to the Jewell Ridge Lateral and Patriot Extension projects.

Financing Activities — Prior to our IPO, all of our cash flow was distributed as a dividend to Spectra Energy, as a result, the changes in cash flow from operating and investing activities impacted our cash flow from financing activities. Most of the year-over-year fluctuation in financing activities was the result of the distribution of $152.1 million to Spectra Energy in 2005. Other year-over-year variances in net cash provided by (used in) financing activities were:


	•	For 2006 compared to 2005, a decrease in cash distributed to Spectra Energy of $57.6 million as a result of higher capital expenditures and lower operating cash flow; and

	•	For 2005 compared to 2004, a net decrease in cash distributed to Spectra Energy of $15.8 million as a result of higher capital expenditures partially offset by higher operating cash flow.

Off Balance Sheet Arrangements

We do not have any off-balance sheet financing entities or structures to 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.

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

Capital Requirements

The transmission and storage businesses can be capital intensive, requiring significant investment to maintain and upgrade existing operations.

We categorize our capital expenditures as either maintenance capital expenditures or expansion capital expenditures. Maintenance capital expenditures are those expenditures required to maintain the existing operating capacity and service capability of our assets including the replacement of system components and equipment which is worn, obsolete, completing its useful life, or necessary to remain in compliance with environmental laws and regulations. Expansion capital expenditures improve the service capability of the existing assets, extend useful lives, increase transmission or storage capacities from existing levels, reduce costs or enhance revenues. We expect our maintenance capital expenditures and expansion capital expenditures for the twelve months ending June 30, 2008 to be $11.8 million and $81.4 million, respectively, including our capital contributions to Gulfstream and Market Hub.

Our historical expansion capital expenditures for East Tennessee were $75.0 million, $51.1 million and $27.6 million for the years ended December 31, 2006, 2005 and 2004, respectively. 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. After the completion of this offering, expansion capital expenditures may vary significantly based on our investment opportunities.

We expect to fund future capital expenditures with funds generated from our operations, borrowings under our new credit facility and the issuance of additional partnership units and debt offerings.

Description of Credit Agreement. In connection with the closing of this offering, we will enter into a $500 million credit facility, which includes both term and revolving borrowing capacity.

We expect that the credit facility will be available for general partnership purposes, including working capital, capital expenditures and acquisitions. We expect that we will incur approximately $50 million of term borrowings and $125 million of revolving borrowings under our credit facility at the closing of this offering. As a result, we will have approximately $325 million of remaining borrowing capacity immediately after the closing.

We will distribute the $50 million in term borrowings to subsidiaries of Spectra Energy in partial consideration for the assets contributed to us upon the closing of this offering. The term borrowings will be secured by an equal amount of United States Treasury and other qualifying securities we purchase with the proceeds from this offering. In the event the underwriters exercise their option to purchase up to an additional 1,725,000 common units from us in full, we will incur up to approximately $32.3 million in additional term borrowings and we will purchase and then pledge an equal amount of United States Treasury and other qualifying securities to further secure the additional borrowings under the credit facility. The proceeds of the additional term loan borrowings will be used to redeem from a subsidiary of Spectra Energy a number of common units equal to the number of common units issued upon exercise of the underwriters’ option, at a price per common unit equal to the proceeds per common unit before expenses but after underwriting discounts and a structuring fee. See “Use of Proceeds.”

We expect that our obligations under the revolving portion of our credit facility will be unsecured and that term borrowings will be secured at all times by the United States Treasury and other qualifying securities in an amount equal to or greater than the outstanding principal amount of the term loan. We expect that upon any prepayment of term borrowings, the amount of the revolving portion of our credit facility will be automatically increased to the extent that the repayment of our term borrowings is made in connection with a permitted acquisition or permitted capital expenditure. We expect that indebtedness under the credit facility will rank equally with all our outstanding unsecured and unsubordinated debt (except that the term loan will have a priority claim to the United States Treasury and other qualifying securities pledged to secure it).

We expect that the credit facility will prohibit us from making distributions of available cash to unitholders if any default or event of default (as defined in the credit facility) exists. In addition, we expect the credit facility will contain other various covenants. If an event of default exists under the credit facility, we expect that the lenders will be able to accelerate the maturity of all borrowings under the credit facility and exercise other rights and remedies. The credit facility is subject to a number of conditions, including the negotiation, execution and delivery of definitive documentation.

Total Contractual Cash Obligations. A summary of our total contractual cash obligations as of December 31, 2006, is as follows (dollars in thousands):


			Less Than 1						More Than 5
			Year		2-3 Years		4-5 Years		Years
	Total		(2007)		(2008 & 2009)		(2010 & 2011)		(Beyond 2011)

Long-term debt(1)	$	150,000	$	—	$	—	$	—	$	150,000
Interest on debt obligations(2)		51,390		8,565		17,130		17,130		8,565
Material/capital purchases		894		894		—		—		—
Right of way payments(3)		5,017		5,017

Total contractual cash obligations	$	207,301	$	14,476	$	17,130	$	17,130	$	158,565


(1)		Represents future principal repayments of notes payable.

(2)		Represents interest expense on notes payable, based on the stated interest rate on the notes of 5.71%.

(3)		Represents capital commitments for various right of way matters.

Debt Obligations. Our debt obligations consisted of the following at the dates indicated:


	December 31,
	2005		2006
	(In thousands)

Long-term debt(1)	$	150,000	$	150,000


(1)		Represents 5.71% senior notes issued by East Tennessee and due in 2012. The table does not reflect borrowings we expect to make at the closing of this offering under our new credit facility.

The separation of the Partnership from Spectra Energy may trigger a change in control provision of East Tennessee’s $150 million notes, whereby the Partnership may be required to repay the notes at face value if elected by the note holders. To the extent that the notes are repurchased, the Partnership intends to refinance the amount with revolving borrowings from the credit facility.

Gulfstream had outstanding indebtedness of $850 million as of December 31, 2005 and 2006, respectively.

Quantitative and Qualitative Disclosures About Market Risk

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

Changes in interest rates expose us to risk as a result of our issuance of fixed-rate debt. We monitor market debt rates to identify the need to mitigate this risk, including consideration of hedging activities, if needed. We have not previously entered into hedging contracts to mitigate this risk except for net sale swaps entered into by Gulfstream in anticipation of its $850 million in offering of senior notes in October 2005.

We are exposed to 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 lent by us to them generally under our parking and lending services and no-notice services. 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 and in some cases, require collateral agreements. Collateral agreements provide for a counterparty to post cash or letters of credit to the exposed party for exposure in excess of the established threshold. The threshold amount represents an unsecured credit, determined in accordance with our credit policy. Collateral agreements also provide that the inability to post collateral is sufficient cause to terminate contracts and liquidate all positions.

In addition our standard customer contracts contain adequate assurance provisions which allow us to suspend services, cancel agreements or continue services to the customer after the customer provides security for payment in a form satisfactory to us. For the year ended December 31, 2006, approximately 89% of our revenue is with customers who have an investment grade credit rating or equivalent based on an analysis performed by the Company.

Since the late 1990s, natural gas prices have risen from a general range of $2.00 to $4.00 per MMBtu to $6.00 to $8.00, with peaks above $15.00 MMBtu. This overall rise in both gas prices and gas price volatility has materially increased our credit risk related to gas loaned to customers. The highest amount of gas loaned out by us over the past 24 months at any one time to our customers has been approximately 10.5 Bcf. The market value of that volume, assuming an average market price of $8.00 per Mcf, would be approximately $84 million. Our credit exposure from gas loans is managed as part of the program described above, and Market Hub obtains security deposits as necessary from third parties and affiliates to cover any excess exposure.

If any significant customer should have credit or financial problems resulting in its delay or failure to repay the gas it owes us, it could have a material adverse effect on our liquidity, financial position and results of operation.

Critical Accounting Policies and Estimates

The accounting policies discussed below are considered by management to be critical to an understanding of our combined financial statements as their application places the most significant demands on management’s judgment. Due to the inherent uncertainties involved with this type of judgment, actual results could differ significantly from estimates and may have a material adverse impact on our results of operations, equity or cash flows. For additional information concerning our other accounting policies, please see the Notes to the financial statements of Spectra Energy Partners Predecessor included elsewhere in this prospectus.

Cost-Based Regulation. We account for our regulated operations at East Tennessee under the provisions of Statement of Financial Accounting Standards (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 would not be recorded under GAAP for non-regulated entities. Management continually assesses whether regulatory assets are probable of future recovery by considering factors such as applicable regulatory changes and recent rate orders applicable to other regulated entities. Based on this continual assessment, management believes the existing regulatory assets are probable of recovery. These regulatory assets are classified in the combined balance sheets as Regulatory Assets and Deferred Debits. We periodically evaluate the applicability of SFAS No. 71, and consider factors such as regulatory changes and the impact of competition. If cost-based regulation ends or competition increases, we may have to reduce certain of its asset balances to reflect a market basis lower than cost and write-off the associated regulatory assets. We had no regulatory liabilities for the periods included in the financial statements.

Goodwill. Goodwill represents the excess of purchase price over fair value of net assets acquired. We evaluate goodwill for potential impairment under the guidance of SFAS No. 142, “Goodwill and Other Intangible Assets.” Under this provision, goodwill is subject to an annual test for impairment. We have designated August 31 as the date it performs the annual review for goodwill impairment for its reporting units. Under the provisions of SFAS No. 142, 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 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 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 growth rates, regulatory stability and the ability to renew contracts, as well as other factors that affect revenue and expense forecasts. We did not record any impairment of its goodwill in 2006, 2005 and 2004 and there have been no additions, amortizations, or other changes in the carrying amount of goodwill during the years then ended. Goodwill of our sole operating segment, East Tennessee, was $118.3 million at December 31, 2006 and 2005.

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.

New Accounting Standards

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

BUSINESS

Overview

Our Assets

East Tennessee System. We own and operate 100% of the approximately 1,400-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 growing energy demands of the Southeast and Mid-Atlantic regions of the United States through its connection to 19 receipt points and more than 175 delivery points and its market delivery capability of approximately 1.3 Bcf/d of natural gas. East Tennessee also owns and operates an LNG storage facility in Kingsport, Tennessee with working gas storage capacity of approximately 1.0 Bcf and regasification capability of 150 MMcf/d.

Gulfstream System. We own a 24.5% interest in the approximately 690-mile Gulfstream interstate natural gas transportation system, which extends from Pascagoula, Mississippi and Mobile, Alabama across the Gulf of Mexico and into Florida. Gulfstream supports the fast growing south and central Florida markets through its connection to seven receipt points and 19 delivery points and its market delivery capability of approximately 1.1 Bcf/d of natural gas. Spectra Energy and The Williams Companies, Inc., respectively, own the remaining 25.5% and 50.0% interests in Gulfstream and jointly operate the system.

Market Hub System. We own a 50.0% interest in Market Hub, which owns and operates two high-deliverability salt cavern natural gas storage facilities located in Acadia Parish, Louisiana and Liberty County, Texas. These two facilities have aggregate working gas storage capacity of approximately 35 Bcf and interconnect with 12 major natural gas pipeline systems. Market Hub’s storage facilities offer access to natural gas supplies from Texas, Louisiana and growing imports of LNG to the Gulf Coast, and each facility interconnects with Spectra Energy’s Texas Eastern System. A subsidiary of Spectra Energy owns the remaining 50.0% interest in Market Hub and operates the system.

Our Operations

We transport and store natural gas for a broad mix of customers, including local gas distribution companies, or LDCs, 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 Federal Energy Regulatory Commission, or FERC, rate-making policies, and, in the case of our storage facility in Texas, by the Texas Railroad Commission, or TRC.

regardless of the actual pipeline or storage capacity utilized by a customer. When a customer utilizes the capacity it has reserved under these contracts, we also collect a variable fee based on the actual volume of natural gas transported or stored. This enables us to recover our variable costs. Variable fees are typically a small percentage of the total fees we receive from our firm contracts. We also derive a smaller portion of our revenues through interruptible contracts under which our customers pay fees based on their actual utilization of our assets for transportation and storage services and other related services. Customers who have executed interruptible contracts are not assured capacity in our pipeline and storage facilities. To the extent that physical capacity that is contracted for firm service is not being fully utilized, we can contract that capacity for interruptible service. The table below sets forth certain information regarding our assets, our contracts and our revenues and the percentage of our physical capacity sold under firm contracts, as of and for the year ended December 31, 2006:


																Weighted
				Revenue Composition %									% of Physical			Average
				Firm Contracts									Capacity			Remaining
				Capacity									Subscribed			Contract Life by
	Our Ownership			Reservation			Variable			Interruptible			Under			Revenue (in
Asset	Interest			Fees			Fees			Contracts			Firm Contracts			years)(1)

East Tennessee		100.0	%		97.7	%		1.7	%		0.6	%		89.7	%		9.3
Gulfstream		24.5	%		85.6	%		2.9	%		11.5	%		68.8	%		20.2
Market Hub		50.0	%		90.0	%		0.0	%		10.0	%		100.0	%		2.4


(1)		The average life of each contract is calculated based on the average annual contract revenue for such contract’s remaining life.

Business Strategies

Our primary business objective is to increase our cash distributions per unit over time by executing the following strategies:


	•	*Pursuing economically attractive organic expansion opportunities and greenfield construction projects.* We and our partners, including Spectra Energy, continually evaluate organic expansion and greenfield construction opportunities in existing and new markets that may increase the volume of natural gas and storage capacity reserved on our systems. For example, two fully-contracted expansion projects are currently being pursued for Gulfstream. These projects will extend the system into South Florida and will increase the system’s total capacity from 1.1 Bcf/d to 1.25 Bcf/d by early 2009 and have applications pending with FERC for approval. On the East Tennessee system, our recently completed Jewell Ridge Lateral and Patriot Extension expansions have provided East Tennessee’s customers with increased access to new sources of supply while extending our market reach and offering additional organic growth opportunities as these systems are further expanded. Finally, we and Spectra Energy are currently pursuing an expansion of the Market Hub storage facility in Egan, Louisiana to increase compression horsepower and increase its working gas storage capacity from 20 Bcf to 24 Bcf by 2008. An application is currently pending with FERC for approval to further expand Egan to 32 Bcf by 2012. Each of these expansions will allow the facility to accommodate additional LNG deliveries anticipated in the Gulf Coast region.

	•	*Increasing contracted capacity for natural gas transportation and storage on our systems by further expanding our customer base and diverse sources of natural gas supply.* To reduce the risk of natural gas supply interruptions, customers frequently seek capacity on pipelines and in storage facilities that have 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. Over time, we anticipate that LNG will become another significant source of

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		supply accessible through our assets, allowing us to increase natural gas volumes contracted for transportation and storage on our systems. Our existing and new customers also benefit from numerous pipeline interconnections, which further minimize the risk of supply interruptions by providing additional sources of natural gas supply. We will continue to seek new sources of natural gas supply to enhance the attractiveness of our systems to current and future customers.


	•	*Optimizing our existing assets and achieving 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. We provide our customers with an array of service offerings designed to address their needs while helping us to maximize the utilization of existing capacity of our systems. For example, we actively seek new customers with non-traditional peak load requirements to increase overall system utilization over time. Our assets are managed to ensure their operations keep fuel costs low and maintenance projects are pursued that provide the dual benefits of improving the integrity of our systems while also providing additional saleable capacity. To further meet both our and our customers’ needs, we intend to continue to utilize a variety of rate and contract structures to provide year-round optimization in the operation and utilization of our assets.

	•	*Growing through strategic and accretive acquisitions of assets from third parties, Spectra Energy or both.* We intend to expand our existing natural gas transportation and storage businesses by pursuing acquisitions that are accretive to distributable cash flow. In recent years, major independent and integrated oil and gas companies have sold pipeline and storage assets in an effort to focus their operations. We expect this trend to continue and believe we are well positioned to take advantage of future acquisition opportunities. We intend to pursue acquisitions either independently or jointly with Spectra Energy. In addition to making acquisitions from third parties, we may also have the opportunity to acquire assets directly from Spectra Energy, although we cannot predict whether any such opportunities will be made available to us. We believe our affiliation with Spectra Energy positions us to pursue a broader array of growth opportunities than may be available to our competitors.

Competitive Strengths

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


	•	Our ability to grow through organic expansion opportunities, greenfield construction projects and acquisitions, along with access to other business development opportunities, is enhanced by our affiliation with Spectra Energy. As the owner of our general partner and a 79.6% limited partner interest in us, and the joint owner of our Gulfstream and Market Hub assets, Spectra Energy is motivated to promote and support the successful execution of our business plan, and to pursue projects that directly or indirectly enhance the value of our assets. For example, East Tennessee benefits from its interconnections with Spectra Energy’s Texas Eastern transportation system and Saltville gas storage business, and Gulfstream should benefit from additional natural gas supplies originating from Spectra Energy’s new interconnected Southeast Supply Header, or SESH, joint venture expected to be completed in 2008. Through our relationship with Spectra Energy, we will have access to a significant pool of management talent, strong commercial relationships throughout the energy industry and access to Spectra Energy’s broad operational, commercial, technical, risk management and administrative infrastructure. Spectra Energy has a long history of successfully pursuing and consummating natural gas transportation and storage operations acquisitions through a disciplined acquisition strategy focused on acquiring complementary assets and integrating the acquired assets into its operations. Spectra Energy has completed over $10 billion in acquisitions since 2000.

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	•	*Our natural gas transportation assets are strategically located to transport natural gas from a number of diverse supply regions to high-demand end-use markets.* Our pipeline systems have access to a diverse range of natural gas supply regions, including the onshore and offshore Gulf Coast, Mid-Continent and Appalachian regions, both directly and through interconnections with numerous interstate and intrastate pipelines. Our pipeline systems transport natural gas directly to rapidly growing, high-demand markets in the Southeast, including Florida, Tennessee, Virginia, Georgia and North Carolina, and indirectly supply the Mid-Atlantic and Northeast markets through interconnections with other interstate pipelines. Our ability to reliably transport gas from diverse supply regions makes us attractive to customers that are consumers of natural gas, and our access to multiple high-demand end-use markets is appealing to customers that are producers of natural gas. Together, these attributes increase the flexibility and reliability of our transportation offerings and allow us to increase the volumes of natural gas contracted for transportation and storage on our systems.

	•	*Our storage assets are strategically positioned to capitalize on expected increased demand for natural gas storage.* Over time, we expect imported LNG to fill a portion of the gap between traditional sources of natural gas supply and the growing demand for natural gas in the United States. Accordingly, we anticipate increased demand for natural gas storage as LNG imports to the Gulf Coast are significantly increased. LNG is typically delivered to the United States in large tanker shipments, with significant supplies of natural gas in a single shipment. Because demand for natural gas is relatively constant, natural gas storage will be an important component in balancing the LNG supply chain. Our storage assets are strategically located in the Gulf Coast region in proximity to anticipated LNG imports. As of February 16, 2007, there were two LNG terminals operating in the Gulf of Mexico or the Gulf Coast area, and 14 out of the 15 additional LNG terminals proposed for the Gulf Coast region had already received approval for construction.

	•	*Our cash flow is relatively stable due to the high percentage of our assets’ revenues obtained from capacity reservation fees and the long-term nature of our contracts.* We provide a significant portion of our pipeline transportation and storage services under firm, fee-based contracts for terms ranging up to 23 years. Our systems have weighted average remaining contract lives based on contracted revenues of approximately 9.3 years for East Tennessee, 20.2 years for Gulfstream and 2.4 years for Market Hub. Capacity reservation fees represented approximately 97.7%, 85.6% and 90.0% of East Tennessee’s, Gulfstream’s and Market Hub’s revenues, respectively, for the year ended December 31, 2006. This contract structure reduces the risk of revenue fluctuations caused by changes in weather or changing supply and demand conditions and therefore provides us with greater stability of cash flows. Additionally, we have little direct commodity price exposure, as we generally do not own the gas we transport for our customers and are entitled to reimbursement for natural gas used as fuel in most of our operations.

	•	*Our management team has significant experience in the management of natural gas transportation and storage and energy industries.* Our general partner’s management team has extensive experience in building, acquiring, integrating and managing energy assets in a reliable and cost-effective manner and includes some of the most senior officers of Spectra Energy. On average, the members of our general partner’s management team have over 20 years of experience in the energy industry, with significant commercial, operational, acquisition and business development expertise.

	•	*Our high quality assets have been well maintained.* Our natural gas pipelines and storage facilities consist of high quality assets that have been well maintained, resulting in low cost, efficient operations. Our recently constructed Gulfstream and Market Hub systems utilize the latest available natural gas transportation and storage equipment and technology. We have been recognized by the industry for our use of superior maintenance practices aimed at improving the reliability of our assets and sustaining their useful life. Additionally, Spectra Energy, through its role in the Interstate Natural Gas Association of America, has actively shaped new industry maintenance regulations such as the U.S. Department of Transportation’s Gas Transmission Pipeline Integrity Management program, and has been an industry leader in implementing pipeline integrity standards.

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Our Relationship with Spectra Energy

One of our principal attributes is our relationship with Spectra Energy, which will own our general partner and a significant interest in us following this offering. Spectra Energy is comprised of the former natural gas businesses of Duke Energy and became a stand-alone publicly traded company in January 2007. Spectra Energy owns and operates a large and diversified portfolio of complementary natural gas-related energy assets and is one of North America’s leading midstream natural gas companies. Spectra Energy, which trades on the New York Stock Exchange under the symbol “SE,” serves three key links in the natural gas value chain: gathering and processing, transportation and storage and distribution. Through its interests in five U.S. pipeline systems and three Canadian pipeline systems, Spectra Energy owns and operates one of the largest long-haul natural gas pipeline networks in North America consisting of approximately 17,500 miles of transportation pipelines. In addition, Spectra Energy is one of the largest operators of natural gas storage in North America with eleven storage facilities with total working gas capacity of approximately 265 Bcf (including East Tennessee’s LNG facility and Market Hub), and owns a 50.0% interest in DCP Midstream, LLC (previously known as Duke Energy Field Services, LLC), which is the largest natural gas liquids producer in North America. DCP Midstream, LLC owns the general partner interest and a 40.7% limited partner interest in DCP Midstream Partners, LP, which is a midstream master limited partnership.

Upon the completion of this offering, Spectra Energy will own our 2% general partner interest, all of our incentive distribution rights and a 79.6% limited partner interest in us. We will enter into an omnibus agreement with Spectra Energy and some of its affiliates that will govern our relationship with them regarding certain reimbursement and indemnification matters. Please read “Certain Relationships and Related Party Transactions — Omnibus Agreement.” While our relationship with Spectra Energy and its subsidiaries is a significant attribute, it may also be a source of conflicts. For example, neither Spectra Energy nor any of its affiliates are prohibited from competing with us. Spectra Energy and its affiliates may acquire, construct or dispose of assets in the future without any obligation to offer us the opportunity to purchase or construct those assets. Please read “Conflicts of Interest and Fiduciary Duties.”

Natural Gas Industry Overview

Natural gas is a critical component of energy consumption in the United States. The U.S. natural gas pipeline grid transports natural gas from producing regions to customers, such as LDCs, industrial users and electric generation facilities. Interstate pipelines carry natural gas across state boundaries and are subject to FERC regulation on (1) the rates charged for their services, (2) the terms and conditions of their services, and (3) the location, construction and abandonment of their facilities. Intrastate pipelines transport natural gas within a particular state and are typically not subject to FERC regulation. At the close of 2004, based on data from the EIA, the U.S. natural gas pipeline grid included 107 interstate systems and more than 90 intrastate systems which collectively accounted for over 297,000 miles of pipeline with a combined 178 Bcf/d of natural gas transportation capacity.

Natural gas storage plays a vital role in maintaining the reliability of gas available for deliveries. Natural gas is typically stored in underground storage facilities, including salt dome caverns and depleted reservoirs. Storage facilities are utilized by (1) pipelines, to manage temporary imbalances in operations, (2) natural gas end-users, such as LDCs, to manage the seasonality of demand and to satisfy future natural gas needs and (3) independent natural gas marketing and trading companies in connection with the execution of their trading strategies. Natural gas storage is expected to become an increasingly important component in managing the supply and demand imbalance created by significant LNG shipments.

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Natural Gas Demand

Substantially all natural gas consumed in the United States is transported to the ultimate end-user on the natural gas pipeline grid. Therefore, utilization of the pipeline grid is highly correlated with growth in domestic consumption of natural gas. According to EIA, natural gas consumption in the United States is expected to grow from 60.2 Bcf/d in 2005 to 70.1 Bcf/d in 2017, or by approximately 1.3% per year.

U.S. Natural Gas Consumption

Source: Energy Information Administration, February 2007.

The industrial and electricity generation sectors are the largest users of natural gas in the United States. During the three years ended December 31, 2006, these two sectors accounted for approximately 57% of the total natural gas consumed in the United States. Additionally, significant natural gas demand comes from the residential and commercial sectors.

Demand for natural gas is usually greater during the winter, primarily due to residential and commercial heating applications. Natural gas produced in excess of that which is used during the summer months is typically stored to meet the increased demand for natural gas during the winter months. However, with the recent trend towards natural gas fired electric generation, demand for natural gas during the summer months is now increasing to satisfy additional electricity requirements for residential and commercial cooling. For example, according to a July 2006 Florida Reliability Coordinating Council report, natural gas used for electric generation in the Florida market is expected to grow by approximately 7.1% per year for the period from 2006-2015, increasing from 556 Bcf in 2006 to 1,033 Bcf in 2015. This growth is largely due to an increasing demand for natural gas fired electric generation to meet both a growing population base and a growing per capita demand for electricity. In addition, according to the EIA, overall demand for natural gas consumption in the markets we serve is expected to grow by approximately 2.1% per year for the period from 2006-2012, from 4.5 Bcf/d in 2006 to 5.1 Bcf/d in 2012.

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Natural Gas Supply

According to the EIA, domestic gas production in the United States is not expected to keep pace with domestic consumption. Production in the lower 48 states is estimated to grow 0.7% per year, from 50.1 Bcf/d in 2005 to 54.3 Bcf/d in 2017. This compares to estimated U.S. natural gas demand in 2012 of 67.3 Bcf/d.

U.S. Natural Gas Production

Source: Energy Information Administration, February 2007.

While supply in certain areas in which we operate is experiencing an increase in production and reserves, traditional supply in other regions of the country in which we operate is beginning to decline. As supply from these areas declines, or becomes less attractive because of vulnerability to hurricanes and other disruptions, the national supply profile is shifting to new, and, in some cases, to non-conventional sources of gas. The bulk of this supply shortfall is expected to be met through natural gas imports from Canada as well as through LNG imports, the majority of which are expected to be delivered through terminals along the U.S. Gulf Coast.

The Gulf Coast region of the United States, which includes offshore Gulf of Mexico and East Texas, is the most prolific U.S. natural gas producing region. Based on data from EIA, the Gulf Coast region accounted for approximately 46.5% of U.S. natural gas supply in 2005, producing approximately 22.6 Bcf/d. The EIA projects aggregate gas production from this region for the period from 2006 to 2012 to grow approximately 0.9% per year. According to the EIA, natural gas production from onshore conventional sources and shallow waters in the Gulf of Mexico is expected to decline, though this decline is expected to be more than offset by expanding natural gas exploration and development activities in onshore unconventional tight gas plays, such as the Barnett Shale and Bossier Sands of North and East Texas, as well as increased exploration activities in deepwater Gulf of Mexico.

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LNG imports are expected to grow on average by 16% per year for the period between 2005 and 2017. The table below shows the EIA’s estimate of LNG imports into the Gulf Coast region through 2017.

U.S. Liquefied Natural Gas import Volume

Source: Energy Information Administration, February 2007.

LNG is expected to become an important part of the U.S. energy market. According to the EIA, LNG’s share of total U.S. natural gas supply could be as high as 17% by 2025. Unlike domestic production however, LNG imports will not provide a steady stream of supply because the number and timing of deliveries are driven by spot prices that fluctuate with market dynamics, and individual deliveries involve the receipt of large volumes within a relatively short period of time. Given the extensive pipeline infrastructure and available natural gas processing capability in and around the region, the Gulf Coast is the target for approximately 15 of the 40 proposed U.S. onshore LNG terminals. LNG projects for this area are, on average, larger than those planned for other U.S. locations. In addition, due to the large existing industrial base located in the region and less anticipated resistance from the local population, more of these projects are likely to obtain the necessary regulatory approvals and be developed more expeditiously than proposed projects located in other areas of the country.

Two additional aspects of natural gas supply are particularly relevant for owners and operators of interstate pipeline systems. The first aspect is the desire by natural gas customers and regulators for greater diversity of natural gas supply sources. Supply disruptions caused by hurricanes and other factors have highlighted the importance to customers of access to multiple supply basins. An example of the way in which pipeline companies can help address this need is the SESH 50/50 joint venture between Spectra Energy and CenterPoint Energy. SESH, comprised of 36” and 42” pipelines, will diversify Gulfstream’s supply sources by bringing natural gas produced in the onshore Louisiana, East Texas and Mid-Continent supply regions to a new interconnect with Gulfstream. SESH is expected to be completed in 2008.

The second aspect of natural gas supply relevant to owners and operators of interstate pipeline systems is the need for improved takeaway capacity from certain natural gas producing regions. For example, certain natural gas producing regions, such as the Appalachian Basin, will be an important part of U.S. natural gas supply in the future because of their long-lived natural gas reserves. Although the Appalachian Basin is one of the more mature gas producing regions in the United States, it has suffered in recent years from below average natural gas pricing due to inadequate transportation to neighboring markets. Regional pipeline expansion projects such as East Tennessee’s Patriot Extension and Jewell Ridge Lateral expansions have

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resulted in improved takeaway capacity and have therefore enabled certain Appalachian producers to sell their natural gas at a premium to regional benchmark prices.

Our Asset Portfolio

East Tennessee Natural Gas System

General. We own and operate 100% of the approximately 1,400 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. Since acquiring East Tennessee in 2000, Spectra Energy has almost doubled the market delivery capability of the East Tennessee pipeline by investing in expansion projects designed to meet the growth needs of its traditional customers and reach new customers in adjacent markets. As a result, East Tennessee has evolved to become a major transportation link between markets in the Mid-Atlantic and supply sources previously inaccessible to those markets, such as Appalachian production, neighboring long haul pipelines and large salt cavern storage facilities.

East Tennessee is connected to 19 receipt points and more than 175 delivery points and has a market delivery capability of approximately 1.3 Bcf/d of natural gas to support the growing energy demands of the Southeastern and Mid-Atlantic regions of the United States. East Tennessee is also connected to Spectra Energy’s 4 Bcf Saltville gas storage facility, which is a source of additional supplies of natural gas for transportation. East Tennessee has pipeline diameters ranging from 8” to 24” and has 21 compressor stations with 97,000 horsepower of compression.

We also own and operate East Tennessee’s LNG storage facility in Kingsport, Tennessee, with total working gas capacity of approximately 1.0 Bcf and regasification capability of 150 MMcf/d. The facility provides our customers with turn-key services consisting of the liquefaction of natural gas and the storage and regasification of LNG.

In addition to field operations offices along the pipeline, East Tennessee has an office in Knoxville, Tennessee that conducts commercial activities in conjunction with our Houston-based staff.

In 2003, East Tennessee placed into service the approximately $300 million Patriot Extension, which linked East Tennessee with markets in North Carolina and the broader Mid-Atlantic. The Patriot Extension includes 95 miles of new 24” pipeline from East Tennessee’s mainline to an interconnection point on The Williams Companies’ Transco pipeline in North Carolina and has added approximately 400 MMcf/d of incremental system capacity. By providing access to natural gas deliveries to the North Carolina and Mid-Atlantic markets through an interconnection with the Transco pipeline, the Patriot Extension provides a desirable outlet for new supplies of Appalachian production accessed by the Jewell Ridge Lateral expansion project. The approximately $60 million Jewell Ridge Lateral, placed into service in October 2006, is a 32-mile, 20” pipeline extending from East Tennessee’s mainline to an interconnection with the Cardinal States Gathering System, where it can access up to 228 MMcf/d of new and existing Appalachian production.

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East Tennessee Customers. East Tennessee has approximately 160 firm transportation contracts with over 60 customers, including LDCs, utilities, direct served industrials, natural gas marketers and producers and power generators. East Tennessee’s three largest customers for the year ended December 31, 2006 were Atmos Energy Corporation, KGen Partners and AGL Resources, which accounted for approximately 18%, 13% and 10% of East Tennessee’s revenues, respectively. Since Spectra Energy’s acquisition of East Tennessee in 2000, East Tennessee’s revenue from firm transportation customers has changed from predominately utilities and industrial end-users to a mix of utilities, industrial end-users, power generators, natural gas marketers and producers and large LDCs in new market areas such as North Carolina and Virginia. In 2000, 94% of East Tennessee’s total capacity was utilized by utilities and industrial end-users while that same customer group decreased to 64% of East Tennessee’s capacity in 2006. As a result of recent supply and market expansion projects, East Tennessee has added several significant new customers to the system, including CNX Gas Corporation, Washington Gas Light, Piedmont Natural Gas, Carolina Power & Light (Progress Energy) and Sequent Energy. These customers are expected to significantly contribute to East Tennessee’s revenue in 2007, and represent a significant change from East Tennessee’s historical customer mix.

Demand from East Tennessee’s customers is expected to continue to increase, primarily due to additional demand for natural gas-fired electric generation and residential consumers’ movement from heating oil-based home heating systems to natural gas-fired furnaces.

East Tennessee Contracts. East Tennessee contracts with its customers to provide firm and interruptible transportation services. East Tennessee’s firm transportation service customers generally pay fees 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 that enables us to recover certain variable

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costs. 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 East Tennessee’s FERC-approved natural gas tariff. East Tennessee can agree to discount services or in certain cases can enter into negotiated rate agreements that, with FERC approval, can have rates or other terms that are different than those provided for in the FERC tariff. The rates in the majority of firm contracts are subject to the maximum rates prescribed in East Tennessee’s 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 East Tennessee 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. For a discussion of the regulatory influences on East Tennessee’s contracts, see “— Regulation . ”

East Tennessee also provides interruptible transportation services under which gas is transported for customers when operationally feasible and customers pay only for the actual volume of gas transported. Under both its firm transportation and interruptible transportation contracts, East Tennessee 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.

Under East Tennessee’s firm LNG storage service contracts, its customers are allowed to inject specified volumes of natural gas into the LNG facility during the summer months and withdraw the same volume of natural gas during the winter months.

As of December 31, 2006, East Tennessee’s firm transportation and storage contracts had a weighted average remaining life of approximately 9.3 years. For the year ended December 31, 2006, approximately 97.7% of East Tennessee’s revenues were derived from capacity reservation charges under firm contracts (including LNG storage services), approximately 1.7% of East Tennessee’s revenues were derived from variable usage fees under firm contracts and approximately 0.6% of East Tennessee’s revenues were derived from interruptible transportation contracts.

East Tennessee 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, we are the sole source of interstate natural gas transportation for many of the firm capacity customers that transport natural gas on East Tennessee. At both ends of our system, we are subject to competition from other pipelines. For example, our customers on the southeastern end of our system in Alabama, Georgia and Tennessee are directly served by other interstate pipelines, as are some customers on the western and northeastern ends of our system.

Much of East Tennessee’s recent growth has come from expansion opportunities into the Southeastern market area, including customers located adjacent to the Transco pipeline in the Carolinas and the lower Mid-Atlantic states. Many of these customers were formerly solely supplied by Transco, and East Tennessee provides them with alternative sources of natural gas supply through our access to Appalachian natural gas production and additional natural gas storage facilities through the Patriot Extension. East Tennessee provides customers in this market with a lower cost alternative for incremental supply additions in direct competition with the Transco pipeline.

Natural gas is in direct competition with electricity for residential and commercial heating demand in East Tennessee’s market area. While this competition does not directly affect our firm sales, our 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 our customers’ demand requirements, East Tennessee has already benefited from the addition of new natural gas fired electric generation constructed in proximity to our pipeline.

An increase in competition in the region served by East Tennessee could arise from new ventures or expanded operations from existing competitors. Other competitive factors include the quantity, location and

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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 our competitors.

East Tennessee Natural Gas Supply. The majority of East Tennessee’s gas supply comes from the Gulf Coast region through Tennessee Gas, as its primary supplier, as well as through Texas Eastern and to a lesser degree Southern Natural Gas and Columbia Gulf. East Tennessee also receives natural gas supply from the Appalachian region through Equitable Resources. East Tennessee also recently began to receive natural gas supply from CNX Gas through the Jewell Ridge Lateral. Natural gas withdrawn from East Tennessee’s LNG storage facility and other on-system storage fields, including Spectra Energy’s Saltville natural gas storage facility, provide East Tennessee with additional supply sources used to supplement peaking demand. Midwestern Natural Gas has announced that it expects to complete a new pipeline interconnection with East Tennessee by the end of 2007 that will provide additional natural gas supply to East Tennessee.

Gulfstream Natural Gas System

General. We own a 24.5% interest in the approximately 690-mile Gulfstream interstate natural gas transportation system. Gulfstream is an interstate natural gas pipeline with market delivery capacity of approximately 1.1 Bcf/d that runs from Pascagoula, Mississippi and Mobile, Alabama across the Gulf of Mexico and into the fast growing south and central Florida market. Gulfstream’s market area is characterized by strong population growth and increasing per capita energy consumption. The Gulfstream pipeline is primarily 30” and 36” in diameter and currently includes approximately 242 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. Gulfstream’s facilities also include gas treatment facilities and compressor station in Coden, Alabama. The compressor station contains three 37,900 horsepower compressor units, one of which serves solely as a back-up unit in the event of an outage of any of the other units.

Gulfstream customers have access to seven supply injection points in Mississippi and Alabama with approximately 3.4 Bcf/d of aggregate natural gas interconnect capacity. Natural gas is delivered by Gulfstream to 19 delivery points throughout southern and central Florida.

Gulfstream was jointly developed by Spectra Energy and The Williams Companies in two phases at a total cost of approximately $1.7 billion. Phase I of the system consisted of the initial 582 miles of pipeline and became operational in May 2002, and Phase II consisted of an additional 110 miles of pipeline that was placed in service in February 2005. Two fully-contracted expansion projects are currently being pursued for Gulfstream that will improve the system’s overall utilization extending the system into South Florida and increase its total capacity from 1.1 Bcf/d to 1.25 Bcf/d by early 2009.

The estimated $135 million Phase III project will fully subscribe the existing 1.1 Bcf/d of mainline capacity by serving Florida Power & Light Company’s planned 2,200 MW plant in Palm Beach County through a 35 mile, 30” pipeline extension. The estimated $117 million Phase IV project will increase mainline capacity to 1.25 Bcf/d through a significant addition of compression capability and an 18-mile, 20” pipeline extension to Progress Energy’s Bartow plant in Pinellas County. Both of these expansions are supported by customer contracts having 23-year initial terms. Further expansions of this pipeline system are feasible through the addition of increased compression horsepower and the construction of additional pipelines in our existing rights of way. FERC certificate approval is required prior to commencement of construction of the Phase III and Phase IV projects. Certificate applications for these projects are currently pending before FERC.

A subsidiary of Spectra Energy retains a 25.5% interest in Gulfstream and a subsidiary of The Williams Companies continue to own the remaining 50.0% interest. Spectra Energy provides the business and commercial functions for Gulfstream while The Williams Companies provides the technical functions. Please see “Certain Relationships and Related Party Transactions — Contracts with Affiliates — Gulfstream Limited Liability Company Agreement” for additional information about the terms of the Gulfstream limited liability company agreement.

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Gulfstream Customers. Gulfstream currently has 11 long-term firm transportation contracts with 9 shippers, comprised of electric utility companies and LDCs, for the transportation of 0.75 Bcf of natural gas per day which represents approximately 69% of Gulfstream’s overall capacity. For the year ended December 31, 2006, Florida Power & Light Company, Florida Power Corporation and Tampa Electric Company and its affiliates accounted for approximately 50%, 22%, and 10%, respectively, of Gulfstream’s revenues. As noted above, the completion of the Gulfstream Phase III project will fully subscribe the remaining 0.35 Bcf/d of mainline capacity.

Demand growth in Gulfstream’s markets is expected to be strong, with our Florida electric utility customers expected to add 16,000 MW of new peak power generation from 2007 to 2015, according to The 2006 Regional Load and Resource report published by the Florida Reliability Coordinating Council. Approximately half of this incremental electric generation is anticipated to be gas fired, requiring over 1.0 Bcf/d of new firm pipeline capacity. We intend to attempt to capture a majority portion of this increased demand.

Gulfstream Contracts. Gulfstream contracts with its customers to provide firm and interruptible transportation services. Gulfstream also provides interruptible park and loan services as well as 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 FERC. As of

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December 31, 2006, Gulfstream’s firm transportation and storage contracts had a weighted average remaining life of approximately 20.2 years. For the year ended December 31, 2006, approximately 85.6% of Gulfstream’s revenues were derived from capacity reservation charges under firm contracts, approximately 2.9% of Gulfstream’s revenues were derived from variable usage fees under firm contracts and approximately 11.5% of Gulfstream’s revenues were derived from interruptible transportation contracts.

Gulfstream 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, a subsidiary of Citrus Corp., which owns an approximately 5,000-mile pipeline extending from south Texas to south Florida with mainline capacity of 2.1 Bcf/d. Florida Gas Transmission plans to upgrade its pipeline to receive gas in Jacksonville, Florida from Southern Natural Gas’ proposed Cypress pipeline, which is expected to extend from its existing pipeline in Chatham County, Georgia and interconnect with a Florida Gas Transmission pipeline in Clay County, Florida.

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, the ability to offer service from multiple storage locations, and the cost of service and rates offered by our competitors.

Gulfstream Natural Gas Supply. 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 interconnected to numerous supply pipelines in the Mobile Bay area. Currently, shippers have the option to inject supply at seven 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

In June of 2008, Gulfstream expects to have access to supplies delivered by Spectra Energy’s SESH joint venture. SESH will originate in Perryville, LA, interconnect with Gulfstream and provide our customers with access to approximately 1.0 Bcf/d of increasing production from Louisiana, East Texas and the Mid-Continent region. Capacity commitments by existing Gulfstream customers make up the majority of the transportation capacity commitments to the SESH project.

Market Hub System

General. We own a 50.0% interest in Market Hub, the owner and operator of two high deliverability salt cavern storage facilities located in Acadia Parish, Louisiana and Liberty County, Texas. These two facilities have aggregate working gas storage capacity of approximately 35 Bcf and interconnect with a total of 12 major natural gas pipeline systems. Market Hub’s storage facilities are capable of being fully or partially filled and depleted, or “cycled,” multiple times per year. This cycling capability is a significant service component Market Hub offers to its customers, providing them with additional operating and financial flexibility. Market Hub’s storage facilities provide storage for natural gas supplies from Texas, Louisiana and growing Gulf Coast LNG supplies and are strategically located near several natural gas transportation systems, including Spectra Energy’s Texas Eastern pipeline system. A subsidiary of Spectra Energy owns the remaining 50.0% interest in Market Hub and operates the system. Please see “Certain Relationships and Related Party Transactions — Contracts with Affiliates — Market Hub Limited Liability Company Agreement” for additional information about the terms of the Market Hub limited liability company agreement.

The Egan storage facility, located in Acadia Parish, Louisiana, has a working gas capacity of approximately 20 Bcf, and includes a 38-mile pipeline system that interconnects with seven major natural gas pipelines. Egan offers access to Gulf Coast, Midwest, Southeast and Northeast markets served by

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pipeline interconnects with Tennessee Gas, Texas Eastern, Columbia Gulf, ANR, Texas Gas, Trunkline and Florida Gas. Since acquiring Market Hub in 2000, Spectra Energy has initiated cavern expansions at Egan totaling 24 Bcf that are projected to bring the total working capacity of the facility to 24 Bcf by 2008 and to 32 Bcf by 2012, and has initiated an approximately 22,800 horsepower compression expansion project designed to increase peak injection capacity. Market Hub must obtain FERC certificate approval prior to the commencement of construction of the expansion project designed to increase working gas storage capacity at Egan from 24 Bcf to 32 Bcf. An application for that project is currently pending before FERC.

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 five major pipeline systems. Moss Bluff offers access to Texas intrastate, Northeast and Midwest markets served by pipeline interconnects with Texas Eastern, Natural Gas Pipeline of America, Kinder Morgan Tejas, Kinder Morgan Texas and Enterprise Intrastate. Since acquiring Market Hub in 2000, Spectra Energy has expanded the storage capacity at Moss Bluff by approximately 4 Bcf and is currently considering additional capacity expansions.

Moss Bluff and Egan offer a range of flexible market-based storage services including firm storage, interruptible storage, wheeling, and parks and loans. These flexible services allow our customers to manage their daily supply-demand balancing needs, and are especially attractive to customers, such as LNG and power companies, that require abbreviated injection and withdrawal cycles. Because Egan and Moss Bluff are interconnected with major pipeline infrastructure and located near several proposed and existing LNG terminals, both facilities should be well-positioned to benefit from future deliveries of LNG to the Gulf Coast of the United States.

Market Hub Customers. Market Hub provides storage services to a broad mix of customers including marketers, power generators, gas producers, pipelines and LDCs. Power generators, marketers and producers generally use storage services for short term balancing, to manage risk and to take advantage of the pricing differential between near-term and long-term natural gas. LDCs use storage services for seasonal balancing, to meet peak day deliveries and ensure reliability. Pipelines use storage services to manage short term operational balancing requirements. For the year ended December 31, 2006 Market Hub’s three largest customers were Northern Indiana Public Service Company, Conectiv, Inc. and Fortis Energy Marketing and Trading, which accounted for approximately 12%, 10% and 8%, respectively, of Market Hub’s revenues.

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We anticipate that LNG terminal capacity holders will become another key market segment for Market Hub’s services. Due to the lack of natural gas storage capacity in other gas markets around the world, we anticipate the U.S. Gulf Coast will become a destination for excess supply in the global LNG market, especially during the summer months when takeaway and storage capacity for LNG is limited in other LNG markets. There are already two LNG storage facilities operating on the Gulf Coast. In addition, as of February 2007, approximately 14 out of a total of approximately 15 additional LNG terminals proposed for construction in the Gulf Coast region have been approved for construction.

Market Hub Contracts. Market Hub contracts with is customers to provide firm storage, park and loan services and wheeling. Under firm storage contracts, customers pay a reservation rate for the firm 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, 2006, Market Hub’s firm storage contracts had a weighted average remaining life by revenue of approximately 2.4 years, which is typical of the shorter contract life of storage systems as compared to transportation systems. For the year ended December 31, 2006, approximately 90% of Market Hub’s revenues were derived from capacity reservation fees under firm storage contracts and approximately 10% of Market Hub’s revenues were derived from interruptible storage contracts, including park and loan services and wheeling.

Despite an increase in the number of competitors in recent years, we have been able to recontract all of Market Hub’s available storage capacity at acceptable rates. We believe our success in renewing contracts is due to various positive attributes of our storage facilities, including their favorable access to neighboring pipeline systems and the flexibility and reliability of our service offerings.

Market Hub 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, supply and market access, and flexibility and reliability of service. Market Hub’s main regional competitors include Jefferson Island storage facility owned by AGL Resources, Spindletop owned by DCP Midstream, North Dayton storage owned by Kinder Morgan and Katy Storage owned by Enstor. An increase in competition in the market could arise from new ventures or expanded operations from existing competitors. We anticipate that growing demand for natural gas storage along the Gulf Coast will be met with increasing storage capacity, either through the expansion of existing facilities or the construction of new storage facilities. For example, we expect additional regional competition from proposed greenfield storage facilities including Liberty Gas Storage, Pine Prairie Energy Center, Starks Gas Storage, Houston Storage Hub and Bobcat Storage.

Market Hub Natural Gas Supply. Egan has aggregate receipt capacity from its major interconnecting pipelines of approximately 3.5 Bcf/d compared to an injection capability of 2.1 Bcf/d. Moss Bluff has aggregate receipt capacity from its major interconnecting pipelines of approximately 2.1 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 future LNG supplies.

Safety and Maintenance

We are subject to regulation by the DOT under the Natural Gas Pipeline Safety Act of 1968, referred to as NGPSA, and the Pipeline Safety Improvement Act of 2002, which was recently reauthorized and amended by the Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006. The NGPSA regulates safety requirements in the design, construction, operation and maintenance of gas pipeline facilities while the Pipeline Safety Improvement Act of 2002 establishes mandatory inspections for all United States

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oil and natural gas transportation pipelines, and some gathering lines in high consequence areas. DOT regulations implementing the Pipeline Safety Improvement Act of 2002 require pipeline operators to conduct integrity management programs, which involve frequent inspections and other measures to ensure pipeline safety in “high consequence areas,” such as high population areas, areas that are difficult to evacuate and locations where people congregate. The DOT may assess fines and penalties for violations of these and other requirements imposed by its regulations. We believe that we are in material compliance with all regulations imposed by the DOT on our natural gas pipeline operations.

We currently estimate that our assets will incur costs of approximately $44.2 million between 2007 and 2012 to conduct integrity management program testing along certain segments of the East Tennessee pipeline and at the Market Hub facilities. The majority of this amount will be capital costs and will be used to modify the East Tennessee pipeline to allow for internal pipeline inspections, or “smart pigging,” whereas most of the remaining costs are for general operations and maintenance on the East Tennessee pipeline. These estimates do not include the costs, if any, for repair, remediation, preventative or mitigating actions that may be determined to be necessary as a result of the testing program.

States are largely preempted by federal law from regulating pipeline safety but may assume responsibility for enforcement of federal intrastate pipeline safety regulations and inspection of intrastate pipelines. In practice, states vary considerably in their authority and capacity to address pipeline safety. We do not anticipate any significant problems in complying with state laws and regulations applicable to our operations. Our natural gas pipelines have inspection and compliance programs designed to maintain compliance with federal and state pipeline safety and pollution control requirements. For instance, the East Tennessee pipeline requires a corrosion control program to protect the integrity of the pipeline and prolong its life. The corrosion control program includes the installation and operation of groundbeds and rectifiers along the pipeline system to maintain adequate cathodic protection, as required by the DOT. We determine the adequacy of this program through annual monitoring of the output of these systems as well as annual checks of cathodic protection readings at various points along the pipeline and at compressor stations. We also monitor the pipeline both internally by cutting the pipeline open to inspect for internal corrosion, and sampling any liquids or solids that we remove from the pipeline, and externally by inspecting the external coating condition of the pipeline every time we excavate and expose the pipeline. We believe this is an aggressive and proactive corrosion control program that may reduce metal loss, limit corrosion and possibly extend the service life of the pipeline.

We are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act, referred to as OSHA, and comparable state statutes, whose purpose is to protect the health and safety of workers, both generally and within the pipeline industry. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act, and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities, and citizens. We are also subject to OSHA Process Safety Management regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. These regulations apply to any process which involves a chemical at or above specified thresholds, or any process which involves 10,000 pounds or more of a flammable liquid or gas in one location. Flammable liquids stored in atmospheric tanks below their normal boiling point without the benefit of chilling or refrigeration are exempt. We have an internal program of inspection designed to monitor and enforce compliance with worker safety requirements. We believe that we are in material compliance with all applicable laws and regulations relating to worker health and safety.

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Regulation

FERC Regulation

Our interstate pipelines are subject to extensive regulation by FERC. With the exception of Market Hub’s Moss Bluff storage facility, each of our operating subsidiaries is a “natural gas company” under the NGA, pursuant to which FERC has jurisdiction with respect to virtually all aspects of our business, including:


	•	transportation and storage of natural gas;

	•	rates and charges;

	•	terms of service including creditworthiness requirements;

	•	construction of new facilities;

	•	extension or abandonment of service and facilities;

	•	accounts and records;

	•	depreciation and amortization policies;

	•	our relationships with our marketing affiliates; and

	•	the initiation and discontinuation of services.

Our interstate pipelines and Market Hub’s Egan facility hold certificates of public convenience and necessity issued by FERC pursuant to Section 7 of the NGA covering our facilities, activities and services. These certificates require our interstate pipelines and storage facilities to provide on a non-discriminatory basis open-access services to all customers who qualify under their respective FERC gas tariffs. Under Section 8 of the NGA, FERC has the power to prescribe the accounting treatment of items for regulatory purposes. The books and records of our interstate pipelines storage facilities may be periodically audited by FERC.

FERC regulates the rates and charges for transportation and storage in interstate commerce. Natural gas companies may not charge rates that have been determined not to be just and reasonable.

The maximum recourse rates that may be charged by our pipelines for their services are established through FERC’s ratemaking process. Generally, the maximum filed recourse rates for interstate pipelines are based on the cost of service including recovery of and a return on the pipeline’s actual prudent historical cost investment. Key determinants in the ratemaking process are costs of providing service, allowed rate of return and volume throughput and contractual capacity commitment assumptions. The allowed rate of return must be approved by FERC as part of the resolution of each rate case. The maximum applicable recourse rates and terms and conditions for service are set forth in each pipeline’s FERC approved tariff. Rate design and the allocation of costs also can impact a pipeline’s profitability. Our interstate pipelines are permitted to discount their firm and interruptible rates without further FERC authorization down to the variable cost of performing service, provided they do not “unduly discriminate.”

Our interstate pipelines may also use “negotiated rates” which, in theory, could involve rates above or below the “recourse rate,” provided the affected customers are willing to agree to such rates. A prerequisite for having the right to agree to negotiated rates is that negotiated rate customers must have had the option to take service under the pipeline’s maximum recourse rates. All of Gulfstream’s firm transportation agreements extending for more than one year are subject to negotiated, rather than recourse, rates. Approximately 30% of East Tennessee’s firm transportation agreements extending for more than one year are subject to negotiated, rather than recourse, rates. Each negotiated rate transaction of Gulfstream and East Tennessee is designed to fix the negotiated rate for the term of the firm transportation agreement or the negotiated rate agreement, as applicable.

On November 1, 2005, East Tennessee placed into effect new rates approved by FERC as a result of a rate settlement with customers. The settlement agreement includes a five year rate moratorium that continues through 2010. Gulfstream currently has no obligation to file a new rate case.

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The Egan facility has market-based rate authority that permits it to charge rates set by the markets for its services. FERC has determined that the market in which Egan provides its interstate services is sufficiently competitive such that the market will set just and reasonable rates for those services. Like our other operating subsidiaries, Egan, as a natural gas company under the NGA, is prohibited from unduly discriminating among customers in the rates, terms and conditions pursuant to which it provides its services. The market-based rates that Egan negotiates with individual customers are made public by a posting on Egan’s website.

Commencing in 2003, FERC issued a series of orders adopting rules for new Standards of Conduct for Transmission Providers (Order No. 2004) which apply to interstate natural gas pipelines, including East Tennessee and Gulfstream, and to certain natural gas storage companies, including Market Hub’s Egan facilities, which provides storage services in interstate commerce. Order No. 2004 became effective in 2004. Among other matters, Order No. 2004 required our interstate pipelines and storage companies to operate independently from their energy affiliates, prohibited our interstate pipelines and storage companies from providing non-public transportation or shipper information to their energy affiliates, prohibited our interstate pipelines and storage companies from favoring their energy affiliates in providing service and obligated our interstate pipelines and storage companies to post on their websites a number of items of information concerning the company, including its organizational structure, facilities shared with energy affiliates, discounts given for service and instances in which the company has agreed to waive discretionary terms of its tariff.

Late in 2006, the United States Court of Appeals for the District of Columbia Circuit vacated and remanded Order No. 2004, as it relates to natural gas transportation providers, including our natural gas pipelines and storage companies. The court objected to FERC’s expansion of the prior standards of conduct to include energy affiliates, and vacated the entire rule as it relates to natural gas transportation providers. On January 9, 2007, and as clarified on March 21, 2007, FERC issued an interim rule re-promulgating on an interim basis the standards of conduct that were not challenged before the court, while FERC decides how to respond to the court’s decision on a permanent basis. The interim rule makes the standards of conduct apply to the relationship between natural gas transportation providers and their marketing affiliates, but not to energy affiliates who are not also marketing affiliates. Several companies requested rehearing and clarification of the interim rule. The March 21, 2007 order on clarification granted same of the requested clarifications and stated that it would address the other requests in its proceeding establishing a permanent rule. FERC has issued a notice of proposed rulemaking, or NOPR, that proposes permanent standards of conduct that FERC states will avoid the aspects of the previous standards of conduct rejected by the court. With respect to natural gas transportation providers, the NOPR proposes (1) that the permanent standards of conduct apply only to the relationship between natural gas transportation providers and their marketing affiliates, and (2) to make permanent the changes adopted in the interim rule permitting risk management employees to be shared by natural gas transportation providers and their marketing affiliates and requiring that tariff waivers be maintained in a written waiver log and available upon request. We have no way to predict with certainty the scope of FERC’s permanent rules on the standards of conduct. However, we do not believe that our natural gas pipeline and storage companies will be affected by any action taken previously or in the future on these matters materially differently than other natural gas service providers with whom we compete.

FERC Policy Statement on Income Tax Allowances

In a decision issued in July 2004 involving an oil pipeline limited partnership, BP West Coast Products, LLC v. FERC, the United States Court of Appeals for the District of Columbia Circuit upheld, among other things, FERC’s determination that certain rates of an interstate petroleum products pipeline, SFPP, L.P., or SFPP, were grandfathered rates under the Energy Policy Act of 1992 and that SFPP’s shippers had not demonstrated substantially changed circumstances that would justify modification of those rates. The court also vacated the portion of FERC’s decision applying the Lakehead policy. In its Lakehead decision, FERC allowed an oil pipeline publicly traded partnership to include in its cost-of-service an income tax allowance to the extent that its unitholders were corporations subject to income tax. In May and June 2005,

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FERC issued a statement of general policy, as well as an order on remand of BP West Coast, respectively, in which it stated it will permit pipelines to include in cost-of-service a tax allowance to reflect actual or potential tax liability on their public utility 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. Whether a pipeline’s owners have such actual or potential income tax liability will be reviewed by FERC on a case-by-case basis. The new policy entails rate risk due to the case-by-case review requirement. FERC’s BP West Coast remand decision and the new tax allowance policy have been appealed to the D.C. Circuit. The D.C. Circuit has not yet acted on these appeals.

On December 8, 2006, FERC issued a new order addressing rates on one of SFPP’s interstate oil pipelines. In that order, FERC chose to take up and address challenges to the policy statement raised by shippers in filings in another docket earlier in 2006. In the new order, FERC refined its income tax allowance policy, and notably raised a new issue regarding the implication of the policy statement for publicly traded partnerships. It noted that the tax deferral features of a publicly traded partnership may cause some investors to receive, for some indeterminate duration, cash distributions in excess of their taxable income, which FERC characterized as a “tax savings.” FERC stated that it is concerned that this created an opportunity for those investors to earn an additional return, funded by ratepayers. Responding to this concern, FERC chose to adjust the pipeline’s equity rate of return downward based on the percentage by which the publicly traded partnership’s cash flow exceeded taxable income. On February 7, 2007, SFPP asked FERC to reconsider this ruling. The ultimate outcome of these proceedings is not certain and could result in changes to FERC’s treatment of income tax allowances in cost of service and to potential adjustment in a future rate case of our pipelines’ respective equity rates of return that underlie their recourse rates to the extent that cash distributions in excess of taxable income are allowed to some unitholders. If the D.C. Circuit were to not uphold FERC’s income tax allowance policy or if FERC were to disallow a substantial portion of East Tennessee’s or Gulfstream’s income tax allowance, it may be more difficult for these pipelines to justify their rates in future proceedings.

Energy Policy Act of 2005

On August 8, 2005, Congress enacted the Energy Policy Act of 2005, or EP Act 2005. Among other matters, EP Act 2005 amends the NGA, to add an antimanipulation provision which makes it unlawful for any entity to engage in prohibited behavior in contravention of rules and regulations to be prescribed by FERC and provides FERC with additional civil penalty authority. On January 19, 2006, FERC issued Order No. 670, a rule implementing the antimanipulation provision of EP Act 2005, and subsequently denied rehearing. The rules make it unlawful in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or to engage in any act or practice that operates as a fraud or deceit upon any person. The new anti-manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of gas pipelines and storage companies that provide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction. EP Act 2005 also amends the NGA and the Natural Gas Policy Act to give FERC authority to impose civil penalties for violations of the NGA up to $1,000,000 per day per violation for violations occurring after August 8, 2005. In connection with this enhanced civil penalty authority, FERC issued a policy statement on enforcement to provide guidance regarding the enforcement of the statutes, orders, rules and regulations it administers, including factors to be considered in determining the appropriate enforcement action to be taken. The antimanipulation rule and enhanced civil penalty authority reflect an expansion of FERC’s NGA enforcement authority. Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, FERC and the courts. The natural gas industry historically has been heavily regulated. Accordingly, we cannot assure you that the less stringent and pro-competition regulatory approach recently pursued by FERC and Congress will continue.

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Additional Regulation of Moss Bluff

FERC performs ratemaking oversight with respect to intrastate pipelines and storage companies that perform service pursuant to Section 311 of the Natural Gas Policy Act of 1978 and that perform service that is similar to Section 311 service but which, for jurisdictional reasons, is actually performed under a limited certificate issued under Section 7 of the NGA. Under Section 311 or a limited Section 7 certificate, an intrastate pipeline or storage company, like Moss Bluff, can perform service that is in interstate commerce, and would therefore ordinarily cause all of the facility’s activities to be subject to FERC’s jurisdiction under the NGA, without subjecting the intrastate pipeline or storage company to comprehensive NGA jurisdiction. FERC regulates the rates for the Section 311 service in one of three ways. FERC may directly regulate the rates using essentially the same methodology as is employed to establish “just reasonable and recourse rates” for interstate pipelines. Intrastate pipelines and storage companies are generally required by FERC to have these Section 311 rates reviewed every three years. As an alternative, some intrastate pipelines and storage companies may be allowed to utilize certain “city gate rates” on file with a state regulatory agency as the rates for Section 311 service. As a second alternative, some intrastate pipelines and storage companies are permitted to charge market-based rates following a determination by FERC that the markets in which the intrastate pipeline or storage company provides services are workably competitive.

Moss Bluff is a “Hinshaw” facility, which is specifically exempt from FERC jurisdiction pursuant to Section 1(c) of the NGA. However, in order to provide service in interstate commerce without subjecting the entirety of its facilities and services to FERC jurisdiction, Moss Bluff provides service in interstate commerce pursuant to a limited certificate issued under Section 7 of the NGA. As a limited certificate holder, Moss Bluff has a Statement of Operating Conditions on file with FERC that govern the services it provides in interstate commerce. With respect to the rates that it charges for such services, FERC has authorized Moss Bluff to charge market-based rates for its firm and interruptible storage services and its interruptible hub services. If FERC determines that the market in which Moss Bluff provides its interstate services is not workably competitive, FERC could revoke Moss Bluff’s ability to charge market-based rates and instead require Moss Bluff to establish rates pursuant to one of the other alternatives discussed above.

The Moss Bluff facility is also subject to the jurisdiction of the TRC as a “gas utility.” As a gas utility, Moss Bluff’s intrastate rates and services and its facilities are subject to TRC regulation. Moss Bluff has a tariff on file with the TRC and it files intrastate service agreements with the TRC. Any future expansion of Moss Bluff’s facilities is subject to approval by the TRC.

Seasonality

Our revenues are not generally seasonal in nature, nor are they typically affected by weather and price volatility. Weather impacts natural gas demand for power generation and heating purposes, which in turn influences the value of transportation and storage across our systems. Colder than normal winters or warmer than normal summers typically result in increased pipeline revenues. Price volatility also affects gas prices, which in turn influences drilling and production. Peak demand for natural gas typically occurs during the winter months, caused by the heating load, although certain markets such as the Florida market served by Gulfstream peaks in the summer months due to cooling demands. During 2006 approximately 48% of our pipeline and storage revenues were realized in the first and fourth calendar quarters while approximately 52% of our pipeline and storage revenues were realized in the second and third calendar quarters.

Environmental Regulation

General. Our natural gas transportation, and natural gas and LNG storage activities are subject to stringent and complex federal, state, and local laws and regulations governing environmental protection, including air emissions, water quality, wastewater discharges, and solid waste management. Such laws and regulations generally require us to obtain and comply with a wide variety of environmental registrations, licenses, permits, and other approvals. These laws and regulations also can restrict or impact our business activities in many ways, such as restricting the way we handle or dispose of our wastes; requiring remedial

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action to mitigate pollution conditions that may be caused by our operations or that are attributable to former operators; and enjoining some or all of the operations of facilities deemed in non-compliance with permits issued pursuant to such environmental laws and regulations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and/or criminal penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations.

We accrue for expenses associated with environmental liabilities when the costs are probable and reasonably estimable. The amount of any accrual for environmental liabilities could change substantially in the future due to factors including the nature and extent of any contamination that we may be required to remediate, changes in remedial requirements, technological changes, discovery of new information, and the involvement and direction taken by the EPA, FERC, DOT and any other governmental authorities on these matters.

We believe that compliance with existing federal, state and local environmental laws and regulations will not have a material adverse effect on our business, financial position, or results of operations. Nevertheless, the trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. As a result, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. The following is a discussion of some of the environmental laws and regulations that are applicable to our natural gas transportation, and natural gas and LNG storage activities.

Waste Management. Our operations generate hazardous and non-hazardous solid wastes that are subject to the federal Resource Conservation and Recovery Act (“RCRA”) and comparable state laws, which impose detailed requirements for the handling, storage, treatment and disposal of hazardous and non-hazardous solid wastes. For instance, RCRA prohibits the disposal of certain hazardous wastes on land without prior treatment, and requires generators of wastes subject to land disposal restrictions to provide notification of pre-treatment requirements to disposal facilities that are in receipt of these wastes. Generators of hazardous wastes also must comply with certain standards for the accumulation and storage of hazardous wastes, as well as recordkeeping and reporting requirements applicable to hazardous waste storage and disposal activities. RCRA imposes fewer restrictions on the handling, storage and disposal of non-hazardous wastes, which includes certain wastes associated with the exploration and production of oil and natural gas.

Site Remediation. The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as “Superfund,” and comparable state laws and regulations impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons responsible for the release of hazardous substances into the environment. Such classes of persons include the current and past owners or operators of sites where a hazardous substance was released, and companies that disposed or arranged for the disposal of hazardous substances at offsite locations, such as landfills. CERCLA authorizes the U.S. Environmental Protection Agency (“EPA”), and in some cases third parties, to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. If in the future we are considered a responsible party under CERCLA, we could be subject to joint and several, strict liability for the costs of cleaning up and restoring sites where hazardous substances have been released into the environment, for damages to natural resources, and for the costs of certain health studies. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of substances or wastes into the environment.

We currently own or lease properties that for many years have been used for the transportation and compression of natural gas, and the storage of natural gas and LNG. Although we typically have used operating and disposal practices that were standard in the industry at the time, wastes may have been disposed of or released on or under the properties owned or leased by us or on or under other locations where such substances have been taken for disposal. In addition, some of the properties may have been operated by third parties or by previous owners whose treatment and disposal or release of wastes was not

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under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove previously disposed wastes, including waste disposed of by prior owners or operators; remediate contaminated property, including groundwater contamination, whether from prior owners or operators or other historic activities or spills; or perform remedial closure operations to prevent future contamination.

Air Emissions. The Clean Air Act (“CAA”) and comparable state laws regulate emissions of air pollutants from various industrial sources, including compressor stations, and also impose various monitoring and reporting requirements. Such laws and regulations may require pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in an increase of existing air emissions; application for, and strict compliance with, air permits containing various emissions and operational limitations; or the utilization of specific emission control technologies to limit emissions. Failure to comply with these requirements could result in monetary penalties, injunctions, conditions or restrictions on operations, and potentially criminal enforcement actions.

We may incur expenditures in the future for air pollution control equipment in connection with obtaining or maintaining operating permits and approvals for air emissions. For instance, we may be required to supplement or modify our air emission control equipment and strategies due to changes in state implementation plans for controlling air emissions in regional non-attainment areas, or stricter regulatory requirements for sources of hazardous air pollutants. However, we do not believe that any such future requirements will have a material adverse affect on our operations.

Water Discharges. The Clean Water Act (“CWA”) and analogous state laws impose strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or an analogous state agency. The CWA also regulates storm water runoff from certain industrial facilities. Accordingly, some states require industrial facilities to obtain and maintain storm water discharge permits, and monitor and sample storm water runoff from their facilities. Under the CWA, federal and state regulatory agencies may impose administrative, civil and/or criminal penalties for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations.

The Oil Pollution Act of 1990 (“OPA”), which amends and augments the CWA, establishes strict liability for owners and operators of facilities that are the site of a release of oil into waters of the United States. OPA and its associated regulations impose a variety of requirements on responsible parties related to the prevention of oil spills and liability for damages resulting from such spills. For example, operators of certain oil and gas facilities must develop, implement and maintain facility response plans, conduct annual spill training for certain employees and provide varying degrees of financial assurance.

Activities on Federal Lands. Natural gas transportation activities conducted on federal lands are subject to the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. Our current activities, as well as any proposed plans for future activities, on federal lands are subject to the requirements of NEPA.

Endangered Species. The Endangered Species Act restricts activities that may affect endangered species or their habitats. Some of our natural gas pipelines are located in areas inhabited by endangered species. Specifically, a portion of the East Tennessee pipeline, known as the Jewell Ridge Lateral pipeline, is located in the Indian Creek watershed, which serves as a habitat for certain endangered mussels. The U.S. Fish and Wildlife Service (“FWS”) notified us in September 2006 of impacts to these mussels and their habitat, which according to the agency, was caused by the runoff of sedimentation into Indian Creek as a result of our operations associated with the construction of the Jewell Ridge Lateral pipeline. We have been in consultation with the FWS and FERC to resolve this matter, and expect that we ultimately will be

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required to provide funding for mitigation measures as well as other habitat restoration and species monitoring projects designated by the FWS. We estimate that these projects may cost between approximately $400,000 and $2 million, depending upon the nature of the measures required by the FWS.

Other Laws and Regulations. Recent studies have suggested that emissions of certain gases may be contributing to warming of the Earth’s atmosphere. In response to these studies, many nations have agreed to limit emissions of “greenhouse gases,” pursuant to the United Nations Framework Convention of Climate Change, also known as the “Kyoto Protocol.” Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of natural gas and oil, and refined petroleum products, are “greenhouse gases” regulated by the Kyoto Protocol. Although the United States is not participating in the Kyoto Protocol, the current session of Congress is considering climate change legislation, with multiple bills having been introduced in the Senate that propose to restrict greenhouse gas emissions. Several states have already adopted legislation, regulations and/or regulatory initiatives to reduce emissions of greenhouse gases. For instance, California adopted the “California Global Warming Solutions Act of 2006”, which requires the California Air Resources Board to achieve a 25% reduction in emissions of greenhouse gases from sources in California by 2020. Additionally, on November 29, 2006, the U.S. Supreme Court heard arguments on and has since begun reviewing a decision made by the U.S. Circuit Court of Appeals for the District of Columbia in Massachusetts, et al v. EPA , a case in which the appellate court held that EPA had discretion under the Clean Air Act to refuse to regulate carbon dioxide emissions from mobile sources. Passage of climate change legislation by Congress or a Supreme Court reversal of the appellate decision could result in federal regulation of carbon dioxide emissions and other greenhouse gases. Currently, our operations are not adversely impacted by existing state and local climate change initiatives, and at this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our operations or financial condition.

Title to Properties and Rights-of-Way

Our real property falls into two categories: (1) parcels that we (or entities in which we own an interest) own in fee and (2) parcels in which our interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities permitting the use of such land for our operations. Portions of the land on which our plants and other major facilities are located are owned by us (or entities in which we own an interest) in fee title, and we believe that we have satisfactory title to these lands. The remainder of the land on which our plant sites and major facilities are located are held by us (or entities in which we own an interest) pursuant to ground leases between us (or entities in which we own an interest), as lessee, and the fee owner of the lands, as lessors. We, our predecessor or our or their affiliates, have leased these lands, in some cases, for many years without any material challenge known to us relating to the title to the land upon which the assets are located, and we believe that we have satisfactory leasehold estates to such lands. We have no knowledge of any challenge to the underlying fee title of any material lease, easement, right-of-way, permit or license held by us or to our title to any material lease, easement, right-of-way, permit or lease, and we believe that we have satisfactory title to all of our material leases, easements, rights-of-way, permits and licenses.

Insurance

Our insurance program includes general liability insurance, auto liability insurance, worker’s compensation insurance, and property insurance in amounts which management believes are reasonable and appropriate.

Facilities

Spectra Energy leases office space for its corporate offices in Houston, Texas. The lease expires on April 1, 2027 with a right of early termination exercisable by Spectra Energy beginning April 1, 2018.

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Employees

We do not have any employees. We are managed and operated by the directors and officers of our general partner. To carry out our operations, as of March 1, 2007, our general partner or its affiliates employed approximately 65 people who will spend at least a majority of their time operating the East Tennessee facilities. 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 by The Williams Companies (with respect to technical functions) pursuant to an operating and maintenance agreement and the employees who operate the Gulfstream assets are therefore not included in the above numbers. Please read “Management — Management of Spectra Energy Partners, LP.”

Legal Proceedings

We are not a party to any legal proceeding other than legal proceedings arising in the ordinary course of our business. We are a party to various administrative and regulatory proceedings that have arisen in the ordinary course of our business. Please read “Regulations — FERC Regulation.”

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MANAGEMENT

Management of Spectra Energy Partners, LP

Because our general partner is a limited partnership, its general partner, Spectra Energy Partners GP, LLC, will manage our operations and activities. Our general partner is not elected by our unitholders and will not be subject to re-election on a regular basis in the future. Unitholders will not be entitled to elect the directors of Spectra Energy Partners GP, LLC or directly or indirectly participate in our management or operation. Our general partner owes a fiduciary duty to our unitholders. Our general partner will be liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made expressly nonrecourse to it. Our general partner therefore may cause us to incur indebtedness or other obligations that are nonrecourse to it.

The directors of Spectra Energy Partners GP, LLC will oversee our operations. Upon the closing of this offering, we will have at least three directors. We intend to increase the size of the board of directors to following the closing of this offering. Spectra Energy will elect all members to the board of directors of Spectra Energy Partners GP, LLC and we expect that, when the size of our board increases to directors, we will have at least three directors that are independent as defined under the independence standards established by the New York Stock Exchange. The New York Stock Exchange does not require a listed limited partnership like us to have a majority of independent directors on the board of directors of our general partner or to establish a nominating and governance committee.

In compliance with the requirements of the New York Stock Exchange, Spectra Energy has appointed as an independent member to the board. Spectra Energy will appoint a second independent member within 90 days of the effective date of the registration statement of which this prospectus is a part and a third independent member within 12 months of the effective date of the registration statement. The independent members of the board of directors of Spectra Energy Partners GP, LLC will serve as the initial members of the conflicts and audit committees of the board of directors of Spectra Energy Partners GP, LLC.

At least two members of the board of directors of Spectra Energy Partners GP, LLC will serve on a conflicts committee to review specific matters that the board believes may involve conflicts of interest. The conflicts committee will determine if the resolution of the conflict of interest is fair and reasonable to us. The members of the conflicts committee may not be officers or employees of our general partner or directors, officers, or employees of its affiliates, and must meet the independence and experience standards established by the New York Stock Exchange and the Securities Exchange Act of 1934, as amended, to serve on an audit committee of a board of directors, and certain other requirements. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners, and not a breach by our general partner of any duties it may owe us or our unitholders.

In addition, Spectra Energy Partners GP, LLC will have an audit committee of at least three directors who meet the independence and experience standards established by the New York Stock Exchange and the Securities Exchange Act of 1934, as amended. The audit committee will assist the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and corporate policies and controls. The audit committee will have the sole authority to retain and terminate our independent registered public accounting firm, approve all auditing services and related fees and the terms thereof, and pre-approve any non-audit services to be rendered by our independent registered public accounting firm. The audit committee will also be responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm will be given unrestricted access to the audit committee. Spectra Energy Partners GP, LLC will also have a compensation committee, which will, among other things, oversee the compensation plans described below.

All of our executive management personnel will be employees of our general partner and will devote all of their time to our business and affairs. The officers of Spectra Energy Partners GP, LLC will manage the day-to-day affairs of our business. We will also utilize a significant number of employees of Spectra Energy

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to operate our business and provide us with general and administrative services. We will reimburse Spectra Energy for allocated expenses of operational personnel who perform services for our benefit and we will reimburse Spectra Energy for allocated general and administrative expenses. Please read “— Reimbursement of Expenses of Our General Partner.”

Directors and Executive Officers

The following table shows information regarding the current directors and executive officers of Spectra Energy Partners GP, LLC. Directors are elected for one-year terms.

Our directors 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.

Martha B. Wyrsch was elected Chairman of the Board of Spectra Energy Partners GP, LLC in March 2007. Ms. Wyrsch is currently President and Chief Executive Officer of Spectra Energy Transmission and also a director of Spectra Energy. Ms. Wyrsch assumed her current position effective in January 2007. Ms. Wyrsch served as President of Duke Energy Gas Transmission from March 2005 until assuming her current position. Ms. Wyrsch served as Group Vice President and General Counsel of Duke Energy Corporation from January 2004 until March 2005. Prior to then, Ms. Wyrsch served as Senior Vice President, Legal Affairs for Duke Energy Corporation from February 2003 until January 2004; Senior Vice President and General Counsel of Duke Energy Field Services from September 1999 until January 2003.

C. Gregory Harper was elected President, Chief Executive Officer and Director of the Board of Spectra Energy Partners GP, LLC in March 2007. Mr. Harper is currently Group Vice President of Analysis and Transition for Spectra Energy. Mr. Harper assumed his current position in May 2006. Mr. Harper served as Group Vice President of Energy Marketing and Management for Duke Energy Americas from January 2004 until May 2006. Prior to then, Mr. Harper served as Senior Vice President of Energy Marketing for Duke Energy North America from January 2003 until January 2004; Vice President of Business Development for Duke Energy Gas Transmission and Vice President of East Tennessee Natural Gas from March 2002 until January 2004; and General Manager from June 1999 until March 2002.

Lon C. Mitchell, Jr. was elected Chief Financial Officer of Spectra Energy Partners GP, LLC in March 2007. Mr. Mitchell is currently acting as Senior Financial Advisor providing transition support for Spectra Energy. Mr. Mitchell assumed his current position in October 2006. Mr. Mitchell previously served as Group Vice President and Chief Financial Officer of Duke Energy Americas from June 2005 until October 2006. Prior to then, Mr. Mitchell served as Senior Vice President and Chief Restructuring Officer for Duke Energy Americas from August 2003 until June 2005; Senior Vice President and Chief Financial Officer of Duke Energy North America from April 2002 until August 2003; Vice President of Duke Energy Merchants from April 2000 until April 2002.

Reimbursement of Expenses of Our General Partner

Our general partner will not receive any management fee or other compensation for its management of our partnership under the omnibus agreement with Spectra Energy or otherwise. Under the terms of the omnibus agreement, we will reimburse Spectra Energy up to $ million annually for the provision of various general and administrative services for our benefit. The partnership agreement provides that our general partner will determine the expenses that are allocable to us. Please see “Certain Relationships and Related Party Transactions — Omnibus Agreement.”

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Executive Compensation

Our general partner and Spectra Energy Partners GP, LLC were formed in March 2007. Accordingly, Spectra Energy Partners GP, LLC has not accrued any obligations with respect to management incentive or retirement benefits for its directors and officers for the 2006 fiscal year. The compensation of the executive officers of Spectra Energy Partners GP, LLC will be set by Spectra Energy. The officers and employees of Spectra Energy Partners GP, LLC may participate in employee benefit plans and arrangements sponsored by Spectra Energy. Spectra Energy Partners GP, LLC has not entered into any employment agreements with any of its officers. We anticipate that the board of directors will grant awards to our key employees and our outside directors pursuant to the Long-Term Incentive Plan described below following the closing of this offering; however, the board has not yet made any determination as to the number of awards, the type of awards or when the awards would be granted.

Compensation Discussion and Analysis

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 will generally be based on time allocated during a period to us and Spectra Energy.

During 2006, our executive officers were not specifically compensated for time expended with respect to our business or assets. Accordingly, we are not presenting any compensation for historical periods. Compensation paid or awarded by us in 2007 with respect to our Chief Executive Officer (our principal executive officer), our Chief Financial Officer (our principal financial officer) and our next most highly compensated executive officers (collectively, the “named executive officers”) will reflect only the portion of compensation paid by Spectra Energy that is allocated to us pursuant to Spectra Energy’s allocation methodology and subject to the terms of the omnibus agreement. The Board of Directors of Spectra Energy has ultimate decision making authority with respect to the compensation of our named executive officers. The elements of compensation discussed below, and Spectra Energy’s decisions with respect to determinations on payments, will not be subject to approvals by the board of directors of our general partner. Compensation of our executive officers, including awards under our long term incentive plan will be approved by the compensation committee of the board of directors of Spectra Energy or its delegate.

With respect to compensation objectives and decisions regarding our named executive officers for 2007, the compensation committee of Spectra Energy will approve the 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 consults with 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 of Spectra Energy, for the compensation to be paid or awarded to executives and employees for consideration. Spectra Energy intends to consult with compensation consultants with respect to determining 2007 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 compensation program discussed below are intended to provide an incentive 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 was provided in the form of short-term and long-term incentives. We expect that compensation for our executive officers in 2007 and the future will be structured in a similar manner.

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The primary elements of Spectra Energy’s compensation program are a combination of annual cash and long-term, equity-based compensation. For 2007, elements of compensation for our named executive officers are expected to be the following:


	•	annual base salary;

	•	annual performance based cash bonuses;

	•	performance awards under Spectra Energy’s and our long-term incentive plan;

	•	Spectra Energy’s contributions under its 401(k) and profit sharing plan; and

	•	Spectra Energy’s other benefit plans on the same basis as all other Spectra Energy employees.

We expect Spectra Energy to establish these salaries based on historical salaries paid to our named executive officers for services rendered to Spectra Energy, the extent of their equity ownership in Spectra Energy, market data and responsibilities of our named executive officers that may or may not be related to our business.

The short term incentive payments, in combination with base salaries and long-term incentive awards, are intended to yield competitive total cash compensation levels for the executive officers and drive performance in support of business strategies as well as our own. The portion of any short-term incentive payments allocable to us will be based on Spectra Energy’s methodology used for allocating general and administrative expenses, subject to the limitations in the omnibus agreement. It is Spectra Energy’s general policy to pay these awards during the first quarter.

We plan to issue our executive officers long-term equity based awards intended to compensate the officers based on the performance of our common units and their continued employment during the vesting period. These awards will be made pursuant to a long-term incentive plan adopted by us and administered by Spectra Energy. Please see “— Long-Term Incentive Plan.” The cost of such awards will be allocated to us pursuant to Spectra Energy’s allocation methodology and subject to the terms of the omnibus agreement. The Spectra Energy Partners equity-based awards that we intend to make to both our named executive officers and the directors of our general partner are intended to align their long-term interests with those of our unitholders.

The terms and amount of Spectra Energy Partners equity awards that we intend to make to each of our non-management and independent directors under our long-term incentive plan will be determined by Spectra Energy and approved by its compensation committee or its delegate.

We believe that each of the base salary, cash award, and equity awards fit the overall compensation objectives of us and of Spectra Energy, as stated above, i.e., to provide competitive compensation opportunities to align and drive employee performance in support of Spectra Energy’s business strategies as well as our own and to attract, motivate and retain high quality talent with the skills and competencies required by Spectra Energy and us.

Compensation of Directors

Officers or employees of Spectra Energy Partners GP, LLC or its affiliates who also serve as directors will not receive additional compensation for their service as a director of Spectra Energy Partners GP, LLC. Our general partner anticipates that directors who are not officers or employees of Spectra Energy Partners GP, LLC or its affiliates will receive compensation for attending meetings of the board of directors and committee meetings. The amount of such compensation has not yet been determined. In addition, each non-employee director will be reimbursed for his out-of-pocket expenses in connection with attending meetings of the board of directors or committees. Each director will be fully indemnified by us for his actions associated with being a director to the fullest extent permitted under Delaware law.

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Long-Term Incentive Plan

General. Spectra Energy Partners GP, LLC intends to adopt a Long-Term Incentive Plan, or the Plan, for employees, consultants and directors of Spectra Energy Partners GP, LLC and its affiliates who perform services for us. The summary of the Plan contained herein does not purport to be complete and is qualified in its entirety by reference to the Plan. The Plan provides for the grant of restricted units, phantom units, unit options and substitute awards and, with respect to unit options and phantom units, the grant of distribution equivalent rights, or DERs. Subject to adjustment for certain events, an aggregate of 575,000 common units may be delivered pursuant to awards under the Plan. Units that are cancelled, forfeited or are withheld to satisfy Spectra Energy Partners GP, LLC’s tax withholding obligations are available for delivery pursuant to other awards. The Plan will be administered by the compensation committee of Spectra Energy Partners GP, LLC’s board of directors.

Restricted Units and Phantom Units. A restricted unit is a common unit that is subject to forfeiture. Upon vesting, the grantee receives a common unit that is not subject to forfeiture. A phantom unit is a notional unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit or, in the discretion of the compensation committee, cash equal to the fair market value of a common unit. The compensation committee may make grants of restricted units and phantom units under the Plan to eligible individuals containing such terms, consistent with the Plan, as the compensation committee may determine, including the period over which restricted units and phantom units granted will vest. The compensation committee may, in its discretion, base vesting on the grantee’s completion of a period of service or upon the achievement of specified financial objectives or other criteria. In addition, the restricted and phantom units will vest automatically upon a change of control (as defined in the Plan) of us or Spectra Energy Partners GP, LLC, subject to any contrary provisions in the award agreement.

If a grantee’s employment, consulting or membership on the board terminates for any reason, the grantee’s restricted units and phantom units will be automatically forfeited unless, and to the extent, the award agreement or the compensation committee provides otherwise. Common units to be delivered with respect to these awards may be common units acquired by Spectra Energy Partners GP, LLC in the open market, common units already owned by Spectra Energy Partners GP, LLC, common units acquired by Spectra Energy Partners GP, LLC directly from us or any other person, or any combination of the foregoing. Spectra Energy Partners GP, LLC will be entitled to reimbursement by us for the cost incurred in acquiring common units. If we issue new common units with respect to these awards, the total number of common units outstanding will increase.

Distributions made by us with respect to awards of restricted units may, in the compensation committee’s discretion, be subject to the same vesting requirements as the restricted units. The compensation committee, in its discretion, may also grant tandem DERs with respect to phantom units on such terms as it deems appropriate. DERs are rights that entitle the grantee to receive, with respect to a phantom unit, cash equal to the cash distributions made by us on a common unit.

We intend for the restricted units and phantom units granted under the Plan to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of the common units. Therefore, participants will not pay any consideration for the common units they receive with respect to these types of awards, and neither we nor our general partner will receive remuneration for the units delivered with respect to these awards.

Unit Options. The Plan also permits the grant of options covering common units. Unit options may be granted to such eligible individuals and with such terms as the compensation committee may determine, consistent with the Plan; however, a unit option must have an exercise price equal to the fair market value of a common unit on the date of grant.

Upon exercise of a unit option, Spectra Energy Partners GP, LLC will acquire common units in the open market at a price equal to the prevailing price on the principal national securities exchange upon which the common units are then traded, or directly from us or any other person, or use common units already owned by the general partner, or any combination of the foregoing. Spectra Energy Partners GP,

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LLC will be entitled to reimbursement by us for the difference between the cost incurred by Spectra Energy Partners GP, LLC in acquiring the common units and the proceeds received by Spectra Energy Partners GP, LLC from an optionee at the time of exercise. Thus, we will bear the cost of the unit options. If we issue new common units upon exercise of the unit options, the total number of common units outstanding will increase, and Spectra Energy Partners GP, LLC will remit the proceeds it received from the optionee upon exercise of the unit option to us. The unit option plan has been designed to furnish additional compensation to employees, consultants and directors and to align their economic interests with those of common unitholders.

Substitution Awards. The compensation committee, in its discretion, may grant substitute or replacement awards to eligible individuals who, in connection with an acquisition made by us, Spectra Energy Partners GP, LLC or an affiliate, have forfeited an equity-based award in their former employer. A substitute award that is an option may have an exercise price less than the value of a common unit on the date of grant of the award.

Termination of Long-Term Incentive Plan. Spectra Energy Partners GP, LLC’s board of directors, in its discretion, may terminate the Plan at any time with respect to the common units for which a grant has not theretofore been made. The Plan will automatically terminate on the earlier of the 10th anniversary of the date it was initially approved by our unitholders or when common units are no longer available for delivery pursuant to awards under the Plan. Spectra Energy Partners GP, LLC’s board of directors will also have the right to alter or amend the Plan or any part of it from time to time and the Committee may amend any award; provided, however, that no change in any outstanding award may be made that would materially impair the rights of the participant without the consent of the affected participant. Subject to unitholder approval, if required by the rules of the principal national securities exchange upon which the common units are traded, the board of directors of Spectra Energy Partners GP, LLC may increase the number of common units that may be delivered with respect to awards under the Plan.

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth the beneficial ownership of our units that will be issued upon the consummation of this offering 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 Spectra Energy Partners GP, LLC;

	•	each named executive officer of Spectra Energy Partners GP, LLC; and

	•	all directors and officers of Spectra Energy Partners GP, LLC as a group.


											Percentage of
											Total Common
								Percentage of			and
	Common Units		Percentage of			Subordinated		Subordinated			Subordinated
	to be		Common Units to			Units to be		Units to be			Units to be
	Beneficially		be Beneficially			Beneficially		Beneficially			Beneficially
Name of Beneficial Owner (1)	Owned		Owned			Owned		Owned			Owned

Spectra Energy Corp(2)		29,812,011		72.2	%		20,030,066		100	%		81.3	%
Spectra Energy Partners MLP LP, LLC(2)(3)		29,812,011		72.2	%		20,030,066		100	%		81.3	%
Martha B. Wyrsch(4)					%				—	%			%
C. Gregory Harper(4)					%				—	%			%
Lon C. Mitchell, Jr.(4)					%				—	%			%
					%				—	%			%
					%				—	%			%
					%				—	%			%
					%				—	%			%
All directors and executive officers as a group (four persons)				—					—	%			%


(*)		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 Corp is the ultimate parent company of Spectra Energy Partners MLP LP, LLC and may, therefore, be deemed to beneficially own the units held by Spectra Energy Partners MLP LP, LLC.

(3)		The address for Spectra Energy Partners MLP LP, LLC is , Delaware.

(4)		Does not include common units that may be purchased in the directed unit program.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

After this offering, Spectra Energy and its affiliates will own 29,812,011 common units and 20,030,066 subordinated units representing an aggregate 79.6% limited partner interest in us. In addition, our general partner will own a 2% general partner interest in us and the incentive distribution rights.

Distributions and Payments to Our General Partner and its Affiliates

The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with the formation, ongoing operation and any liquidation of Spectra Energy Partners, LP. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm’s-length negotiations.

Formation Stage


The consideration received by Spectra Energy and its subsidiaries for the contribution of the assets and liabilities to us		• 29,812,011 common units;

		• 20,030,066 subordinated units;

		• 1,251,879 general partner units;

		• the incentive distribution rights;

		• $150 million cash payment from the proceeds of this offering as reimbursement for capital expenditures incurred by subsidiaries of Spectra Energy prior to the closing of this offering related to the assets to be contributed to us upon the closing of this offering; and

		• $175 million cash payment from the proceeds of borrowings under our credit facility.

Operational Stage


Distributions of available cash to our general partner and its affiliates		We will generally make cash distributions 98% to our unitholders pro rata, including our general partner and its affiliates, as the holders of an aggregate 29,812,011 common units 20,030,066 subordinated units, and 2% to our general partner. In addition, if distributions exceed the minimum quarterly distribution and other higher target distribution levels, our general partner will be entitled to increasing percentages of the distributions, up to 50% of the distributions above the highest target distribution level.

		Assuming we have sufficient available cash to pay the full minimum quarterly distribution on all of our outstanding units for four quarters, our general partner and its affiliates would receive an annual distribution of approximately $1.6 million on their general partner units and $64.8 million on their common and subordinated units.

Payments to our general partner and its affiliates		We will reimburse Spectra Energy and its affiliates for the payment of certain operating expenses and for the provision of

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		various general and administrative services for our benefit. For further information regarding the administrative fee, please read “Certain Relationship and Related Party Transactions — Omnibus Agreement — Reimbursement of Operating and General and Administrative Expense.”

Withdrawal or removal of our general partner		If our 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. Please read “The Partnership Agreement — Withdrawal or Removal of the General Partner.”

Liquidation Stage


Liquidation		Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their respective capital account balances.

Agreements Governing the Transactions

We and other parties have entered into or will enter into the various documents and agreements that will effect the offering transactions, including the vesting of assets in, and the assumption of liabilities by, us and our subsidiaries, and the application of the proceeds of this offering. These agreements will not be the result of arm’s-length negotiations, and they, or any of the transactions that they provide for, may not be effected on terms at least as favorable to the parties to these agreements as they could have been obtained from unaffiliated third parties. All of the transaction expenses incurred in connection with these transactions, including the expenses associated with transferring assets into our subsidiaries, will be paid from the proceeds of this offering.

Omnibus Agreement

Upon the closing of this offering, we will enter into an omnibus agreement with Spectra Energy, our general partner and others that will address the following matters:


	•	our obligation to reimburse Spectra Energy the payment of operating expenses, including salary and benefits of operating personnel, it incurs on our behalf in connection with our business and operations;

	•	our obligation to reimburse Spectra Energy for providing us general and administrative services with respect to our business and operations, which reimbursement is capped at $ million, subject to increases in connection with expansions of our operations through the acquisition or construction of new assets or businesses with the concurrence of our conflicts committee;

	•	our obligation to reimburse Spectra Energy for insurance coverage expenses it incurs with respect to our business and operations and with respect to director and officer liability coverage;

	•	Spectra Energy’s obligation to indemnify us for certain liabilities and our obligation to indemnify Spectra Energy for certain liabilities; and

	•	Spectra Energy’s obligation to continue to maintain its credit support, including without limitation guarantees and letters of credit, for our obligations related to commercial contracts with respect to our business or operations that are in effect at the closing of this offering until the expiration of such contracts.

Our general partner and its affiliates will also receive payments from us pursuant to the contractual arrangements described below under the caption “— Contracts with Affiliates.”

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Any or all of the provisions of the omnibus agreement, other than the indemnification provisions described below, will be terminable by Spectra Energy at its option if our general partner is removed without cause and units held by our general partner and its affiliates are not voted in favor of that removal. The omnibus agreement will also terminate in the event of a change of control of us, our general partner or the general partner of our general partner.

Reimbursement of Operating and General and Administrative Expense

Under the omnibus agreement we will reimburse Spectra Energy for the payment of certain operating expenses and for the provision of various general and administrative services (a portion of which will be capped at $ million annually) for our benefit with respect to the assets contributed to us at the closing of this offering. The omnibus agreement will further provide that we will reimburse Spectra Energy for our allocable portion of the premiums on insurance policies covering our assets.

Pursuant to these arrangements, Spectra Energy will perform centralized corporate functions for us, such as legal, accounting, treasury, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes and engineering. We will reimburse Spectra Energy for the expenses to provide these services as well as other expenses it incurs on our behalf, such as salaries of operational personnel performing services for our benefit and the cost of their employee benefits, including 401(k), pension and health insurance benefits.

Competition

Neither Spectra Energy or any of its affiliates will be restricted, under either our partnership agreement or the omnibus agreement, from competing with us. 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 us the opportunity to purchase or construct those assets.

Indemnification

Under the omnibus agreement, Spectra Energy will indemnify us for three years after the closing of this offering against certain potential environmental claims, losses and expenses associated with the operation of the assets and occurring before the closing date of this offering. The maximum liability of Spectra Energy for this indemnification obligation will not exceed $ million and Spectra Energy will not have any obligation under this indemnification until our aggregate losses exceed $ . Spectra Energy will have no indemnification obligations with respect to environmental claims made as a result of additions to or modifications of environmental laws promulgated after the closing date of this offering. We have agreed to indemnify Spectra Energy against environmental liabilities related to our assets to the extent Spectra Energy is not required to indemnify us.

Additionally, Spectra Energy will indemnify us for losses attributable to title defects, retained assets and liabilities (including preclosing litigation relating to contributed assets) and income taxes attributable to pre-closing operations. We will indemnify Spectra Energy for all losses attributable to the postclosing operations of the assets contributed to us, to the extent not subject to Spectra Energy’s indemnification obligations.

Contracts with Affiliates

Gulfstream Limited Liability Company Agreement

In connection with the closing of this offering, Spectra Energy will contribute to us 49.0% of its 50.0% interest in Gulfstream, at which time we will own a 24.5% interest in Gulfstream, Spectra Energy will own a 25.5% interest and The Williams Companies will 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

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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 law or other agreements.

The management committee representatives of Spectra Energy and The Williams Companies will jointly make the determinations related to Gulfstream’s available cash. In addition, because we will hold less than a 25% interest in Gulfstream, under the terms of the limited liability company agreement, Spectra Energy and The Williams Companies will be able to collectively make all decisions with respect to the operation of Gulfstream without our 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 Limited Liability Company Agreement

In connection with the closing of this offering, Spectra Energy will contribute to us 50.0% of its interest in Market Hub, after which we will own a 50.0% interest in Market Hub and Spectra Energy will own a 50.0% interest. An amended and restated limited liability company 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 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 us will jointly make the determinations related to Market Hub’s available cash.

Storage and Transportation Related Arrangements

We charge 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 three pipeline balancing agreements with the following Spectra Energy affiliates: Texas Eastern Transmission (Texas Eastern), LP; Saltville Gas Storage, LLC (Saltville) and Spectra Energy Early Grove Company. Each agreement was entered into in accordance with East Tennessee FERC gas tariff and provides for the monthly balancing of natural gas at receipt and delivery points with affiliates interconnecting with East Tennessee’s pipeline system. In addition, East Tennessee has entered into an interruptible storage service agreement with Saltville and a firm storage service agreement with Spectra Energy Virginia Pipeline Company for the purpose of balancing the operations of East Tennessee.

Market Hub. Spectra Energy’s Texas Eastern Transmission, LP 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 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.

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CONFLICTS OF INTEREST AND FIDUCIARY DUTIES

Conflicts of Interest

Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates (including Spectra Energy) on the one hand, and our partnership and our limited partners, on the other hand. The directors and officers of Spectra Energy Partners GP, LLC have fiduciary duties to manage Spectra Energy Partners GP, LLC and our general partner in a manner beneficial to its owners. At the same time, our general partner has a fiduciary duty to manage our partnership in a manner beneficial to us and our unitholders.

Whenever a conflict arises between our general partner or its affiliates, on the one hand, and us or any other partner, on the other hand, our general partner will resolve that conflict. Our partnership agreement contains provisions that modify and limit our general partner’s fiduciary duties to our unitholders. Our partnership agreement also restricts the remedies available to unitholders for actions taken that, without those limitations, might constitute breaches of fiduciary duty.

Our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our unitholders if the resolution of the conflict is:


	•	approved by the conflicts committee, although our general partner is not obligated to seek such approval;

	•	approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates;

	•	on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

	•	fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.

Our general partner may, but is not required to, seek the approval of such resolution from the conflicts committee of the board of directors of Spectra Energy Partners GP, LLC. If our general partner does not seek approval from the conflicts committee and the board of directors of Spectra Energy Partners GP, LLC determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third and fourth bullet points above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in our partnership agreement, our general partner or the conflicts committee may consider any factors it determines in good faith to consider when resolving a conflict. When our partnership agreement provides that someone act in good faith, it requires that person to believe he is acting in the best interests of the partnership.

Conflicts of interest could arise in the situations described below, among others.

Spectra Energy and its affiliates, including DCP Midstream, LLC and DCP Midstream Partners, LP, are not limited in their ability to compete with us, which could cause conflicts of interest and limit our ability to acquire additional assets or businesses which in turn could adversely affect our results of operations and cash available for distribution to our unitholders.

Neither our partnership agreement nor the omnibus agreement between us, Spectra Energy and others will prohibit Spectra Energy and its affiliates, including 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, storage or other assets in the future, without any obligation to offer us the opportunity to purchase or construct any of those assets. Spectra Energy is a large, established participant in the transportation and

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storage business, and has significantly greater resources and experience than we have, which factors may make it more difficult for us to compete with Spectra Energy with respect to commercial activities as well as for acquisitions candidates. As a result, competition from Spectra Energy and its affiliates could adversely impact our results of operations and cash available for distribution.

Neither our partnership agreement nor any other agreement requires Spectra Energy to pursue a business strategy that favors us or utilizes our assets or dictates what markets to pursue or grow. Spectra Energy’s directors 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.

Because certain of the directors of our general partner are also directors and/or officers of Spectra Energy, such directors have fiduciary duties to Spectra Energy that may cause them to pursue business strategies that disproportionately benefit Spectra Energy or which otherwise are not in our best interests.

Our general partner is allowed to take into account the interests of parties other than us, such as Spectra Energy, in resolving conflicts of interest.

Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. 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. Examples include the exercise of its right to make a determination to receive Class B units in exchange for resetting the target distribution levels related to its incentive distribution rights, its limited call right, its voting rights with respect to the units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation of the partnership.

We will not have any employees and will rely on the employees of our general partner and its affiliates.

All of our executive management personnel will be employees of our general partner and will devote all of their time to our business and affairs. We will also utilize a significant number of employees of Spectra Energy to operate our business and provide us with general and administrative services for which we will reimburse Spectra Energy for allocated expenses of operational personnel who perform services for our benefit and we will reimburse Spectra Energy for allocated general and administrative expenses. Affiliates of our general partner and Spectra Energy will also conduct businesses and activities of their own in which we will have no economic interest. If these separate activities are significantly greater than our activities, there could be material competition for the time and effort of the officers and employees who provide services to Spectra Energy and its affiliates.


	•	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. Examples include the exercise of its limited call right, the exercise of its rights to transfer or vote the units it owns, the exercise of its registration rights and its determination whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement;

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	•	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 and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us;

	•	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 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.

Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.

Under our partnership agreement, our general partner has full power and authority to do all things, other than those items that require unitholder approval or with respect to which our general partner has sought conflicts committee approval, on such terms as it determines to be necessary or appropriate to conduct our business including, but not limited to, the following:


	•	the making of any expenditures, the lending or borrowing of money, the assumption or guarantee of or other contracting for, indebtedness and other liabilities, the issuance of evidences of indebtedness, including indebtedness that is convertible into our securities, and the incurring of any other obligations;

	•	the purchase, sale or other acquisition or disposition of our securities, or the issuance of additional options, rights, warrants and appreciation rights relating to our securities;

	•	the mortgage, pledge, encumbrance, hypothecation or exchange of any or all of our assets;

	•	the negotiation, execution and performance of any contracts, conveyances or other instruments;

	•	the distribution of our cash;

	•	the selection and dismissal of employees and agents, outside attorneys, accountants, consultants and contractors and the determination of their compensation and other terms of employment or hiring;

	•	the maintenance of insurance for our benefit and the benefit of our partners;

	•	the formation of, or acquisition of an interest in, the contribution of property to, and the making of loans to, any limited or general partnerships, joint ventures, corporations, limited liability companies or other relationships;

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	•	the control of any matters affecting our rights and obligations, including the bringing and defending of actions at law or in equity and otherwise engaging in the conduct of litigation, arbitration or mediation and the incurring of legal expense and the settlement of claims and litigation;

	•	the indemnification of any person against liabilities and contingencies to the extent permitted by law;

	•	the making of tax, regulatory and other filings, or rendering of periodic or other reports to governmental or other agencies having jurisdiction over our business or assets; and

	•	the entering into of agreements with any of its affiliates to render services to us or to itself in the discharge of its duties as our general partner.

Our partnership agreement provides that our general partner must act in “good faith” when making decisions on our behalf, and our partnership agreement further provides that in order for a determination by our general partner to be made in “good faith,” our general partner must believe that the determination is in our best interests. Please read “The Partnership Agreement — Voting Rights” for information regarding matters that require unitholder approval.

Our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuance of additional partnership securities and the creation, reduction or increase of reserves, each of which can affect the amount of cash that is distributed to our unitholders.

The amount of cash that is available for distribution to unitholders is affected by decisions of our general partner regarding such matters as:

• amount and timing of asset purchases and sales;


	•	cash expenditures;

	•	borrowings;

	•	the issuance of additional units; and

	•	the creation, reduction or increase of reserves in any quarter.

In addition, our general partner may use an amount equal to two times the amount needed for any one quarter for us to pay a distribution on all of our units (including general partner units), which would not otherwise constitute available cash from operating surplus, in order to permit the payment of cash distributions on its units and incentive distribution rights. All of these actions may affect the amount of cash distributed to our unitholders and the general partner and may facilitate the conversion of subordinated units into common units. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions.”

In addition, borrowings by us and our affiliates do not constitute a breach of any duty owed by the general partner to our unitholders, including borrowings that have the purpose or effect of:


	•	enabling our general partner or its affiliates to receive distributions on any subordinated units held by them or the incentive distribution rights; or

	•	hastening the expiration of the subordination period.

For example, in the event we have not generated sufficient cash from our operations to pay the minimum quarterly distribution on our common units and our subordinated units, our partnership agreement permit us to borrow funds, which would enable us to make this distribution on all outstanding units. Please read “Provisions of Our Partnership Agreement Related to Cash Distributions — Subordination Period.”

Our partnership agreement provides that we and our subsidiaries may borrow funds from our general partner and its affiliates. Our general partner and its affiliates may not borrow funds from us, our operating company, or its operating subsidiaries.

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Our general partner determines which costs incurred by Spectra Energy are reimbursable by us.

We will reimburse our general partner and its affiliates for costs incurred in managing and operating us, including costs incurred in rendering corporate staff and support services to us. The partnership agreement provides that our general partner will determine the expenses that are allocable to us in good faith.

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

Our partnership agreement allows our general partner to determine, in good faith, any amounts to pay itself or its affiliates for any services rendered to us. Our general partner may also enter into additional contractual arrangements with any of its affiliates on our behalf. Neither our partnership agreement nor any of the other agreements, contracts or arrangements between us, on the one hand, and our general partner and its affiliates, on the other hand, that will be in effect as of the closing of this offering will be the result of arm’s-length negotiations. Similarly, agreements, contracts or arrangements between us and our general partner and its affiliates that are entered into following the closing of this offering will not be required to be negotiated on an arm’s-length basis, although, in some circumstances, our general partner may determine that the conflicts committee of our general partner may make a determination on our behalf with respect to one or more of these types of situations.

Our general partner will determine, in good faith, the terms of any of these transactions entered into after the sale of the common units offered in this offering.

Our general partner and its affiliates will have no obligation to permit us to use any facilities or assets of our general partner or its affiliates, except as may be provided in contracts entered into specifically dealing with that use. There is no obligation of our general partner or its affiliates to enter into any contracts of this kind.

Our general partner intends to limit its liability regarding our obligations.

Our general partner intends to limit its liability under contractual arrangements so that the other party has recourse only to our assets, and not against our general partner or its assets. The partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner’s fiduciary duties, even if we could have obtained more favorable terms without the limitation on liability.

Our general partner may exercise its right to call and purchase common units if it and its affiliates own more than 80% of the common units.

Our general partner may exercise its right to call and purchase common units as provided in the partnership agreement or assign this right to one of its affiliates or to us. Our general partner is not bound by fiduciary duty restrictions in determining whether to exercise this right. As a result, a common unitholder may have his common units purchased from him at an undesirable time or price. Please read “The Partnership Agreement — Limited Call Right.”

Common unitholders will have no right to enforce obligations of our general partner and its affiliates under agreements with us.

Any agreements between us on the one hand, and our general partner and its affiliates, on the other, will not grant to the unitholders, separate and apart from us, the right to enforce the obligations of our general partner and its affiliates in our favor.

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

The attorneys, independent accountants and others who have performed services for us regarding this offering have been retained by our general partner. Attorneys, independent accountants and others who perform services for us are selected by our general partner or the conflicts committee and may perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the holders of common units in the event of a conflict of interest between our general partner and its affiliates, on the one hand, and us or the holders of common units, on the other, depending on the nature of the conflict. We do not intend to do so in most cases.

Our general partner may elect to cause us to issue Class B units to it in connection with a resetting of the target distribution levels related to our general partner’s incentive distribution rights without the approval of the conflicts committee of our general partner or our unitholders. This may result in lower distributions to our common unitholders 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. 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 we are experiencing declines in our aggregate cash distributions or at a time when our general partner expects that we will experience declines in our aggregate cash distributions in the foreseeable future. In such situations, our general partner may be 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 specified priorities with respect to our distributions and which therefore may be more advantageous for the general partner to own in lieu of the right to receive incentive distribution payments based on target distribution levels that are less certain to be achieved in the then current business environment. 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. Please read “Provisions of Our Partnership Agreement Related to Cash Distributions — General Partner Interest and Incentive Distribution Rights.”

Fiduciary Duties

Our general partner is accountable to us and our unitholders as a fiduciary. Fiduciary duties owed to unitholders by our general partner are prescribed by law and the partnership agreement. The Delaware Revised Uniform Limited Partnership Act, which we refer to in this prospectus as the Delaware Act, provides that Delaware limited partnerships may, in their partnership agreements, modify, restrict or expand the fiduciary duties otherwise owed by a general partner to limited partners and the partnership.

Our partnership agreement contains various provisions modifying and restricting the fiduciary duties that might otherwise be owed by our general partner. We have adopted these restrictions to allow our general partner or its affiliates to engage in transactions with us that would otherwise be prohibited by state-law fiduciary duty standards and to take into account the interests of other parties in addition to our interests when resolving conflicts of interest. We believe this is appropriate and necessary because our general partner’s board of directors will have fiduciary duties to manage our general partner in a manner

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beneficial to its owners, as well as to you. Without these modifications, the general partner’s ability to make decisions involving conflicts of interest would be restricted. The modifications to the fiduciary standards enable the general partner to take into consideration all parties involved in the proposed action, so long as the resolution is fair and reasonable to us. These modifications also enable our general partner to attract and retain experienced and capable directors. These modifications are detrimental to our common unitholders because they restrict the remedies available to unitholders for actions that, without those limitations, might constitute breaches of fiduciary duty, as described below, and permit our general partner to take into account the interests of third parties in addition to our interests when resolving conflicts of interest. The following is a summary of the material restrictions of the fiduciary duties owed by our general partner to the limited partners:


State-law fiduciary duty standards		Fiduciary duties are generally considered to include an obligation to act in good faith and with due care and loyalty. The duty of care, in the absence of a provision in a partnership agreement providing otherwise, would generally require a general partner to act for the partnership in the same manner as a prudent person would act on his own behalf. The duty of loyalty, in the absence of a provision in a partnership agreement providing otherwise, would generally prohibit a general partner of a Delaware limited partnership from taking any action or engaging in any transaction where a conflict of interest is present.

		The Delaware Act generally provides that a limited partner may institute legal action on behalf of the partnership to recover damages from a third party where a general partner has refused to institute the action or where an effort to cause a general partner to do so is not likely to succeed. In addition, the statutory or case law of some jurisdictions may permit a limited partner to institute legal action on behalf of himself and all other similarly situated limited partners to recover damages from a general partner for violations of its fiduciary duties to the limited partners.

Partnership agreement modified standards		Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates that might otherwise raise issues about compliance with fiduciary duties or applicable law. For example, our partnership agreement provides that when our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must act in “good faith” and will not be subject to any other standard under applicable law. In addition, when our general partner is acting in its individual capacity, as opposed to in its capacity as our general partner, it may act without any fiduciary obligation to us or the unitholders whatsoever. These standards reduce the obligations to which our general partner would otherwise be held.

		In addition to the other more specific provisions limiting the obligations of our general partner, our partnership agreement further 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 errors of judgment or for any acts or omissions unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that the general partner or its officers and directors acted in bad faith or engaged in

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		fraud or willful misconduct or in the case of a criminal matter, acted with knowledge that the indemnitee’s conduct was criminal.

		Special provisions regarding affiliated transactions. Our partnership agreement generally provides that affiliated transactions and resolutions of conflicts of interest not involving a vote of unitholders and that are not approved by the conflicts committee of the board of directors of our general partner must be:

		• on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

		• “fair and reasonable” to us, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to us).

		If our general partner does not seek approval from the conflicts committee and its board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the bullet points above, then it will be presumed that, in making its decision, the board of directors, which may include board members affected by the conflict of interest, acted in good faith and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. These standards reduce the obligations to which our general partner would otherwise be held.

By purchasing our common units, each common unitholder automatically agrees to be bound by the provisions in the partnership agreement, including the provisions discussed above. This is in accordance with the policy of the Delaware Act favoring the principle of freedom of contract and the enforceability of partnership agreements. The failure of a limited partner or assignee to sign a partnership agreement does not render the partnership agreement unenforceable against that person.

We must indemnify our general partner and its officers, directors, managers and certain other specified persons, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by our general partner or these other persons. We must provide this indemnification unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that these persons acted in bad faith or engaged in fraud or willful misconduct. We must also provide this indemnification for criminal proceedings unless our general partner or these other persons acted with knowledge that their conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it meets the requirements set forth above. To the extent these provisions purport to include indemnification for liabilities arising under the Securities Act, in the opinion of the SEC, such indemnification is contrary to public policy and, therefore, unenforceable. Please read “The Partnership Agreement — Indemnification.”

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DESCRIPTION OF THE COMMON UNITS

The Units

The common units and the subordinated units are separate classes of limited partner interests in us. The holders of units are entitled to participate in partnership distributions and exercise the rights or privileges available to limited partners under our partnership agreement. For a description of the relative rights and preferences of holders of common units and subordinated units in and to partnership distributions, please read this section and “Our Cash Distribution Policy and Restrictions on Distributions.” For a description of the rights and privileges of limited partners under our partnership agreement, including voting rights, please read “The Partnership Agreement.”

Transfer Agent and Registrar

Duties. will serve as registrar and transfer agent for the common units. We will pay all fees charged by the transfer agent for transfers of common units except the following that must be paid by unitholders:


	•	surety bond premiums to replace lost or stolen certificates, taxes and other governmental charges;

	•	special charges for services requested by a common unitholder; and

	•	other similar fees or charges.

There will be no charge to unitholders for disbursements of our cash distributions. We will indemnify the transfer agent, its agents and each of their stockholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.

Resignation or Removal. The transfer agent may resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If no successor has been appointed and has accepted the appointment within 30 days after notice of the resignation or removal, our general partner may act as the transfer agent and registrar until a successor is appointed.

Transfer of Common Units

The transfer of the common units to persons that purchase directly from the underwriters will be accomplished through the proper completion, execution and delivery of a transfer application by the investor. Any later transfers of a common unit will not be recorded by the transfer agent or recognized by us unless the transferee executes and delivers a properly completed transfer application. By executing and delivering a transfer application, the transferee of common units:


	•	becomes the record holder of the common units and is an assignee until admitted into our partnership as a substituted limited partner;

	•	automatically requests admission as a substituted limited partner in our partnership;

	•	executes and agrees to be bound by the terms and conditions of our partnership agreement;

	•	represents that the transferee has the capacity, power and authority to enter into our partnership agreement;

	•	grants powers of attorney to the officers of our general partner and any liquidator of us as specified in our partnership agreement;

	•	gives the consents, covenants, representations and approvals contained in our partnership agreement, such as the approval of all transactions and agreements we are entering into in connection with our formation and this offering; and

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	•	certifies:


	-	that the transferee is an individual or is an entity subject to United States federal income taxation on the income generated by us; or

	-	that, if the transferee is an entity not subject to United States federal income taxation on the income generated by us, as in the case, for example, of a mutual fund taxed as a regulated investment company or a partnership, all the entity’s owners are subject to United States federal income taxation on the income generated by us.

An assignee will become a substituted limited partner of our partnership for the transferred common units automatically upon the recording of the transfer on our books and records. Our general partner will cause any unrecorded transfers for which a properly completed and duly executed transfer application has been received to be recorded on our books and records no less frequently than quarterly.

A transferee’s broker, agent or nominee may, but is not obligated to, complete, execute and deliver a transfer application. We are entitled to treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holder’s rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

Common units are securities and are transferable according to the laws governing transfer of securities. In addition to other rights acquired upon transfer, the transferor gives the transferee the right to request admission as a substituted limited partner in our partnership for the transferred common units. A purchaser or transferee of common units who does not execute and deliver a properly completed transfer application obtains only:


	•	the right to assign the common unit to a purchaser or other transferee; and

	•	the right to transfer the right to seek admission as a substituted limited partner in our partnership for the transferred common units.

Thus, a purchaser or transferee of common units who does not execute and deliver a properly completed transfer application:


	•	will not receive cash distributions;

	•	will not be allocated any of our income, gain, deduction, losses or credits for federal income tax or other tax purposes;

	•	may not receive some federal income tax information or reports furnished to record holders of common units; and

	•	will have no voting rights;

unless the common units are held in a nominee or “street name” account and the nominee or broker has executed and delivered a transfer application and certification as to itself and any beneficial holders.

The transferor of common units has a duty to provide the transferee with all information that may be necessary to transfer the common units. The transferor does not have a duty to ensure the execution of the transfer application by the transferee and has no liability or responsibility if the transferee neglects or chooses not to execute and deliver a properly completed transfer application to the transfer agent. Please read “The Partnership Agreement — Status as Limited Partner or Assignee.”

Until a common unit has been transferred on our books, we and the transfer agent may treat the record holder of the unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

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THE PARTNERSHIP AGREEMENT

The following is a summary of the material provisions of our partnership agreement. The form of our partnership agreement is included in this prospectus as Appendix A. We will provide prospective investors with a copy of our partnership agreement upon request at no charge.

We summarize the following provisions of our partnership agreement elsewhere in this prospectus:


	•	with regard to distributions of available cash, please read “Provisions of Our Partnership Agreement Relating to Cash Distributions”;

	•	with regard to the fiduciary duties of our general partner, please read “Conflicts of Interest and Fiduciary Duties”;

	•	with regard to the transfer of common units, please read “Description of the Common Units — Transfer of Common Units”; and

	•	with regard to allocations of taxable income and taxable loss, please read “Material Tax Consequences.”

Organization and Duration

Our partnership was organized March 19, 2007 and will have a perpetual existence.

Purpose

Our purpose under the partnership agreement is limited to any business activity that is approved by our general partner and that lawfully may be conducted by a limited partnership organized under Delaware law; provided, that our general partner shall not cause us to engage, directly or indirectly, in any business activity that our general partner determines would cause us to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes.

Although our general partner has the ability to cause us and our subsidiaries to engage in activities other than the business of transporting and storing natural gas, our general partner has no current plans to do so and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners. Our general partner is authorized in general to perform all acts it determines to be necessary or appropriate to carry out our purposes and to conduct our business.

Power of Attorney

Each limited partner, and each person who acquires a unit from a unitholder, by accepting the common unit, automatically grants to our general partner and, if appointed, a liquidator, a power of attorney to, among other things, execute and file documents required for our qualification, continuance or dissolution. The power of attorney also grants our general partner the authority to amend, and to make consents and waivers under, our partnership agreement.

Cash Distributions

Our partnership agreement specifies the manner in which we will make cash distributions to holders of our common units and other partnership securities as well as to our general partner in respect of its general partner interest and its incentive distribution rights. For a description of these cash distribution provisions, please read “Provisions of Our Partnership Agreement Relating to Cash Distributions.”

Capital Contributions

Unitholders are not obligated to make additional capital contributions, except as described below under “— Limited Liability.”

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For a discussion of our general partner’s right to contribute capital to maintains its 2% general partner interest if we issue additional units, please read “— Issuance of Additional Securities.”

Voting Rights

The following is a summary of the unitholder vote required for the matters specified below. Matters requiring the approval of a “unit majority” require:


	•	during the subordination period, the approval of a majority of the common units, excluding those common units held by our general partner and its affiliates, and a majority of the subordinated units, voting as separate classes; and

	•	after the subordination period, the approval of a majority of the common units and Class B units, if any, voting as a single class.

In voting their common, Class B and subordinated units, our general partner and its affiliates will have no fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners.


Issuance of additional units		No approval right.
Amendment of the partnership agreement		Certain amendments may be made by the general partner without the approval of the unitholders. Other amendments generally require the approval of a unit majority. Please read “— Amendment of the Partnership Agreement.”
Merger of our partnership or the sale of all or substantially all of our assets		Unit majority in certain circumstances. Please read “— Merger, Consolidation, Conversion, Sale or Other Disposition of Assets.”
Dissolution of our partnership		Unit majority. Please read “— Termination and Dissolution.”
Continuation of our business upon dissolution		Unit majority. Please read “— Termination and Dissolution.”
Withdrawal of the general partner		Under most circumstances, the approval of a majority of the common units, excluding common units held by our general partner and its affiliates, is required for the withdrawal of our general partner prior to June 30, 2017 in a manner that would cause a dissolution of our partnership. Please read “— Withdrawal or Removal of the General Partner.”
Removal of the general partner		Not less than 66 2 / 3 % of the outstanding units, voting as a single class, including units held by our general partner and its affiliates. Please read “— Withdrawal or Removal of the General Partner.”
Transfer of the general partner interest		Our general partner may transfer all, but not less than all, of its general partner interest in us without a vote of our unitholders to an affiliate or another person in connection with its merger or consolidation with or into, or sale of all or substantially all of its assets to, such person. The approval of a majority of the common units, excluding common units held by the general partner and its affiliates, is required in other circumstances for a transfer of the general partner interest to a third party prior to June 30, 2017. See “— Transfer of General Partner Units.”

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Transfer of incentive distribution rights		Our general partner may transfer any or all of the incentive distribution rights without a vote of our unitholders to an affiliate or another person as part of our general partner’s merger or consolidation with or into, or sale of all or substantially all of its assets or the sale of all of the ownership interests in such holder to, such person. The approval of a majority of the common units, excluding common units held by the general partner and its affiliates, is required in other circumstances for a transfer of the incentive distribution rights to a third party prior to June 30, 2017. Please read “— Transfer of Incentive Distribution Rights.”
Transfer of ownership interests in our general partner		No approval required at any time. Please read “— Transfer of Ownership Interests in the General Partner.”

Limited Liability

Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and that he otherwise acts in conformity with the provisions of the partnership agreement, his liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital he is obligated to contribute to us for his common units plus his share of any undistributed profits and assets. If it were determined, however, that the right, or exercise of the right, by the limited partners as a group:


	•	to remove or replace the general partner;

	•	to approve some amendments to the partnership agreement; or

	•	to take other action under the partnership agreement;

constituted “participation in the control” of our business for the purposes of the Delaware Act, then the limited partners could be held personally liable for our obligations under the laws of Delaware, to the same extent as the general partner. This liability would extend to persons who transact business with us who reasonably believe that the limited partner is a general partner. Neither the partnership agreement nor the Delaware Act specifically provides for legal recourse against the general partner if a limited partner were to lose limited liability through any fault of the general partner. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for this type of a claim in Delaware case law.

Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, would exceed the fair value of the assets of the limited partnership. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years. Under the Delaware Act, a substituted limited partner of a limited partnership is liable for the obligations of his assignor to make contributions to the partnership, except that such person is not obligated for liabilities unknown to him at the time he became a limited partner and that could not be ascertained from the partnership agreement.

Our subsidiaries conduct business in nine states and we may have subsidiaries that conduct business in other states in the future. Maintenance of our limited liability as a limited partner of the operating

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partnership may require compliance with legal requirements in the jurisdictions in which the operating partnership conducts business, including qualifying our subsidiaries to do business there.

Limitations on the liability of limited partners for the obligations of a limited partner have not been clearly established in many jurisdictions. If, by virtue of our partnership interest in our operating partnership or otherwise, it were determined that we were conducting business in any state without compliance with the applicable limited partnership or limited liability company statute, or that the right or exercise of the right by the limited partners as a group to remove or replace the general partner, to approve some amendments to the partnership agreement, or to take other action under the partnership agreement constituted “participation in the control” of our business for purposes of the statutes of any relevant jurisdiction, then the limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as the general partner under the circumstances. We will operate in a manner that the general partner considers reasonable and necessary or appropriate to preserve the limited liability of the limited partners.

Issuance of Additional Securities

Our partnership agreement authorizes us to issue an unlimited number of additional partnership securities for the consideration and on the terms and conditions determined by our general partner without the approval of the unitholders.

It is possible that we will fund acquisitions through the issuance of additional common units, subordinated units or other partnership securities. Holders of any additional common units we issue will be entitled to share equally with the then-existing holders of common units in our distributions of available cash. In addition, the issuance of additional common units or other partnership securities may dilute the value of the interests of the then-existing holders of common units in our net assets.

In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership securities that, as determined by our general partner, may have special voting rights to which the common units are not entitled. In addition, our partnership agreement does not prohibit the issuance by our subsidiaries of equity securities, which may effectively rank senior to the common units.

Upon issuance of additional partnership securities (other than the issuance of common units upon exercise by the underwriters of their option to purchase additional common units, the issuance of Class B units in connection with a reset of the incentive distribution target levels or the issuance of partnership securities upon conversion of outstanding partnership securities), our general partner will be entitled, but not required, to make additional capital contributions to the extent necessary to maintain its 2% general partner interest in us. Our general partner’s 2% interest in us will be reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its 2% general partner interest. Moreover, our general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units, subordinated units or other partnership securities whenever, and on the same terms that, we issue those securities to persons other than our general partner and its affiliates, to the extent necessary to maintain the percentage interest of the general partner and its affiliates, including such interest represented by common units and subordinated units, that existed immediately prior to each issuance. The holders of common units will not have preemptive rights to acquire additional common units or other partnership securities.

Amendment of the Partnership Agreement

General. Amendments to our partnership agreement may be proposed only by or with the consent of our general partner. However, our general partner will have no duty or obligation to propose any amendment and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners. In order to adopt a proposed amendment, other than the amendments discussed below, our general partner is required to seek written approval of the holders of the number of units required to approve the amendment or call a

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meeting of the limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a unit majority.

Prohibited Amendments. No amendment may be made that would:


	•	enlarge the obligations of any limited partner without its consent, unless approved by at least a majority of the type or class of limited partner interests so affected; or

	•	enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without the consent of our general partner, which consent may be given or withheld at its option.

The provision of our partnership agreement preventing the amendments having the effects described in any of the clauses above can be amended upon the approval of the holders of at least 90% of the outstanding units voting together as a single class (including units owned by our general partner and its affiliates). Upon completion of the offering, our general partner and its affiliates will own approximately 81.3% of the outstanding common and subordinated units.

No Unitholder Approval. Our general partner may generally make amendments to our partnership agreement without the approval of any limited partner to reflect:


	•	a change in our name, the location of our principal place of our business, our registered agent or our registered office;

	•	the admission, substitution, withdrawal or removal of partners in accordance with our partnership agreement;

	•	a change that our general partner determines to be necessary or appropriate to qualify or continue our qualification as a limited partnership or a partnership in which the limited partners have limited liability under the laws of any state or to ensure that neither we nor the operating partnership nor any of its subsidiaries will be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes;

	•	an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner or its directors, officers, agents or trustees from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisors Act of 1940, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, or ERISA, whether or not substantially similar to plan asset regulations currently applied or proposed;

	•	an amendment that our general partner determines to be necessary or appropriate for the authorization of additional partnership securities or rights to acquire partnership securities, including any amendment that our general partner determines is necessary or appropriate in connection with:


	•	the adjustments of the minimum quarterly distribution, first target distribution, second target distribution and third target distribution in connection with the reset of our general partner’s incentive distribution rights as described under “Provisions of Our Partnership Agreement Relating to Cash Distributions — General Partner’s Right to Reset Incentive Distribution Levels”; or

	•	the implementation of the provisions relating to our general partner’s right to reset its incentive distribution rights in exchange for Class B units; and

	•	any modification of the incentive distribution rights made in connection with the issuance of additional partnership securities or rights to acquire partnership securities, provided that, any such modifications and related issuance of partnership securities have received approval by a majority of the members of the conflicts committee of our general partner;


	•	any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone;

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	•	an amendment effected, necessitated or contemplated by a merger agreement that has been approved under the terms of our partnership agreement;

	•	any amendment that our general partner determines to be necessary or appropriate for the formation by us of, or our investment in, any corporation, partnership or other entity, as otherwise permitted by our partnership agreement;

	•	a change in our fiscal year or taxable year and related changes;

	•	conversions into, mergers with or conveyances to another limited liability entity that is newly formed and has no assets, liabilities or operations at the time of the conversion, merger or conveyance other than those it receives by way of the conversion, merger or conveyance; or

	•	any other amendments substantially similar to any of the matters described in the clauses above.

In addition, our general partner may make amendments to our partnership agreement without the approval of any limited partner if our general partner determines that those amendments:


	•	do not adversely affect in any material respect the limited partners considered as a whole or any particular class of limited partners;

	•	are necessary or appropriate to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;

	•	are necessary or appropriate to facilitate the trading of limited partner interests or to comply with any rule, regulation, guideline or requirement of any securities exchange on which the limited partner interests are or will be listed for trading;

	•	are necessary or appropriate for any action taken by our general partner relating to splits or combinations of units under the provisions of our partnership agreement; or

	•	are required to effect the intent expressed in this prospectus or the intent of the provisions of our partnership agreement or are otherwise contemplated by our partnership agreement.

Opinion of Counsel and Unitholder Approval. For amendments of the type not requiring unitholder approval, our general partner will not be required to obtain an opinion of counsel that an amendment will not result in a loss of limited liability to the limited partners or result in our being treated as an entity for federal income tax purposes in connection with any of the amendments. No other amendments to our partnership agreement will become effective without the approval of holders of at least 90% of the outstanding units voting as a single class unless we first obtain an opinion of counsel to the effect that the amendment will not affect the limited liability under applicable law of any of our limited partners.

In addition to the above restrictions, any amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding units in relation to other classes of units will require the approval of at least a majority of the type or class of units so affected. Any amendment that reduces the voting percentage required to take any action is required to be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the voting requirement sought to be reduced.

Merger, Consolidation, Conversion, Sale or Other Disposition of Assets

A merger, consolidation or conversion of us requires the prior consent of our general partner. However, our general partner will have no duty or obligation to consent to any merger, consolidation or conversion and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interest of us or the limited partners.

In addition, the partnership agreement generally prohibits our general partner without the prior approval of the holders of a unit majority, from causing us to, among other things, sell, exchange or otherwise dispose of all or substantially all of our assets in a single transaction or a series of related transactions, including by

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way of merger, consolidation or other combination, or approving on our behalf the sale, exchange or other disposition of all or substantially all of the assets of our subsidiaries. Our general partner may, however, mortgage, pledge, hypothecate or grant a security interest in all or substantially all of our assets without that approval. Our general partner may also sell all or substantially all of our assets under a foreclosure or other realization upon those encumbrances without that approval. Finally, our general partner may consummate any merger without the prior approval of our unitholders if we are the surviving entity in the transaction, our general partner has received an opinion of counsel regarding limited liability and tax matters, the transaction would not result in a material amendment to the partnership agreement, each of our units will be an identical unit of our partnership following the transaction, and the partnership securities to be issued do not exceed 20% of our outstanding partnership securities immediately prior to the transaction.

If the conditions specified in the partnership agreement are satisfied, our general partner may convert us or any of our subsidiaries into a new limited liability entity or merge us or any of our subsidiaries into, or convey all of our assets to, a newly formed entity if the sole purpose of that conversion, merger or conveyance is to effect a mere change in our legal form into another limited liability entity, our general partner has received an opinion of counsel regarding limited liability and tax matters, and the governing instruments of the new entity provide the limited partners and the general partner with the same rights and obligations as contained in the partnership agreement. The unitholders are not entitled to dissenters’ rights of appraisal under the partnership agreement or applicable Delaware law in the event of a conversion, merger or consolidation, a sale of substantially all of our assets or any other similar transaction or event.

Termination and Dissolution

We will continue as a limited partnership until terminated under our partnership agreement. We will dissolve upon:


	•	the election of our general partner to dissolve us, if approved by the holders of units representing a unit majority;

	•	there being no limited partners, unless we are continued without dissolution in accordance with applicable Delaware law;

	•	the entry of a decree of judicial dissolution of our partnership; or

	•	the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner other than by reason of a transfer of its general partner interest in accordance with our partnership agreement or withdrawal or removal following approval and admission of a successor.

Upon a dissolution under the last clause above, the holders of a unit majority may also elect, within specific time limitations, to continue our business on the same terms and conditions described in our partnership agreement by appointing as a successor general partner an entity approved by the holders of units representing a unit majority, subject to our receipt of an opinion of counsel to the effect that:


	•	the action would not result in the loss of limited liability of any limited partner; and

	•	neither our partnership, our operating partnership nor any of our other subsidiaries would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of that right to continue.

Liquidation and Distribution of Proceeds

Upon our dissolution, unless we are continued as a new limited partnership, the liquidator authorized to wind up our affairs will, acting with all of the powers of our general partner that are necessary or appropriate to liquidate our assets and apply the proceeds of the liquidation as described in “Provisions of Our Partnership Agreement Relating to Cash Distributions — Distributions of Cash Upon Liquidation.” The liquidator may defer liquidation or distribution of our assets for a reasonable period of time or distribute assets to partners in kind if it determines that a sale would be impractical or would cause undue loss to our partners.

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Withdrawal or Removal of the General Partner

Except as described below, our general partner has agreed not to withdraw voluntarily as our general partner prior to June 30, 2017 without obtaining the approval of the holders of at least a majority of the outstanding common units, excluding common units held by the general partner and its affiliates, and furnishing an opinion of counsel regarding limited liability and tax matters. On or after June 30, 2017, our general partner may withdraw as general partner without first obtaining approval of any unitholder by giving 90 days’ written notice, and that withdrawal will not constitute a violation of our partnership agreement. Notwithstanding the information above, our general partner may withdraw without unitholder approval upon 90 days’ notice to the limited partners if at least 50% of the outstanding common units are held or controlled by one person and its affiliates other than the general partner and its affiliates. In addition, the partnership agreement permits our general partner in some instances to sell or otherwise transfer all of its general partner interest in us without the approval of the unitholders. Please read “— Transfer of General Partner Units” and “— Transfer of Incentive Distribution Rights.”

Upon withdrawal of our general partner under any circumstances, other than as a result of a transfer by our general partner of all or a part of its general partner interest in us, the holders of a unit majority, voting as separate classes, may select a successor to that withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated, unless within a specified period after that withdrawal, the holders of a unit majority agree in writing to continue our business and to appoint a successor general partner. Please read “— Termination and Dissolution.”

Our general partner may not be removed unless that removal is approved by the vote of the holders of not less than 66 2 / 3 % of the outstanding units, voting together as a single class, including units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of our general partner is also subject to the approval of a successor general partner by the vote of the holders of a majority of the outstanding common units and Class B units, if any, voting as a separate class, and subordinated units, voting as a separate class. The ownership of more than 33 1 / 3 % of the outstanding units by our general partner and its affiliates would give them the practical ability to prevent our general partner’s removal. At the closing of this offering, our general partner and its affiliates will own 81.3% of the outstanding common and subordinated units.

Our partnership agreement also provides that if our general partner is removed as our general partner under circumstances where cause does not exist and units held by the general partner and its affiliates are not voted in favor of that removal:


	•	the subordination period will end, and all outstanding subordinated units will immediately convert into common units on a one-for-one basis;

	•	any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and

	•	our general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests based on the fair market value of those interests at that time.

In the event of removal of a general partner under circumstances where cause exists or withdrawal of a general partner where that withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the general partner interest and incentive distribution rights of the departing general partner for a cash payment equal to the fair market value of those interests. Under all other circumstances where a general partner withdraws or is removed by the limited partners, the departing general partner will have the option to require the successor general partner to purchase the general partner interest of the departing general partner and its incentive distribution rights for fair market value. In each case, this fair market value will be determined by agreement between the departing general partner and the successor general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing general partner and the successor general partner will

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determine the fair market value. Or, if the departing general partner and the successor general partner cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.

If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner’s general partner interest and its incentive distribution rights will automatically convert into common units equal to the fair market value of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.

In addition, we will be required to reimburse the departing general partner for all amounts due the departing general partner, including, without limitation, all employee-related liabilities, including severance liabilities, incurred for the termination of any employees employed by the departing general partner or its affiliates for our benefit.

Transfer of General Partner Units

Except for transfer by our general partner of all, but not less than all, of its general partner units to:


	•	an affiliate of our general partner (other than an individual); or

	•	another entity as part of the merger or consolidation of our general partner with or into another entity or the transfer by our general partner of all or substantially all of its assets to another entity,

our general partner may not transfer all or any of its general partner units to another person prior to June 30, 2017 without the approval of the holders of at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates. As a condition of this transfer, the transferee must assume, among other things, the rights and duties of our general partner, agree to be bound by the provisions of our partnership agreement, and furnish an opinion of counsel regarding limited liability and tax matters.

Our general partner and its affiliates may at any time, transfer units to one or more persons, without unitholder approval, except that they may not transfer subordinated units to us.

Transfer of Ownership Interests in the General Partner

At any time, Spectra Energy and its affiliates may sell or transfer all or part of their partnership interests in our general partner, or their membership interest in Spectra Energy Partners GP, LLC, the general partner of our general partner, to an affiliate or third party without the approval of our unitholders.

Transfer of Incentive Distribution Rights

Our general partner or its affiliates or a subsequent holder may transfer its incentive distribution rights to an affiliate of the holder (other than an individual) or another entity as part of the merger or consolidation of such holder with or into another entity, the sale of all of the ownership interest in the holder or the sale of all or substantially all of its assets to, that entity without the prior approval of the unitholders. Prior to June 30, 2017, other transfers of incentive distribution rights will require the affirmative vote of holders of a majority of the outstanding common units, excluding common units held by our general partner and its affiliates. On or after June 30, 2017, the incentive distribution rights will be freely transferable.

Change of Management Provisions

Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove Spectra Energy Partners (DE) GP, LP as our general partner or otherwise change our management. If any person or group other than our general partner and its affiliates acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units

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from our general partner or its affiliates and any transferees of that person or group approved by our general partner or to any person or group who acquires the units with the prior approval of the board of directors of our general partner.

Our partnership agreement also provides that if our general partner is removed as our general partner under circumstances where cause does not exist and units held by our general partner and its affiliates are not voted in favor of that removal:


	•	the subordination period will end and all outstanding subordinated units will immediately convert into common units on a one-for-one basis;

	•	any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and

	•	our general partner will have the right to convert its general partner units and its incentive distribution rights into common units or to receive cash in exchange for those interests based on the fair market value of those interests at that time.

Limited Call Right

If at any time our general partner and its affiliates own more than 80% of the then-issued and outstanding limited partner interests of any class, our general partner will have the right, which it may assign in whole or in part to any of its affiliates or to us, to acquire all, but not less than all, of the limited partner interests of the class held by unaffiliated persons as of a record date to be selected by our general partner, on at least 10 but not more than 60 days notice. The purchase price in the event of this purchase is the greater of:


	•	the highest cash price paid by either of our general partner or any of its affiliates for any limited partner interests of the class purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those limited partner interests; and

	•	the current market price as of the date three days before the date the notice is mailed.

As a result of our general partner’s right to purchase outstanding limited partner interests, a holder of limited partner interests may have his limited partner interests purchased at a price that may be lower than market prices at various times prior to such purchase or lower than a unitholder may anticipate the market price to be in the future. The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his common units in the market. Please read “Material Tax Consequences — Disposition of Common Units.”

Non-Taxpaying Assignees; Redemption

To avoid any adverse effect on the maximum applicable rates chargeable to customers by our subsidiaries that are regulated interstate natural gas pipelines, or in order to reverse an adverse determination that has occurred regarding such maximum rate, transferees (including purchasers from the underwriters in this offering) are required to fill out a properly completed transfer application certifying, and our general partner, acting on our behalf, may at any time require each unitholder to re-certify:


	•	that the transferee or unitholder is an individual or an entity subject to United States federal income taxation on the income generated by us; or

	•	that, if the transferee unitholder is an entity not subject to United States federal income taxation on the income generated by us, as in the case, for example, of a mutual fund taxed as a regulated investment company or a partnership, all the entity’s owners are subject to United States federal income taxation on the income generated by us.

This certification can be changed in any manner our general partner determines is necessary or appropriate to implement its original purpose.

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If a unitholder fails to furnish:


	•	a transfer application containing the required certification;

	•	a re-certification containing the required certification within 30 days after request; or

	•	provides a false certification; then

we will have the right, which we may assign to any of our affiliates, to acquire all but not less than all of the units held by such unitholder. Further, the units will not be entitled to any allocations of income or loss, distributions or voting rights while held by such unitholder.

The purchase price in the event of such an acquisition for each unit held by such unitholder will be the lesser of:

(1) the price paid by such unitholder for the relevant unit; and

(2) the current market price as of the date three days before the date the notice is mailed.

The purchase price will be paid in cash or by delivery of a promissory note, as determined by our general partner. Any such promissory note will bear interest at the rate of 5% annually and be payable in three equal annual installments of principal and accrued interest, commencing one year after the redemption date.

Meetings; Voting

Except as described below regarding a person or group owning 20% or more of any class of units then outstanding, record holders of units on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited.

Our general partner does not anticipate that any meeting of unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or without a meeting if consents in writing describing the action so taken are signed by holders of the number of units necessary to authorize or take that action at a meeting. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20% of the outstanding units of the class for which a meeting is proposed. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting has been called represented in person or by proxy will constitute a quorum unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage.

Each record holder of a unit has a vote according to his percentage interest in us, although additional limited partner interests having special voting rights could be issued. Please read “— Issuance of Additional Securities.” However, if at any time any person or group, other than our general partner and its affiliates, or a direct or subsequently approved transferee of our general partner or its affiliates, acquires, in the aggregate, beneficial ownership of 20% or more of any class of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum or for other similar purposes. Common units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and his nominee provides otherwise. Except as our partnership agreement otherwise provides, subordinated units will vote together with common units and Class B units as a single class.

Any notice, demand, request, report or proxy material required or permitted to be given or made to record holders of common units under our partnership agreement will be delivered to the record holder by us or by the transfer agent.

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Status as Limited Partner

By transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission is reflected in our books and records. Except as described under “— Limited Liability,” the common units will be fully paid, and unitholders will not be required to make additional contributions.

Non-Citizen Assignees; Redemption

If we are or become subject to federal, state or local laws or regulations that, in the reasonable determination of our general partner, create a substantial risk of cancellation or forfeiture of any property that we have an interest in because of the nationality, citizenship or other related status of any limited partner, we may redeem the units held by the limited partner at their current market price. In order to avoid any cancellation or forfeiture, our general partner may require each limited partner to furnish information about his nationality, citizenship or related status. If a limited partner fails to furnish information about his nationality, citizenship or other related status within 30 days after a request for the information or our general partner determines after receipt of the information that the limited partner is not an eligible citizen, the limited partner may be treated as a non-citizen assignee. A non-citizen assignee is entitled to an interest equivalent to that of a limited partner for the right to share in allocations and distributions from us, including liquidating distributions. A non-citizen assignee does not have the right to direct the voting of his units and may not receive distributions in-kind upon our liquidation.

Indemnification

Under our partnership agreement, in most circumstances, we will indemnify the following persons, to the fullest extent permitted by law, from and against all losses, claims, damages or similar events:


	•	our general partner;

	•	any departing general partner;

	•	any person who is or was an affiliate of a general partner or any departing general partner;

	•	any person who is or was a director, officer, member, partner, fiduciary or trustee of any entity set forth in the preceding three bullet points;

	•	any person who is or was serving as director, officer, member, partner, fiduciary or trustee of another person at the request of our general partner or any departing general partner; and

	•	any person designated by our general partner.

Any indemnification under these provisions will only be out of our assets. Unless it otherwise agrees, our general partner will not be personally liable for, or have any obligation to contribute or lend funds or assets to us to enable us to effectuate, indemnification. We may purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under our partnership agreement.

Reimbursement of Expenses

Our partnership agreement requires us to reimburse our general partner for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. The general partner is entitled to determine in good faith the expenses that are allocable to us.

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Books and Reports

Our general partner is required to keep appropriate books of our business at our principal offices. The books will be maintained for both tax and financial reporting purposes on an accrual basis. For tax and fiscal reporting purposes, our fiscal year is the calendar year.

We will furnish or make available to record holders of common units, within 120 days after the close of each fiscal year, an annual report containing audited financial statements and a report on those financial statements by our independent public accountants. Except for our fourth quarter, we will also furnish or make available summary financial information within 90 days after the close of each quarter.

We will furnish each record holder of a unit with information reasonably required for tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to unitholders will depend on the cooperation of unitholders in supplying us with specific information. Every unitholder will receive information to assist him in determining his federal and state tax liability and filing his federal and state income tax returns, regardless of whether he supplies us with information.

Right to Inspect Our Books and Records

Our partnership agreement provides that a limited partner can, for a purpose reasonably related to his interest as a limited partner, upon reasonable written demand stating the purpose of such demand and at his own expense, have furnished to him:


	•	a current list of the name and last known address of each partner;

	•	a copy of our tax returns;

	•	information as to the amount of cash, and a description and statement of the agreed value of any other property or services, contributed or to be contributed by each partner and the date on which each partner became a partner;

	•	copies of our partnership agreement, our certificate of limited partnership, related amendments and powers of attorney under which they have been executed;

	•	information regarding the status of our business and financial condition; and

	•	any other information regarding our affairs as is just and reasonable.

Our general partner may, and intends to, keep confidential from the limited partners, trade secrets or other information the disclosure of which our general partner believes in good faith is not in our best interests or that we are required by law or by agreements with third parties to keep confidential.

Registration Rights

Under our partnership agreement, we have agreed to register for resale under the Securities Act and applicable state securities laws any common units, subordinated units or other partnership securities proposed to be sold by our general partner or any of its affiliates or their assignees if an exemption from the registration requirements is not otherwise available. These registration rights continue for two years following any withdrawal or removal of Spectra Energy Partners (DE) GP, LP as general partner. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts and a structuring fee. Please read “Units Eligible for Future Sale.”

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UNITS ELIGIBLE FOR FUTURE SALE

After the sale of the common units offered hereby and assuming that the underwriters do not exercise their option to purchase additional units, management of our general partner and Spectra Energy and its affiliates will hold an aggregate of 29,812,011 common units and 20,030,066 subordinated units. The sale of these units could have an adverse impact on the price of the common units or on any trading market that may develop.

The common units sold in the offering will generally be freely transferable without restriction or further registration under the Securities Act, except that any common units owned by an “affiliate” of ours may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption under Rule 144 or otherwise. Rule 144 permits securities acquired by an affiliate of the issuer to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:


	•	1% of the total number of the securities outstanding; or

	•	the average weekly reported trading volume of the common units for the four calendar weeks prior to the sale.

Sales under Rule 144 are also subject to specific manner of sale provisions, holding period requirements, notice requirements and the availability of current public information about us. A person who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned his common units for at least two years, would be entitled to sell common units under Rule 144 without regard to the public information requirements, volume limitations, manner of sale provisions and notice requirements of Rule 144.

The partnership agreement does not restrict our ability to issue any partnership securities at any time. Any issuance of additional common units or other equity securities would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributions to and market price of, common units then outstanding. Please read “The Partnership Agreement — Issuance of Additional Securities.”

Under our partnership agreement, our general partner and its affiliates have the right to cause us to register under the Securities Act and state securities laws the offer and sale of any common units, subordinated units or other partnership securities that they hold. Subject to the terms and conditions of our partnership agreement, these registration rights allow our general partner and its affiliates or their assignees holding any units or other partnership securities to require registration of any of these units or other partnership securities and to include them in a registration by us of other units, including units offered by us or by any unitholder. Our general partner will continue to have these registration rights for two years following its withdrawal or removal as our general partner. In connection with any registration of this kind, we will indemnify each unitholder participating in the registration and its officers, directors and controlling persons from and against any liabilities under the Securities Act or any state securities laws arising from the registration statement or prospectus. We will bear all costs and expenses incidental to any registration, excluding any underwriting discounts and a structuring fee. Except as described below, our general partner and its affiliates may sell their units or other partnership interests in private transactions at any time, subject to compliance with applicable laws.

Spectra Energy, our partnership, our operating company, our general partner and the directors and executive officers of our general partner, have agreed not to sell any common units they beneficially own for a period of 180 days from the date of this prospectus. For a description of these lock-up provisions, please read “Underwriting.”

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MATERIAL TAX CONSEQUENCES

This section is a summary of the material tax considerations that may be relevant to prospective unitholders who are individual citizens or residents of the United States and, unless otherwise noted in the following discussion, is the opinion of Vinson & Elkins L.L.P., counsel to our general partner and us, as to all material tax matters and all legal conclusions insofar as it relates to matters of United States federal income tax law and legal conclusions with respect to those matters. This section is based upon current provisions of the Internal Revenue Code, existing and proposed regulations and current administrative rulings and court decisions, all of which are subject to change. Later changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to “us” or “we” are references to Spectra Energy Partners, LP and our operating company.

The following discussion does not comment on all federal income tax matters affecting us or our unitholders. Moreover, the discussion focuses on unitholders who are individual citizens or residents of the United States and has only limited application to corporations, estates, trusts, nonresident aliens or other unitholders subject to specialized tax treatment, such as tax-exempt institutions, foreign persons, individual retirement accounts (IRAs), real estate investment trusts (REITs) or mutual funds. Accordingly, we encourage each prospective unitholder to consult, and depend on, his own tax advisor in analyzing the federal, state, local and foreign tax consequences particular to him of the ownership or disposition of common units.

All statements as to matters of law and legal conclusions, but not as to factual matters, contained in this section, unless otherwise noted, are the opinion of Vinson & Elkins L.L.P. and are, to the extent noted herein, based on the accuracy of the representations made by us.

No ruling has been or will be requested from the IRS regarding any matter affecting us or prospective unitholders. Instead, we will rely on opinions of Vinson & Elkins L.L.P. Unlike a ruling, an opinion of counsel represents only that counsel’s best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements made herein may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for the common units and the prices at which common units trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will result in a reduction in cash available for distribution to our unitholders and our general partner and thus will be borne indirectly by our unitholders and our general partner. Furthermore, the tax treatment of us, or of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.

For the reasons described below, Vinson & Elkins L.L.P. has not rendered an opinion with respect to the following specific federal income tax issues: (1) the treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units (please read “— Tax Consequences of Unit Ownership — Treatment of Short Sales”); (2) whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (please read “— Disposition of Common Units — Allocations Between Transferors and Transferees”); and (3) whether our method for depreciating Section 743 adjustments is sustainable in certain cases (please read “— Tax Consequences of Unit Ownership — Section 754 Election”).

Partnership Status

A partnership is not a taxable entity and incurs no federal income tax liability. Instead, each partner of a partnership is required to take into account his share of items of income, gain, loss and deduction of the partnership in computing his federal income tax liability, regardless of whether cash distributions are made to him by the partnership. Distributions by a partnership to a partner are generally not taxable unless the amount of cash distributed is in excess of the partner’s adjusted basis in his partnership interest.

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Section 7704 of the Internal Revenue Code provides that publicly traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to as the “Qualifying Income Exception,” exists with respect to publicly traded partnerships of which 90% or more of the gross income for every taxable year consists of “qualifying income.” Qualifying income includes income and gains derived from the transportation, storage, processing and marketing of crude oil, natural gas and products thereof. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income. We estimate that less than % of our gross current income is not qualifying income; however, this estimate could change from time to time. Based upon and subject to this estimate, the factual representations made by us and the general partner and a review of the applicable legal authorities, Vinson & Elkins L.L.P. is of the opinion that at least 90% of our current gross income constitutes qualifying income.

No ruling has been or will be sought from the IRS and the IRS has made no determination as to our status for federal income tax purposes or whether our operations generate “qualifying income” under Section 7704 of the Internal Revenue Code. Instead, we will rely on the opinion of Vinson & Elkins L.L.P. on such matters. It is the opinion of Vinson & Elkins L.L.P. that, based upon the Internal Revenue Code, its regulations, published revenue rulings and court decisions and the representations described below, we will be classified as a partnership and the operating company will be disregarded as an entity separate from us for federal income tax purposes.

In rendering its opinion, Vinson & Elkins L.L.P. has relied on factual representations made by us and the general partner. The representations made by us and our general partner upon which Vinson & Elkins L.L.P. has relied are:

(a) Neither we nor the operating company will elect to be treated as a corporation; and

(b) For each taxable year, more than 90% of our gross income will be income that Vinson & Elkins L.L.P. has opined or will opine is “qualifying income” within the meaning of Section 7704(d) of the Internal Revenue Code.

If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery, we will be treated as if we had transferred all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation, and then distributed that stock to the unitholders in liquidation of their interests in us. This contribution and liquidation should be tax-free to unitholders and us so long as we, at that time, do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as a corporation for federal income tax purposes.

If we were treated as a corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss and deduction would be reflected only on our tax return rather than being passed through to our unitholders, and our net income would be taxed to us at corporate rates. In addition, any distribution made to a unitholder would be treated as either taxable dividend income, to the extent of our current or accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the unitholder’s tax basis in his common units, or taxable capital gain, after the unitholder’s tax basis in his common units is reduced to zero. Accordingly, taxation as a corporation would result in a material reduction in a unitholder’s cash flow and after-tax return and thus would likely result in a substantial reduction of the value of the units.

The discussion below is based on Vinson & Elkins L.L.P.’s opinion that we will be classified as a partnership for federal income tax purposes.

Limited Partner Status

Unitholders who have become limited partners of Spectra Energy Partners, LP will be treated as partners of Spectra Energy Partners, LP for federal income tax purposes. Also, unitholders whose common

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units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their common units will be treated as partners of Spectra Energy Partners, LP for federal income tax purposes.

A beneficial owner of common units whose units have been transferred to a short seller to complete a short sale would appear to lose his status as a partner with respect to those units for federal income tax purposes. Please read “— Tax Consequences of Unit Ownership — Treatment of Short Sales.”

Income, gain, deductions or losses would not appear to be reportable by a unitholder who is not a partner for federal income tax purposes, and any cash distributions received by a unitholder who is not a partner for federal income tax purposes would therefore appear to be fully taxable as ordinary income. These holders are urged to consult their own tax advisors with respect to their tax consequences of holding common units in Spectra Energy Partners, LP.

The references to “unitholders” in the discussion that follows are to persons who are treated as partners in Spectra Energy Partners, LP for federal income tax purposes.

Tax Consequences of Unit Ownership

Flow-Through of Taxable Income. We will not pay any federal income tax. Instead, each unitholder will be required to report on his income tax return his share of our income, gains, losses and deductions without regard to whether corresponding cash distributions are received by him. Consequently, we may allocate income to a unitholder even if he has not received a cash distribution. Each unitholder will be required to include in income his allocable share of our income, gains, losses and deductions for our taxable year ending with or within his taxable year. Our taxable year ends on December 31.

Treatment of Distributions. Distributions by us to a unitholder generally will not be taxable to the unitholder for federal income tax purposes, except to the extent the amount of any such cash distribution exceeds his tax basis in his common units immediately before the distribution. Our cash distributions in excess of a unitholder’s tax basis generally will be considered to be gain from the sale or exchange of the common units, taxable in accordance with the rules described under “— Disposition of Common Units.” Any reduction in a unitholder’s share of our liabilities for which no partner, including the general partner, bears the economic risk of loss, known as “nonrecourse liabilities,” will be treated as a distribution of cash to that unitholder. To the extent our distributions cause a unitholder’s “at risk” amount to be less than zero at the end of any taxable year, he must recapture any losses deducted in previous years. Please read “— Limitations on Deductibility of Losses.”

A decrease in a unitholder’s percentage interest in us because of our issuance of additional common units will decrease his share of our nonrecourse liabilities, and thus will result in a corresponding deemed distribution of cash. A non-pro rata distribution of money or property may result in ordinary income to a unitholder, regardless of his tax basis in his common units, if the distribution reduces the unitholder’s share of our “unrealized receivables,” including depreciation recapture, and/or substantially appreciated “inventory items,” both as defined in the Internal Revenue Code, and collectively, “Section 751 Assets.” To that extent, he will be treated as having been distributed his proportionate share of the Section 751 Assets and having exchanged those assets with us in return for the non-pro rata portion of the actual distribution made to him. This latter deemed exchange will generally result in the unitholder’s realization of ordinary income, which will equal the excess of (1) the non-pro rata portion of that distribution over (2) the unitholder’s tax basis for the share of Section 751 Assets deemed relinquished in the exchange.

Ratio of Taxable Income to Distributions. We estimate that a purchaser of common units in this offering who owns those common units from the date of closing of this offering through the record date for distributions for the period ending December 31, 2010, will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be % or less of the cash distributed with respect to that period. Thereafter, we anticipate that the ratio of allocable taxable income to cash distributions to the unitholders will increase. These estimates are based upon the assumption that gross income from operations will approximate the amount required to make the minimum quarterly distribution on all units and other

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assumptions with respect to capital expenditures, cash flow, net working capital and anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and tax reporting positions that we will adopt and with which the IRS could disagree. Accordingly, we cannot assure you that these estimates will prove to be correct. The actual percentage of distributions that will constitute taxable income could be higher or lower than expected, and any differences could be material and could materially affect the value of the common units. For example, the ratio of allocable taxable income to cash distributions to a purchaser of common units in this offering will be greater, and perhaps substantially greater, than our estimate with respect to the period described above if:


	•	gross income from operations exceeds the amount required to make the minimum quarterly distribution on all units, yet we only distribute the minimum quarterly distribution on all units; or

	•	we make a future offering of common units and use the proceeds of the offering in a manner that does not produce substantial additional deductions during the period described above, such as to repay indebtedness outstanding at the time of this offering or to acquire property that is not eligible for depreciation or amortization for federal income tax purposes or that is depreciable or amortizable at a rate significantly slower than the rate applicable to our assets at the time of this offering.

Basis of Common Units. A unitholder’s initial tax basis for his common units will be the amount he paid for the common units plus his share of our nonrecourse liabilities. That basis will be increased by his share of our income and by any increases in his share of our nonrecourse liabilities. That basis will be decreased, but not below zero, by distributions from us, by the unitholder’s share of our losses, by any decreases in his share of our nonrecourse liabilities and by his share of our expenditures that are not deductible in computing taxable income and are not required to be capitalized. A unitholder will have no share of our debt that is recourse to our general partner, but will have a share, generally based on his share of profits, of our nonrecourse liabilities. Please read “— Disposition of Common Units — Recognition of Gain or Loss.”

Limitations on Deductibility of Losses. The deduction by a unitholder of his share of our losses will be limited to the tax basis in his units and, in the case of an individual unitholder or a corporate unitholder, if more than 50% of the value of the corporate unitholder’s stock is owned directly or indirectly by or for five or fewer individuals or some tax-exempt organizations, to the amount for which the unitholder is considered to be “at risk” with respect to our activities, if that is less than his tax basis. A unitholder must recapture losses deducted in previous years to the extent that distributions cause his at risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable to the extent that his tax basis or at risk amount, whichever is the limiting factor, is subsequently increased. Upon the taxable disposition of a unit, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at risk limitation but may not be offset by losses suspended by the basis limitation. Any excess loss above that gain previously suspended by the at risk or basis limitations is no longer utilizable.

In general, a unitholder will be at risk to the extent of the tax basis of his units, excluding any portion of that basis attributable to his share of our nonrecourse liabilities, reduced by (i) any portion of that basis representing amounts otherwise protected against loss because of a guarantee, stop loss agreement or other similar arrangement and (ii) any amount of money he borrows to acquire or hold his units, if the lender of those borrowed funds owns an interest in us, is related to the unitholder or can look only to the units for repayment. A unitholder’s at risk amount will increase or decrease as the tax basis of the unitholder’s units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in his share of our nonrecourse liabilities.

The passive loss limitations generally provide that individuals, estates, trusts and some closely-held corporations and personal service corporations can deduct losses from passive activities, which are generally trade or business activities in which the taxpayer does not materially participate, only to the extent of the taxpayer’s income from those passive activities. The passive loss limitations are applied separately with

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respect to each publicly traded partnership. Consequently, any passive losses we generate will only be available to offset our passive income generated in the future and will not be available to offset income from other passive activities or investments, including our investments or investments in other publicly traded partnerships, or salary or active business income. Passive losses that are not deductible because they exceed a unitholder’s share of income we generate may be deducted in full when he disposes of his entire investment in us in a fully taxable transaction with an unrelated party. The passive activity loss limitations are applied after other applicable limitations on deductions, including the at risk rules and the basis limitation.

A unitholder’s share of our net income may be offset by any of our suspended passive losses, but it may not be offset by any other current or carryover losses from other passive activities, including those attributable to other publicly traded partnerships.

Limitations on Interest Deductions. The deductibility of a non-corporate taxpayer’s “investment interest expense” is generally limited to the amount of that taxpayer’s “net investment income.” Investment interest expense includes:


	•	interest on indebtedness properly allocable to property held for investment;

	•	our interest expense attributed to portfolio income; and

	•	the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.

The computation of a unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment. The IRS has indicated that net passive income earned by a publicly traded partnership will be treated as investment income to its unitholders. In addition, the unitholder’s share of our portfolio income will be treated as investment income.

Entity-Level Collections. If we are required or elect under applicable law to pay any federal, state, local or foreign income tax on behalf of any unitholder or our general partner or any former unitholder, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the unitholder on whose behalf the payment was made. If the payment is made on behalf of a person whose identity cannot be determined, we are authorized to treat the payment as a distribution to all current unitholders. We are authorized to amend our partnership agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under the partnership agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of an individual unitholder in which event the unitholder would be required to file a claim in order to obtain a credit or refund.

Allocation of Income, Gain, Loss and Deduction. In general, if we have a net profit, our items of income, gain, loss and deduction will be allocated among our general partner and the unitholders in accordance with their percentage interests in us. At any time that distributions are made to the common units in excess of distributions to the subordinated units, or incentive distributions are made to our general partner, gross income will be allocated to the recipients to the extent of these distributions. If we have a net loss for the entire year, that loss will be allocated first to our general partner and the unitholders in accordance with their percentage interests in us to the extent of their positive capital accounts and, second, to our general partner.

Specified items of our income, gain, loss and deduction will be allocated to account for the difference between the tax basis and fair market value of property contributed to us by our general partner and its affiliates, referred to in this discussion as “Contributed Property.” The effect of these allocations to a

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unitholder purchasing common units in this offering will be essentially the same as if the tax basis of our assets were equal to their fair market value at the time of this offering. In addition, items of recapture income will be allocated to the extent possible to the unitholder who was allocated the deduction giving rise to the treatment of that gain as recapture income in order to minimize the recognition of ordinary income by some unitholders. Finally, although we do not expect that our operations will result in the creation of negative capital accounts, if negative capital accounts nevertheless result, items of our income and gain will be allocated in such amount and manner as is needed to eliminate the negative balance as quickly as possible.

An allocation of items of our income, gain, loss or deduction, other than an allocation required by the Internal Revenue Code to eliminate the difference between a partner’s “book” capital account, credited with the fair market value of Contributed Property, and “tax” capital account, credited with the tax basis of Contributed Property, referred to in this discussion as the “Book-Tax Disparity,” will generally be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction only if the allocation has substantial economic effect. In any other case, a partner’s share of an item will be determined on the basis of his interest in us, which will be determined by taking into account all the facts and circumstances, including:


	•	his relative contributions to us;

	•	the interests of all the partners in profits and losses;

	•	the interest of all the partners in cash flow; and

	•	the rights of all the partners to distributions of capital upon liquidation.

Vinson & Elkins L.L.P. is of the opinion that, with the exception of the issues described in “— Tax Consequences of Unit Ownership — Section 754 Election” and “— Disposition of Common Units — Allocations Between Transferors and Transferees,” allocations under our partnership agreement will be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction.

Treatment of Short Sales. A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period:


	•	any of our income, gain, loss or deduction with respect to those units would not be reportable by the unitholder;

	•	any cash distributions received by the unitholder as to those units would be fully taxable; and

	•	all of these distributions would appear to be ordinary income.

Vinson & Elkins L.L.P. has not rendered an opinion regarding the treatment of a unitholder where common units are loaned to a short seller to cover a short sale of common units; therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from loaning their units. The IRS has announced that it is actively studying issues relating to the tax treatment of short sales of partnership interests. Please also read “— Disposition of Common Units — Recognition of Gain or Loss.”

Alternative Minimum Tax. Each unitholder will be required to take into account his distributive share of any items of our income, gain, loss or deduction for purposes of the alternative minimum tax. The current minimum tax rate for noncorporate taxpayers is 26% on the first $175,000 of alternative minimum taxable income in excess of the exemption amount and 28% on any additional alternative minimum taxable income. Prospective unitholders are urged to consult with their tax advisors as to the impact of an investment in units on their liability for the alternative minimum tax.

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Tax Rates. In general, the highest effective United States federal income tax rate for individuals is currently 35.0% and the maximum United States federal income tax rate for net capital gains of an individual is currently 15.0% if the asset disposed of was held for more than twelve months at the time of disposition.

Section 754 Election. We will make the election permitted by Section 754 of the Internal Revenue Code. That election is irrevocable without the consent of the IRS. The election will generally permit us to adjust a common unit purchaser’s tax basis in our assets (“inside basis”) under Section 743(b) of the Internal Revenue Code to reflect his purchase price. This election does not apply to a person who purchases common units directly from us. The Section 743(b) adjustment belongs to the purchaser and not to other unitholders. For purposes of this discussion, a unitholder’s inside basis in our assets will be considered to have two components: (1) his share of our tax basis in our assets (“common basis”) and (2) his Section 743(b) adjustment to that basis.

Where the remedial allocation method is adopted (which we will adopt as to property other than certain goodwill properties), the Treasury Regulations under Section 743 of the Internal Revenue Code require a portion of the Section 743(b) adjustment that is attributable to recovery property under Section 168 of the Internal Revenue Code to be depreciated over the remaining cost recovery period for the Section 704(c) built-in gain. If we elect a method other than the remedial method with respect to a goodwill property, Treasury Regulation Section 1.197-2(g)(3) generally requires that the Section 743(b) adjustment attributable to an amortizable Section 197 intangible, which includes goodwill property, should be treated as a newly-acquired asset placed in service in the month when the purchaser acquires the common unit. Under Treasury Regulation Section 1.167(c)-1(a)(6), a Section 743(b) adjustment attributable to property subject to depreciation under Section 167 of the Internal Revenue Code, rather than cost recovery deductions under Section 168, is generally required to be depreciated using either the straight-line method or the 150% declining balance method. If we elect a method other than the remedial method, the depreciation and amortization methods and useful lives associated with the Section 743(b) adjustment, therefore, may differ from the methods and useful lives generally used to depreciate the inside basis in such properties. Under our partnership agreement, our general partner is authorized to take a position to preserve the uniformity of units even if that position is not consistent with these and any other Treasury Regulations. If we elect a method other than the remedial method with respect to a goodwill property, the common basis of such property is not amortizable. Please read “— Uniformity of Units.”

Although Vinson & Elkins L.L.P. is unable to opine as to the validity of this approach because there is no direct or indirect controlling authority on this issue, we intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the common basis of the property, or treat that portion as non-amortizable to the extent attributable to property the common basis of which is not amortizable. This method is consistent with the methods employed by other publicly traded partnerships but is arguably inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets, and Treasury Regulation Section 1.197-2(g)(3). To the extent this Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may take a depreciation or amortization position under which all purchasers acquiring units in the same month would receive depreciation or amortization, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. This kind of aggregate approach may result in lower annual depreciation or amortization deductions than would otherwise be allowable to some unitholders. Please read “— Uniformity of Units.” A unitholder’s tax basis for his common units is reduced by his share of our deductions (whether or not such deductions were claimed on an individual’s income tax return) so that any position we take that understates deductions will overstate the common unitholder’s basis in his common units, which may cause the unitholder to understate gain or overstate loss on any sale of such units. Please read “— Disposition of Common Units — Recognition of Gain or Loss.” The IRS

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may challenge our position with respect to depreciating or amortizing the Section 743(b) adjustment we take to preserve the uniformity of the units. If such a challenge were sustained, the gain from the sale of units might be increased without the benefit of additional deductions.

A Section 754 election is advantageous if the transferee’s tax basis in his units is higher than the units’ share of the aggregate tax basis of our assets immediately prior to the transfer. In that case, as a result of the election, the transferee would have, among other items, a greater amount of depreciation and depletion deductions and his share of any gain or loss on a sale of our assets would be less. Conversely, a Section 754 election is disadvantageous if the transferee’s tax basis in his units is lower than those units’ share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the units may be affected either favorably or unfavorably by the election. A basis adjustment is required regardless of whether a Section 754 election is made in the case of a transfer of an interest in us if we have a substantial built–in loss immediately after the transfer, or if we distribute property and have a substantial basis reduction. Generally a built–in loss or a basis reduction is substantial if it exceeds $250,000.

The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. For example, the allocation of the Section 743(b) adjustment among our assets must be made in accordance with the Internal Revenue Code. The IRS could seek to reallocate some or all of any Section 743(b) adjustment allocated by us to our tangible assets to goodwill instead. Goodwill, as an intangible asset, is generally nonamortizable or amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure you that the determinations we make will not be successfully challenged by the IRS and that the deductions resulting from them will not be reduced or disallowed altogether. Should the IRS require a different basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than he would have been allocated had the election not been revoked.

Tax Treatment of Operations

Accounting Method and Taxable Year. We use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in income his share of our income, gain, loss and deduction for our taxable year ending within or with his taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of his units following the close of our taxable year but before the close of his taxable year must include his share of our income, gain, loss and deduction in income for his taxable year, with the result that he will be required to include in income for his taxable year his share of more than one year of our income, gain, loss and deduction. Please read “— Disposition of Common Units — Allocations Between Transferors and Transferees.”

Initial Tax Basis, Depreciation and Amortization. The tax basis of our assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. The federal income tax burden associated with the difference between the fair market value of our assets and their tax basis immediately prior to this offering will be borne by our general partner. Please read “— Tax Consequences of Unit Ownership — Allocation of Income, Gain, Loss and Deduction.”

To the extent allowable, we may elect to use the depreciation and cost recovery methods that will result in the largest deductions being taken in the early years after assets are placed in service. Because our general partner may determine not to adopt the remedial method of allocation with respect to any difference between the tax basis and the fair market value of goodwill immediately prior to this or any future offering, we may not be entitled to any amortization deductions with respect to any goodwill conveyed to us on formation or held by us at the time of any future offering. Please read “— Uniformity of Units.” Property we subsequently acquire or construct may be depreciated using accelerated methods permitted by the Internal Revenue Code.

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If we dispose of depreciable property by sale, foreclosure or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of his interest in us. Please read “— Tax Consequences of Unit Ownership — Allocation of Income, Gain, Loss and Deduction” and “— Disposition of Common Units — Recognition of Gain or Loss.”

The costs we incur in selling our units (called “syndication expenses”) must be capitalized and cannot be deducted currently, ratably or upon our termination. There are uncertainties regarding the classification of costs as organization expenses, which may be amortized by us, and as syndication expenses, which may not be amortized by us. The underwriting discounts and commissions we incur will be treated as syndication expenses.

Valuation and Tax Basis of Our Properties. The federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values, and the initial tax bases, of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deductions previously reported by unitholders might change, and unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

Disposition of Common Units

Recognition of Gain or Loss. Gain or loss will be recognized on a sale of units equal to the difference between the amount realized and the unitholder’s tax basis for the units sold. A unitholder’s amount realized will be measured by the sum of the cash or the fair market value of other property received by him plus his share of our nonrecourse liabilities. Because the amount realized includes a unitholder’s share of our nonrecourse liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.

Prior distributions from us in excess of cumulative net taxable income for a common unit that decreased a unitholder’s tax basis in that common unit will, in effect, become taxable income if the common unit is sold at a price greater than the unitholder’s tax basis in that common unit, even if the price received is less than his original cost.

Except as noted below, gain or loss recognized by a unitholder, other than a “dealer” in units, on the sale or exchange of a unit held for more than one year will generally be taxable as capital gain or loss. Capital gain recognized by an individual on the sale of units held more than twelve months will generally be taxed at a maximum rate of 15%. However, a portion of this gain or loss will be separately computed and taxed as ordinary income or loss under Section 751 of the Internal Revenue Code to the extent attributable to assets giving rise to depreciation recapture or other “unrealized receivables” or to “inventory items” we own. The term “unrealized receivables” includes potential recapture items, including depreciation recapture. Ordinary income attributable to unrealized receivables, inventory items and depreciation recapture may exceed net taxable gain realized upon the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and a capital loss upon a sale of units. Net capital losses may offset capital gains and no more than $3,000 of ordinary income, in the case of individuals, and may only be used to offset capital gains in the case of corporations.

The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an “equitable apportionment” method, which generally means that the tax basis allocated to the interest sold equals an amount that bears the same relation to the partner’s tax basis in his entire interest in

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the partnership as the value of the interest sold bears to the value of the partner’s entire interest in the partnership. Treasury Regulations under Section 1223 of the Internal Revenue Code allow a selling unitholder who can identify common units transferred with an ascertainable holding period to elect to use the actual holding period of the common units transferred. Thus, according to the ruling, a common unitholder will be unable to select high or low basis common units to sell as would be the case with corporate stock, but, according to the regulations, may designate specific common units sold for purposes of determining the holding period of units transferred. A unitholder electing to use the actual holding period of common units transferred must consistently use that identification method for all subsequent sales or exchanges of common units. A unitholder considering the purchase of additional units or a sale of common units purchased in separate transactions is urged to consult his tax advisor as to the possible consequences of this ruling and application of the regulations.

Specific provisions of the Internal Revenue Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an “appreciated” partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into:


	•	a short sale;

	•	an offsetting notional principal contract; or

	•	a futures or forward contract with respect to the partnership interest or substantially identical property.

Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is also authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.

Allocations Between Transferors and Transferees. In general, our taxable income and losses will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month, which we refer to in this prospectus as the “Allocation Date.” However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business will be allocated among the unitholders on the Allocation Date in the month in which that gain or loss is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.

The use of this method may not be permitted under existing Treasury Regulations. Accordingly, Vinson & Elkins L.L.P. is unable to opine on the validity of this method of allocating income and deductions between transferee and transferor unitholders. If this method is not allowed under the Treasury Regulations, or only applies to transfers of less than all of the unitholder’s interest, our taxable income or losses might be reallocated among the unitholders. We are authorized to revise our method of allocation between transferee and transferor unitholders, as well as unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations.

A unitholder who owns units at any time during a quarter and who disposes of them prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss and deductions attributable to that quarter but will not be entitled to receive that cash distribution.

Notification Requirements. A unitholder who sells any of his units is generally required to notify us in writing of that sale within 30 days after the sale (or, if earlier, January 15 of the year following the sale). A purchaser of units who purchases units from another unitholder is also generally required to notify us in writing of that purchase within 30 days after the purchase. Upon receiving such notifications, we are required to notify the IRS of that transaction and to furnish specified information to the transferor and

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transferee. Failure to notify us of a purchase may, in some cases, lead to the imposition of penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the United States and who effects the sale or exchange through a broker who will satisfy such requirements.

Constructive Termination. We will be considered to have been terminated for 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. A constructive termination results in the closing of our taxable year for all unitholders. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. We would be required to make new tax elections after a termination, including a new election under Section 754 of the Internal Revenue Code, and a termination would result in a deferral of our deductions for depreciation. A termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a termination might either accelerate the application of, or subject us to, any tax legislation enacted before the termination.

Uniformity of Units

Because we cannot match transferors and transferees of units, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory. A lack of uniformity can result from a literal application of Treasury Regulation Section 1.167(c)-1(a)(6) and Treasury Regulation Section 1.197-2(g)(3). Any non-uniformity could have a negative impact on the value of the units. Please read “— Tax Consequences of Unit Ownership — Section 754 Election.”

We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the common basis of that property, or treat that portion as nonamortizable, to the extent attributable to property the common basis of which is not amortizable, consistent with the regulations under Section 743 of the Internal Revenue Code, even though that position may be inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets, and Treasury Regulations Section 1.197-2(g)(3). Please read “— Tax Consequences of Unit Ownership — Section 754 Election.” To the extent that the Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may adopt a depreciation and amortization position under which all purchasers acquiring units in the same month would receive depreciation and amortization deductions, whether attributable to a common basis or Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our property. If this position is adopted, it may result in lower annual depreciation and amortization deductions than would otherwise be allowable to some unitholders and risk the loss of depreciation and amortization deductions not taken in the year that these deductions are otherwise allowable. This position will not be adopted if we determine that the loss of depreciation and amortization deductions will have a material adverse effect on the unitholders. If we choose not to utilize this aggregate method, we may use any other reasonable depreciation and amortization method to preserve the uniformity of the intrinsic tax characteristics of any units that would not have a material adverse effect on the unitholders. The IRS may challenge any method of depreciating the Section 743(b) adjustment described in this paragraph. If this challenge were sustained, the uniformity of units might be affected, and the gain from the sale of units might be increased without the benefit of additional deductions. Please read “— Disposition of Common Units — Recognition of Gain or Loss.”

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Tax-Exempt Organizations and Other Investors

Ownership of units by employee benefit plans, other tax-exempt organizations, non-resident aliens, foreign corporations and other foreign persons raises issues unique to those investors and, as described below, may have substantially adverse tax consequences to them.

Employee benefit plans and most other organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, are subject to federal income tax on unrelated business taxable income. Virtually all of our income allocated to a unitholder that is a tax-exempt organization will be unrelated business taxable income and will be taxable to them.

Non-resident aliens and foreign corporations, trusts or estates that own units will be considered to be engaged in business in the United States because of the ownership of units. As a consequence, they will be required to file federal tax returns to report their share of our income, gain, loss or deduction and pay federal income tax at regular rates on their share of our net income or gain. Moreover, under rules applicable to publicly traded partnerships, we will withhold at the highest applicable effective tax rate from cash distributions made quarterly to foreign unitholders. Each foreign unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8BEN or applicable substitute form in order to obtain credit for these withholding taxes. A change in applicable law may require us to change these procedures.

In addition, because a foreign corporation that owns units will be treated as engaged in a United States trade or business, that corporation may be subject to the United States branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our income and gain, as adjusted for changes in the foreign corporation’s “U.S. net equity,” which are effectively connected with the conduct of a United States trade or business. That tax may be reduced or eliminated by an income tax treaty between the United States and the country in which the foreign corporate unitholder is a “qualified resident.” In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Internal Revenue Code.

Under a ruling of the IRS, a foreign unitholder who sells or otherwise disposes of a unit will be subject to federal income tax on gain realized on the sale or disposition of that unit to the extent that this gain is effectively connected with a United States trade or business of the foreign unitholder. Because a foreign unitholder is considered to be engaged in business in the United States by virtue of the ownership of units, under this ruling a foreign unitholder who sells or otherwise disposes of a unit generally will be subject to federal income tax on gain realized on the sale or disposition of units. Apart from the ruling, a foreign unitholder will not be taxed or subject to withholding upon the sale or disposition of a unit if he has owned less than 5% in value of the units during the five-year period ending on the date of the disposition and if the units are regularly traded on an established securities market at the time of the sale or disposition.

Administrative Matters

Information Returns and Audit Procedures. We intend to furnish to each unitholder, within 90 days after the close of each calendar year, specific tax information, including a Schedule K-1, which describes his share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each unitholder’s share of income, gain, loss and deduction. We cannot assure you that those positions will in all cases yield a result that conforms to the requirements of the Internal Revenue Code, Treasury Regulations or administrative interpretations of the IRS. Neither we nor Vinson & Elkins L.L.P. can assure prospective unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the units.

The IRS may audit our federal income tax information returns. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year’s tax liability, and possibly may result in an audit of

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his return. Any audit of a unitholder’s return could result in adjustments not related to our returns as well as those related to our returns.

Partnerships generally are treated as separate entities for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Internal Revenue Code requires that one partner be designated as the “Tax Matters Partner” for these purposes. Our partnership agreement names our General Partner as our Tax Matters Partner.

The Tax Matters Partner will make some elections on our behalf and on behalf of unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review will go forward, and each unitholder with an interest in the outcome may participate.

A unitholder must file a statement with the IRS identifying the treatment of any item on his federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.

Nominee Reporting. Persons who hold an interest in us as a nominee for another person are required to furnish to us:

(a) the name, address and taxpayer identification number of the beneficial owner and the nominee;

(b) whether the beneficial owner is:

1. a person that is not a United States person;

2. a foreign government, an international organization or any wholly owned agency or instrumentality of either of the foregoing; or

3. a tax-exempt entity;

(d) specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from sales.

Brokers and financial institutions are required to furnish additional information, including whether they are United States persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $50 per failure, up to a maximum of $100,000 per calendar year, is imposed by the Internal Revenue Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.

Accuracy-Related Penalties. An additional tax equal to 20% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed by the Internal Revenue Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for that portion and that the taxpayer acted in good faith regarding that portion.

For individuals, a substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10% of the tax required to be shown on the return for the taxable

171

year or $5,000 ($10,000 for most corporations). The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:

(1) for which there is, or was, “substantial authority”; or

(2) as to which there is a reasonable basis and the pertinent facts of that position are disclosed on the return.

If any item of income, gain, loss or deduction included in the distributive shares of unitholders might result in that kind of an “understatement” of income for which no “substantial authority” exists, we must disclose the pertinent facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns and to take other actions as may be appropriate to permit unitholders to avoid liability for this penalty. More stringent rules apply to “tax shelters,” which we do not believe includes us.

A substantial valuation misstatement exists if the value of any property, or the adjusted basis of any property, claimed on a tax return is 200% or more of the amount determined to be the correct amount of the valuation or adjusted basis. No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for most corporations). If the valuation claimed on a return is 400% or more than the correct valuation, the penalty imposed increases to 40%.

Reportable Transactions. If we were to engage in a “reportable transaction,” we (and possibly you and others) would be required to make a detailed disclosure of the transaction to the IRS. A transaction may be a reportable transaction based upon any of several factors, including the fact that it is a type of tax avoidance transaction publicly identified by the IRS as a “listed transaction” or that it produces certain kinds of losses for partnerships, individuals, S corporations, and trusts in excess of $2 million in any single year, or $4 million in any combination of tax years. Our participation in a reportable transaction could increase the likelihood that our federal income tax information return (and possibly your tax return) would be audited by the IRS. Please read “— Information Returns and Audit Procedures.”

Moreover, if we were to participate in a reportable transaction with a significant purpose to avoid or evade tax, or in any listed transaction, you may be subject to the following provisions of the American Jobs Creation Act of 2004:


	•	accuracy-related penalties with a broader scope, significantly narrower exceptions, and potentially greater amounts than described above at “— Accuracy Related Penalties,”

	•	for those persons otherwise entitled to deduct interest on federal tax deficiencies, nondeductibility of interest on any resulting tax liability and

	•	in the case of a listed transaction, an extended statute of limitations.

We do not expect to engage in any “reportable transactions.”

State, Local, Foreign and Other Tax Considerations

In addition to federal income taxes, you likely will be subject to other taxes, such as state, local and foreign income taxes, unincorporated business taxes, and estate, inheritance or intangible taxes that may be imposed by the various jurisdictions in which we do business or own property or in which you are a resident. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on his investment in us. We will initially own property or conduct business in the States of 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. We may also own property or conduct business in other jurisdictions that impose an income tax in the future. Although you may not be required to file a return and pay taxes in some jurisdictions because your income from the jurisdictions falls below the filing and payment requirement, you will be required to file income tax returns and to pay income taxes in many of these jurisdictions in which we do business or own property

172

and may be subject to penalties for failure to comply with those requirements. In some jurisdictions, tax losses may not produce a tax benefit in the year incurred and may not be available to offset income in subsequent taxable years. Some of the jurisdictions may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the jurisdiction. Withholding, the amount of which may be greater or less than a particular unitholder’s income tax liability to the jurisdiction, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld will be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. Please read “— Tax Consequences of Unit Ownership — Entity-Level Collections”. Based on current law and our estimate of our future operations, the general partner anticipates that any amounts required to be withheld will not be material.

It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent jurisdictions, of his investment in us. Accordingly, each prospective unitholder is urged to consult, and depend upon, his tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all state, local and foreign, as well as United States federal tax returns, that may be required of him. Vinson & Elkins L.L.P. has not rendered an opinion on the state, local or foreign tax consequences of an investment in us.

173

SELLING UNITHOLDER

If the underwriters exercise all or any portion of their option to purchase additional common units, we will issue up to 1,725,000 additional common units, and we will redeem an equal number of units from a subsidiary of Spectra Energy, who may be deemed to be a selling unitholder in this offering. The redemption price per common unit will be equal to the price per common unit (net of underwriting discounts and a structuring fee) sold to the underwriters upon exercise of their option.

The following table sets forth information concerning the ownership of common and subordinated units by a subsidiary of Spectra Energy, Spectra Energy Partners MLP LP, LLC. The numbers in the table are presented assuming:


	•	the underwriters’ option to purchase additional units is not exercised; and

	•	the underwriters exercise their option to purchase additional units in full.

Units Owned Immediately

Units Owned

After Exercise of

Immediately After

Underwriters’ Option and

This Offering

Related Unit Redemption

Assuming

Underwriters’

Option is Not

Option is Exercised

Name of Selling Unitholder

Exercised

Percent(1)

in Full

Percent(1)

Spectra Energy Partners MLP LP, LLC Common units

29,812,011

47.6

28,087,011

44.9

Spectra Energy Partners MLP LP, LLC Subordinated units

20,030,066

32.0

20,030,066

32.0


(1)		Percentage of total units outstanding, including common units, subordinated units and general partner units.

174

INVESTMENT IN SPECTRA ENERGY PARTNERS, LP BY EMPLOYEE BENEFIT PLANS

An investment in us by an employee benefit plan is subject to additional considerations because the investments of these plans are subject to the fiduciary responsibility and prohibited transaction provisions of ERISA and restrictions imposed by Section 4975 of the Internal Revenue Code. For these purposes the term “employee benefit plan” includes, but is not limited to, qualified pension, profit-sharing and stock bonus plans, Keogh plans, simplified employee pension plans and tax deferred annuities or IRAs established or maintained by an employer or employee organization. Among other things, consideration should be given to:


	•	whether the investment is prudent under Section 404(a)(1)(B) of ERISA;

	•	whether in making the investment, that plan will satisfy the diversification requirements of Section 404(a)(1)(C) of ERISA; and

	•	whether the investment will result in recognition of unrelated business taxable income by the plan and, if so, the potential after-tax investment return. Please read “Material Tax Consequences — Tax-Exempt Organizations and Other Investors”.

The person with investment discretion with respect to the assets of an employee benefit plan, often called a fiduciary, should determine whether an investment in us is authorized by the appropriate governing instrument and is a proper investment for the plan.

Section 406 of ERISA and Section 4975 of the Internal Revenue Code prohibit employee benefit plans, and also IRAs that are not considered part of an employee benefit plan, from engaging in specified transactions involving “plan assets” with parties that are “parties in interest” under ERISA or “disqualified persons” under the Internal Revenue Code with respect to the plan.

In addition to considering whether the purchase of common units is a prohibited transaction, a fiduciary of an employee benefit plan should consider whether the plan will, by investing in us, be deemed to own an undivided interest in our assets, with the result that our operations would be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Internal Revenue Code.

The Department of Labor regulations provide guidance with respect to whether the assets of an entity in which employee benefit plans acquire equity interests would be deemed “plan assets” under some circumstances. Under these regulations, an entity’s assets would not be considered to be “plan assets” if, among other things:

(a) the equity interests acquired by employee benefit plans are publicly offered securities — i.e., the equity interests are widely held by 100 or more investors independent of the issuer and each other, freely transferable and registered under some provisions of the federal securities laws;

(b) the entity is an “operating company,” — i.e., it is primarily engaged in the production or sale of a product or service other than the investment of capital either directly or through a majority-owned subsidiary or subsidiaries; or

(c) there is no significant investment by benefit plan investors, which is defined to mean that less than 25% of the value of each class of equity interest is held by the employee benefit plans referred to above, IRAs and other employee benefit plans not subject to ERISA, including governmental plans.

Our assets should not be considered “plan assets” under these regulations because it is expected that the investment will satisfy the requirements in (a) above.

Plan fiduciaries contemplating a purchase of common units should consult with their own counsel regarding the consequences under ERISA and the Internal Revenue Code in light of the serious penalties imposed on persons who engage in prohibited transactions or other violations.

175

UNDERWRITING

Citigroup Global Markets Inc. and Lehman Brothers Inc. are acting as joint bookrunning managers of the offering and representatives of the underwriters named below. Subject to the terms and conditions stated in the underwriting agreement dated the date of this prospectus, each underwriter named below has severally agreed to purchase, and we have agreed to sell to that underwriter, the number of common units set forth opposite the underwriter’s name.


	Number of
	Common Units

Citigroup Global Markets Inc.
Lehman Brothers Inc.

Total		11,500,000

The underwriting agreement provides that the obligations of the underwriters to purchase the common units included in this offering are subject to approval of legal matters by counsel and to other conditions. The underwriters are obligated to purchase all the common units (other than those covered by their option to purchase additional common units described below) if they purchase any of the units.

The underwriters propose to offer some of the common units directly to the public at the public offering price set forth on the cover page of the prospectus and some of the units to dealers at the public offering price less a concession not to exceed $ per unit. If all of the units are not sold at the initial offering price, the representatives may change the public offering price and the other selling terms. The representatives have advised us that the underwriters do not intend sales to discretionary accounts to exceed five percent of the total number of our units offered by them.

We have granted to the underwriters an option, exercisable for 30 days from the date of this prospectus, to purchase up to 1,725,000 additional common units at the public offering price less the underwriting discount. The underwriters may exercise the option solely for the purpose of covering over-allotments, if any, in connection with this offering. To the extent the option is exercised, each underwriter must purchase a number of additional units approximately proportionate to that underwriter’s initial purchase commitment.

We, our general partner, all of the officers and directors of our general partner and Spectra Energy and certain of its affiliates have agreed that, for a period of 180 days from the date of this prospectus, we and they will not, without the prior written consent of the representatives, dispose of or hedge any of our common units or any securities convertible into or exchangeable for our common units. Notwithstanding the foregoing, if (1) during the last 17 days of the 180-day period, we issue an earnings release or material news or a material event relating to us occurs; or (2) prior to the expiration of the 180-day restricted period, we announce that we will release earnings results during the 16-day period beginning on the last day of the 180-day period, the restrictions described above shall continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release or the occurrence of the material news or material event.

The representatives, in their sole discretion, may release any of the securities subject to these lock-up agreements at any time without notice. The representatives have no present intent or arrangement to release any of the securities subject to these lock-up agreements. The release of any lock-up is considered on a case by case basis. Factors in deciding whether to release common units may include the length of time before the lock-up expires, the number of units involved, the reason for the requested release, market conditions, the trading price of our common units, historical trading volumes of our common units and whether the person seeking the release is an officer, director or affiliate of us.

At our request, the underwriters have reserved up to 5% of the common units for sale at the initial offering price to persons who are directors, officers and employees of our general partner, or who are otherwise associated with us through a directed unit program. The number of common units available for sale to the general public will be reduced by the number of directed units purchased by participants in the

176

program. Any directed units not purchased will be offered by the underwriters to the general public on the same basis as all other common units offered. We have agreed to indemnify the underwriters against certain liabilities and expenses, including liabilities under the Securities Act, in connection with the sales of the directed units. The common units reserved for sale under the directed unit program will be subject to a day lock-up agreement following this offering.

Prior to this offering, there has been no public market for our common units. Consequently, the initial public offering price for the units will be determined by negotiations between our general partner and the representatives. Among the factors considered in determining the initial public offering price will be our record of operations, our current financial condition, our future prospects, our markets, the economic conditions in and future prospects for the industry in which we compete, our management, and currently prevailing general conditions in the equity securities markets, including current market valuations of publicly traded partnerships considered comparable to our partnership. We cannot assure you, however, that the prices at which the units will sell in the public market after this offering will not be lower than the initial public offering price or that an active trading market in our common units will develop and continue after this offering.

We intend to apply to list our common units listed on The New York Stock Exchange under the symbol “SEP.”

The following table shows the underwriting discounts and commissions that we are to pay to the underwriters in connection with this offering. These amounts are shown assuming both no exercise and full exercise of the underwriters’ option to purchase additional common units.


	No Exercise	Full Exercise

Per Unit	$	$
Total	$	$

In addition, we will pay a structuring fee equal to an aggregate of 0.25% of the gross proceeds from this offering to Citigroup Global Markets Inc. and Lehman Brothers Inc. for evaluation, analysis and structuring of our partnership.

We estimate that our portion of the total expenses of this offering, excluding underwriting discounts and commissions and structuring fees, will be approximately $6 million. The underwriters have agreed to reimburse us for a portion of these expenses in an amount of up to 0.25% of the gross proceeds of this offering (including any exercise of the underwriters’ option to purchase additional common units).

In no event will the maximum amount of compensation to be paid to NASD members in connection with this offering exceed 10% of the gross proceeds (plus 0.5% for bona fide, accountable due diligence expenses).

Our partnership agreement requires that all common unitholders be Eligible Holders. 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 beneficial owners are subject to such taxation. Accordingly, all potential investors who are not individuals must have completed and returned the Certification Form for Non-individual Investors attached as Appendix C to this prospectus to the underwriter with whom they placed an order by the date indicated on the form in order to be allocated common units in this offering. As all individuals are Eligible Holders, they were not required to complete and return a Certification Form for Non-individual Investors.

In connection with the offering, Citigroup Global Markets Inc. on behalf of the underwriters, may purchase and sell common units in the open market. These transactions may include short sales, syndicate covering transactions and stabilizing transactions. Short sales involve syndicate sales of common units in excess of the number of units to be purchased by the underwriters in the offering, which creates a syndicate short position. “Covered” short sales are sales of units made in an amount up to the number of units represented by the underwriters’ option to purchase additional common units. In determining the source of units to close out the covered syndicate short position, the underwriters will consider, among other things,

177

the price of units available for purchase in the open market as compared to the price at which they may purchase units through their option to purchase additional common units. Transactions to close out the covered syndicate short position involve either purchases of the common units in the open market after the distribution has been completed or the exercise of their option to purchase additional common units. The underwriters may also make “naked” short sales of units in excess of their option to purchase additional common units. The underwriters must close out any naked short position by purchasing common units in the open market. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of the units in the open market after pricing that could adversely affect investors who purchase in the offering. Stabilizing transactions consist of bids for or purchases of units in the open market while the offering is in progress.

The underwriters also may impose a penalty bid. Penalty bids permit the underwriters to reclaim a selling concession from a syndicate member when an underwriter repurchases units originally sold by that syndicate member in order to cover syndicate short positions or make stabilizing purchases.

Any of these activities, as well as purchases by the underwriters for their own accounts, may have the effect of preventing or retarding a decline in the market price of the units. They may also cause the price of the units to be higher than the price that would otherwise exist in the open market in the absence of these transactions. The underwriters may conduct these transactions on The New York Stock Exchange or otherwise. If the underwriters commence any of these transactions, they may discontinue them at any time.

The underwriters have performed from time to time and are performing investment banking and advisory services for us and Spectra Energy and its predecessor for which they have received and will receive customary fees and expenses. In addition, the underwriters may, from time to time, engage in other transactions with and perform services for Spectra Energy or us in the ordinary course of their business.

A prospectus in electronic format may be made available by one or more of the underwriters. The representatives may agree to allocate a number of units to underwriters for sale to their online brokerage account holders. The representatives will allocate units to underwriters that may make Internet distributions on the same basis as other allocations. In addition, units may be sold by the underwriters to securities dealers who resell units to online brokerage account holders.

Other than the prospectus in electronic format, the information on any underwriter’s web site and any information contained in any other web site maintained by an underwriter is not part of the prospectus or the registration statement of which this prospectus forms a part, has not been approved and/or endorsed by us or any underwriter in its capacity as an underwriter and should not be relied upon by investors.

We and our general partner have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act, and to contribute to payments the underwriters may be required to make because of any of those liabilities.

Because the National Association of Securities Dealers views the units offered by this prospectus as interests in a direct participation program, the offering is being made in compliance with Rule 2810 of the NASD’s Conduct Rules. Investor suitability with respect to the units should be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.

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VALIDITY OF THE COMMON UNITS

The validity of the common units will be passed upon for us by Vinson & Elkins L.L.P., Houston, Texas. Certain legal matters in connection with the common units offered hereby will be passed upon for the underwriters by Baker Botts L.L.P., Houston, Texas.

EXPERTS

The combined financial statements of Spectra Energy Partners Predecessor as of December 31, 2006 and 2005 and for each of the three years in the period ended December 31, 2006, included in this prospectus and the related financial statement schedules included elsewhere in the registration statement have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report appearing herein (which report expresses an unqualified opinion on the combined financial statements and financial statement schedule and includes an explanatory paragraph relating to the preparation of the combined financial statements of Spectra Energy Partners Predecessor from the separate records maintained by Spectra Energy Capital, LLC) and have been so included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

The balance sheet of Spectra Energy Partners, LP as of March 26, 2007 and the balance sheet of Spectra Energy Partners (DE) GP, LP as of March 26, 2007 included in this prospectus have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their reports appearing herein, and are included in reliance upon the reports of such firm given upon their authority as experts in accounting and auditing.

The consolidated financial statements of Market Hub Partners Holding, LLC and subsidiaries as of December 31, 2006 and 2005 and for each of the three years in the period ended December 31, 2006, included in this prospectus have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report appearing herein, and are included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

The financial statements of Gulfstream Natural Gas System, L.L.C. as of December 31, 2006 and 2005 and for each of the three years in the period ended December 31, 2006, included in this prospectus have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report appearing herein, and are included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the Securities and Exchange Commission, or the SEC, a registration statement on Form S-l regarding the common units. This prospectus does not contain all of the information found in the registration statement. For further information regarding us and the common units offered by this prospectus, you may desire to review the full registration statement, including its exhibits and schedules, filed under the Securities Act. The registration statement of which this prospectus forms a part, including its exhibits and schedules, may be inspected and copied at the public reference room maintained by the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Copies of the materials may also be obtained from the SEC at prescribed rates by writing to the public reference room maintained by the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. You may obtain information on the operation of the public reference room by calling the SEC at 1-800-SEC-0330. The SEC maintains a web site on the Internet at http://www.sec.gov. Our registration statement, of which this prospectus constitutes a part, can be downloaded from the SEC’s web site.

We intend to furnish our unitholders annual reports containing our audited financial statements and furnish or make available quarterly reports containing our unaudited interim financial information for the first three fiscal quarters of each of our fiscal years.

179

UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS

Introduction

The unaudited pro forma combined financial statements of Spectra Energy Partners, LP as of and for the year ended December 31, 2006 are based upon the historical audited combined financial statements of Spectra Energy Partners Predecessor (the Predecessor). The Predecessor includes 100% of East Tennessee Natural Gas LLC (East Tennessee), 50.0% of Market Hub Partners Holding, LLC (Market Hub), and 24.5% of Gulfstream Natural Gas System, LLC (Gulfstream). The Predecessor includes East Tennessee in its financial statements, and accounts for the interests in Gulfstream and Market Hub using the equity method of accounting. Following the offering, Spectra Energy Partners, LP (the Partnership) will own these entities in the same proportions as represented in the Predecessor, and consequently, the Partnership will consolidate its interest in East Tennessee and will account for its 50.0% interest in Market Hub and its 24.5% in Gulfstream using the equity method of accounting.

The contribution by Spectra Energy Corp (Spectra Energy) to the Partnership of the East Tennessee, Market Hub and Gulfstream assets will be recorded at historical cost as it is considered to be a reorganization of entities under common control. Unless the context otherwise requires, references herein to the Partnership include the Partnership and its operating companies. The unaudited pro forma combined statement of operations assumes the offering and transactions as described in this prospectus occurred on January 1, 2006, and the unaudited pro forma combined balance sheet assumes that the offering and the transactions occurred as of December 31, 2006. The unaudited pro forma combined financial statements have been prepared on the assumption that the Partnership will be treated as a partnership for federal income tax purposes. The unaudited pro forma combined financial statements should be read in conjunction with the notes accompanying such unaudited pro forma combined financial statements and with the historical audited combined financial statements and related notes set forth elsewhere in this Prospectus.

The unaudited pro forma combined balance sheet and the unaudited pro forma combined statement of operations were derived by adjusting the historical audited combined financial statements of the Predecessor. The adjustments are based upon currently available information and certain estimates and assumptions. Actual effects of these transactions will differ from the pro forma adjustments. However, the Predecessor’s management (management) believes that the assumptions provide a reasonable basis for presenting the significant effects of the transactions as contemplated and that the pro forma adjustments are factually supportable and give appropriate effect to the expected impact of events that are directly attributable to the formation of the Partnership, the transfer of the operations of the Predecessor and the related transactions, and that are expected to have a continuing impact on the Partnership.

In connection with the offering:


	•	Spectra Energy or its subsidiaries will contribute certain of their assets to us or our subsidiaries;

	•	we will issue to Spectra Energy Partners (DE) GP, LP, a subsidiary of Spectra Energy, a 2% general partner interest in us and all of our incentive distribution rights, which will entitle our general partner to increasing percentages of the cash we distribute in excess of $0.3738 per unit per quarter (115% of the minimum quarterly distribution);

	•	we will issue 11,500,000 common units to the public in this offering, representing an 18.4% limited partner interest in us, and will use the proceeds as described in “Use of Proceeds”;

	•	we will enter into a new $500 million credit facility under which we expect to borrow $50 million in term debt and $125 million in revolving debt; and

	•	we will enter into an omnibus agreement with Spectra Energy, our general partner and certain of their affiliates pursuant to which:


	—	we will reimburse Spectra Energy for the payment of certain operating expenses and for providing various general and administrative services.

The unaudited pro forma combined financial statements are not necessarily indicative of the results that actually would have occurred if the Partnership had assumed the operations of the Predecessor on the dates indicated or which would be obtained in the future.

F-2

SPECTRA ENERGY PARTNERS, LP

UNAUDITED PRO FORMA COMBINED STATEMENT OF OPERATIONS

Year Ended December 31, 2006


	Spectra Energy					Spectra Energy
	Partners Predecessor		Pro Forma			Partners, LP
	Historical		Adjustments			Pro Forma
	(In thousands, except unit and per unit data)

Operating Revenues
Transportation of natural gas	$	80,577	$	—		$	80,577
Storage of natural gas		2,032		—			2,032

Total operating revenues		82,609		—			82,609

Operating Expenses
Operations, maintenance and other		21,831		—			21,831
Depreciation and amortization		18,986		—			18,986
Property and other taxes		4,177		—			4,177

Total operating expenses		44,994		—			44,994

Operating Income		37,615		—			37,615
Other Income and Expenses
Equity in earnings of unconsolidated affiliates		41,105		—			41,105
Other income		1,780		—			1,780

Total other income and expenses		42,885		—			42,885

Interest Expense		8,151		7,625	(a)		15,976
				200	(b)

Earnings before Income Taxes		72,349		(7,825	)		64,524
Income Tax Expense		10,741		(10,288	)(c)		453

Net Income	$	61,608	$	2,463		$	64,071

General partner’s interest in net income						$	1,281

Limited partners’ interest in net income						$	62,790

Net income per limited partners’ unit
Common units						$	1.02

Subordinated units						$	1.02

Weighted average number of limited partners’ units outstanding
Common units							41,312,011

Subordinated units							20,030,066

See accompanying notes to unaudited pro forma combined financial statements

F-3

SPECTRA ENERGY PARTNERS, LP

UNAUDITED PRO FORMA COMBINED BALANCE SHEET

December 31, 2006


	Spectra Energy						Spectra Energy
	Partners Predecessor			Pro Forma			Partners, LP
	Historical			Adjustments			Pro Forma
				(In thousands)

ASSETS
Current Assets
Cash and cash equivalents	$	—		$	230,000	(d)	$	8,693
					(20,307	)(e)
					(150,000	)(f)
					(50,000	)(g)
					50,000	(h)
					125,000	(i)
					(1,000	)(j)
					(175,000	)(k)
Accounts receivable
Trade		9,098			(9,098	)(l)		—
Natural gas imbalance receivables		7,692			—			7,692
Inventory		2,460			—			2,460
Other		1,526			—			1,526

Total current assets		20,776			(405	)		20,371

Investments and Other Assets
Long-term investments		—			50,000	(g)		50,000
Investment in unconsolidated affiliates		442,793			(6,029	)(l)		431,081
					(5,273	)(m)
					(410	)(n)
Goodwill		118,293			—			118,293

Total investments and other assets		561,086			38,288			599,374

Property, Plant and Equipment
Cost		800,053			—			800,053
Less accumulated depreciation and amortization		(108,233	)		—			(108,233	)

Net property, plant and equipment		691,820			—			691,820

Regulatory Assets and Deferred Debits		10,900			1,000	(j)		11,900

Total Assets	$	1,284,582		$	38,883		$	1,323,465

See accompanying notes to unaudited pro forma combined financial statements

F-4

SPECTRA ENERGY PARTNERS, LP

UNAUDITED PRO FORMA COMBINED BALANCE SHEET

December 31, 2006


	Spectra Energy					Spectra Energy
	Partners Predecessor		Pro Forma			Partners, LP
	Historical		Adjustments			Pro Forma
			(In thousands)

LIABILITIES AND PARTNERS’ CAPITAL/ PARENT NET EQUITY
Current Liabilities
Accounts payable trade	$	2,237	$	—		$	2,237
Taxes accrued		6,756		(5,356	)(c)		1,400
Interest accrued		357		—			357
Accrued liabilities		8,917		—			8,917
Natural gas imbalance payables		4,470		—			4,470
Other		2,810		(795	)(m)		2,015

Total current liabilities		25,547		(6,151	)		19,396

Long-term Debt		150,000		50,000	(h)		325,000
				125,000	(i)
Deferred Credits and Other Liabilities
Deferred income taxes		113,011		(108,241	)(c)		4,770
Other		6,899		—			6,899

Total deferred credits and other liabilities		119,910		(108,241	)		11,669

Partners’ Capital/Parent Net Equity
Parent net investment		985,333		(4,478	)(m)		—
				113,597	(c)
				(150,000	)(f)
				(175,000	)(k)
				(15,127	)(l)
				(410	)(n)
				(753,915	)(o)
Accumulated other comprehensive income		3,792		—			3,792
Common unitholders — public		—		230,000	(d)		209,693
				(20,307	)(e)
Common unitholders — sponsor		—		439,890	(o)		439,890
Subordinated unitholders — sponsor		—		295,553	(o)		295,553
General partner interest		—		18,472	(o)		18,472

Total partners’ capital/parent net equity		989,125		(21,725	)		967,400

Total Liabilities and Partners’ Capital/Parent Net Equity	$	1,284,582	$	38,883		$	1,323,465

See accompanying notes to unaudited pro forma combined financial statements

F-5

SPECTRA ENERGY PARTNERS, LP

NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS

1. Basis of Presentation, The Offering and Other Transactions

The unaudited pro forma combined financial statements of Spectra Energy Partners, LP (the Partnership) have been prepared from information derived from historical audited combined financial statements of Spectra Energy Partners Predecessor appearing elsewhere in this prospectus, and the assumptions outlined in Note 2 below. The unaudited pro forma combined statement of operations assumes the offering and transactions as described in this prospectus occurred on January 1, 2006, and the unaudited pro forma combined balance sheet assumes that the offering and the transactions occurred as of December 31, 2006. The adjustments are based upon currently available information and certain estimates and assumptions, and therefore the actual effects of these transactions will differ from the pro forma adjustments.

The unaudited pro forma combined financial statements reflect the following significant assumptions and transactions:


	•	East Tennessee’s and Market Hub’s distribution of accounts receivable of $9.1 million and $12.1 million, respectively, to Spectra Energy Corp;

	•	The net proceeds to Spectra Energy Partners, LP of $215.6 million from the issuance and sale of 11.5 million common units at an initial offering price of $20.00 per unit, and the payment of underwriting commissions of $14.4 million;

	•	Spectra Energy Partner, LP’s borrowings under a new $500 million credit facility of $50 million in term debt and $125 million in revolving debt;

	•	The use of proceeds and borrowings to pay transaction expenses and underwriting commissions, reimburse Spectra Energy for certain capital expenditures, replenish working capital, and invest in U.S. Treasury, and other qualifying securities; and

	•	Spectra Energy will indemnify us for certain environmental and tax liabilities and title and right-of-way defects.

Upon completion of this offering, Spectra Energy Partners, LP anticipates incurring incremental general and administrative expense of approximately $5.5 million per year as a result of being a publicly traded limited partnership, including costs associated with annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs and director compensation. The unaudited pro forma combined financial statements do not reflect these expenses.

2. Pro Forma Adjustments and Assumptions

(a) Reflects the interest expense related to the borrowings described in (h) and (i) below, net of the interest income related to the U.S. Treasury securities described in (g) below. The interest expense for the revolving debt is based on an estimated average variable interest rate of 6%. The term debt interest expense, net of the interest income, is based on an estimated net of 0.25% interest expense. A change of 1% would have increased or decreased the net interest expense and interest income by $1.3 million for the year ended December 31, 2006.

(b) Reflects the amortization of the deferred issuance costs related to the debt described in (h) and (i) below over the term of the associated debt, 5 years.

(c) Reflects the elimination of historical income taxes for all current and deferred taxes apart from Tennessee state income taxes which will continue to be borne by the Partnership post-offering.

(d) Reflects the assumed gross proceeds to the Partnership of $230 million from the issuance and sale of 11.5 million common units at an assumed initial public offering price of $20.00 per unit.

F-6

SPECTRA ENERGY PARTNERS, LP

NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS — (Continued)

(e) Reflects the payment of underwriting commission of $14.4 million and other offering expenses of $5.9 million for a total of $20.3 million, which will be allocated to the public common units.

(f) Reflects the distribution of $150 million to reimburse Spectra Energy for certain capital expenditures incurred prior to the offering.

(g) Reflects the purchase of $50 million of U.S. Treasury and other qualifying securities using a portion of the proceeds from the offering. These securities are pledged as collateral for the borrowings under the term loan portion of our credit facility.

(h) Reflects $50 million of term borrowings under the term portion of the new $500 million credit facility.

(i) Reflects $125 million of revolving borrowings under the revolving portion of the new $500 million credit facility.

(j) Reflects estimated deferred debt issuance costs associated with the new $500 million credit facility.

(k) Reflects the distribution to Spectra Energy of a portion of the net proceeds from the offering and borrowings of the new credit facility.

(l) Reflects the distribution to Spectra Energy of accounts receivable of an estimated $9.1 million for East Tennessee and an estimated $12.1 million for Market Hub, $6.0 million net for our interest.

(m) Reflects the partnership’s share of a distribution from Market Hub and a distribution to East Tennessee by Spectra Energy Capital for funds swept by Spectra Energy Capital as part of its treasury management activities for security deposits received by Market Hub.

(n) Reflects Spectra Energy’s retention of certain Market Hub assets related to Copiah County Storage Co, LLC that will not be transferred to the Partnership as part of the offering.

(o) Reflects the conversion of the adjusted parent net investment of Spectra Energy Partners Predecessor of $753.9 million from parent net investment to common and subordinated limited partner capital of Spectra Energy Partners, LP and the general partner’s interest in Spectra Energy Partners, LP. The conversion is allocated as follows:


	•	$439.9 million for 29,812,011 common units purchased by Spectra Energy;

	•	$295.5 million for 20,030,066 subordinated units; and

	•	$18.5 million for 1,251,879 general partner units.

After the conversion, the equity amounts of the common and subordinated unitholders are 66% and 32%, respectively, of total capital, with the remaining 2% capital representing the general partner interest.

The above assumes that the underwriters’ over-allotment option is not exercised. If the underwriters exercise their option to purchase additional common units in full, we would receive approximately $32.3 million of net proceeds from the sale of these common units and will (1) use such net proceeds from the sale of these additional units to purchase an equivalent amount of United States Treasury and other qualifying securities and (2) borrow an additional amount under the term loan facility equal to such net proceeds.

3. Pro Forma Net Income per Unit

Pro forma net income per unit is determined by dividing the pro forma net income that would have been allocated to the common and subordinated unitholders, which is 98% of the pro forma net income, by the number of common and subordinated units expected to be outstanding at the closing of the offering.

F-7

SPECTRA ENERGY PARTNERS, LP

NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS — (Continued)

For purposes of this calculation, 41,312,011 common units and 20,030,066 subordinated units (excludes exercise of the underwriters’ over-allotment option) was assumed to be outstanding at all times during the period presented. All units were assumed to have been outstanding since January 1, 2006. Basic and diluted pro forma net income per unit are equivalent as there are no dilutive units at the date of closing of the initial public offering of the common units of Spectra Energy Partners, LP. Pursuant to the partnership agreement, to the extent that the quarterly distributions exceed certain targets, the general partner is entitled to receive certain incentive distributions that will result in more net income proportionately being allocated to the general partner than to the holders of common and subordinated units. The pro forma net income per unit calculations assume that no incentive distributions were made to the general partner because no such distribution would have been paid based upon the pro forma available cash for distribution for the period.

SEC Staff Accounting Bulletin 1:B:3 requires that certain distributions to owners prior to or coincident with an initial public offering be considered as distributions in contemplation of that offering. Upon completion of this offering, Spectra Energy Partners, LP intends to distribute approximately $325 million in cash to affiliates of Spectra Energy Corp. This distribution will be paid with (i) $125 million of revolving borrowings; (ii) $50 million of term borrowings under the new credit facility and (iii) $150 million from the proceeds of the issuance and sale of common units. Assuming additional common units were issued to give effect to this distribution, pro forma net income per limited partners’ unit would have been $0.91 for common and subordinated units for the year ended December 31, 2006.

F-8

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors

Spectra Energy Corp

Houston, Texas

We have audited the accompanying combined balance sheets of Spectra Energy Partners Predecessor (“the Company”) as of December 31, 2006 and 2005, and the related combined statements of operations, parent net equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2006. Our audits also included the financial statement schedule listed in Item 16. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such combined financial statements present fairly, in all material respects, the combined financial position of Spectra Energy Partners Predecessor as of December 31, 2006 and 2005, and the combined results of its operations and its cash flows for each of the three years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic combined financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

The accompanying combined financial statements 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 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.

/s/ Deloitte & Touche LLP

Houston, Texas

March 27, 2007

F-9

SPECTRA ENERGY PARTNERS PREDECESSOR

COMBINED STATEMENTS OF OPERATIONS


	Years Ended December 31,
	2006		2005		2004
			(In thousands)

Operating Revenues
Transportation of natural gas	$	80,531	$	77,553	$	69,242
Transportation of natural gas - affiliates		46		150		9,352
Storage of natural gas and other		2,032		2,300		3,122

Total operating revenues		82,609		80,003		81,716

Operating Expenses
Operations, maintenance and other		8,970		16,680		19,679
Operations, maintenance and other - affiliates		12,861		7,968		6,402
Depreciation and amortization		18,986		23,640		21,492
Property and other taxes		4,177		5,264		518

Total operating expenses		44,994		53,552		48,091

Operating Income		37,615		26,451		33,625

Other Income and Expenses
Equity in earnings of unconsolidated affiliates		41,105		46,287		35,495
Other income, net		1,780		552		1,491

Total other income and expenses		42,885		46,839		36,986

Interest Expense		8,151		8,506		8,258

Earnings before Income Taxes		72,349		64,784		62,353
Income Tax Expense		10,741		7,834		9,202

Net Income	$	61,608	$	56,950	$	53,151

See notes to combined financial statements

F-10

SPECTRA ENERGY PARTNERS PREDECESSOR

COMBINED BALANCE SHEETS


	December 31,
	2006			2005
	(In thousands)

ASSETS
Current Assets
Accounts receivable
Trade, net of allowance for doubtful accounts of $241 thousand, and $274 thousand, respectively	$	9,098		$	8,898
Natural gas imbalance receivables		3,077			3,577
Natural gas imbalance receivables - affiliates		4,615			21,363
Inventory		2,460			1,503
Taxes receivable - affiliates		1,488			1,156
Other		38			331

Total current assets		20,776			36,828

Investments and Other Assets
Investment in unconsolidated affiliates		442,793			422,340
Goodwill		118,293			118,293

Total investments and other assets		561,086			540,633

Property, Plant and Equipment
Cost		800,053			706,669
Less accumulated depreciation and amortization		(108,233	)		(90,353	)

Net property, plant and equipment		691,820			616,316

Regulatory Assets and Deferred Debits		10,900			8,995

Total Assets	$	1,284,582		$	1,202,772


LIABILITIES AND NET PARENT EQUITY
Current Liabilities
Accounts payable trade	$	122		$	2,061
Accounts payable trade - affiliates		2,115			974
Taxes accrued		3,419			4,163
Taxes accrued - affiliates		3,337			5,820
Interest accrued		357			357
Accrued liabilities		8,917			14,967
Natural gas imbalance payables		1,103			7,673
Natural gas imbalance payables - affiliates		3,367			20,143
Other		2,810			896

Total current liabilities		25,547			57,054

Long-term Debt		150,000			150,000

Deferred Credits and Other Liabilities
Deferred income taxes		113,011			96,811
Other		6,899			3,211

Total deferred credits and other liabilities		119,910			100,022

Commitments and Contingencies
Parent Net Equity
Parent net investment		985,333			891,586
Accumulated other comprehensive income		3,792			4,110

Total parent net equity		989,125			895,696

Total Liabilities and Parent Net Equity	$	1,284,582		$	1,202,772

See notes to combined financial statements

F-11

SPECTRA ENERGY PARTNERS PREDECESSOR

COMBINED STATEMENTS OF CASH FLOWS


	Years Ended December 31,
	2006			2005			2004
				(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	61,608		$	56,950		$	53,151
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization		18,986			23,640			21,492
Equity in earnings of unconsolidated affiliates		(41,105	)		(46,287	)		(35,495	)
Allowance for funds used during construction — equity		(1,760	)		(506	)		(1,483	)
Distributions received from equity investments		20,335			29,645			13,720
Deferred income taxes		12,813			4,369			31,165
(Increase) decrease in
Accounts receivable		301			(1,804	)		(2,757	)
Accounts receivable - affiliates		(252	)		2,738			1,909
Taxes receivable - affiliates		—			6,121			11,630
Other current assets		(878	)		68			1,207
Other assets		(7,725	)		32			2,145
Increase (decrease) in
Accounts payable		58			757			(4,526	)
Accounts payable - affiliates		(856	)		930			(261	)
Accrued taxes		(401	)		1,838			(1,785	)
Accrued taxes - affiliates		(2,944	)		5,689			347
Other current liabilities		(9,033	)		6,038			(1,336	)
Other current liabilities - affiliates		106			(4,421	)		(1,861	)
Other liabilities		13,025			7,475			(3,275	)

Net cash provided by operating activities	$	62,278		$	93,272		$	83,987

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(85,910	)		(59,316	)		(34,269	)
Distributions received from equity investments		—			152,143			—

Net cash (used in) provided by investing activities	$	(85,910	)	$	92,827		$	(34,269	)

CASH FLOWS FROM FINANCING ACTIVITIES
Member’s dividend (East Tennessee Natural Gas)		—			—			(3,000	)
Transfers from (to) Parent, net		23,632			(186,099	)		(46,718	)

Net cash provided by (used in) financing activities	$	23,632		$	(186,099	)	$	(49,718	)

Net change in cash and cash equivalents	$	—		$	—		$	—
Cash and cash equivalents at beginning of the period		—			—			—

Cash and cash equivalents at end of the period	$	—		$	—		$	—

Supplemental Disclosures
Cash paid for interest, net of amount capitalized	$	8,591		$	8,566		$	12,955
Cash paid (refunded) to (from) Parent for income taxes		1,086			(5,518	)		(37,369	)
Significant non-cash transactions:
Transfer of assets from affiliate	$	(8,506	)	$	—		$	—
Contribution of assets to affiliate		—			4,018			—
Deferred taxes related to transfer of assets from affiliate		2,958			—			—
Gas imbalances receivables		17,248			(24,940	)		(1,005	)
Property, plant and equipment accruals		1,554			12,220			(20,893	)
Capitalization of development costs		5,701			—			—

See notes to combined financial statements

F-12

SPECTRA ENERGY PARTNERS PREDECESSOR

COMBINED STATEMENTS OF PARENT NET EQUITY AND COMPREHENSIVE INCOME


				Accumulated Other
	Parent Net			Comprehensive			Parent Net
	Investment			Income (Loss)			Equity
				(In thousands)

Balance January 1, 2004	$	1,021,321		$	—		$	1,021,321

Net income		53,151			—			53,151
Member’s dividends		(3,000	)		—			(3,000	)
Net transfers to parent		(46,719	)		—			(46,719	)

Balance December 31, 2004	$	1,024,753		$	—		$	1,024,753

Net income		56,950			—			56,950
Other comprehensive income
Net unrealized gains on cash flow hedges		—			4,167			4,167
Reclassification into earnings from cash flow hedges		—			(57	)		(57	)

Total comprehensive income								61,060
Net transfers to parent		(190,117	)		—			(190,117	)

Balance December 31, 2005	$	891,586		$	4,110		$	895,696

Net income		61,608			—			61,608
Other comprehensive loss
Reclassification into earnings from cash flow hedges		—			(318	)		(318	)

Total comprehensive income								61,290
Net transfers from parent		32,139			—			32,139

Balance December 31, 2006	$	985,333		$	3,792		$	989,125

See notes to combined financial statements

F-13

SPECTRA ENERGY PARTNERS PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS

Years Ended December 31, 2006, 2005 and 2004


1.	Description of Business and Basis of Presentation

These financial statements of Spectra Energy Partners Predecessor (the Company) are prepared in connection with the proposed initial public offering of limited partnership units in Spectra Energy Partners, LP (the Partnership), which was formed in March 2007 and which will own certain of the operations and assets of the Company, as further described below. Through its operating units, the Company is 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 and in south central Louisiana.

The Company is comprised of companies that were subsidiaries of Duke Energy Corporation (Duke Energy) for the periods presented in these financial statements.

In June 2006, the Board of Directors of Duke Energy authorized management to pursue a plan to create two separate publicly traded companies by spinning off Duke Energy’s natural gas business to Duke Energy shareholders. The spin-off was completed on January 2, 2007, at which time Spectra Energy became a separate publicly-traded entity. Spectra Energy primarily owns the Natural Gas Transmission and Field Services segments of Spectra Energy Capital LLC (Spectra Energy Capital), formerly Duke Capital LLC.

The combined financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States on the basis of Spectra Energy’s Predecessor historical ownership percentages of the operations that are expected to be contributed to the Partnership. These historical ownership percentages included: 100% for East Tennessee Natural Gas LLC (East Tennessee), 50% of Market Hub Partners Holding, LLC (Market Hub) and 24.5% of Gulfstream Natural Gas System, LLC (Gulfstream). The Company accounts for investments in 20%-to 50%-owned affiliates, and investments in less than 20% owned affiliates where it has the ability to exercise significant influence, under the equity method. Accordingly, the combined historical financial statements for the Company, as the financial statement predecessor to the Partnership, reflect the inclusion of East Tennessee and investments in Market Hub and Gulfstream using the equity method of accounting. These combined financial statements have been prepared from the separate records maintained by Spectra Energy Capital and may not necessarily be indicative of the actual results of operations that might have occurred if the Company had been operated separately during those periods. Because a direct ownership relationship did not exist among the entities comprising the Company, the net investment in the Company is shown as Parent Net Equity in lieu of owner’s equity in the combined financial statements.

As part of the initial public offering of limited partnership units of the Partnership, Spectra Energy plans to contribute to the Partnership certain of the operations and assets of the Company. The Partnership will own 100% of East Tennessee, 50.0% of Market Hub (excluding Spectra Energy’s retention of certain Market Hub assets related to Copiah County Storage Co, LLC that will not be transferred to the Partnership as part of the offering) and 24.5% of Gulfstream. The Partnership is expected to consolidate its ownership in East Tennessee, with equity accounting for Market Hub and Gulfstream.

A subsidiary of Spectra Energy will serve as the general partner of the Partnership and will provide services to the Partnership pursuant to operating and management agreements between the parties.

The accompanying combined balance sheets do not include certain Spectra Energy Capital assets and liabilities that are not specifically identifiable to the Company:


	•	Spectra Energy Capital managed its cash on a centralized basis for the entire Duke Energy consolidated group, which in the three years ended December 31, 2006, included the various assets and operations of the companies comprising the Company. The individual cash accounts maintained at the business unit levels (i.e. within the Company’s entities) were swept to a Spectra Energy

F-14

SPECTRA ENERGY PARTNERS PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

Capital corporate account on a daily basis, creating an Advance Receivable between Spectra Energy Capital (or other affiliates/corporate entities) and Company units. Therefore, the Company’s financials do not reflect any cash balances. These net advances do not bear interest and are carried as unsecured, intercompany balances. Spectra Energy and the Company’s operating units expect to settle the cumulative advance balances through equity distributions or contributions, as applicable, prior to contribution of these units to the Partnership. Therefore, the consolidated net advances have been reclassified to Parent Net Equity in the Company’s combined balance sheets.


	•	The Company’s financing requirements have been managed historically with cash generated by operations and debt issuances, as needed, by the Company’s businesses. Therefore, Spectra Energy Capital’s corporate-level debt issuances and related interest amounts, which generally financed operations outside of the Company’s operations, are not included in the Company’s historical combined financial statements.

Gulfstream, as an unconsolidated affiliate of Spectra Energy Capital, did not participate in the centralized cash management activity of Spectra Energy Capital.

The Company’s costs of doing business have been reflected in the financial accounting records of the Company for the periods presented. These costs include direct charges and allocations from Spectra Energy Capital 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,

	•	Pension and other post-retirement benefit costs.

Transactions between the Company and other Spectra Energy Capital operations have been identified in the combined financial statements as transactions between affiliates (see Note 3).

In the opinion of management, the assumptions underlying the combined financial statements are reasonable.


2.	Summary of Significant Accounting Policies

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

Inventory. Inventory primarily consists of natural gas held in storage and is recorded at the lower of cost or market value, primarily using the average cost method.

Cost-Based Regulation . The Company accounts for its regulated operations at East Tennessee 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, the Company records assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for non-regulated entities. Management continually assesses whether regulatory assets are probable of future recovery by considering factors such as applicable regulatory changes and recent rate orders applicable to other regulated entities. Based on this continual assessment, management believes the existing regulatory assets are probable of recovery. These regulatory assets and liabilities are classified in the Combined

F-15

SPECTRA ENERGY PARTNERS PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

Balance Sheets as Regulatory Assets and Deferred Debits, and Deferred Credits and Other Liabilities. The Company periodically evaluates the applicability of SFAS No. 71, and considers factors such as regulatory changes and the impact of competition. If cost-based regulation ends or competition increases, the Company may have to reduce certain of its asset balances to reflect a market basis lower than cost and write-off the associated regulatory assets. The Company has no regulatory liabilities for the periods included in the financial statements. (For further information, see Note 5.)

Goodwill . Goodwill represents the excess of purchase price over fair value of net assets acquired. The Company evaluates goodwill for potential impairment under the guidance of Statement of Financial Accounting Standards (SFAS) No. 142, “Goodwill and Other Intangible Assets.” Under this provision, goodwill is subject to an annual test for impairment. The Company has designated August 31 as the date it performs the annual review for goodwill impairment for its reporting units. Under the provisions of SFAS No. 142, the Company performs the annual review for goodwill impairment at the reporting unit level, which the Company has determined to be an operating segment or one level below.

The Company uses a discounted cash flow analysis to determine fair value. Key assumptions in the determination of fair value include the use of an appropriate discount rate and estimated future cash flows. In estimating cash flows, the Company incorporates expected growth rates, regulatory stability and the ability to renew contracts, as well as other factors that affect revenue and expense forecasts. The Company did not record any impairment of its goodwill in 2006, 2005 and 2004, and there have been no additions, amortizations, or other changes in the carrying amount of goodwill during the years then ended. Goodwill for the Company’s sole operating segment, East Tennessee, was $118,293 thousand at December 31, 2006 and 2005.

Property, Plant and Equipment . Property, plant and equipment are stated at the lower of historical cost less accumulated depreciation or fair value, if impaired. The Company capitalizes all construction-related direct labor and material costs, as well as indirect construction costs. Indirect costs include general engineering, taxes and the cost of funds used during construction. The cost of renewals and betterments that extend the useful life of property, plant and equipment is also capitalized. The cost of repairs, replacements and major maintenance projects, which do not extend the useful life or increase the expected output of property, plant and equipment, is expensed as it is incurred. Depreciation is generally computed over the asset’s estimated useful life using the straight-line method. The composite weighted-average depreciation rates were 2.6% for 2006, 3.7% for 2005, and 3.7% for 2004.

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

Asset Retirement Obligations. In June 2001, the FASB issued SFAS No. 143, “Accounting For Asset Retirement Obligations” which was adopted by the Company on January 1, 2003 and addresses financial accounting and reporting for legal obligations associated with the retirement of tangible long-lived assets

F-16

SPECTRA ENERGY PARTNERS PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

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

Asset retirement obligations of the Company relate primarily to right-of-way agreements, asbestos removal and contractual leases for land use. In accordance with SFAS No. 143, the Company identified certain assets that have an indeterminate life, and thus the fair value of the retirement obligation is not reasonably estimable. These assets included on-shore pipelines. A liability for these asset retirement obligations will be recorded when a fair value is determinable.

In March 2005, the FASB issued Financial Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47). The adoption of FIN 47 had no impact on the income of the regulated gas pipeline operations. Any effects would be offset by the establishment of regulatory assets and liabilities pursuant to SFAS No. 71.

Unamortized Debt Expense . Debt expenses incurred with the issuance of outstanding long-term debt are deferred and 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.

Long-Lived Asset Impairment and Assets Held For Sale . The Company evaluates whether long-lived assets, excluding goodwill, have been impaired when circumstances indicate the carrying value of those assets may not be recoverable. For such long-lived assets, impairment exists when its carrying value exceeds the sum of estimates of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. When alternative courses of action to recover the carrying amount of a long-lived asset are under consideration, a probability-weighted approach is used for developing estimates of future undiscounted cash flows. If the carrying value of the long-lived asset is not recoverable based on these estimated future undiscounted cash flows, the impairment loss is measured as the excess of the asset’s carrying value over its fair value, such that the asset’s carrying value is adjusted to its estimated fair value.

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

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

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SPECTRA ENERGY PARTNERS PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

Equity Method Investments. The Company accounts for investments in 20% to 50% owned affiliates, and investments in less than 20% owned affiliates where Spectra Energy Partners Predecessor has the ability to exercise significant influence, under the equity method.

Natural Gas Imbalances . The Combined Balance Sheets include in-kind balances as a result of differences in gas volumes received and delivered for customers. Natural gas volumes owed to or by the Company are valued at market index prices as of the balance sheet dates. Since the settlement of imbalances in the Company’s pipeline operations is in-kind, changes in these balances do not have an impact on the Company’s Combined Statements of Cash Flows. Accounts receivable includes $7,692 thousand and $24,940 thousand as of December 31, 2006 and 2005, respectively, and other current liabilities includes $4,471 thousand and $20,412 thousand as of December 31, 2006 and 2005, respectively, related to gas imbalances. Natural gas volumes owed to (by) the Company are valued at natural gas market index prices as of the balance sheet dates.

Environmental Expenditures . The Company expenses environmental expenditures related to conditions caused by past operations that do not generate current or future revenues. Environmental expenditures related to operations that generate current or future revenues are expensed or capitalized, as appropriate. Liabilities are recorded when the necessity for environmental remediation becomes probable and the costs can be reasonably estimated, or when other potential environmental liabilities are reasonably estimable and probable.

Revenue Recognition . Revenues on natural gas transportation and storage are recognized when the service is provided. Revenues from long-term contracts with billed rates that decline annually are recognized evenly over the term of the contract. This results in increasing deferred revenue balances in the early years of the contract that are recognized in revenue over the later years of the contract. 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 revenues are immaterial. From time to time, certain revenues may be subject to refund pending the outcome of rate matters before the FERC, and reserves are established where required. There were no pending rate cases and no related reserves were recorded as of December 31, 2006 and 2005. The allowance for doubtful accounts was $241 thousand for 2006, $274 thousand for 2005 and $208 thousand for 2004.

Significant Customers . The customers accounting for 10% or more of combined revenues during the years ended December 31, 2006, 2005, and 2004 are as follows:


	% of Revenues
	Years Ended
	December 31,
Customer	2006			2005			2004

Atmos Energy Corporation		18	%		16	%		16	%
KGEN Murray I and II, LLC		13	%		14	%		⁽¹	⁾
Knoxville Utilities Board		⁽¹	⁾		10	%		10	%
Duke Energy Murray, LLC		⁽²	⁾		⁽²	⁾		10	%

⁽¹⁾ Percentage below 10%

⁽²⁾ Duke Energy Murray, LLC, owned by a related party, was sold to KGEN Murray, LLC in September 2004.

Allowance for Funds Used During Construction (AFUDC) . 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

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SPECTRA ENERGY PARTNERS PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

Cost, with offsetting credits to the Combined Statements of Operations. After construction is completed, the Company is permitted to recover these costs through inclusion in the rate base calculation. The total amount of AFUDC included in the Combined Statements of Operations was $2,236 thousand in 2006, which consisted of an equity component of $1,760 thousand and an interest expense component of $476 thousand. The total amount of AFUDC included in the Combined Statements of Operations was $651 thousand in 2005, which consisted of an equity component of $506 thousand and an interest expense component of $145 thousand. The total amount of AFUDC included in the Combined Statements of Operations was $1,935 thousand in 2004, which consisted of an equity component of $1,483 thousand and an interest expense component of $452 thousand.

Income Taxes . Duke Energy and its subsidiaries historically filed a consolidated federal income tax return and other state returns as required. The Company’s East Tennessee operations were subject to corporate income tax under a tax sharing agreement with Duke Energy. Income taxes have been provided by the Company on the basis of its separate company income and deductions related to East Tennessee in accordance with established practices of 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.

Management evaluates and records contingent tax liabilities and related interest based on the probability of ultimately sustaining the tax deductions or income positions. Management assesses the probabilities of successfully defending the tax deductions or income positions based upon statutory, judicial or administrative authority. There were no such contingent liabilities recorded by the Company for the periods presented.

Market Hub and Gulfstream are not subject to income tax, but rather the taxable income or loss of these entities is reported on the respective income tax returns of the respective members. Accordingly, there is no tax provision related to those entities in these combined 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 annual and interim financial reports. Operating segments are components of an enterprise about which separate financial information is available and evaluated regularly by the chief operating decision maker in deciding how to allocate resources and evaluate performance. Two or more operating segments may be aggregated into a single reportable segment provided aggregation is consistent with the objectives 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 the Company’s defined business segments. SFAS No. 131 also establishes standards and related disclosures about the way the operating segments were determined, products and services, geographic areas and major customers, differences between the measurements used in reporting segment information and those used in the Company’s general-purpose financial statements, and changes in the measurement of segment amounts from period to period. The description of the Company’s reportable segments, consistent with how business results are expected to be reported internally to the Partnership’s management and the disclosure of segment information in accordance with SFAS No. 131, are presented in Note 4.

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

F-19

SPECTRA ENERGY PARTNERS PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

New Accounting Standards. The following new accounting standards were adopted by the Company during the year ended December 31, 2006 and the impact of such adoption, if applicable, has been presented in the accompanying combined financial statements:

FSP No. FAS 115-1 and 124-1, “The Meaning of Other-Than-Temporary Impairment and its Application to Certain Investments.” The Financial Accounting Standards Board (FASB) issued FASB Staff Position (FSP) No. FAS 115-1 and 124-1 in November 2005, which was effective for the Company beginning January 1, 2006. This FSP addresses the determination as to when an investment is considered impaired, whether that impairment is other than temporary and the measurement of an impairment loss. This FSP also includes accounting considerations subsequent to the recognition of an other-than-temporary impairment and requires certain disclosures about unrealized losses that have not been recognized as other-than-temporary impairments. The guidance in this FSP amends SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities,” and SFAS No. 124, “Accounting for Certain Investments Held by Not-for-Profit Organizations,” and APB Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock.” The adoption of FSP No. FAS 115-1 and 124-1 did not have an impact on the Company’s combined results of operations, cash flows or financial position.

FERC Accounting Order. In June 2005, the FERC issued an Order on Accounting for Pipeline Assessment Costs that requires most pipeline inspection and integrity assessment activities to be recognized as expenses, as incurred. In the Order, FERC confirmed that pipeline betterments and replacements, including those resulting from integrity inspections, will continue to be capitalized when appropriate. This FERC Order was effective for pipeline inspection and integrity assessment costs incurred on or subsequent to January 1, 2006 and increased annual expenses for the Company by approximately $1,698 thousand. Pipeline inspection and integrity assessment costs capitalized prior to the effective date of the rule were not impacted.

SAB No. 108, “Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in Current Year Financial Statements” (SAB No. 108) . In September 2006 the SEC issued SAB No. 108, which provides interpretive guidance on how the effects of the carryover or reversal of prior year misstatements should be considered in quantifying a current year misstatement. Traditionally, there have been two widely-recognized approaches for quantifying the effects of financial statement misstatements. The income statement approach focuses primarily on the impact of a misstatement on the income statement — including the reversing effect of prior year misstatements — but its use can lead to the accumulation of misstatements in the balance sheet. The balance sheet approach, on the other hand, focuses primarily on the effect of correcting the period-end balance sheet with less emphasis on the reversing effects of prior year errors on the income statement. The SEC staff believes that registrants should quantify errors using both a balance sheet and an income statement approach (a “dual approach”) and evaluate whether either approach results in quantifying a misstatement that, when all relevant quantitative and qualitative factors are considered, is material.

SAB No. 108 was effective for the year ending December 31, 2006. SAB No. 108 permits existing public companies to initially apply its provisions either by (i) restating prior financial statements as if the “dual approach” had always been used or (ii), under certain circumstances, recording the cumulative effect of initially applying the “dual approach” as adjustments to the carrying values of assets and liabilities as of January 1, 2006 with an offsetting adjustment recorded to the opening balance of retained earnings. Spectra Energy has historically used a dual approach for quantifying identified financial statement misstatements. Therefore, the adoption of SAB No. 108 did not have any material impact on the Company’s consolidated results of operations, cash flows or financial position.

F-20

SPECTRA ENERGY PARTNERS PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

The following new accounting standards were adopted by the Company during the year ended December 31, 2005 and the impact of such adoption, if applicable, has been presented in the accompanying combined financial statements:

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

SFAS No. 154 “Accounting Changes and Error Corrections,” or SFAS 154. In June 2005, the FASB issued SFAS 154, a replacement of APB Opinion No. 20, or APB 20, “Accounting Changes” and SFAS No. 3, “Reporting Accounting Changes in Interim Financial Statements.” Among other changes, SFAS 154 requires that a voluntary change in accounting principle be applied retrospectively with all prior period financial statements presented under the new accounting principle, unless it is impracticable to do so. SFAS 154 also (1) provides that a change in depreciation or amortization of a long-lived nonfinancial asset be accounted for as a change in estimate (prospectively) that was effected by a change in accounting principle, and (2) carries forward without change the guidance within APB 20 for reporting the correction of an error in previously issued financial statements and a change in accounting estimate. The adoption of SFAS 154 on January 1, 2006, did not have a material impact on our consolidated results of operations, cash flows or financial position.

FIN 47 “Accounting for Conditional Asset Retirement Obligations.” In March 2005, the FASB issued FIN 47, which clarifies the accounting for conditional asset retirement obligations as used in SFAS No. 143. A conditional asset retirement obligation is an unconditional legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. Therefore, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation under SFAS No. 143 if the fair value of the liability can be reasonably estimated. The provisions of FIN 47 were effective for the Company as of December 31, 2005. The adoption of FIN 47 did not have an impact on the Company’s combined results of operations, cash flows or financial position.

FSP No. APB 18-1, “Accounting by an Investor for Its Proportionate Share of Accumulated Other Comprehensive Income of an Investee Accounted for under the Equity Method in Accordance with APB Opinion No. 18 upon a Loss of Significant Influence.” In July 2005, the FASB staff issued FSP No. APB 18-1 which provides guidance for how an investor should account for its proportionate share of an investee’s equity adjustments for other comprehensive income (OCI) upon a loss of significant influence. APB Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock”, requires a transaction of an equity method investee of a capital nature be accounted for as if the investee were a combined subsidiary, which requires the investor to record its proportionate share of the investee’s adjustments for OCI as increases or decreases to the investment account with corresponding adjustments in equity. FSP No. APB 18-1 requires that an investor’s proportionate share of an investee’s equity adjustments for OCI should be offset against the carrying value of the

F-21

SPECTRA ENERGY PARTNERS PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

investment at the time significant influence is lost and equity method accounting is no longer appropriate. However, to the extent that the offset results in a carrying value of the investment that is less than zero, an investor should (a) reduce the carrying value of the investment to zero and (b) record the remaining balance in income. The guidance in FSP No. APB 18-1 was effective for the Company beginning October 1, 2005. The adoption of FSP No. APB 18-1 did not have a material impact on the Company’s combined results of operations, cash flows or financial position.

The following new accounting standards were adopted by the Company during the year ended December 31, 2004 and the impact of such adoption, if applicable, has been presented in the accompanying combined financial statements:

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

The provisions of FIN 46 applied immediately to variable interest entities created, or interests in variable interest entities obtained, after January 31, 2003, while the provisions of FIN 46R were required to be applied to those entities, except for special purpose entities, by the end of the first reporting period ending after March 15, 2004. For variable interest entities created, or interests in variable interest entities obtained, on or before January 31, 2003, FIN 46 or FIN 46R was required to be applied to special-purpose entities by the end of the first reporting period ending after December 15, 2003, and was required to be applied to all other non-special purpose entities by the end of the first reporting period ending after March 15, 2004. The adoption of FIN 46 and FIN 46R did not have a material impact on the Company’s combined results of operations, cash flows, or financial position.

The Company has not identified any variable interest entities created, or interests in variable entities obtained, after January 31, 2003, which require consolidation or disclosure under FIN 46R.

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

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

FIN 48, “ Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109. ” In July 2006, the FASB issued FIN 48, which provides guidance on accounting for income tax positions about which Spectra Energy Partners has concluded there is a level of uncertainty with respect to the recognition in Spectra Energy Partners’ financial statements. FIN 48 prescribes a minimum recognition threshold a tax position is required to meet. Tax positions are defined very broadly and include not only tax deductions and credits but also decisions not to file in a particular jurisdiction, as well as the taxability of transactions. Spectra Energy Partners will implement FIN 48 effective January 1, 2007. In addition, subsequent accounting for FIN 48 (after January 1, 2007) will involve an evaluation to determine if any changes have occurred that would impact the existing

F-22

SPECTRA ENERGY PARTNERS PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

uncertain tax positions as well as determining whether any new tax positions are uncertain. Any impacts resulting from the evaluation of existing uncertain tax positions or from the recognition of new uncertain tax positions would impact income tax expense and interest expense in the Consolidated Statement of Operations. The implementation is not expected to result in a material impact to the Company’s combined results of operations, cash flows or financial position.

SFAS No. 159 “The Fair Value Option for Financial Assets and Financial Liabilities — including an amendment of FAS 115,” or SFAS 159. In February 2007, the FASB issued SFAS 159, which allows entities to choose, at specified election dates, to measure eligible financial assets and liabilities at fair value that are not otherwise required to be measured at fair value. If a company elects the fair value option for an eligible item, changes in that item’s fair value in subsequent reporting periods must be recognized in current earnings. SFAS 159 also establishes presentation and disclosure requirements designed to draw comparison between entities that elect different measurement attributes for similar assets and liabilities. SFAS 159 is effective for us on January 1, 2008. We have not assessed the impact of SFAS 159 on our consolidated results of operations, cash flows or financial position.

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


3.	Transactions with Affiliates

In the normal course of business, the Company provides natural gas transportation, storage and other services to Spectra Energy Capital and its affiliates. In addition, the Company engages in other transactions with affiliates, including reimbursement of costs incurred by affiliates on behalf of the Company and allocations from affiliates for various corporate services including legal, accounting, treasury, information technology and human resources. Affiliates charge such expenses based on the cost of actual services provided or using various allocation methodologies based on the Company’s percentage of assets, employees, earnings or other measures, as compared to other affiliates. Management believes the allocation methodologies are reasonable; however, these allocations and estimates may not represent the amounts that would have been incurred had the Company operated as a separate entity.

F-23

SPECTRA ENERGY PARTNERS PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

Transactions with affiliates are summarized in the tables below:

Statement of Operations


	Years Ended December 31,
	2006		2005		2004
	(In thousands)

Transportation of natural gas(1)	$	46	$	150	$	9,352
Operation and maintenance expenses(2)		12,861		7,968		6,402


(1)		In the normal course of business, the Company provides natural gas transportation, storage and other services to affiliates.

(2)		Includes operation and maintenance costs incurred by the Company in relation to those natural gas storage and other services provided to Spectra Energy Capital and its affiliates as identified above. Additionally includes costs the Company has incurred as allocations of various overhead charges that are based either on the cost of actual service received or using various allocation methodologies based on the Company’s percentage of assets, employees, earnings or other measures, as compared to Spectra Energy Capital affiliates.

Balance Sheet


	December 31,
	2006		2005
	(In thousands)

Natural gas imbalance receivable	$	4,615	$	21,363
Accounts payable		2,115		974
Taxes accrued		3,337		5,820
Natural gas imbalance payables		3,367		20,143
Taxes receivable		1,488		1,156

See also Notes 1, 9, 10 and 11 for discussion of other specific related party transactions.

Advances receivable from and 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 operations, capital expenditures and debt payments of the Company.

On August 1, 2004, East Tennessee made a dividend of approximately $3 million to Duke Energy Gas Transmission (DEGT) through Advances Receivable (Payable) – Affiliates account, representing the Company’s ownership interest in its wholly owned subsidiaries, Duke Energy Gas Transmission Investments, LLC and Duke Energy Gas Services Finance Corporation.


4.	Business Segments

The Company’s operations are organized into one business segment: East Tennessee. The Company’s business segment is considered the sole reportable segment under SFAS No. 131.

East Tennessee provides interstate transportation of natural gas and the storage and redelivery of liquified natural gas (LNG) for customers in the southeastern U.S. These operations are primarily subject to the Federal Energy Regulatory Commission (FERC) and the U.S. Department of Transportation’s (DOT) rules and regulations.

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

F-24

SPECTRA ENERGY PARTNERS PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

Market Hub owns and operates two natural gas storage facilities, Moss Bluff and Egan. These two facilities have aggregate working gas storage capacity of approximately 35 billion cubic feet (Bcf) as of December 31, 2006. The Moss Bluff facility consists of three storage caverns located in Southeast Texas and has access to five major pipeline systems. The Egan facility consists of three storage caverns located in South Central Louisiana and has access to seven major pipeline systems. These operations are subject to the rules and regulations of FERC and DOT.

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

Accounting policies for the Company’s sole segment is the same as those described in Note 2. 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


			Segment EBIT /
			Combined				Capital and
			Earnings before		Depreciation and		Investment
	Total Revenues		Income Taxes		Amortization		Expenditures
	(In thousands)
Year Ended December 31, 2006
East Tennessee	$	82,609	$	42,096	$	18,986	$	85,910
Other		—		38,404		—		—

Total		82,609		80,500		18,986		85,910
Interest expense		—		8,151		—		—

Total combined	$	82,609	$	72,349	$	18,986	$	85,910

Year Ended December 31, 2005
East Tennessee	$	80,003	$	28,722	$	23,640	$	59,316
Other		—		44,568		—		—

Total		80,003		73,290		23,640		59,316
Interest expense		—		8,506		—		—

Total combined	$	80,003	$	64,784	$	23,640	$	59,316

Year Ended December 31, 2004
East Tennessee	$	81,716	$	36,464	$	21,492	$	34,269
Other		—		34,147		—		—

Total		81,716		70,611		21,492		34,269
Interest expense		—		8,258		—		—

Total combined	$	81,716	$	62,353	$	21,492	$	34,269

Segment Assets


	December 31,
	2006		2005
	(In thousands)

East Tennessee	$	841,789	$	780,432
Other		442,793		422,340

Total combined	$	1,284,582	$	1,202,772

F-25

SPECTRA ENERGY PARTNERS PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

5. Regulatory Matters

Regulatory Assets. Pursuant to the requirements of SFAS No. 71, the Company records assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for non-regulated entities. For the years presented, the Company’s entities have no regulatory liabilities.


	December 31,				Recovery/Refund
	2006		2005		Period Ends
	(In thousands)

Regulatory Assets(1)
Regulatory asset related to income taxes(2)	$	8,481	$	7,711		(3)
Vacation accrual (non-current)(2)		1,989		812		2007

Total Regulatory Assets	$	10,470	$	8,523

All regulatory assets are excluded from rate base unless otherwise noted.


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

(2)		These amounts are expected to be included in future rate filings.

(3)		Recovery/refund period currently unknown.

East Tennessee. On November 1, 2005, East Tennessee placed into effect new rates approved by FERC as a result of a rate settlement with customers. The settlement agreement includes a five-year rate moratorium, a reduction of depreciation rates, and certain operational changes. On December 14, 2006, East Tennessee filed to establish system wide segmentation on part of its system, subject to FERC approval. This filing was generally supported by the customers, and is proposed to be implemented effective November 1, 2007.

Gulfstream. In September 2005, FERC approved Gulfstream’s Cost and Revenue study that was required to be filed as a condition in its Phase I and Phase II expansion projects. Gulfstream is not anticipated to have further filing requirements until three years after its Phase III expansion facilities are placed into service, currently expected in 2008.

Management believes that the effect of these matters will have no material adverse effect on the Company’s future combined results of operations, cash flows or financial position.

F-26

SPECTRA ENERGY PARTNERS PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

6. Income Taxes

Income Tax Expense


	For the Years Ended
	December 31,
	2006			2005		2004
	(In thousands)

Current income taxes
Federal	$	(1,622	)	$	3,240	$	(22,210	) ⁽¹⁾
State		(450	)		225		247

Total current income taxes		(2,072	)		3,465		(21,963	)

Deferred income taxes
Federal		11,489			3,068		31,094	⁽¹⁾
State		1,324			1,301		71

Total deferred income taxes		12,813			4,369		31,165

Total income tax expense presented in Combined Statements of Operations	$	10,741		$	7,834	$	9,202


⁽¹⁾	Current and deferred federal income taxes in 2004 were impacted by an organizational restructuring undertaken by the Company’s parent, Spectra Energy.

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


	For the Years Ended
	December 31,
	2006			2005			2004

Income tax expense, computed at the statutory rate of 35%	$	25,322		$	22,674		$	21,824
State income tax, net of federal income tax effect		568			992			206
Entities not subject to income tax		(14,387	)		(16,200	)		(12,423	)
Other items, net		(763	)		368			(405	)

Total income tax expense from operations	$	10,741		$	7,834		$	9,202

Effective tax rate		14.8	%		12.1	%		14.8	%

F-27

SPECTRA ENERGY PARTNERS PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

Net Deferred Income Tax Liability Components


	December 31,
	2006			2005

Deferred credits and other liabilities	$	3,365		$	6,819
Valuation allowance		—			—

Net deferred income tax assets		3,365			6,819

Accelerated depreciation rates		(112,041	)		(100,253	)
State deferred income tax, net of federal tax effect		(4,335	)		(3,377	)

Total deferred income tax liabilities		(116,376	)		(103,630	)

Total net deferred income tax liabilities	$	(113,011	)	$	(96,811	)


7.	Interest Rate, Credit Risk and Financial Instruments

Credit Risk. The Company’s principal customers for natural gas transportation activities are industrial end-users, marketers, exploration and production companies, local distribution companies and utilities located throughout the southern and southeastern U.S. The Company has concentrations of receivables from natural gas and electric utilities and their affiliates, as well as industrial customers, exploration and production companies and marketers. These concentrations of customers may affect the Company’s overall credit risk in that risk factors can negatively impact the credit quality of the entire sector. Where exposed to credit risk, the Company analyzes the counterparties’ financial condition prior to entering into an agreement, establishes credit limits and monitors the appropriateness of those limits on an ongoing basis.

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

Interest Rate. Changes in interest rates expose the Company to risk as a result of its issuance of fixed-rate debt. The Company monitors market debt rates to identify the need to mitigate this risk, including consideration of hedging activities, if needed. The Company has not previously entered into hedging contracts to mitigate this risk, except for interest rate swaps entered into by Gulfstream in anticipation of their $850 million in project financing, issued October 2005.

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, 2006 and 2005 are not necessarily indicative of the amounts the Company could have realized in current markets.

Financial Instruments


	December 31,
			Approximate				Approximate
	Book Value		Fair Value		Book Value		Fair Value

	2006				2005
	(In thousands)

Long-term debt(1)	$	150,000	$	150,065	$	150,000	$	152,924


(1)		There are no current maturities.

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

F-28

SPECTRA ENERGY PARTNERS PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)


8.	Deferred Revenues

East Tennessee has a long-term contract with a customer with billed amounts that decline annually over the term of the contract. The revenues billed over the 20 year term of the contract range from $9.9 million to $8.7 million. The annual amount of revenue recognized is $9.4 million with the difference deferred in Deferred Revenues, a long-term Other Liability account. The long-term liability for this contract is $2.3 million as of December 31, 2006 and $1.8 million as of December 31, 2005.


9.	Investments in Unconsolidated Affiliates and Related Transactions

Investments in affiliates that are not controlled by the Company, but over which it has significant influence, are accounted for using the equity method. As of December 31, 2006, the carrying amount of investments represented a 50% interest in Market Hub and a 24.5% interest in Gulfstream. The Company’s share of net earnings from these unconsolidated affiliates is reflected in the Combined Statements of Operations as Equity in Earnings of Unconsolidated Affiliates.

The Company received distributions of $20,335 thousand in 2006 from Gulfstream. These distributions are included in Distributions from Equity Investments within Cash Flows from Operating Activities on the accompanying Combined Statements of Cash Flows. In 2005, the Company received distributions of $181,788 thousand from Gulfstream. Of these distributions, $29,645 thousand are included in Distributions from Equity Investments within Cash Flows from Operating Activities and $152,143 thousand, characterized as a financing activity by Gulfstream, are included in Distributions from Equity Investments within Cash Flows from Investing Activities on the accompanying Combined Statements of Cash Flows. The Company received distributions of $13,720 thousand from Gulfstream in 2004. These distributions are included in Distributions from Equity Investments within Cash Flows from Operating Activities on the accompanying Combined Statements of Cash Flows.

In October 2005, Gulfstream issued $500,000 thousand aggregate principal amount of 5.56% Senior Notes due 2015 and $350,000 thousand aggregate principal amount of 6.19% Senior Notes due 2025. The proceeds were used by Gulfstream to pay off a construction loan and the balance of the proceeds, net of transaction costs, of approximately $621,000 thousand was distributed to the partners based upon their ownership percentage, which resulted in the distribution of $152,143 thousand to the Company that is classified within Cash Flows from Investing Activities in 2005 noted above.

Investment in Unconsolidated Affiliates


	December 31,
	2006		2005
	(In thousands)

Gulfstream	$	186,354	$	190,243
Market Hub		256,439		232,097

Total	$	442,793	$	422,340

F-29

SPECTRA ENERGY PARTNERS PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

Equity in Earning of Unconsolidated Affiliates


	For the Years Ended
	December 31,
	2006		2005		2004
			(In thousands)

Gulfstream	$	16,763	$	16,611	$	11,081
Market Hub		24,342		29,676		24,414

Total	$	41,105	$	46,287	$	35,495

Summarized Combined Financial Information of Unconsolidated Affiliates


	December 31,
	2006		2005
	(In thousands)

Balance Sheets
Current assets	$	104,919	$	190,901
Non-current assets		2,228,787		2,106,631
Current liabilities		179,925		150,562
Non-current liabilities		855,734		881,490

Net assets	$	1,298,047	$	1,265,480


	Years Ended December 31,
	2006		2005		2004
			(In thousands)

Statement of Operations
Operating revenues	$	259,062	$	223,033	$	159,458
Operating expenses		101,528		73,310		61,225
Net income		117,106		127,153		94,057


10.	Property, Plant and Equipment


	Estimated		December 31,
	Useful Life		2006			2005
	(In thousands)

Land		N/A	$	1,054		$	1,054
Natural gas transmission		50 years		757,345			651,531
Equipment		3-10 years		3,392			3,220
Vehicles		3-5 years		2,415			2,453
Construction in process		N/A		12,265			25,823
Other		5-33 years		23,582			22,588

Total property, plant and equipment				800,053			706,669
Total accumulated depreciation				(108,233	)		(90,353	)

Total net property, plant and equipment			$	691,820		$	616,316

Capitalized interest, which includes the interest expense component of AFUDC, amounted to $3,362 thousand for 2006, $1,421 thousand for 2005 and $2,350 thousand for 2004.

F-30

SPECTRA ENERGY PARTNERS PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

In 2006, the Company capitalized $5.7 million of previously expensed project development costs based on managements’ determination that such costs are properly included in regulated rates. The Company also capitalized in 2005 a non-cash accrual of $7.5 million for acquisition of right of way for the Patriot Expansion project. In 2004, the Company capitalized $24.0 million representing a capital accrual for the resolution of certain construction-related litigation. (See discussion at Note 12).

East Tennessee . In March 2006 Duke Energy Gas Services (DEGS), an affiliated company, contributed to East Tennessee approximately 34 miles of 10-inch diameter pipeline running from Lee County, Virginia to an interconnection with the Company’s Hawkins County Lateral in Rogersville, Tennessee at net book value of approximately $8,506 thousand by an equity transfer between the affiliated companies. Associated deferred taxes of $2,958 thousand related to such assets were transferred from the affiliate. These assets were part of DEGS’ Stone Mountain System and the remaining Stone Mountain System assets were sold by DEGS’ to an unrelated third party.

On February 8, 2006, the FERC issued a certificate of public convenience and necessity authorizing East Tennessee to construct and operate the Jewell Ridge Lateral, a 32-mile, 20-inch diameter pipeline in Tazewell and Smyth Counties, Virginia. On March 16, 2006, FERC issued a letter order approving the East Tennessee’s request to install tee and side tap valve assemblies to its existing pipelines as part of the Jewell Ridge Lateral project. The lateral was constructed during the summer of 2006 and was placed into service in October 2006. The amounts capitalized to Property, Plant and Equipment included $60,150 thousand for the Jewell Ridge Lateral natural gas pipeline project in Southwest Virginia.


11.	Debt

Long-term Debt. Long-term debt consists of notes payable of $150 million at 5.71% outstanding as of December 31, 2006 and 2005 due in one installment in 2012. Interest payments of $4,283 thousand are paid on June and December each year through 2012.

Restrictive Debt Covenants. The Company’s debt agreement contains financial covenants which limit the amount of debt that can be outstanding as a percentage of the total capital. Failure to maintain the covenants could require the Company to immediately pay down the outstanding balance. The covenant calculations are performed by the Company on a quarterly basis to establish that they are in compliance with the covenant. As of December 31, 2006, the Company was in compliance with those covenants. In addition, the debt agreement may allow for acceleration of payments or termination of the agreements due to nonpayment, or to the acceleration of other significant indebtedness of the borrower or some of its subsidiaries, if any. The debt agreement does not contain material adverse change clauses.

Change in Control Covenant. The separation of the Partnership from Spectra Energy may trigger a change in control provision of East Tennessee’s $150 million notes, whereby the Partnership may be required to repay the notes at face value if elected by the note holders. To the extent that the notes are redeemed, the Partnership intends to refinance the amount with revolving borrowings from the credit facility.


12.	Commitments and Contingencies

General Insurance. The Company’s operations have carried, through Duke Energy’s captive insurance company, insurance and reinsurance coverages consistent with companies engaged in similar commercial operations with similar type properties. Following the separation of Spectra Energy from Duke Energy, Spectra Energy is providing substantially similar insurance and reinsurance coverages. The Company’s insurance coverage includes (1) commercial general public liability insurance for liabilities arising to third parties for bodily injury and property damage resulting from the Company’s operations; (2) workers’ compensation liability coverage to required statutory limits; (3) automobile liability insurance for all owned,

F-31

SPECTRA ENERGY PARTNERS PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

non-owned and hired vehicles covering liabilities to third parties for bodily injury and property damage; (4) financial services insurance policies in support of the indemnification provisions of the Company’s by-law and, and (5) property insurance covering the replacement value of all real and personal property damage, including damages arising from machinery breakdowns, earthquake, flood damage and business interruption/extra expense. All coverages are subject to certain deductibles, terms and conditions common for companies with similar types of operations.

The Company maintains excess liability insurance coverage above the established primary limits for commercial general liability and automobile liability insurance. Limits, terms, conditions and deductibles are comparable to those carried by other energy companies of similar size. The cost of the Parent’s general insurance coverages and applicable allocations to the Company continued to fluctuate over the past year reflecting the changing conditions of the insurance markets.

Environmental. The Company is 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 that will have a material adverse effect on the Company’s results of operations, cash flows, or financial position.

Litigation and Legal Proceedings. The Company is involved in legal, tax and regulatory proceedings in various forums regarding performance, contracts and other matters arising in the ordinary course of business, some of which involve substantial amounts. Management believes that the final disposition of these proceedings will have no material adverse effect on the Company’s results of operations, cash flows or financial position.

The Company’s prime contractor for certain capital expansion projects claimed in a federal court lawsuit and in arbitration that it was underpaid for services provided on the projects. Numerous subcontractors also filed liens or lawsuits against the Contractor and in some cases the Company. In January 2005, all disputes were resolved and litigation between the parties was dismissed. Third party claims were also resolved in 2005 in consideration of a $24,500 thousand settlement between the Company and the Contractor.

The Company’s operating entities are involved in other legal, tax and regulatory proceedings in various forms regarding performance, contracts, royalty disputes, mismeasurement and mispayment claims (some of which are brought as class actions) and other matters arising in the ordinary course of business, some of which involve substantial amounts. Management believes that the final disposition of these proceedings will have no material adverse effect on the Company’s combined results of operations, cash flows or financial position.

Other Commitments and Contingencies. The Company enters into contracts that require payment of cash at specified periods, based on stated minimum quantities and prices. The following table summarizes the Company’s contractual cash obligations for each of the periods presented. The table below excludes all amounts classified as current liabilities on the Combined Balance Sheets:


			Less than 1						More Than 5
			Year		2-3 Years		4-5 Years		Years
	Total		(2007)		(2008 & 2009)		(2010 & 2011)		(Beyond 2011)
					(in thousands)

Long-term debt(1)	$	150,000	$	—	$	—	$	—	$	150,000
Interest on debt obligations(2)		51,390		8,565		17,130		17,130		8,565
Material/capital purchases		894		894		—		—
Right of way payments(3)		5,017		5,017

Total contractual cash obligations	$	207,301	$	14,476	$	17,130	$	17,130	$	158,565

F-32

SPECTRA ENERGY PARTNERS PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

(1) Represents future principal repayments of notes payable.

(2) Represents interest expense on notes payable, based on the stated interest rate on the notes of 5.71%.

(3) Represents capital commitments for various right of way matters.

Leases. The Company leases assets in several areas of operations. Rental expense for these leases were $54 thousand and $664 thousand in 2006 and 2005, respectively.

Future minimum rental payments under operating leases for the years 2007 through 2008 are de minimus. There are no future minimum lease payments beyond 2008.

13. Stock-Based Compensation

Duke Energy granted stock options, phantom stock and performance awards to designated employees. Spectra Energy expects to make similar grants to designated employees. The costs of these awards are identified by employee and are an expense of the subsidiary for which the employee works. The Company had employees participating in the awards. Effective January 1, 2006, Duke Energy and the Company adopted SFAS No. 123R, “Share-Based Payments,” which requires that compensation cost relating to share-based payment transactions be recognized in the financial statements. That cost is measured based on the fair value of the equity or liability instruments issued.

The Company recorded $338 thousand of expense for stock options, phantom stock and performance awards for 2006. Prior to 2006, no Company employees received any of the Duke Energy grants of such awards.

14. Employee Benefit Plans

Duke Energy U.S. Retirement Plan. Historically, the Company participated in Duke Energy’s non-contributory defined benefit retirement plan and with the separation of Spectra Energy from Duke Energy, now participates in Spectra Energy’s non-contributory defined benefit retirement plan. The plan covers most U.S. employees using a cash balance formula. Under a cash balance formula, a plan participant accumulates a retirement benefit consisting of pay credits that are based upon a percentage (which may vary with age and years of service) of current eligible earnings and current interest credits.

Duke Energy’s policy is to fund amounts on an actuarial basis to provide assets sufficient to meet benefits to be paid to plan participants. Duke Energy did not make any contributions to its defined benefit retirement plan in 2006 or 2005. Duke Energy made voluntary contributions of $250 million in 2004. Duke Energy does not anticipate making a contribution to the plan in 2007.

Actuarial gains and losses are amortized over the average remaining service period of the active employees. The average remaining service period of the active employees covered by the retirement plan is 11 years. Duke Energy determines the market-related value of plan assets using a calculated value that recognizes changes in fair value of the plan assets over five years. Duke Energy uses a September 30 measurement date for its defined benefit retirement plan.

The fair value of Duke Energy’s plan assets was $4,324 million as of September 30, 2006 and $2,948 million as of September 30, 2005. The projected benefit obligation was $4,823 million as of September 30, 2006 and $2,853 million as of September 30, 2005. The accumulated benefit obligation was $4,408 million at September 30, 2006 and $2,753 million at September 30, 2005.

The Company’s net periodic pension benefit expense for the U.S. plan, as allocated by Duke Energy, was $232.5 thousand for 2006, $159.1 thousand for 2005, and $148.6 thousand in 2004. These allocations were based on expenses; net of asset returns, as actuarially determined for the employees associated with the Company’s operating units.

F-33

SPECTRA ENERGY PARTNERS PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

Duke Energy also sponsors, and the Company participates in, an employee savings plan that covers substantially all U.S. employees. Duke Energy contributes a matching contribution equal to 100% of before-tax employee contributions, of up to 6% of eligible pay per period. Duke Energy expensed employer matching contributions of $75 million in 2006, $61 million in 2005 and $57 million in 2004. The Company’s net periodic pension benefit expense for the U.S. plan, as allocated by Duke Energy, was $374.9 thousand for 2006, $265.8 thousand for 2005, and $262.4 thousand in 2004.

Duke Energy U.S. Other Post-Retirement Benefits. The Company participates in Duke Energy’s, health care and life insurance benefit plans that provide such benefits for retired employees on a contributory and non-contributory basis. Employees are eligible for these benefits if they have met age and service requirements at retirement, as defined in the plans.

These benefit costs are accrued over an employee’s active service period to the date of full benefits eligibility. The net unrecognized transition obligation is amortized over approximately 20 years. Actuarial gains and losses are amortized over the average remaining service period of the active employees. The average remaining service period of the active employees covered by the plan is 13 years. The fair value of Duke Energy’s plan assets was $237 million as of December 31, 2006 and $242 million as of December 31, 2005. The accumulated post-retirement benefit obligation was $1,264 million as of December 31, 2006, and $791 million as of December 31, 2005. Duke Energy uses a September 30 measurement date for its other post-retirement benefit plan.

The Company’s net periodic post-retirement benefit cost, as allocated by Duke Energy, was $665.0 thousand, $511.6 thousand, and $560.8 thousand for December 31, 2006, 2005, and 2004, respectively.

F-34

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners of Spectra Energy Partners, LP
Houston, Texas

We have audited the accompanying balance sheet of Spectra Energy Partners, LP (the “Company”) as of March 26, 2007. This financial statement is the responsibility of the Company’s management. Our responsibility is to express an opinion on this financial statement based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the balance sheet is free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the balance sheet, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall balance sheet presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, such balance sheet presents fairly, in all material respects, the financial position of Spectra Energy Partners, LP as of March 26, 2007, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Houston, Texas

March 27, 2007

F-35

SPECTRA ENERGY PARTNERS, LP

NOTE TO THE BALANCE SHEET


1.	Nature of Operations

Spectra Energy Partners, LP (the Partnership) is a Delaware limited partnership formed on March 19, 2007 to acquire certain of the assets of Spectra Energy Corp (the Company), including 100% of East Tennessee Natural Gas LLC, a 50% equity method investment in Market Hub Partners Holding, LLC, and a 24.5% equity method investment in Gulfstream Natural Gas System, LLC.

The Partnership intends to offer 11,500,000 common units, representing limited partner interests, pursuant to a public offering and to concurrently issue 29,812,011 common units and 20,030,066 subordinated units, representing additional limited partner interests, to subsidiaries of the Company, as well as 1,251,879 general partner units representing an aggregate 2% general partner interest in the Partnership and its operating partnership on a consolidated basis to Spectra Energy (DE) GP, LP.

Spectra Energy (DE) GP, LP, as general partner, contributed $60 and the Company and Spectra Energy (DE) GP, LP, as the organizational limited partner, contributed $2,940 all in the form of notes receivable to the Partnership on March 19, 2007. The receivables from the Company and Spectra Energy (DE) GP, LP have been reflected as a deduction from Partners’ equity on the accompanying balance sheet. There have been no other transactions involving the Partnership as of March 26, 2007.

F-37

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners of Spectra Energy Partners (DE) GP, LP
Houston, Texas

We have audited the accompanying balance sheet of Spectra Energy Partners (DE) GP, LP (the “Company”) as of March 26, 2007. This financial statement is the responsibility of the Company’s management. Our responsibility is to express an opinion on this financial statement based on our audit.

In our opinion, such balance sheet presents fairly, in all material respects, the financial position of Spectra Energy Partners (DE) GP, LP as of March 26, 2007, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Houston, Texas

March 27, 2007

F-38

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors
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, 2006 and 2005, and the related statements of operations, members’ equity, comprehensive income, and cash flows for each of the three years in the period ended December 31, 2006. 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.

In our opinion, such financial statements present fairly, in all material respects, the financial position of Gulfstream Natural Gas Systems, L.L.C. as of December 31, 2006 and 2005, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Houston, Texas

March 27, 2007

F-41

GULFSTREAM NATURAL GAS SYSTEM, L.L.C.

STATEMENTS OF OPERATIONS


	Years Ended December 31,
	2006			2005			2004
	(In thousands)

Operating Revenues
Transportation of natural gas	$	178,768		$	140,287		$	90,411
Other		1,489			4,817			3,204

Total operating revenues		180,257			145,104			93,615

Operating Expenses
Operations and maintenance		7,234			1,542			1,750
Operations and maintenance — affiliates		7,992			7,755			7,705
Depreciation and amortization		30,406			29,190			25,354
Property and other taxes		17,847			15,060			7,839

Total operating expenses		63,479			53,547			42,648

Operating Income		116,778			91,557			50,967
Gains on Sales of Other Assets and Other, net		78			—			—
Other Income and Expenses
Allowance for funds used during construction — equity		241			1,113			3,107
Other income and expenses, net		112			670			246

Total other income and expenses		353			1,783			3,353

Interest Expense
Long-term debt		48,911			27,029			13,248
Allowance for funds used during construction — borrowed		(124	)		(1,489	)		(4,156	)

Total interest expense		48,787			25,540			9,092

Net Income	$	68,422		$	67,800		$	45,228

See notes to financial statements

F-42

GULFSTREAM NATURAL GAS SYSTEM, L.L.C.

BALANCE SHEETS


	December 31,
	2006		2005
	(In thousands)

ASSETS
Current Assets
Cash and cash equivalents	$	29,426	$	27,255
Accounts receivable		14,964		19,096
Other		2,292		2,434

Total current assets		46,682		48,785

Property, Plant and Equipment
Cost		1,719,116		1,708,436
Less accumulated depreciation and amortization		123,866		93,524

Net property, plant and equipment		1,595,250		1,614,912

Deferred Charges
Allowance for funds used during construction — gross up		22,490		22,731
Unamortized debt expense		7,878		8,278
Other		230		192

Total deferred charges		30,598		31,201

Total Assets	$	1,672,530	$	1,694,898


LIABILITIES AND MEMBERS’ EQUITY
Current Liabilities
Accounts payable	$	2,004	$	5,715
Accounts payable — affiliates		903		834
Accrued taxes		13,983		5,933
Accrued interest		8,244		8,931
Other liabilities		5,719		6,594
Fuel tracker liabilities		2,455		5,493
Other		1,345		2,160

Total current liabilities		34,653		35,660

Other Long-term Liabilities		6,160		11,441

Long-term Debt		849,571		849,534

Commitments and Contingencies
Members’ Equity
Members’ equity		766,668		781,487
Accumulated other comprehensive income		15,478		16,776

Total members’ equity		782,146		798,263

Total Liabilities and Members’ Equity	$	1,672,530	$	1,694,898

See notes to financial statements

F-43

GULFSTREAM NATURAL GAS SYSTEM, L.L.C.

STATEMENTS OF CASH FLOWS


	Years Ended December 31,
	2006			2005			2004
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	68,422		$	67,800		$	45,228
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		31,099			33,716			30,679
Allowance for funds used during construction — equity		(241	)		(1,113	)		(3,107	)
Gains on sales of assets		(78	)		—			—
Reclassification adjustments from accumulated other comprehensive income into net income		(1,298	)		(234	)		—
(Increase) decrease in
Accounts receivable		3,772			(9,698	)		420
Other current assets		(545	)		(143	)		3,575
Deferred charges		2,814			402			(642	)
Increase (decrease) in
Account payable		994			(2,066	)		102
Accrued taxes		8,050			4,861			(1,264	)
Accrued interest		(687	)		6,709			1,573
Accrued liabilities		(875	)		5,830			(172	)
Fuel tracker liabilities		(2,260	)		2,962			—
Other current liabilities		3,197			2,940			223
Long-term liabilities		(5,281	)		(108	)		2

Net cash provided by operating activities		107,083			111,858			76,617

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(21,654	)		(62,206	)		(124,057	)

Net cash used in investing activities		(21,654	)		(62,206	)		(124,057	)

CASH FLOWS FROM FINANCING ACTIVITIES
Members’ distributions		(83,000	)		(741,990	)		(56,000	)
Proceeds from the settlement of hedge instruments		—			17,010			—
Proceeds from the issuance of long-term debt		—			892,069			128,257
Payments for the redemption of long-term debt		—			(217,680	)		—
Payments for debt issuance costs		(258	)		(8,399	)		—

Net cash (used in) provided by financing activities		(83,258	)		(58,990	)		72,257

Net change in cash and cash equivalents		2,171			(9,338	)		24,817
Cash and cash equivalents at beginning of year		27,255			36,593			11,776

Cash and cash equivalents at end of year	$	29,426		$	27,255		$	36,593

Supplemental Disclosures
Cash paid for interest, net of amounts capitalized	$	49,423		$	15,794		$	6,349
Significant non-cash transactions:
Property, plant and equipment accruals		2,204			—			—
Gas imbalances payable		778			2,531			492
Allowance for funds used during construction-gross up		(241	)		274			1,431
Contribution in aid of construction		—			16,685			—
Hurricane insurance receivable		—			—			(4,783	)

See notes to financial statements

F-44

GULFSTREAM NATURAL GAS SYSTEM, L.L.C.

STATEMENTS OF MEMBERS’ EQUITY


	Spectra Energy			The Williams
	Capital, LLC			Companies			Total
	(In thousands)

Balance January 1, 2004	$	732,372		$	732,372		$	1,464,744

Members’ distributions		(28,000	)		(28,000	)		(56,000	)
Attributed deferred tax benefit		715			716			1,431
Net income		22,614			22,614			45,228

Balance December 31, 2004	$	727,701		$	727,702		$	1,455,403

Members’ distributions		(370,995	)		(370,995	)		(741,990	)
Attributed deferred tax benefit		137			137			274
Other comprehensive income		8,505			8,505			17,010
Reclassification into earnings from cash flow hedges		(117	)		(117	)		(234	)
Net income		33,900			33,900			67,800

Balance December 31, 2005	$	399,131		$	399,132		$	798,263

Members’ distributions		(41,500	)		(41,500	)		(83,000	)
Attributed deferred tax benefit		(120	)		(121	)		(241	)
Reclassification into earnings from cash flow hedges		(649	)		(649	)		(1,298	)
Net income		34,211			34,211			68,422

Balance December 31, 2006	$	391,073		$	391,073		$	782,146

See notes to financial statements

F-45

GULFSTREAM NATURAL GAS SYSTEM, L.L.C.

NOTES TO FINANCIAL STATEMENTS

For the Years Ended December 31, 2006, 2005 and 2004


1.	Nature of Operations

In June 2006, the Board of Directors of Duke Energy Corporation (Duke Energy) authorized management to pursue a plan to create two separate publicly traded companies by spinning off Duke Energy’s natural gas business to Duke Energy shareholders. The spin-off was completed on January 2, 2007 creating Spectra Energy Corp (Spectra Energy), which primarily owns the Natural Gas Transmission and Field Services segments of Spectra Energy Capital LLC (Spectra Energy Capital), formerly Duke Capital LLC. Gulfstream Natural Gas System, L.L.C. (the Company) is 50% owned by Spectra Energy.

The Company was formed on May 17, 1999 as a Delaware limited liability company.

The Company is an interstate natural gas pipeline system owned 50% by a subsidiary of Duke Energy Corporation (Duke Energy) and 50% by a subsidiary of The Williams Companies, Inc. (Williams). The Company is under the joint management of Duke Energy, which provides the business functions, and of Williams, which provides the technical functions.

In May 2002, the Company placed the Phase I facilities in service which consists of 582 miles of pipeline which originates near Pascagoula, Mississippi and Mobile, Alabama, extends in a southeasterly direction across the Gulf of Mexico into southern Tampa Bay, Florida, continues east across central Florida, turns north through Polk County and terminates in Osceola County, Florida. In February 2005, the Company placed the Phase II facilities in service, which extends the pipeline system an additional 109 miles across to eastern Florida and into Martin County, Florida.

The Company can transport up to 1.1 billion cubic feet of natural gas each day from natural gas reserves in the Mobile Bay area of the Gulf of Mexico to a variety of customers, including electric utilities, local distribution companies and municipal users in gas markets in south and central Florida. The pipeline has seven supply connection points in Mississippi and Alabama. The Company’s interstate natural gas transmission operations are subject to the rules and regulations of the Federal Energy Regulatory Commission (FERC).


2.	Summary of Significant Accounting Policies

Basis of Presentation. The financial statements reflect the financial position, results of operations, and cash flows of the Company. The financial statements do not include any of the assets, liabilities, revenues, or expenses of the members.

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

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

Accounting for Hedges. The Company entered into derivative transactions that are hedges of the future cash flows of forecasted transactions (cash flow hedges). These derivatives are recorded on the Balance Sheets at their fair value as Accumulated Other Comprehensive Income. Cash outflows and inflows related to derivative instruments are a component of operating and financing cash flows in the accompanying Statements of Cash Flows.

Qualifying non-trading derivatives may be designated as either a hedge of a forecasted transaction or future cash flows (cash flow hedge). For all hedge contracts, the Company provides formal documentation of the hedge in accordance with Statement of Financial Accounting Standards (SFAS) No. 133,

F-47

GULFSTREAM NATURAL GAS SYSTEM, L.L.C.

NOTES TO FINANCIAL STATEMENTS — (Continued)

“Accounting for Derivative Instruments and Hedging Activities.” In addition, at inception and on a monthly basis the Company formally assesses whether the hedge contract is highly effective in offsetting changes in cash flows. The Company documents hedging activity by transaction type (i.e. swaps) and risk management strategy (i.e. interest rate risk).

Cash Flow Hedges. 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. The Company discontinues hedge accounting prospectively when it has determined that a derivative no longer qualifies as an effective hedge, or when it is no longer probable that the hedged forecasted transaction will occur. When hedge accounting is discontinued because the derivative no longer qualifies as an effective hedge, the derivative is subject to the Mark-to-Market Model of Accounting (MTM Model) prospectively. Gains and losses related to discontinued hedges that were previously accumulated in AOCI will remain in AOCI until the underlying contract is reflected in earnings; unless it is probable that the hedged forecasted transaction will not occur at which time associated deferred amounts in AOCI are immediately recognized in current earnings.

Valuation. When available, quoted market prices or prices obtained through external sources are used to measure a contract’s fair value. For contracts with a delivery location or duration for which quoted market prices are not available, fair value is determined based on internally developed valuation techniques or models.

Property, Plant and Equipment. Property, plant and equipment are stated at historical cost less accumulated depreciation. The Company capitalizes all construction-related direct labor and material costs, as well as indirect construction costs. Indirect costs include administrative and general costs and the cost of funds used during construction. The cost of renewals and betterments that extend the useful life of property, plant and equipment is also capitalized. The cost of repairs, replacements and major maintenance projects, which do not extend the useful life or increase the expected output of property, plant and equipment, is expensed as it is incurred. Depreciation is generally computed over the asset’s estimated useful life using the straight-line method. The composite weighted-average depreciation rates were 1.8% for 2006, 1.9% for 2005 and 1.7% for 2004.

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

F-48

GULFSTREAM NATURAL GAS SYSTEM, L.L.C.

NOTES TO FINANCIAL STATEMENTS — (Continued)

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. The unamortized amount was $7,878 thousand and $8,278 thousand at December 31, 2006 and 2005, respectively, and is classified in Deferred Charges in the accompanying Balance Sheets.

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

Revenue Recognition. Revenues on natural gas transportation are recognized when the service is provided. From time to time, certain revenues may be subject to refund pending the outcome of rate matters before the FERC, and reserves are established where required. There were no pending rate cases and no related reserves were recorded as of December 31, 2006, or 2005. The allowances for doubtful accounts were $54 thousand, and $0 as of December 31, 2006, and December 31, 2005, respectively.

F-49

GULFSTREAM NATURAL GAS SYSTEM, L.L.C.

NOTES TO FINANCIAL STATEMENTS — (Continued)

Customer billings that are equal to or greater than 10% of revenues during the years ended December 31, 2006 and 2005 are as follows:

Customer


	December 31,
	2006			2005			2004

Florida Power & Light Company		51	%		41	%		23	%
Florida Power Corporation		22	%		23	%		29	%
TECO Energy and subsidiaries		10	%		13	%		(1	)
Calpine Energy and subsidiaries		(1	)		(1	)		15	%


(1)		Percentage below 10%

Allowance for Funds Used During Construction (AFUDC). AFUDC, which represents the estimated debt and equity costs of capital funds necessary to finance the construction of new regulated facilities, consists of two components, an equity component and an interest component. The equity component is a non-cash item. AFUDC is capitalized as a component of Property, Plant and Equipment cost, with offsetting credits to the Statements of Operations. After construction is completed, the Company is permitted to recover these costs through inclusion in the rate base and in the depreciation provision. The total amount of AFUDC included in the Statements of Operations for 2006 was $365 thousand, which consisted of an equity component of $241 thousand and an interest expense component of $124 thousand. The total amount of AFUDC included in the Statements of Operations for 2005 was $2,602 thousand, which consisted of an equity component of $1,113 thousand and an interest expense component of $1,489 thousand. The total amount of AFUDC included in the Statements of Operations for 2004 was 7,263 thousand, which consisted of an equity component of $3,107 thousand and an interest expense component of $4,156 thousand.

Income Taxes. The Company is not subject to income tax, but rather the taxable income or loss of the Company is reported on the respective income tax returns of its members. Accordingly, there is no federal tax provision in these financial statements. Since the Company is not responsible for the attributed income taxes, amounts related to the gross-up of AFUDC-Equity are carried in the individual capital accounts of the members. Deferred charges at December 31, 2006, and 2005, reflect the deferred income tax effect of the AFUDC equity gross up of $22,490 thousand and $22,731 thousand, respectively.

New Accounting Standards. The following new accounting standard has been issued, but has not yet been adopted by the Company as of December 31, 2006:

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


3.	Regulatory Matters

“In September 2005, FERC approved Gulfstream’s Cost and Revenue study that was required to be filled as a condition in its Phase I and Phase II expansion projects. Gulfstream is not anticipated to have

F-50

GULFSTREAM NATURAL GAS SYSTEM, L.L.C.

NOTES TO FINANCIAL STATEMENTS — (Continued)

further filing requirements until three years after its recently announced Phase III expansion facilities are placed into service, currently expected in 2008.”

FERC Accounting Order. In June 2005, FERC issued an Order on Accounting for Pipeline Assessment Costs that requires most pipeline inspection and integrity assessment activities to be recognized as expenses, as incurred. In the Order, FERC confirmed that pipeline betterments and replacements, including those resulting from integrity inspections, will continue to be capitalized when appropriate. This FERC Order is effective for pipeline inspection and for integrity assessment costs incurred on or subsequent to January 1, 2006, and increased annual expenses for the Company by an immaterial amount for 2006. Pipeline inspection and integrity assessment costs capitalized prior to the effective date of the rule are not impacted.


4.	Related Party Transactions

Statements of Operations


	Years Ended December 31,
	2006		2005		2004
	(In thousands)

Operation and maintenance expenses	$	7,992	$	7,755	$	7,705

Balance Sheets


	December 31,
	2006		2005
	(In thousands)

Property, plant and equipment(a)	$	2,995	$	12,066
Accounts payable		903		834


(a)		Reflects amounts billed in the annual period.

In 2005, approximately $9,622 thousand of this amount consisted of a construction fee to Gulfstream Management & Operating Services, L.L.C. (GMOS) related to the successful completion of Phase II pipeline construction. In 2006, there was not a construction fee.

GMOS, 50%-owned by an affiliate of Duke Energy and 50%-owned by an affiliate of Williams, provides management, construction and operating services pursuant to agreements entered into with the Company and with affiliates of Duke Energy and Williams. GMOS bills the Company 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 for the year as Operation and Maintenance Expenses or in the Balance Sheets as Property, Plant and Equipment, as appropriate.


5.	Gas Imbalances

The Balance Sheets include in-kind balances as a result of differences in gas volumes received and delivered for customers. Since the settlement of imbalances is in-kind, changes in the balances do not have an impact on the Company’s Statements of Cash Flows. Accounts Receivable include $1,712 thousand and $1,802 thousand as of both December 31, 2006 and 2005, respectively, and Other Current Liabilities include $1,345 thousand and $2,161 thousand, as of December 31, 2006 and 2005, respectively, related to gas imbalances. Natural gas volumes owed to (by) the Company are valued at natural gas market index prices as of the balance sheet dates.

F-51

GULFSTREAM NATURAL GAS SYSTEM, L.L.C.

NOTES TO FINANCIAL STATEMENTS — (Continued)


6.	Property, Plant and Equipment


	Estimated	December 31,
	Useful Life	2006			2005
		(In thousands)

Land	N/A	$	18,013		$	18,208
Natural gas transmission	60 years		1,642,926			1,634,239
Equipment	5-7 years		1,257			1,231
Vehicles	5 years		417			417
Construction in process	N/A		12,193			10,114
Other	5-20 years		44,310			44,227

Total property, plant and equipment			1,719,116			1,708,436
Total accumulated depreciation			(123,866	)		(93,524	)

Total net property, plant and equipment		$	1,595,250		$	1,614,912


7.	Hedging Activities, Financial Instruments and Credit Risk

Interest Rate Cash Flow Hedges. The Company was exposed to the impact of market fluctuations in interest rates. To protect the Company from increasing interest rates and the resulting higher cost of the debt that was issued in 2005, the Company made a decision to lock in existing interest rates by using financial derivatives (swaps) for hedge strategies. The total amount of the debt issued was $850,000 thousand of which $500,000 thousand was hedged. As of September 30, 2005, the Company entered into interest rate swaps totaling $500,000 thousand, all of which 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 Accumulated Other Comprehensive Income (AOCI). 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 until earnings are affected by the hedged transaction. Subsequent to the termination of the interest rate hedges, deferred gains of $15,478 thousand in AOCI as of December 31, 2006 will continue to be amortized to interest expense over the term of the new debt issued through November 1, 2015.

Financial Instruments. The Company’s financial instruments include $850,000 thousand of long-term debt with an approximate fair value of $852,492 thousand and $857,584 thousand as of December 31, 2006 and 2005, respectively. Judgment is required in interpreting market data to develop the estimates of fair value. Accordingly, the estimates determined as of December 31, 2006, and 2005, are not necessarily indicative of the amounts the Company could have realized in current markets.

Credit Risk. The Company’s principal customers for natural gas transportation are utilities located throughout the state of Florida. The Company has concentrations of receivables from utilities throughout Florida. These concentrations of customers may affect the Company’s overall credit risk in that risk factors can negatively impact the credit quality of the entire sector. Where exposed to credit risk, the Company analyzes the counterparties’ financial condition prior to entering into an agreement, establishes credit limits and monitors the appropriateness of those limits on an ongoing basis. The Company also obtains cash, letters of credit or other acceptable forms of security from customers, where appropriate, based on its financial analysis of the customer and the regulatory or contractual terms and conditions applicable to each transaction.

Long-term Debt. In October 2005, the Company entered into two fixed rate senior notes. $500,000 thousand mature on November 1, 2015, and $350,000 thousand mature on November 1, 2025. Proceeds

F-52

GULFSTREAM NATURAL GAS SYSTEM, L.L.C.

NOTES TO FINANCIAL STATEMENTS — (Continued)

from the debt issuance were used to repay the existing indebtedness and the remaining proceeds were distributed to the Company’s members.

Debt


	December 31,
	2006			2005
	(In thousands)

Note payable, 5.56%	$	500,000		$	500,000
Note payable, 6.19%		350,000			350,000
Unamortized debt discount		(429	)		(466	)
Total debt	$	849,571		$	849,534

Less current maturity		—			—

Total Long-term portion	$	849,571		$	849,534


8.	Commitments and Contingencies

General Insurance. The Company carries, through Williams, insurance consistent with companies engaged in similar commercial operations with similar type properties. The Company’s insurance coverage includes (1) excess liability insurance for liabilities arising to third parties for bodily injury and property damage resulting from the Company’s operations; and (2) automobile liability insurance for all owned, non-owned and hired vehicles covering liabilities to third parties for bodily injury and property damage. Each owner insures their 50% ownership of the Company’s property with insurance covering the replacement value of all real and personal property damage, including damages arising from machinery breakdowns, earthquake, and flood damage. The Company has onshore business interruption/extra expense insurance. All coverages are subject to certain deductibles, terms and conditions common for companies with similar types of operations.

Each owner of the Company also maintains excess liability insurance coverage for their ownership interest excess of the limits for excess liability insurance maintained by the Company. Limits, terms, conditions and deductibles are comparable to those carried by other energy companies of similar size.

The cost of the Company’s general insurance coverages continued to fluctuate over the past year reflecting the changing conditions of the insurance markets.

Environmental. The Company is subject to federal, state and local regulations regarding air and water quality, hazardous and solid waste disposal and other environmental matters. Management believes that there are no matters that will have a material adverse effect on the Company’s results of operations, cash flows or financial position.

Litigation. The Company is involved in legal, tax and regulatory proceedings in various forums, regarding performance, contracts and other matters arising in the ordinary course of business, some of which involve substantial amounts. Management believes that the final disposition of these proceedings will have no material adverse effect on consolidated results of operations, cash flows or financial position.

Contractual Obligations. The Company enters into contracts that require payment of cash at certain specified periods, based on certain specified minimum quantities and prices. The following table summarizes the Company’s contractual cash obligations for each of the periods presented. The table below excludes all amounts classified as current liabilities on the Balance Sheets, other than current maturities of long-term

F-53

GULFSTREAM NATURAL GAS SYSTEM, L.L.C.

NOTES TO FINANCIAL STATEMENTS — (Continued)

debt. It is expected that the majority of current liabilities on the Balance Sheets will be paid in cash in 2006.

Payment Due By Period


			Less than		2-3 Years		4-5 Years		More than
			1 Year		(2008 &		(2010 &		5 Years
	Total		(2007)		2009)		2011)		(Beyond 2011)
	(In thousands)

Long-term debt	$	850,000	$	—	$	—	$	—	$	850,000
Operating leases		811		419		284		108		—
Material/Capital purchases(1)		12,000		6,000		6,000		—		—

Total contractual cash obligations	$	862,811	$	6,419	$	6,284	$	108	$	850,000


(1)		The Company entered into a contract in which it will provide a $28,000 thousand contribution in aid of construction (“CIAC”), under the provisions of it’s FERC gas tariff, to a customer in six unequal installments through December 31, 2008. In return for the $28,000 thousand payment, the customer will construct a lateral that will connect to the Company’s mainline. The customer agreed to execute two consecutive Firm Transportation Service (“FTS”) contracts that will be used on the Company’s mainline system. These contracts combined began on June 1, 2005, and will extend through December 31, 2028. The Company has recorded an asset of $26,100 thousand which is included within Property, Plant and Equipment and a corresponding liability which is included in Other Current Liabilities and Long-term Liabilities on the Company’s Balance Sheets. Through December 31, 2006, the Company has paid $16,000 thousand to the customer pursuant to the contract.

F-54

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors

Market Hub Partners Holding, LLC

Houston, Texas

We have audited the accompanying consolidated balance sheets of Market Hub Partners Holding, LLC and subsidiaries (the “Company”) as of December 31, 2006 and 2005, and the related consolidated statements of operations, member’s equity, and cash flows for each of the three years in the period ended December 31, 2006. 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.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Market Hub Partners Holding, LLC and subsidiaries as of December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Houston, Texas

March 27, 2007

F-55

MARKET HUB PARTNERS HOLDING, LLC

CONSOLIDATED BALANCE SHEETS


	December 31,
	2006		2005
	(In thousands)


ASSETS
Current Assets
Accounts receivable, net of allowance for doubtful accounts	$	12,058	$	27,791
Accounts receivable — affiliates		—		132
Inventory		906		6,013
Natural gas imbalance receivables		5,957		29,073
Natural gas imbalance receivables — affiliates		39,316		79,107

Total current assets		58,237		142,116

Other Assets
Advances receivable — affiliates		94,177		—
Goodwill, net of accumulated amortization		200,497		200,497
Other assets		67		1,211

Total other assets		294,741		201,708

Property, Plant and Equipment
Cost		370,721		315,141
Less accumulated depreciation and amortization		62,523		56,331

Net property, plant and equipment		308,198		258,810

Total Assets	$	661,176	$	602,634


LIABILITIES AND MEMBER’S EQUITY
Current Liabilities
Accounts payable	$	6,034	$	714
Accounts payable — affiliates		—		516
Accrued taxes		1,309		930
Natural gas imbalance payables		43,794		108,180
Natural gas imbalance payables — affiliates		2,485		—
Collateral liabilities		3,631		2,290
Collateral liabilities — affiliates		55,000		—
Other accrued liabilities		8,019		2,272

Total current liabilities		120,272		114,902

Deferred Credits and Other Liabilities
Advances payable — affiliates		—		20,511
Other		3		4
Other — affiliates		25,000		—

Total deferred credits and other liabilities		25,003		20,515

Commitments & Contingencies
Paid-in capital		290,258		276,382
Retained earnings		225,643		190,835
Member’s Equity		515,901		467,217

Total Liabilities and Member’s Equity	$	661,176	$	602,634

See notes to consolidated financial statements

F-57

MARKET HUB PARTNERS HOLDING, LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Years Ended December 31,
	2006			2005			2004
	(In thousands)

CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	48,684		$	59,353		$	48,829
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		7,815			6,938			6,788
Gain on sale of other assets		(10,553	)		(1,136	)		(1,539	)
(Increase) decrease in:
Accounts receivable		5,812			15,728			(36,810	)
Accounts receivable — affiliates		132			578			128
Inventory		6,113			(3,137	)		(808	)
Other current assets		—			—			260
Other assets		21,608			(1,085	)		330
Increase (decrease) in:
Accounts payable		5,320			(879	)		1,593
Accounts payable — affiliates		(516	)		516			—
Accrued taxes		379			(506	)		(214	)
Collateral liabilities		1,341			491			1,799
Collateral liabilities — affiliates		55,000			—			—
Other accrued liabilities		2,638			(14,587	)		22,852
Deferred credits and other liabilities		(2	)		4			(304	)
Deferred credits and other liabilities — affiliates		25,000			—			—

Net cash provided by operating activities		168,771			62,278			42,904

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(54,083	)		(37,987	)		(17,000	)
Net increase in advances receivable — affiliates		(94,177	)		—			—
Net decrease in advances payable — affiliates		(20,511	)		(24,291	)		(28,294	)
Proceeds on sale of other assets		—			—			2,390

Net cash used in investing activities		(168,771	)		(62,278	)		(42,904	)

Net change in cash and cash equivalents		—			—			—
Cash and cash equivalents at beginning of year		—			—			—

Cash and cash equivalents at end of year	$	—		$	—		$	—

Supplemental Disclosures
Cash paid for interest, net of amounts capitalized	$	43		$	—		$	—
Significant non-cash transactions:
Gas imbalances		62,907			61,274			1,349
Property, plant and equipment accruals		4,853			1,771			1,757
Property, plant and equipment retirements		3,348			978			7,445
Interaccount property, plant and equipment transfers/reclasses		—			2,001			11,287
Intercompany property, plant and equipment transfers		—			—			6,132

See notes to consolidated financial statements

F-58

MARKET HUB PARTNERS HOLDING, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the Years Ended December 31, 2006, 2005 and 2004


1.	Nature of Operations

In June 2006, the Board of Directors of Duke Energy Corporation (Duke Energy) authorized management to pursue a plan to create two separate publicly traded companies by spinning off Duke Energy’s natural gas business to Duke Energy shareholders. The spin-off was completed on January 2, 2007 at which time Spectra Energy Corp (Spectra Energy) became a separate publicly-traded entity. Spectra Energy primarily owns the Natural Gas Transmission and Field Services segments of Spectra Energy Capital LLC (Spectra Energy Capital), formerly Duke Capital LLC. Market Hub Partners Holding, LLC (the Company) is a wholly owned subsidiary of Spectra Energy.

The Company was converted from a Delaware limited partnership to a Delaware limited liability company on December 31, 2003. The Company was wholly owned by indirect subsidiaries of Duke Energy. The Company owns and operates two natural gas storage facilities: Moss Bluff, located near Houston, Texas and Egan, located in Acadia Parish, Louisiana. These 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. The Company’s Egan facilities are subject to the rules and regulations of the Federal Energy Regulatory Commission (FERC). Moss Bluff, as a Hinshaw pipeline, must also comply with some requirements under FERC regulations.


2.	Summary of Significant Accounting Policies

Consolidation. These Consolidated Financial Statements include, after eliminating intercompany transactions and balances, the accounts of the Company and all majority - owned subsidiaries.

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

Inventory. Inventory primarily consists of natural gas held in storage and is recorded at the lower of cost or market value, primarily determined using the average cost method. An adjustment to inventory was recorded in 2006 as a result of a reconciliation between the physical and book balances of natural gas held in storage. This adjustment was recognized by reducing recorded inventory by $1,984 thousand, increasing natural gas imbalance payables by $1,006 thousand and charging a like amount to operation and maintenance.

Goodwill. The Company evaluates the impairment of goodwill related to the purchase of the Company under the guidance of Statement of Financial Accounting Standards (SFAS) No. 142, “Goodwill and Other Intangible Assets.” Under this provision, goodwill is subject to an annual test for impairment. The Company has designated August 31 as the date it performs the annual review for goodwill impairment. Impairment testing of goodwill consists of a two-step process. The first step involves a comparison of the fair value of the Company with its carrying amount. If the carrying amount of the company exceeds its fair value, the second step of the process involves a comparison of the fair value and the carrying value of the goodwill of the Company. If the carrying value of the goodwill of the Company exceeds the fair value of that goodwill, an impairment loss is recognized in an amount equal to the excess. Additional impairment tests are performed between the annual reviews; if events or changes in circumstances make it more likely than not that the fair value of the company is below its carrying amount.

F-60

MARKET HUB PARTNERS HOLDING, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Property, Plant and Equipment. Property, plant and equipment are stated at cost less accumulated depreciation. The Company capitalizes all construction-related direct labor and material costs, as well as indirect construction costs. Indirect costs include general engineering, taxes and the cost of funds used during construction. The cost of renewals and betterments that extend the useful life of property, plant and equipment is also capitalized. The cost of repairs, replacements and major maintenance projects, which do not extend the useful life or increase the expected output of property, plant and equipment, is expensed as it is incurred. Depreciation is generally computed over the asset’s estimated useful life using the straight-line method. The composite weighted-average depreciation rates were 3.00% for 2006, 3.01% for 2005 and 3.11% for 2004.

When the Company retires its regulated property, plant and equipment, it charges the original cost plus the cost of retirement, less salvage, to accumulated depreciation and amortization. When it sells entire regulated operating units, or retires or sells non-regulated properties, the cost is removed from the property account and the related accumulated depreciation and amortization accounts are reduced. Any gain or loss is recorded as income.

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

Environmental Expenditures. The Company expenses environmental expenditures related to conditions caused by past operations that do not generate current or future revenues. Environmental expenditures related to operations that generate current or future revenues are expensed or capitalized, as appropriate. Liabilities are recorded when the necessity for environmental remediation becomes probable and the costs can be reasonably estimated, or when other potential environmental liabilities are reasonably estimable and probable.

F-61

MARKET HUB PARTNERS HOLDING, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Revenue Recognition. Revenues on natural gas storage are recognized when the service is provided. There were no pending rate cases and no related reserves were recorded as of December 31, 2006 and 2005. The allowance for doubtful accounts was $0 as of both December 31, 2006, and 2005.

Customer billings that exceeded 10% of revenues during the years ended 2006, 2005 and 2004 are as follows:


	% of Consolidated Revenues
	Years Ended December 31,
Customer	2006			2005			2004

Northern Indiana Public Service Co		10.6	%		11.2	%		16.2	%

New Accounting Standards. The following new accounting standards have been issued, but have not yet been adopted by the Company as of December 31, 2006.

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


3.	Related Party Transactions

Consolidated Statements of Operations


	Years Ended December 31,
	2006		2005		2004
	(In thousands)

Storage of natural gas and other services (1)	$	308	$	3,564	$	6,787
Operation and maintenance expenses (2)		12,133		5,832		2,997


(1)		In the normal course of business, the Company provides natural gas storage and other services to affiliates.

(2)		Includes reimbursement of costs incurred by affiliates on behalf of the Company and allocations from Spectra Capital 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 the Company’s percentage of assets, employees, earnings, or other measures, as compared to other affiliates.

Consolidated Balance Sheets


	December 31,
	2006		2005
	(In thousands)

Accounts receivable	$	—	$	132
Natural gas imbalance receivables		39,316		79,107
Accounts payable		—		516
Natural gas imbalance payables		2,485		—
Collateral liabilities		55,000		—
Other		25,000		—

F-62

MARKET HUB PARTNERS HOLDING, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Advances receivable and payable-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 operations and capital expenditures of the Company.

During 2006 in accordance with the Company’s credit policies, the Company received an $80,000 thousand security deposit from an affiliate, associated with natural gas imbalance receivables from the affiliate. The Company is required to pay a market rate of interest on the security deposit. Of the $80,000 thousand balance, $55,000 thousand is classified as a current liability with $25,000 thousand classified as long term since it relates to a contract position that is not expected to be repaid until April 2008.


4.	Gas Imbalances

The Consolidated Balance Sheets include in-kind balances as a result of differences in gas volumes received and delivered for customers. Since the settlement of imbalances is in-kind, changes in the balances do not have an impact on the Company’s Consolidated Statements of Cash Flows. Natural gas volumes owed to (by) the Company are valued at natural gas market index prices as of the balance sheet dates.


5.	Property, Plant and Equipment

Net Property, Plant and Equipment


	Estimated	December 31,
	Useful Life	2006			2005
		(In thousands)

Land	N/A	$	12,415		$	12,415
Salt Cavern Storage facilities	15-40 years		312,787			272,082

Equipment	10-40 years		221			217
Vehicles	5 years		115			133

Constructions in process	N/A		42,583			28,179
Other	5 years		2,600			2,115
Total property, plant and equipment			370,721			315,141
Total accumulated depreciation			(62,523	)		(56,331	)
Total net property, plant and equipment		$	308,198		$	258,810


6.	Credit Risk

Credit Risk. The Company markets high deliverability natural gas storage services and hub services to pipelines, local distribution companies, producers, end-users, power generators, and energy marketers. The Company has concentrations of receivables from these industries throughout these regions. These concentrations of customers may affect the Company’s overall credit risk in that risk factors can negatively impact the credit quality of the entire sector. Where exposed to credit risk, the Company analyzes the counterparties’ financial condition prior to entering into an agreement, establishes credit limits and monitors the appropriateness of those limits on an ongoing basis. The Company also obtains cash, letters of credit or other acceptable forms of security from customers, where appropriate, based on its financial analysis of the customer and the regulatory or contractual terms and conditions applicable to each transaction.


7.	Commitments and Contingencies

General Insurance. The Company carries, through a Duke Energy Affiliate, insurance and reinsurance coverages consistent with companies engaged in similar commercial operations with similar type properties.

F-63

MARKET HUB PARTNERS HOLDING, LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The Company’s insurance coverage includes (1) commercial general public liability insurance for liabilities arising to third parties for bodily injury and property damage resulting from the Company’s operations; (2) workers’ compensation liability coverage to required statutory limits; (3) automobile liability insurance for all owned, non-owned and hired vehicles covering liabilities to third parties for bodily injury and property damage, (4) financial services insurance policies in support of the indemnification provisions of the Company’s by-laws and (5) property insurance covering the replacement value of all real and personal property damage, including damages arising from machinery breakdowns, earthquake, flood damage and business interruption/extra expense. All coverages are subject to certain deductibles, terms and conditions common for companies with similar types of operations.

The Company also maintains, through an affiliate, excess liability insurance coverage above the established primary limits for commercial general liability and automobile liability insurance. Limits, terms, conditions and deductibles are comparable to those carried by other energy companies of similar size. The cost of the Company’s general insurance coverages continued to fluctuate over the past year reflecting the changing conditions of the insurance markets.

Litigation. The Company is involved in legal, tax and regulatory proceedings in various forums regarding performance, contracts and other matters arising in the ordinary course of business, some of which involve substantial amounts. Management believes that the final disposition of these proceedings will have no material adverse effect on the Company’s consolidated results of operations, cash flows or financial position.

Leases. The Company leases assets in several areas of operations. Rental expense for these leases, including amounts allocated from Duke Energy affiliates, was $377 thousand for 2006, $311 thousand for 2005 and $35 thousand for 2004.

F-64

Appendix B

APPLICATION FOR TRANSFER OF COMMON UNITS

Transferees of Common Units must execute and deliver this application to SPECTRA ENERGY PARTNERS, LP, c/o Spectra Energy Partners GP, LP, 5400 Westheimer Ct., Houston, TX 77056; Attn: CFO, to be admitted as limited partners to SPECTRA ENERGY PARTNERS, LP.

The undersigned (“Assignee”) hereby applies for transfer to the name of the Assignee of the Common Units evidenced hereby and hereby certifies to SPECTRA ENERGY PARTNERS, LP (the “Partnership”) that the Assignee (including to the best of Assignee’s knowledge, any person for whom the Assignee will hold the Common Units) is an Eligible Holder.*(

The Assignee (a) requests admission as a Substituted Limited Partner and agrees to comply with and be bound by, and hereby executes, the Amended and Restated Agreement of Limited Partnership of the Partnership, as amended, supplemented or restated to the date hereof (the “Partnership Agreement”), (b) represents and warrants that the Assignee has all right, power and authority and, if an individual, the capacity necessary to enter into the Partnership Agreement, (c) appoints the General Partner of the Partnership and, if a Liquidator shall be appointed, the Liquidator of the Partnership as the Assignee’s attorney-in-fact to execute, swear to, acknowledge and file any document, including, without limitation, the Partnership Agreement and any amendment thereto and the Certificate of Limited Partnership of the Partnership and any amendment thereto, necessary or appropriate for the Assignee’s admission as a Substituted Limited Partner and as a party to the Partnership Agreement, (d) gives the powers of attorney provided for in the Partnership Agreement, and (e) makes the waivers and gives the consents and approvals contained in the Partnership Agreement. Capitalized terms not defined herein have the meanings assigned to such terms in the Partnership Agreement. This application constitutes a Taxation Certification, as defined in the Partnership Agreement.

Date:

Social Security or other identifying number of Assignee

Signature of Assignee

Purchase Price including commissions, if any Name and Address of Assignee

Type of Entity (check one):

o Individual o Partnership o Corporation

o Trust o Other (specify)

( * The Term “Eligible Holder” means (a) an individual or entity subject to United States federal income taxation on the income generated by the Partnership; or (b) an entity not subject to United States federal income taxation on the income generated by the Partnership, so long as all of the entity’s owners are subject to United States federal income taxation on the income generated by the Partnership. Individuals or entities are subject to taxation, in the context of defining an Eligible Holder, to the extent they are taxable on the items of income and gain allocated by the Partnership or would be taxable on the items of income and gain allocated by the Partnership if they had no offsetting deductions or tax credits unrelated to the ownership of the Common Units. Schedule I hereto contains a list of various types of investors that are categorized and identified as either “Eligible Holders” or “Non-Eligible Holders.”

B-1

If not an Individual (check one):

o the entity is subject to United States federal income taxation on the income generated by the Partnership;

o the entity is not subject to United States federal income taxation, but it is a pass-through entity and all of its beneficial owners are subject to United States federal income taxation on the income generated by the Partnership; the entity is not subject to United States federal income taxation and it is (a) not a pass-through entity or (b) a pass-through entity, but not all of its beneficial owners are subject to United States federal income taxation on the income generated by the Partnership. Important Note — by checking this box, the Assignee is contradicting its certification that it is an Eligible Holder.

Nationality (check one):

o U.S. Citizen, Resident or Domestic Entity o Non-resident Alien

o Foreign Corporation

If the U.S. Citizen, Resident or Domestic Entity box is checked, the following certification must be completed.

Under Section 1445(e) of the Internal Revenue Code of 1986, as amended (the “Code”), the Partnership must withhold tax with respect to certain transfers of property if a holder of an interest in the Partnership is a foreign person. To inform the Partnership that no withholding is required with respect to the undersigned interestholder’s interest in it, the undersigned hereby certifies the following (or, if applicable, certifies the following on behalf of the interestholder).

Complete Either A or B:

A. Individual Interestholder

1. I am not a non-resident alien for purposes of U.S. income taxation.

2. My U.S. taxpayer identification number (Social Security Number) is .

3. My home address is .

B. Partnership, Corporation or Other Interestholder

1. The interestholder is not a foreign corporation, foreign partnership, foreign trust or foreign estate (as those terms are defined in the Code and Treasury Regulations).

2. The interestholder’s U.S. employer identification number is .

3. The interestholder’s office address and place of incorporation (if applicable) is .

The interestholder agrees to notify the Partnership within sixty (60) days of the date the interestholder becomes a foreign person.

The interestholder understands that this certificate may be disclosed to the Internal Revenue Service and the Federal Energy Regulatory Commission by the Partnership and that any false statement contained herein could be punishable by fine, imprisonment or both.

B-2

Under penalties of perjury, I declare that I have examined this certification and, to the best of my knowledge and belief, it is true, correct and complete and, if applicable, I further declare that I have authority to sign this document on behalf of:

Name of Interestholder

Signature and Date

Title (if applicable)

Note: If the Assignee is a broker, dealer, bank, trust company, clearing corporation, other nominee holder or an agent of any of the foregoing, and is holding for the account of any other person, this application should be completed by an officer thereof or, in the case of a broker or dealer, by a registered representative who is a member of a registered national securities exchange or a member of the National Association of Securities Dealers, Inc., or, in the case of any other nominee holder, a person performing a similar function. If the Assignee is a broker, dealer, bank, trust company, clearing corporation, other nominee owner or an agent of any of the foregoing, the above certification as to any person for whom the Assignee will hold the Common Units shall be made to the best of the Assignee’s knowledge.

B-3

SCHEDULE I

Eligible Holders

The following are considered Eligible Holders:


	•	Individuals (U.S. or non-U.S.)

	•	C corporations (U.S. or non-U.S.)

	•	Tax exempt organizations subject to tax on unrelated business taxable income or “UBTI,” including IRAs, 401(k) plans and Keough accounts

	•	S corporations with shareholders that are individuals, trusts or tax exempt organizations subject to tax on UBTI

Potentially Eligible Holders


	•	S corporations (unless they have ESOP shareholders*()

	•	Partnerships (unless its partners include mutual funds, real estate investment trusts or “REITs,” governmental entities and agencies, S corporations with ESOP shareholders* or other partnerships with such partners)

	•	Trusts (unless beneficiaries are not subject to tax)

Non-Eligible Holders

The following are not considered Eligible Holders:


	•	Mutual Funds

	•	REITs

	•	Governmental entities and agencies

	•	S corporations with ESOP shareholders*

( * “S corporations with ESOP shareholders” are S corporations with shareholders that include employee stock ownership plans.

B-4

Appendix C

CERTIFICATION FORM FOR NON-INDIVIDUAL INVESTORS

As described in this Prospectus, only Eligible Holders (as defined on Schedule I hereto) may purchase common units in the Partnership’s proposed public offering (the “Offering”). In order to comply with this requirement, all potential investors that are not natural persons, including institutions, partnerships and trusts (“Non-individual Investors”), must complete this Certification Form.


	•	If you have an institutional sales account with Citigroup Global Markets Inc. and Lehman Brothers Inc., you should fax signed forms to by 5:00 pm Eastern time on, , 2007 (the “Return Date”).

	•	If you have any other type of brokerage account with any of the broker-dealers on page 2, you should fax signed forms to your retail broker or financial advisor upon initial indication of interest.

Non-individual Investors who do not complete and return this form by the
Return Date will not be allocated units in this offering.

1. Acknowledgement and Consent to Forward this Certification Form. The undersigned Non-individual Investor acknowledges and understands that an underwriter who receives this Certification Form may forward it to the Partnership and/or the transfer agent for the Common Units. Accordingly, the undersigned hereby grants its consent for Citigroup Global Markets Inc. or Lehman Brothers Inc. or any underwriter or affiliate thereof listed on page 2 to forward this Certification Form to the Partnership and/or the transfer agent for the Common Units.

2. Acknowledgement of Obligation to Complete a Transfer Application. The undersigned Non-individual Investor further acknowledges that, if it purchases Common Units in the Offering, it must complete a Transfer Application in the form included as Appendix A to the Prospectus and deliver it to the address as instructed on the Transfer Application. The undersigned Non-individual Investor further acknowledges that no underwriter or affiliate of an underwriter has any responsibility or obligation to complete or deliver a Transfer Application on behalf of the undersigned.

3. Certification as to Tax Status. The undersigned Non-individual Investor hereby certifies that it is either (check one):

o an entity that is subject to United States federal income taxation on the income generated by the Partnership; or

o an entity that is not subject to United States federal income taxation, but is a pass-through entity and all of its beneficial owners are subject to United States federal income taxation on the income generated by the Partnership.

Signing this form shall not obligate the undersigned Non-individual Investor to provide or share any tax-related information with the Partnership, the transfer agent or any underwriter in connection with the purchase and sale of common units in the Offering.

Executed this day of , 2007.

(Name of Entity)


	By:

Name:


	Title:

NON-INDIVIDUAL INVESTOR RETAIL BROKER DEALERS

Smith Barney, a division of Citigroup Global Markets Inc.

Lehman Brothers Private Wealth Management

C-1

SCHEDULE I

An “Eligible Holder” is (a) an individual or entity subject to United States federal income taxation on the income generated by the Partnership or (b) an entity not subject to United States federal income taxation on the income generated by the Partnership, so long as all of the entity’s owners are subject to United States federal income taxation on the income generated by the Partnership or would be taxable on the items of income and gain allocated by the Partnership if they had no offsetting deductions or tax credits unrelated to the ownership of the Common Units. Set forth below is a list of various types of investors that are categorized and identified as Eligible Holders , Potentially Eligible Holders or Non-Eligible Holders.

Eligible Holders

The following are considered Eligible Holders:


	•	Individuals (U.S. or non-U.S.)

	•	C corporations (U.S. or non-U.S.)

	•	Tax exempt organizations subject to tax on unrelated business taxable income or “UBTI,” including IRAs, 401(k) plans and Keough accounts

	•	S corporations with shareholders that are individuals, trusts or tax exempt organizations subject to tax on UBTI

Potentially Eligible Holders

The following are considered Eligible Holders, unless the bracketed information applies:


	•	Partnerships (unless its partners include mutual funds, real estate investment trusts or “REITs,” governmental entities and agencies, S corporations with ESOP shareholders ¹ ( or other partnerships with such partners)

	•	Trusts (unless beneficiaries are not subject to tax)

Non-Eligible Holders

The following are not considered Eligible Holders:


	•	Mutual Funds

	•	REITs

	•	Governmental entities and agencies

	•	S corporations with ESOP shareholders ³

( ¹ “S corporations with ESOP shareholders” are S corporations with shareholders that include employee stock ownership plans.

C-2

Appendix D

GLOSSARY OF TERMS

Adjusted Operating Surplus: For any period, operating surplus generated during that period is adjusted to:

(a) increase operating surplus by any net decreases made in subsequent periods in cash reserves for operating expenditures initially established with respect to such period;

(b) decrease operating surplus by any net decrease in cash reserves for operating expenditures with respect to that period not relating to an operating expenditure made with respect to that period; and

(c) increase operating surplus by any net increase in cash reserves for operating expenditures with respect to that period required by any debt instrument for the repayment of principal, interest or premium.

Adjusted operating surplus does not include the portion of operating surplus described in subpart (a)(2) of the definition of “operating surplus” in this Appendix D.

Available Cash: For any quarter ending prior to liquidation:

(a) the sum of:

(1) all cash and cash equivalents of Spectra Energy Partners, LP and its 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 Spectra Energy Partners, LP and its 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 Spectra Energy Partners, LP and its subsidiaries (including reserves for future capital expenditures and for future credit needs of Spectra Energy Partners, LP and its subsidiaries) after that quarter;

(2) comply with applicable law or any debt instrument or other agreement or obligation to which Spectra Energy Partners, LP or any of its subsidiaries is a part or its 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.

Bcf: One billion cubic feet of natural gas.

Bcf/d: One billion cubic feet per day.

Btu: British Thermal Units.

Capital Account: The capital account maintained for a partner under the partnership agreement. The capital account of a partner for a common unit, a Class B unit, a subordinated unit, an incentive distribution right or any other partnership interest will be the amount which that capital account would be if that common unit, a Class B unit, subordinated unit, incentive distribution right or other partnership interest were the only interest in Spectra Energy Partners, LP held by a partner.

D-1

Capital Surplus: All available cash distributed by us on any date from any source will be treated as distributed from operating surplus until the sum of all available cash distributed since the closing of the initial public offering equals the operating surplus from the closing of the initial public offering through the end of the quarter immediately preceding that distribution. Any excess available cash distributed by us on that date will be deemed to be capital surplus.

Closing Price: The last sale price on a day, regular way, or in case no sale takes place on that day, the average of the closing bid and asked prices on that day, regular way, in either case, as reported in the principal consolidated transaction reporting system for securities listed or admitted to trading on the principal national securities exchange on which the units of that class are listed or admitted to trading. If the units of that class are not listed or admitted to trading on any national securities exchange, the last quoted price on that day. If no quoted price exists, the average of the high bid and low asked prices on that day in the over-the-counter market, as reported by the New York Stock Exchange or any other system then in use. If on any day the units of that class are not quoted by any organization of that type, the average of the closing bid and asked prices on that day as furnished by a professional market maker making a market in the units of the class selected by the our board of directors. If on that day no market maker is making a market in the units of that class, the fair value of the units on that day as determined reasonably and in good faith by our board of directors.

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.

Current Market Price: For any class of units listed or admitted to trading on any national securities exchange as of any date, the average of the daily closing prices for the 20 consecutive trading days immediately prior to that date.

Eligible Holders: Individuals or entities either (a) subject to United States federal income taxation on the income generated by us or (b) in the case of entities that are pass-through entities for United States federal income taxation, all of whose beneficial owners are subject to United States federal income taxation on the income generated by us.

GAAP: Generally accepted accounting principles in the United States.

Greenfield Construction: The construction of an asset or system in an area where no previous facilities existed.

Interim Capital Transactions: The following transactions if they occur prior to liquidation:

(a) borrowings, refinancings or refundings of indebtedness and sales of debt securities (other than for items purchased on open account in the ordinary course of business) by Spectra Energy Partners, LP or any of its subsidiaries;

(b) sales of equity interests and debt securities of Spectra Energy Partners, LP or any of its subsidiaries;

(c) sales or other voluntary or involuntary dispositions of any assets of Spectra Energy Partners, LP or any of its subsidiaries (other than sales or other dispositions of inventory, accounts receivable and other assets in the ordinary course of business, and sales or other dispositions of assets as a part of normal retirements or replacements);

(d) the termination of interest rate swap agreements or commodity hedge contracts prior to the termination date specified therein;

(e) capital contributions; and

(f) corporate reorganizations or restructurings.

Local Distribution Company or LDC: LDCs are companies involved in the delivery of natural gas to consumers within a specific geographic area.

D-2

Mcf: One thousand cubic feet of natural gas. We have converted each of the throughput numbers from a heating value number to a volumetric number based upon the following conversion factor: 1 MMBtu = 1 Mcf.

MMBtu: One million British thermal units which is roughly equivalent to one Mcf.

MMcf: One million cubic feet of natural gas.

MMBtu/d: One million British Thermal Units per day.

MMcf/d: One million cubic feet per day.

Operating Expenditures: All of our expenditures and expenditures of our subsidiaries, including, but not limited to, taxes, payments to our general partner reimbursements of expenses incurred by our 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 will not constitute operating expenditures.

(b) Operating expenditures will 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 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 Spectra Energy Partners, LP 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 two times the amount needed for any one quarter for us to pay a distribution on all units (including general partner units) and incentive distribution rights at the same per-unit amount as was distributed in the immediately preceding quarter; 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 that is established by our general partner to provide funds for future operating expenditures; provided however, that disbursements made (including contributions to Spectra Energy Partners LP or our subsidiaries or disbursements on behalf of Spectra Energy Partners, LP 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.

Peak Day: The highest level of throughput transported through a pipeline system on any given day.

D-3

Subordination Period: The subordination period will extend from the closing of the initial public offering 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 $0.488 per quarter (150% of the minimum quarterly distribution of $0.325 per quarter, which is $1.95 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 volume of natural gas transported or passing through a pipeline, plant, terminal or other facility in an economically meaningful period of time.

Working Gas: Natural gas storage capacity that can be used for system operations or is available to be sold to the market as firm or interruptible storage capacity or as the storage component of no notice service.

D-4

PART II

INFORMATION NOT REQUIRED IN THE PROSPECTUS


Item 13.	*Other Expenses of Issuance and Distribution.*

Set forth below are the expenses expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the Securities and Exchange Commission registration fee, the NASD filing fee and the New York Stock Exchange listing fee, the amounts set forth below are estimates.


SEC registration fee	$	8,526
NASD filing fee		28,273
New York Stock Exchange listing fee		250,000
Printing and engraving expenses		*
Accounting fees and expenses		*
Legal fees and expenses		*
Transfer agent and registrar fees		*
Subscription Agent fees		*
Information Agent fees		*
Standby Commitment fees		*
Miscellaneous		*

Total	$	6,000,000


*		To be filed by amendment.


Item 14.	*Indemnification of Directors and Officers.*

The section of the prospectus entitled “The Partnership Agreement — Indemnification” is incorporated herein by this reference. Reference is also made to the Underwriting Agreement filed as Exhibit 1.1 to this registration statement. Subject to any terms, conditions or restrictions set forth in the partnership agreement, Section 17-108 of the Delaware Revised Uniform Limited Partnership Act empowers a Delaware limited partnership to indemnify and hold harmless any partner or other person from and against all claims and demands whatsoever.


Item 15.	*Recent Sales of Unregistered Securities.*

On March 19, 2007, in connection with the formation of Spectra Energy Partners, LP (the “Partnership”), the Partnership issued to (i) Spectra Energy Partners (DE) GP, LP the 2% general partner interest in the Partnership for $60 and (ii) Spectra Energy Transmission, LLC the 98% limited partner interest in the Partnership for $2,940. The issuance was exempt from registration under Section 4(2) of the Securities Act. There have been no other sales of unregistered securities within the past three years.


Item 16.	*Exhibits and Financial Statement Schedules.*

(a) The following documents are filed as exhibits to this registration statement:


Exhibit
Number			Description

	1	.1*	Form of Underwriting Agreement
	3	.1	Certificate of Limited Partnership of Spectra Energy Partners, LP
	3	.2*	Form of First Amended and Restated Agreement of Limited Partnership of Spectra Energy Partners, LP (included as Appendix A to the Prospectus)
	3	.3	Certificate of Limited Partnership of Spectra Energy Partners (DE) GP, LP
	3	.4*	Form of Amended and Restated Agreement of Limited Partnership of Spectra Energy Partners (DE) GP, LP

II-1


Exhibit
Number			Description

	3	.5	Certificate of Formation of Spectra Energy Partners GP, LLC
	3	.6*	Form of Amended and Restated Limited Liability Company Agreement of Spectra Energy Partners GP, LLC
	5	.1*	Opinion of Vinson & Elkins L.L.P. as to the legality of the securities being registered
	8	.1*	Opinion of Vinson & Elkins L.L.P. relating to tax matters
	10	.1*	Form of Credit Agreement
	10	.2*	Form of Contribution, Conveyance and Assumption Agreement
	10	.3*	Form of Omnibus Agreement
	10	.5*	Form of Long Term Incentive Plan of Spectra Energy Partners, LP
	10	.6*	Second Amended and Restated Limited Liability Company Agreement of Gulfstream Natural Gas System, L.L.C.
	10	.7*	Amended and Restated Limited Liability Company Agreement of Market Hub Partners Holding, LLC
	10	.6*	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
	10	.7*	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
	21	.1*	List of subsidiaries of Spectra Energy Partners, LP
	23	.1	Consent of Deloitte & Touche LLP
	23	.2	Consent of Deloitte & Touche LLP
	23	.3	Consent of Deloitte & Touche LLP
	23	.4*	Consent of Vinson & Elkins L.L.P. (contained in Exhibit 5.1)
	23	.5*	Consent of Vinson & Elkins L.L.P. (contained in Exhibit 8.1)
	24	.1	Powers of Attorney (included on the signature page)


*		To be filed by amendment.

(b) Financial Statement Schedules

SPECTRA ENERGY PARTNERS PREDECESSOR

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS AND RESERVES


			Additions
	Balance at				Charged to					Balance at
	Beginning of		Charged to		Other		Deductions			End of
	Period		Expense		Accounts		(a)			Period
	(In thousands)

December 31, 2006:
Allowance for doubtful accounts	$	274	$	19	$	—	$	(52	)	$	241
Litigation reserves		—		—		—		—			—

	$	274	$	19	$	—	$	(52	)	$	241

December 31, 2005:
Allowance for doubtful accounts	$	208	$	170	$	—	$	(104	)	$	274
Litigation reserves		20,000		—		4,500		(24,500	)		—

	$	20,208	$	170	$	4,500	$	(24,604	)	$	274

December 31, 2004:
Allowance for doubtful accounts	$	208	$	—	$	—	$	—		$	208
Litigation reserves		—		—		20,000		—			20,000

	$	208	$	1,737	$	20,000	$	—		$	20,208

II-2


(a)		Principally cash payments and reserve reversals


Item 17.	*Undertakings.*

The undersigned registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction of the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

The undersigned registrant hereby undertakes that:

(1) For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.

(2) For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

The registrant undertakes to send to each limited partner at least on an annual basis a detailed statement of any transactions with Spectra Energy Partners GP, LLC or its affiliates, and of fees, commissions, compensation and other benefits paid, or accrued to Spectra Energy Partners GP, LLC or its affiliates for the fiscal year completed, showing the amount paid or accrued to each recipient and the services performed.

The registrant undertakes to provide to the limited partners the financial statements required by Form 10-K for the first full fiscal year of operations of the partnership.

II-3

SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, as amended, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, State of Texas, on March 30, 2007.

SPECTRA ENERGY PARTNERS, LP


	By:	SPECTRA ENERGY PARTNERS (DE) GP, LP, its General Partner


	By:	SPECTRA ENERGY PARTNERS GP, LLC, its General Partner


	By:	/s/ C. Gregory Harper

C. Gregory Harper
President and Chief Executive Officer

Each person whose signature appears below appoints C. Gregory Harper and Lon C. Mitchell, Jr. and each of them, any of whom may act without the joinder of the other, as the undersigned’s true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for the undersigned and in the undersigned’s name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this Registration Statement and any Registration Statement (including any amendment thereto) for this offering that is to be effective upon filing pursuant to Rule 462(b) under the Securities Act of 1933 and to file the same, with all exhibits thereto, and all other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as the undersigned might or would do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them of their or the undersigned’s substitute and substitutes, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Act of 1933, as amended, this Registration Statement has been signed below by the following persons in the capacities and on March 30, 2007.


Signature				Title

/s/ C. Gregory Harper C. Gregory Harper				Chief Executive Officer (Principal Executive Officer)

/s/ Lon C. Mitchell, Jr. Lon C. Mitchell, Jr.				Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)

/s/ Martha B. Wyrsch Martha B. Wyrsch				Chairman of the Board

II-4

EXHIBIT INDEX


Exhibit
Number			Description

	1	.1*	Form of Underwriting Agreement
	3	.1	Certificate of Limited Partnership of Spectra Energy Partners, LP
	3	.2*	Form of First Amended and Restated Agreement of Limited Partnership of Spectra Energy Partners, LP (included as Appendix A to the Prospectus)
	3	.3	Certificate of Limited Partnership of Spectra Energy Partners (DE) GP, LP
	3	.4*	Form of Amended and Restated Agreement of Limited Partnership of Spectra Energy Partners (DE) GP, LP
	3	.5	Certificate of Formation of Spectra Energy Partners GP, LLC
	3	.6*	Form of Amended and Restated Limited Liability Company Agreement of Spectra Energy Partners GP, LLC
	5	.1*	Opinion of Vinson & Elkins L.L.P. as to the legality of the securities being registered
	8	.1*	Opinion of Vinson & Elkins L.L.P. relating to tax matters
	10	.1*	Form of Credit Agreement
	10	.2*	Form of Contribution, Conveyance and Assumption Agreement
	10	.3*	Form of Omnibus Agreement
	10	.5*	Form of Long Term Incentive Plan of Spectra Energy Partners, LP
	10	.6*	Second Amended and Restated Limited Liability Company Agreement of Gulfstream Natural Gas System, L.L.C.
	10	.7*	Amended and Restated Limited Liability Company Agreement of Market Hub Partners Holding, LLC
	10	.6*	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
	10	.7*	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
	21	.1*	List of subsidiaries of Spectra Energy Partners, LP
	23	.1	Consent of Deloitte & Touche LLP
	23	.2	Consent of Deloitte & Touche LLP
	23	.3	Consent of Deloitte & Touche LLP
	23	.4*	Consent of Vinson & Elkins L.L.P. (contained in Exhibit 5.1)
	23	.5*	Consent of Vinson & Elkins L.L.P. (contained in Exhibit 8.1)
	24	.1	Powers of Attorney (included on the signature page)


*		To be filed by amendment.


SUMMARY			1
Spectra Energy Partners, LP			1
Our Relationship with Spectra Energy			4
Summary of Risk Factors			5
Formation Transactions and Partnership Structure			7
Management of Spectra Energy Parners, LP			7
Organizational Structure and Ownership			8
Principal Executive Offices and Internet Address			9
Summary of Conflicts of Interest and Fiduciary Duties			9
The Offering			10
Summary Historical and Pro Forma Financial and Operating Data			15
Non-GAAP Financial Measures			18
RISK FACTORS			22
Risks Related to Our Business			22
Risks Inherent in an Investment in Us			34
Tax Risks to Common Unitholders			42
USE OF PROCEEDS			45
CAPITALIZATION			46
DILUTION			47
OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS			49
General			49
Our Initial Distribution Rate			50
Unaudited Pro Forma Cash Available for Distribution for the Year Ended December 31, 2006			52
Minimum Estimated Cash Available for Distribution for the Twelve-Month Period Ending June 30, 2008			56
Assumptions and Considerations			60
PROVISIONS OF OUR PARTNERSHIP AGREEMENT RELATING TO CASH DISTRIBUTIONS			65
Distributions of Available Cash			65
Operating Surplus and Capital Surplus			66
Subordination Period			67
Distributions of Available Cash from Operating Surplus during the Subordination Period			68
Distributions of Available Cash from Operating Surplus after the Subordination Period			69
General Partner Interest and Incentive Distribution Rights			69
Percentage Allocations of Available Cash from Operating Surplus			70
General Partner’s Right to Reset Incentive Distribution Levels			70
Distributions from Capital Surplus			72
Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels			73
Distributions of Cash Upon Liquidation			74
SELECTED HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA			76
Non-GAAP Financial Measures			79
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			83
Overview			83
Factors that Impact our Business			83
How We Evaluate Our Operations			84
Results of Operations			87


Future Trends and Outlook			91
Liquidity and Capital Resources			92
Off Balance Sheet Arrangements			94
Capital Requirements			94
Quantitative and Qualitative Disclosures About Market Risk			96
Critical Accounting Policies and Estimates			97
New Accounting Standards			98
BUSINESS			99
Business Strategies			100
Competitive Strengths			101
Our Relationship with Spectra Energy			103
Natural Gas Industry Overview			103
Our Asset Portfolio			107
Safety and Maintenance			114
Regulation			116
Seasonality			119
Environmental Regulation			119
Title to Properties and Rights-of-Way			122
Insurance			122
Facilities			122
Employees			123
Legal Proceedings			123
MANAGEMENT			124
Management of Spectra Energy Partners, LP			124
Directors and Executive Officers			125
Reimbursement of Expenses of Our General Partner			125
Executive Compensation			126
Compensation Discussion and Analysis			126
Compensation of Directors			127
Long-Term Incentive Plan			128
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT			130
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS			131
Distributions and Payments to Our General Partner and its Affiliates			131
Agreements Governing the Transactions			132
Omnibus Agreement			132
Contracts with Affiliates			133
CONFLICTS OF INTEREST AND FIDUCIARY DUTIES			135
Conflicts of Interest			135
Fiduciary Duties			140
DESCRIPTION OF THE COMMON UNITS			143
The Units			143
Transfer Agent and Registrar			143
Transfer of Common Units			143
THE PARTNERSHIP AGREEMENT			145
Organization and Duration			145
Purpose			145


Power of Attorney			145
Cash Distributions			145
Capital Contributions			145
Voting Rights			146
Limited Liability			147
Issuance of Additional Securities			148
Amendment of the Partnership Agreement			148
Merger, Consolidation, Conversion, Sale or Other Disposition of Assets			150
Termination and Dissolution			151
Liquidation and Distribution of Proceeds			151
Withdrawal or Removal of the General Partner			152
Transfer of General Partner Units			153
Transfer of Ownership Interests in the General Partner			153
Transfer of Incentive Distribution Rights			153
Change of Management Provisions			153
Limited Call Right			154
Non-Taxpaying Assignees; Redemption			154
Meetings; Voting			155
Status as Limited Partner			156
Non-Citizen Assignees; Redemption			156
Indemnification			156
Reimbursement of Expenses			156
Books and Reports			157
Right to Inspect Our Books and Records			157
Registration Rights			157
UNITS ELIGIBLE FOR FUTURE SALE			158
MATERIAL TAX CONSEQUENCES			159
Partnership Status			159
Limited Partner Status			160
Tax Consequences of Unit Ownership			161
Tax Treatment of Operations			166
Disposition of Common Units			167
Uniformity of Units			169
Tax-Exempt Organizations and Other Investors			170
Administrative Matters			170
State, Local, Foreign and Other Tax Considerations			172
SELLING UNITHOLDER			174
INVESTMENT IN SPECTRA ENERGY PARTNERS, LP BY EMPLOYEE BENEFIT PLANS			175
UNDERWRITING			176
VALIDITY OF THE COMMON UNITS			179
EXPERTS			179
WHERE YOU CAN FIND MORE INFORMATION			179
FORWARD-LOOKING STATEMENTS			180


Public Common Units	18.4	%
Spectra Energy Common and Subordinated Units	79.6	%
General Partner Units	2.0	%

Total	100.0	%


		as of December 31, 2006, after giving effect to the application of the net proceeds of this offering is as follows:


SPECTRA ENERGY PARTNERS, LP UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS:
Introduction			F-2
Unaudited Pro Forma Combined Statement of Operations for the year ended December 31, 2006			F-3
Unaudited Pro Forma Combined Balance Sheet as of December 31, 2006			F-4
Notes to the Unaudited Pro Forma Combined Financial Statements			F-6

SPECTRA ENERGY PARTNERS PREDECESSOR COMBINED FINANCIAL STATEMENTS:
Report of Independent Registered Public Accounting Firm			F-9
Combined Statements of Operations for the years ended December 31, 2006, 2005, and 2004			F-10
Combined Balance Sheets as of December 31, 2006 and 2005			F-11
Combined Statements of Cash Flows for the years ended December 31, 2006, 2005, and 2004			F-12
Combined Statements of Parent Net Equity and Comprehensive Income for the years ended December 31, 2006, 2005, and 2004			F-13
Notes to Combined Financial Statements			F-14

SPECTRA ENERGY PARTNERS, LP FINANCIAL STATEMENTS:
Report of Independent Registered Public Accounting Firm			F-35
Balance Sheet as of March 26, 2007			F-36
Note to the Balance Sheet			F-37

SPECTRA ENERGY PARTNERS (DE) GP, LP FINANCIAL STATEMENTS:
Report of Independent Registered Public Accounting Firm			F-38
Balance Sheet as of March 26, 2007			F-39
Note to the Balance Sheet			F-40

GULFSTREAM NATURAL GAS SYSTEM, L.L.C. FINANCIAL STATEMENTS:
Report of Independent Registered Public Accounting Firm			F-41
Statements of Operations for the years ended December 31, 2006, 2005 and 2004			F-42
Balance Sheets as of December 31, 2006 and 2005			F-43
Statements of Cash Flows for the years ended December 31, 2006, 2005 and 2004			F-44
Statements of Members’ Equity for the years ended December 31, 2006, 2005, and 2004			F-45
Statements of Comprehensive Income			F-46
Notes to Financial Statements			F-47

MARKET HUB PARTNERS HOLDING, LLC CONSOLIDATED FINANCIAL STATEMENTS:
Report of Independent Registered Public Accounting Firm			F-55
Consolidated Statements of Operations for the years ended December 31, 2006, 2005, and 2004			F-56
Consolidated Balance Sheets as of December 31, 2006 and 2005			F-57
Consolidated Statements of Cash Flows for the years ended December 31, 2006, 2005, and 2004			F-58
Consolidated Statements of Member’s Equity for the years ended December 31, 2006, 2005, and 2004			F-59
Notes to Consolidated Financial Statements			F-60


ASSETS

Total assets	$	—


PARTNERS’ EQUITY
Partners’ Equity
Limited partners’ equity	$	2,940
General partner’s equity		60
Less receivables from Spectra Energy Corp and Spectra Energy Partners (DE) GP, LP		(3,000	)

Total liabilities and partners’ equity	$	—


		Spectra Energy Partners (DE) GP, LP, its General Partner

		By:		Spectra Energy Partners GP, LLC, its General Partner

		By:		Spectra Energy Transmission, LLC, its sole member

		By:		/s/ C. Gregory Harper

				C. Gregory Harper Authorized Person


		Spectra Energy Partners GP, LLC, its General Partner

		By:		Spectra Energy Transmission, LLC, its sole member

		By:		/s/ C. Gregory Harper

				C. Gregory Harper Authorized Person