Edgar Filing: Spectra Energy Partners, LP

Form 10-k for fiscal year ended December 31, 2011

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

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

SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2011

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number 001-33556

SPECTRA ENERGY PARTNERS, LP

(Exact name of registrant as specified in its charter)


Delaware		41-2232463
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

5400 Westheimer Court, Houston, Texas		77056
(Address of principal executive offices)		(Zip Code)

713-627-5400

(Registrant’s telephone number, including area code)

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


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

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

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

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨

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

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


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

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

Estimated aggregate market value of the Common Units held by non-affiliates of the registrant at June 30, 2011: $1,123,000,000.

At January 31, 2012, there were 96,348,795 Common Units and 1,966,303 General Partner Units outstanding.

SPECTRA ENERGY PARTNERS, LP

FORM 10-K FOR THE YEAR ENDED

DECEMBER 31, 2011

TABLE OF CONTENTS


Item		Page
	PART I.
1.	Business		4
	General		4
	Initial Public Offering		4
	Acquisitions		4
	Gas Transportation and Storage		5
	East Tennessee		5
	Saltville		6
	Ozark		6
	Big Sandy		7
	Gulfstream		10
	Market Hub		11
	Revenue Contract Summary		13
	Supplies and Raw Materials		13
	Regulations		13
	Environmental Matters		14
	Employees		15
	Glossary		15
	Additional Information		16
1A.	Risk Factors		17
1B.	Unresolved Staff Comments		35
2.	Properties		35
3.	Legal Proceedings		35
4.	Mine Safety Disclosures		35
	PART II.
5.	Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities		36
6.	Selected Financial Data		38
7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		40
7A.	Quantitative and Qualitative Disclosures About Market Risk		59
8.	Financial Statements and Supplementary Data		60
9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		88
9A.	Controls and Procedures		88
9B.	Other Information		89
	PART III.
10.	Directors, Executive Officers and Corporate Governance		90
11.	Executive Compensation		95
12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters		112
13.	Certain Relationships and Related Transactions, and Director Independence		113
14.	Principal Accounting Fees and Services		117
	PART IV.
15.	Exhibits, Financial Statement Schedules		118
Signatures			119
Exhibit Index

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

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

•

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

•

outcomes of litigation and regulatory investigations, proceedings or inquiries;

•

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

•

the timing and extent of changes in interest rates;

•

general economic conditions, including the risk of a prolonged economic slowdown or decline, or the risk of delay in a recovery, which can affect the long-term demand for natural gas and related services;

•

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

•

changes in environmental, safety and other laws and regulations;

•

the development of alternative energy resources;

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

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

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

PART I

Item 1. Business.

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

General

Spectra Energy Partners, LP, through its subsidiaries and equity affiliates, is engaged in the transportation and gathering of natural gas through interstate pipeline systems with over 3,200 miles of pipelines that serve the southeastern quadrant of the United States and the storage of natural gas in underground facilities with aggregate working gas storage capacity of approximately 57 billion cubic feet (Bcf) that are located in southeast Texas, south central Louisiana and southwest Virginia. We are a Delaware master limited partnership (MLP) formed on March 19, 2007. Our common units are listed on the New York Stock Exchange (NYSE) under the symbol “SEP.” Our internet website is http://www.spectraenergypartners.com.

We transport, gather and store natural gas for a broad mix of customers, including local gas distribution companies (LDC), municipal utilities, interstate and intrastate pipelines, direct industrial users, electric power generators, marketers and producers, and exploration and production companies. In addition to serving the directly connected southeastern quadrant of the United States, our pipeline, storage and gathering systems have access to customers in the mid-Atlantic, northeastern and midwestern regions of the United States through numerous interconnections with major pipelines. Our interstate gas transmission pipeline and storage operations are regulated by the Federal Energy Regulatory Commission (FERC) with the exception of Moss Bluff intrastate storage operations and the Ozark gathering facilities which are subject to oversight by various state commissions.

Our wholly owned operations and activities are managed by our general partner, Spectra Energy Partners (DE) GP, LP, which in turn is managed by its general partner, Spectra Energy Partners GP, LLC, (the General Partner). The General Partner is wholly owned by a subsidiary of Spectra Energy Corp (Spectra Energy). Spectra Energy is a separate, publicly traded entity which trades on the NYSE under the symbol “SE.” As of December 31, 2011, Spectra Energy and its subsidiaries collectively owned 64% of us and the remaining 36% was publicly owned.

Initial Public Offering

On July 2, 2007, immediately prior to the closing of our initial public offering (IPO) of 11.5 million common units, Spectra Energy contributed to us 100% of the ownership of East Tennessee Natural Gas, LLC (East Tennessee), 50% of the ownership of Market Hub Partners Holding (Market Hub) and a 24.5% interest in Gulfstream Natural Gas System, L.L.C. (Gulfstream). Spectra Energy indirectly owned 100% of us prior to the closing of the IPO.

Acquisitions

In 2008, we completed the acquisition of the equity interests of Saltville Gas Storage Company L.L.C. (Saltville) and the P-25 pipeline from a wholly owned subsidiary of Spectra Energy at a purchase price of $107.0 million, which included the issuance of 4.2 million common units and 0.1 million general partner units, and a cash payment of $4.7 million to Spectra Energy.

In 2009, we acquired all of the ownership interests of NOARK Pipeline System, Limited Partnership (NOARK) from Atlas Pipeline Partners, L.P. (Atlas) for approximately $294.5 million in cash. NOARK’s assets

consist of 100% ownership interests of Ozark Gas Transmission, L.L.C. (Ozark Gas Transmission) and Ozark Gas Gathering, L.L.C. (Ozark Gas Gathering) (collectively referred to as Ozark). This transaction was partially refinanced in 2009 through a sale of 9.8 million common units.

In 2010, we acquired an additional 24.5% interest in Gulfstream from a wholly owned subsidiary of Spectra Energy for the aggregate consideration of $330.0 million, consisting of $66.0 million of newly issued units, the assumption of approximately $7.4 million in debt owed to a subsidiary of Spectra Energy and a cash payment of $256.6 million to Spectra Energy. Following the acquisition, we own a 49% interest in Gulfstream.

On July 1, 2011, we completed the acquisition of Big Sandy Pipeline, LLC (Big Sandy) from EQT Corporation (EQT) for approximately $390 million in cash. Big Sandy’s primary asset is a 68-mile FERC-regulated natural gas pipeline system in eastern Kentucky with capacity of approximately 0.2 Bcf per day (Bcf/d). The Big Sandy natural gas pipeline system connects Appalachian and Huron Shale natural gas supplies to markets in the mid-Atlantic and northeast portions of the United States. EQT, a natural gas production and midstream business, is the main shipper on the pipeline, with over 80% of the pipeline’s capacity. With 100% fee-based revenues and a weighted average contract life of 14 years, the acquisition of Big Sandy strengthens our portfolio of fee-based natural gas assets and is consistent with our strategy of growth through third-party acquisitions.

For financial information on our acquisitions, see Item 8. Financial Statements and Supplementary Data, Note 3 of Notes to Consolidated Financial Statements.

Gas Transportation and Storage

Our sole segment, Gas Transportation and Storage, includes East Tennessee, Saltville, Ozark and Big Sandy. Gas Transportation and Storage provides interstate transportation, storage, fee-based gathering of natural gas, and storage and regasification of liquefied natural gas (LNG) for customers in the southeastern quadrant of the United States. These operations are mainly subject to the FERC’s and the Department of Transportation’s (DOT’s) rules and regulations.

General

East Tennessee

LOGO

We own and operate 100% of the 1,517-mile East Tennessee interstate natural gas transportation system, which extends from central Tennessee eastward into southwest Virginia and northern North Carolina, and southward into northern Georgia. East Tennessee supports the energy demands of the southeast and mid-Atlantic regions of the United States through connections to 33 receipt points and 179 delivery points and has market delivery capability of approximately 1.7 Bcf/d of natural gas. East Tennessee also owns and operates a LNG storage facility in Kingsport, Tennessee with a working gas storage capacity of 1.1 Bcf and regasification capability of 150 million cubic feet per day (MMcf/d).

On September 1, 2011, we placed into service the Northeastern Tennessee (NET) project. This project provides 150,000 dekatherms per day (Dth/d) of gas service to an electric generation plant in Hawkins County, Tennessee.

Saltville

We own and operate 100% of the Saltville natural gas storage facilities which consist of 5.4 Bcf of total storage capacity. The storage facilities interconnect with the East Tennessee system in southwest Virginia and offer high deliverability salt cavern and reservoir storage capabilities that are strategically located near markets in Tennessee, Virginia and North Carolina.

Ozark

LOGO

We own and operate 100% of the 565-mile Ozark Gas Transmission interstate natural gas transportation system, which extends from southeastern Oklahoma through Arkansas to southeastern Missouri. This system has connections to 53 receipt points and 28 delivery points and market delivery capability of approximately 0.5 Bcf/d of natural gas. We also own and operate 100% of the 365-mile Ozark Gas Gathering system that accesses the Fayetteville Shale and Arkoma natural gas production that feeds into Ozark Gas Transmission.

Big Sandy

LOGO

We own and operate 100% of the 68 mile Big Sandy pipeline system located in Carter, Floyd, Johnson, and Lawrence counties, of Kentucky. This system serves local producers and transports East Kentucky supply from its main receipt point to its main interconnecting delivery point for transportation to downstream markets. EQT is the main shipper on the pipeline, with over 80% of the pipeline’s capacity. The system has capacity of approximately 0.2 Bcf/d of natural gas.

Customers and Contracts

Gas Transportation and Storage’s customers include LDCs, utilities, municipalities, interstate and intrastate pipelines, industrial companies, natural gas marketers and producers, electric power generators, and exploration and production companies. Gas Transportation and Storage’s largest customer in 2011 was EQT, a natural gas production and midstream company, which accounted for 12% of its revenues. For 2012, we anticipate Tennessee Valley Authority to be one of the segment’s largest customers.

Gas Transportation and Storage has contracts with its customers to provide firm transportation and storage services as well as fee-based gathering services. Payments under firm transportation and storage services are based mainly on the volume of capacity reserved on the system regardless of the capacity actually used, and also include a variable charge based on the volume of natural gas actually transported. As a result, firm transportation revenues typically remain relatively constant over the term of the contracts. Fee-based gathering service contracts, which represent less than 4% of Gas Transportation and Storage operating revenues in 2011, include variable charges based on the volume of natural gas actually gathered and the number of compression stages needed to deliver the gathered gas. Maximum and minimum rates for firm transportation and storage services are governed by the applicable FERC-approved natural gas tariff while fee-based gathering services are governed by the applicable state oil and gas commissions.

Gas Transportation and Storage also provides interruptible transportation and storage services under which gas is transported or stored for customers when operationally feasible and customers pay only for the actual volume of gas transported or stored. Under all contracts, except for those on Big Sandy, Gas Transportation and Storage retains, at no cost, a fixed percentage of the natural gas it transports in order to supply the fuel needed for natural gas compression on the system. For Big Sandy, all compression is powered by electric drivers and all power costs are paid by the shippers.

As of December 31, 2011, East Tennessee and Saltville firm transportation and storage contracts had a weighted average remaining life of approximately nine years and Big Sandy’s contracts had a weighted average remaining life of approximately 14 years. Ozark, excluding gathering contracts, had a weighted average remaining life of approximately three years. In 2011, 97% of East Tennessee and Saltville, 93% of Big Sandy, and 80% of Ozark Gas Transmission’s revenues were derived from capacity reservation charges under firm contracts (including LNG storage services), with the remainder representing variable usage fees under firm and interruptible transportation contracts.

East Tennessee currently operates under the tariff rates approved by the FERC in November 2005.

In 2008, Saltville placed into effect new rates approved by the FERC as a result of a settlement with customers associated with a rate proceeding. This settlement included a rate moratorium until October 1, 2011. Following expiration of the moratorium, Saltville’s rates remain the same, subject to further negotiation or a future rate proceeding. Also pursuant to the settlement, Saltville is required to file a rate case by October 1, 2013.

Ozark Gas Transmission operates under rates established as a result of an uncontested settlement agreement with customers approved by the FERC in 2000. In 2011, Ozark Gas Transmission filed a Cost and Revenue Study as a result of a FERC rate proceeding. A settlement agreement in the 2011 rate proceeding was approved by the FERC on October 1, 2011 and had no impact on results of operations, financial position, or cash flows.

Big Sandy operates under rates approved by the FERC in 2006. That order required Big Sandy to file a Cost and Revenue Study within three years after its in-service date. Big Sandy filed the Cost and Revenue Study on April 8, 2011. The Cost and Revenue Study was accepted by the FERC for filing on October 26, 2011. There was no change to the currently effective rates and the rates will remain in effect subject to further negotiations or a future rate proceeding.

Source of Supply

Gas supply attachments are a critical factor for Gas Transportation and Storage customers. Its customers benefit from gas supply from the Gulf Coast region through Tennessee Gas Pipeline Company, Texas Eastern Transmission, L.P. (Texas Eastern, a subsidiary of Spectra Energy), Southern Natural Gas Company, Columbia Gulf Transmission Company and Midwestern Gas Pipeline System. Gas Transportation and Storage customers also receive natural gas supply from conventional and non-conventional sources such as Appalachian Shale, Huron Shale, and coal-bed methane, as well as from Fayetteville Shale and Arkoma supply basins. Natural gas

withdrawn from East Tennessee’s LNG storage facility and other on-system storage fields, including Saltville’s natural gas storage facilities, provide customers with additional supply sources used to supplement supplies during periods of peak demand.

Competition

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

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

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

The Ozark assets compete with CenterPoint Energy Gas Transmission Company, Texas Gas Transmission, LLC’s Fayetteville Lateral, which went into service in 2009, and the Fayetteville Express Pipeline LLC, which went into service in the latter half of 2010.

Big Sandy indirectly serves the mid-Atlantic and northeast markets and competes for supply from the Huron Shale with NiSource’s Columbia Gas Transmission system.

Gulfstream

General

LOGO

We own a 49% interest in the 745-mile Gulfstream interstate natural gas transportation system which extends from Pascagoula, Mississippi and Mobile, Alabama across the Gulf of Mexico and into Florida. The Gulfstream pipeline currently includes approximately 279 miles of onshore pipeline in Florida, 12 miles of onshore pipeline in Alabama and Mississippi, and 454 miles of offshore pipeline in the Gulf of Mexico. Facilities also include gas treatment facilities and a compressor station in Coden, Alabama. Gulfstream supports the south and central Florida markets through its connection to nine receipt points and 23 delivery points and has market delivery capability of 1.29 Bcf/d of natural gas. The Phase V compression project was placed in service April 1, 2011. Spectra Energy and affiliates of The Williams Companies, Inc. (Williams) own the remaining 1% and 50% interests in Gulfstream, respectively, and jointly operate the system.

Customers, Contracts and Supply

In 2011, Florida Power & Light Company and Florida Power Corporation d/b/a Progress Energy Florida, Inc. accounted for approximately 53% and 28%, respectively, of Gulfstream’s revenues.

Gulfstream provides firm and interruptible transportation services, interruptible park and loan services, and operational balancing agreements to resolve any differences between scheduled and actual receipts and deliveries. All of Gulfstream’s firm transportation contracts include negotiated rates through the life of the contract.

As of December 31, 2011, Gulfstream’s firm transportation and storage contracts had a weighted average remaining life of 18 years. In 2011, 97% of Gulfstream’s revenues were derived from capacity reservation charges under firm contracts, with the remainder derived from variable usage fees under firm and interruptible transportation contracts.

Gulfstream is connected to processing plants and supply pipelines in the Mobile Bay area. Gulfstream shippers have the ability to source supply through nine receipt points. The abundant supplies interconnected directly or indirectly to Gulfstream provide supply diversity to Gulfstream’s customers, potentially offsetting some of the risks associated with offshore Gulf of Mexico natural gas production.

Competition

Gulfstream’s most direct competitor is Florida Gas Transmission Company, LLC, owned by subsidiaries of El Paso Corporation and Southern Union Company. Within the Florida market, Gulfstream competes with other pipelines that transport and supply natural gas to the end-user. 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.

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

Market Hub

General

LOGO

We own a 50% interest in Market Hub, which owns and operates two high-deliverability salt cavern natural gas storage facilities — the Egan and Moss Bluff facilities. These storage facilities are capable of being fully or partially filled and depleted, or “cycled,” multiple times per year. As a result of numerous interconnections with major pipelines, Market Hub’s storage facilities offer convenient service for Gulf of Mexico natural gas supplies, onshore Texas and Louisiana supplies, mid-continent production, non-conventional (shale and tight-sands) onshore production, and imports of LNG to the Gulf Coast. Spectra Energy owns the remaining 50% interest in Market Hub and operates the system.

The Egan storage facility, located in Acadia Parish, Louisiana, has four storage caverns with a working gas capacity of approximately 29 Bcf, and includes a 58-mile pipeline system that interconnects with eight interstate pipeline systems, including Texas Eastern. Egan offers access to Gulf Coast, midwest, southeast and northeast markets and is regulated by FERC. Egan has undergone a multi-year expansion program, which added approximately 8 Bcf of storage capacity and 16 miles of pipeline extensions. The final phase of the project was placed in commercial service in the second quarter of 2011.

The Moss Bluff storage facility, located in Liberty County, Texas, has four storage caverns with a working gas capacity of approximately 22 Bcf, and includes a 22-mile pipeline system that interconnects with two interstate pipeline systems, including Texas Eastern, and three intrastate pipeline systems. Moss Bluff offers access to Texas, northeast and midwest markets. Due to a FERC exemption, Moss Bluff is subject to the oversight of the Railroad Commission of Texas (RRC) as opposed to FERC regulation. The Cavern 4 multi-year project was placed in commercial service in the second quarter of 2011 and increased working capacity by 6.5 Bcf as well as upgrading top-side facilities and expanding pipeline interconnects.

Customer, Contracts and Supply

Market Hub provides storage services to a broad mix of customers including marketers, electric power generators, gas producers, pipelines and LDCs. In 2011, there were no customers that accounted for more than 10% of Market Hub’s revenues.

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

As of December 31, 2011, Market Hub’s firm storage contracts had a weighted average remaining life of approximately two years, which is typical of the shorter contract life of market-based storage facilities as compared to transportation systems. Approximately 89% of Market Hub’s revenues in 2011 were derived from capacity reservation fees under firm storage contracts and 10% from interruptible storage contracts including park and loan services.

Egan has aggregate receipt capacity from major interconnecting pipelines of approximately 4.3 Bcf/d and an injection capability of 1.3 Bcf/d. Moss Bluff has aggregate receipt capacity from major interconnecting pipelines of approximately 2.3 Bcf/d and an injection capability of 0.6 Bcf/d. Egan has access to major interstate pipelines, while Moss Bluff has access to major interstate and intrastate pipelines. This level of supply connectivity gives customers access to a broad range of natural gas supply sources from existing onshore and offshore Gulf Coast and mid-Continent production areas as well as LNG supplies.

Competition

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

Revenue Contract Summary

As noted previously, we provide a significant portion of our transportation and storage services through firm contracts and derive a smaller portion of our revenue through interruptible contracts, seeking to maximize the portion of physical capacity sold under firm contracts. To the extent physical capacity that is contracted for firm service is not being fully utilized, we have the option to contract such capacity for interruptible service. Our gathering services, representing less than 4% of Gas Transportation and Storage operating revenues, are fee-based and dependent upon the volume of natural gas gathered. The table below summarizes certain information regarding our contracts and revenues as of and for the year ended December 31, 2011:


	Revenue Composition %												Weighted Average Remaining Firm Contract Life (in years)(a)
	Firm Contracts						Interruptible Contracts			Volume- based Fees
Asset	Capacity Reservation Fees			Variable Fees			Interruptible Contracts			Volume- based Fees
East Tennessee		98	%		1	%		1	%		—	%		10
Ozark
Transmission		80			18			2			—			3
Gathering		—			—			—			100			n/a
Big Sandy		93			7			—			—			14
Saltville		92			7			1			—			6
Gulfstream		97			2			1			—			18
Market Hub		89			1			10			—			2

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

n/a	Indicates not applicable.

Supplies and Raw Materials

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

We utilize Spectra Energy’s supply chain management function which operates a North American supply chain management network. The supply chain management group uses the economies-of-scale of Spectra Energy to maximize the efficiency of supply networks where applicable.

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

Regulations

Our interstate gas transmission pipeline and storage operations are regulated by the FERC with the exception of Moss Bluff intrastate storage operations and the Ozark gathering facilities. The FERC regulates natural gas transportation in U.S. interstate commerce including the establishment of recourse rates for services. The FERC also regulates the construction of U.S. interstate pipelines and storage facilities, including the extension, enlargement and abandonment of facilities. The Moss Bluff intrastate storage operations are subject to oversight by the RRC. Our Ozark gathering operations are subject to oversight by the Arkansas Public Service Commission and Oklahoma Corporation Commission.

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

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

Under current policy, the FERC permits pipelines and storage companies to include a tax allowance in the cost-of-service used as the basis for calculating their regulated rates. For pipelines and storage companies owned by partnerships or limited liability company interests, the tax allowance will reflect the actual or potential income tax liability on the FERC jurisdictional income attributable to all partnership or limited liability company interests if the ultimate owner of the interest has an actual or potential income tax liability on such income. This policy was upheld on May 29, 2007 by the Court of Appeals for the District of Columbia Circuit. Whether the owners of a pipeline or storage company have such actual or potential income tax liability will be reviewed by the FERC on a case-by-case basis. In a future rate case, the pipelines and storage companies in which we own an interest may be required to demonstrate the extent to which inclusion of an income tax allowance in the applicable cost-of-service is permitted under the current income tax allowance policy. Egan and Moss Bluff have authority to charge market-based rates and therefore this tax allowance issue does not affect the rates that they charge their customers.

Environmental Matters

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

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

•

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

•

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

•

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

•

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

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

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

Employees

We do not have any employees. We are managed by the directors and officers of our general partner. Our general partner or its affiliates currently employ 115 people who spend a majority of their time operating the East Tennessee, Ozark, Big Sandy and Saltville facilities, and 5 people who are primarily dedicated to us. Market Hub is operated by Spectra Energy pursuant to an operating and maintenance agreement and the employees who operate the Market Hub assets are therefore not included in the above numbers. Gulfstream is jointly operated by Spectra Energy (with respect to business functions) and Williams (with respect to technical functions) pursuant to an operating and maintenance agreement, and therefore, the employees who operate the Gulfstream assets are also not included in the above numbers.

Glossary

Terms used to describe our business are defined below.

Available Cash. For any quarter ending prior to liquidation:

(a) the sum of:

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

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

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

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

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

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

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

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

(a) the sum of:

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

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

(b) the sum of:

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

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

Additional Information

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

Item 1A. Risk Factors.

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

Risks Related to our Business

We may not have sufficient cash from operations to enable us to make cash distributions to common unitholders.

In order to make cash distributions at our minimum distribution rate of $0.30 per common unit per quarter, or $1.20 per unit per year, we will require Available Cash of approximately $29 million per quarter, or $116 million per year, depending on the actual number of common units outstanding. We may not have sufficient Available Cash from operating surplus each quarter to enable us to make cash distributions at the minimum distribution rate. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from operations, which will fluctuate based on, among other things:

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

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the overall demand for natural gas in the southeastern, mid-Continent 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;

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

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changes in environmental, safety and other laws and regulations;

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

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

In addition, the actual amount of Available Cash will depend on other factors, some of which are beyond our control, including:

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the level of capital expenditures to complete construction projects;

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the cost and form of payment of acquisitions;

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debt service requirements and other liabilities;

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fluctuations in working capital needs;

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the ability to borrow funds and access capital markets;

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restrictions on distributions contained in debt agreements; and

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the amount of cash reserves established by our general partner.

Our subsidiaries and equity affiliates conduct operations and own our operating assets, which may affect our ability to make distributions to our unitholders. In addition, we cannot control the amount of cash that will be received from Gulfstream and Market Hub, and we may be required to contribute significant cash to fund their operations.

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 these subsidiaries and equity investments and their ability to

distribute funds to us. The ability of our subsidiaries and equity investments 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.

Market Hub and Gulfstream generated approximately 60% of the cash available for distribution in 2011. Spectra Energy operates Market Hub and the operation of Gulfstream is shared between Spectra Energy and Williams. Accordingly, we do not control the amount of cash distributed to us nor do we control ongoing operational decisions, including the incurrence of capital expenditures that we may be required to fund.

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

Our natural gas pipeline systems and certain of our storage facilities and related assets are subject to regulation by the FERC, which could have an adverse effect on our ability to establish transportation, storage and gathering rates that would allow us to recover the full cost of operating our pipelines, including a reasonable return, and our ability to make distributions.

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

Action by the FERC on currently pending regulatory matters as well as matters arising in the future could adversely affect our ability to establish or charge rates that would cover future increase in their costs, such as additional costs related to environmental matters including any climate change regulation, or even to continue to collect rates that cover current costs, including a reasonable return. We cannot assure unitholders that our pipeline systems will be able to recover all of their costs through existing or future rates.

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

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

Under the FERC policy, a regulated service provider and a customer may mutually agree to sign a contract for service at a “negotiated rate” which may be above or below the FERC-regulated “recourse rate” for that service. For 2011, 70% of Gas Transportation and Storage’s and Gulfstream’s firm revenues were derived from such negotiated rate contracts. These negotiated rate contracts are not subject to adjustment for increased costs which could be produced by inflation or other factors relating to the specific facilities being used to perform the services. It is possible that Gulfstream’s, East Tennessee’s, Ozark’s, Big Sandy’s and Saltville’s costs to perform services under these negotiated rate contracts will exceed the negotiated rates. If this occurs, it could decrease cash flows from Gulfstream and Gas Transportation and Storage.

Market Hub’s right to charge “market-based rates” at its Egan storage facility 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.

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

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

We compete primarily with other interstate and intrastate pipelines, storage and gathering facilities in the transportation, storage and gathering of natural gas. Some of these competitors may expand or construct transportation, storage and gathering 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, storage and gathering assets are rates, terms of service, access to natural gas supplies, flexibility and reliability. The FERC’s policies promoting competition in natural gas markets are having the effect of increasing the natural gas transportation, storage and gathering options for our traditional customer base. As a result, we could experience some “turnback” of firm capacity as existing agreements expire. If East Tennessee, Ozark, Big Sandy, Saltville, Gulfstream or Market Hub are unable to remarket this capacity or can remarket it only at substantially discounted rates compared to previous contracts, they may have to bear the costs associated with the turned back capacity. Increased competition could reduce the volumes of natural gas transported, stored or gathered by our systems or, in cases where we do not have long-term fixed rate contracts, could force us to lower our transportation, storage or gathering rates. Competition could intensify the negative effect of factors that significantly decrease demand for natural gas in the markets served by our pipeline systems, such as competing or alternative forms of energy, a recession or other adverse economic conditions, 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 an adverse effect on our business, results of operations, financial condition or cash flows, including our ability to make distributions.

Any significant decrease in supplies of natural gas connected to our areas of operation could adversely affect business, financial results and reduce Available Cash.

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

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

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

Our primary exposure to market risk occurs at the time existing transportation, storage and gathering contracts expire and are subject to renegotiation and renewal. A portion of the revenue generated by our systems in 2011 is attributable to firm capacity reservation fees that are set to expire on or prior to December 31, 2014. For Gas Transportation and Storage and Market Hub, those portions were 17% and 67%, respectively, and none for Gulfstream. 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:

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

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the growth in demand for natural gas in our markets;

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

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whether our business strategy continues to be successful; and

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the effects of state regulation on customer contracting practices.

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

We have market-based rates for some of our storage operations and sell our storage services based on natural gas market spreads and volatility. Natural gas storage prices have recently been challenged as a result of increasing natural gas supply and narrower seasonal price spreads. Gas supply and demand dynamics continue to change as a result of the development of new unconventional shale gas supplies. In the near term, these market factors will continue to keep downward pressure on storage values.

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

We rely on a limited number of customers for a significant portion of revenues. For the year ended December 31, 2011, the three largest customers for Gas Transportation and Storage were EQT Corporation, Atmos Energy Corporation and CNX Gas Company, LLC; for Gulfstream were Florida Power & Light Company, Florida Power Corporation d/b/a Progress Energy Florida, Inc. and TECO Energy and its affiliates; and for Market Hub were AGL Resources Inc., EDF Trading North America, LLC and Northern Indiana Public Service. In 2011, these customers accounted for approximately 29%, 88% and 26% of the operating revenues for Gas Transportation and Storage, Gulfstream and Market Hub, respectively. While most of these customers are subject to long-term contracts, the loss of all or even a portion of the contracted volumes of these customers as a result of competition, creditworthiness, inability to negotiate extensions or replacements of contracts or otherwise, could have an adverse effect on our results of operations, financial condition or cash flows, including our ability to make distributions.

If third-party pipelines and other facilities interconnected to our pipelines become unavailable to transport natural gas, our revenues and Available Cash could be adversely affected.

We depend upon third-party pipelines and other facilities that provide delivery options to and from our pipelines and storage facilities. Because we do not own these third-party pipelines or facilities, their continuing

operation is not within our control. If these or any other pipeline connection were to become unavailable for current or future volumes of natural gas due to repairs, damage to the facility, lack of capacity or any other reason, our ability to operate efficiently and continue shipping natural gas to end-markets could be restricted, thereby reducing revenues. Any temporary or permanent interruption at any key pipeline interconnect could have an adverse effect on our business, results of operations, financial condition or cash flows, including our ability to make distributions.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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customer losses at the acquired business.

As a result, our new facilities may not achieve expected investment returns, which could adversely affect our results of operations, financial position or cash flows. If any expansion projects or acquisitions that we ultimately complete are not accretive to cash available for distribution, our ability to make distributions may be reduced.

Significant prolonged changes in natural gas prices could affect supply and demand, reducing contracted volumes on our systems and adversely affecting revenues and Available Cash 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 contracted volumes on our systems. Also, lower natural gas prices over the long term could result in a decline in production of natural gas resulting in reduced contracted volumes on our system. In addition, prolonged reduced price volatility could reduce the revenues generated by our storage services. As a result, significant prolonged changes in natural gas prices could have an adverse effect on our results of operations, financial condition or cash flows, including our ability to make distributions.

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

Our natural gas transportation, storage and gathering activities are subject to stringent and complex federal, state and local environmental laws and regulations. We may incur substantial costs in order to conduct our operations in compliance with these laws and regulations. Moreover, new and 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 noncompliance, with environmental laws and regulations or for personal injury or property damage that may result from environmental and other effects of operations. We may not be able to recover some or any of these costs through insurance or increased revenues, which may have an adverse effect on our business, results of operations, financial condition or cash flows, including our ability to make cash distributions.

The enactment of future climate change legislation could result in increased operating costs and delays in obtaining necessary permits for our capital projects.

The current international climate framework, the United Nations-sponsored Kyoto Protocol, prescribes specific targets to reduce greenhouse gas (GHG) emissions for developed countries for the 2008-2012 period. The Kyoto Protocol expires in 2012 and has not been signed by the United States. United Nations-sponsored international negotiations were held in Durban, South Africa in December 2011 with the intent of defining a future agreement for 2012 and beyond. A non-binding agreement was reached to develop a roadmap aimed at creating a global agreement on climate action to be implemented by 2020.

In the United States, climate change action is evolving at state, regional and federal levels. We expect that some of our assets and operations in the United States could be affected either directly or indirectly by eventual mandatory GHG programs; however, the timing and specific policy objectives in many jurisdictions, including at the federal level, remain uncertain. In addition, a number of U.S. states have joined regional greenhouse gas initiatives, and a number are developing their own programs that would mandate reductions in GHG emissions. However, as the key details of future GHG restrictions and compliance mechanisms remain undefined, the likely future effects on our business are highly uncertain.

The EPA finalized a Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule in 2009 to address how GHG emissions would be regulated under the existing Clean Air Act. Regulation began in 2011, and over time, certain existing Spectra Energy Partners U.S. facilities will be subject to this regulation. Some new construction and modification projects in the future may be subject to this regulation as well. At this time, it is not anticipated that the costs will be material, although additional permitting requirements could result in delays in completing capital projects. In addition, several legislative proposals that would impose GHG emissions constraints have been considered by the U.S. Congress. To date, no such legislation has been enacted into law.

Due to the speculative outlook regarding any U.S. federal and state policies, we cannot estimate the potential effect of proposed GHG policies on our future consolidated results of operations, financial position or cash flows. However, such legislation or regulation could materially increase our operating costs, require material capital expenditures or create additional permitting, which could delay proposed construction projects.

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

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

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perform ongoing assessments of pipeline integrity;

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

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improve data collection, integration and analysis;

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repair and remediate the pipeline as necessary; and

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implement preventive and mitigating actions.

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

Our operations are subject to operational hazards and unforeseen interruptions.

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

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

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

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

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collapse of storage caverns;

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operator error;

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environmental pollution;

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explosions and blowouts;

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risks related to underwater pipelines in the Gulf of Mexico, which are susceptible to damage from shifting as a result of water currents, as well as damage from vessels;

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

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risks related to operating in a marine environment.

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

We are subject to pipeline safety laws and regulations, compliance with which may require significant capital expenditures, increase our cost of operations and affect or limit our business plans.

Our interstate pipeline operations are subject to pipeline safety regulation administered by the Pipeline and Hazardous Materials Safety Administration (PHMSA) of the U.S. Department of Transportation. These laws and regulations require us to comply with a significant set of requirements for the design, construction, maintenance and operation of our interstate pipelines. These regulations, among other things, include requirements to monitor and maintain the integrity of our pipelines. The regulations determine the pressures at which our pipelines can operate.

In 2010, serious pipeline incidents on systems unrelated to ours focused the attention of Congress and the public on pipeline safety. Legislative proposals have been introduced in Congress that would strengthen PHMSA’s enforcement and penalty authority, and expand the scope of its oversight. In August 2011, PHMSA initiated an Advance Notice of Proposed Rulemaking announcing its consideration of substantial revisions in its regulations to increase pipeline safety. PHMSA also has issued guidance that states it will focus near-term enforcement efforts on recordkeeping and integrity management, following urgent recommendations by the National Transportation Safety Board related to pipeline pressure and recordkeeping. On January 3, 2012, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 was signed into law. This Act (the 2012 PSA Amendments) amends the Pipeline Safety Act in a number of significant ways, including:

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Authorizing PHMSA to assess higher penalties for violations of its regulations,

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Requiring PHMSA to adopt appropriate regulations within two years requiring the use of automatic or remote-controlled shutoff valves on new or rebuilt pipeline facilities and to perform a study on the application of such technology to existing pipeline facilities in High Consequence Areas (HCAs),

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Requiring operators of pipelines to verify maximum allowable operating pressure and report exceedances within five days,

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Requiring PHMSA to study and report on the adequacy of soil cover requirements in HCAs, and

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Requiring PHMSA to evaluate in detail whether integrity management requirements should be expanded to pipeline segments outside of HCAs (where the requirements currently apply).

These legislative changes, when implemented, will impose additional costs on new pipeline projects as well as on existing operations. It is still uncertain what regulatory changes PHMSA will propose as a result of the Advance Notice of Proposed Rulemaking, but PHMSA will begin to undertake the various requirements imposed on it by the 2012 PSA Amendments. In this climate of increasingly stringent regulation, pipeline failures or failures to comply with applicable regulations could result in reduction of allowable operating pressures as authorized by PHMSA, which would reduce available capacity on our pipelines. Should any of these risks materialize, it may have an adverse effect on our operations, earnings, financial condition or cash flows.

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

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

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

The operating and financial restrictions and covenants in our credit facility and any future financing agreements could restrict our ability to finance future operations or capital needs or to expand or pursue business activities associated with our subsidiaries and equity investments. Our credit facility contains covenants that restrict or limit our ability to:

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

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

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incur additional indebtedness or guarantee other indebtedness;

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grant liens or make certain negative pledges;

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make certain loans or investments;

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engage in transactions with affiliates;

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

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make a disposition of assets; or

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

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

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

The credit and business risk profiles of our general partner and Spectra Energy may be factors considered in credit evaluations of us. This is because our general partner controls our business activities, including our cash

distribution policy, acquisition strategy and business risk profile. Another factor that may be considered is the financial condition of Spectra Energy, including the degree of its financial leverage and its dependence on cash flow from the partnership to service its indebtedness.

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

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

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

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

Risks Inherent in an Investment in Us

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

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

•

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

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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;

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

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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;

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

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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, issuances of additional partnership securities and reserves, each of which can affect the amount of cash that is distributed to unitholders;

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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;

•

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

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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 incentive distributions;

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

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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;

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

•

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

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

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

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

In order to comply with certain FERC rate-making policies applicable to entities that pass through taxable income to their owners, we have adopted certain requirements regarding those investors who may own our common and subordinated units. Eligible Holders are individuals or entities subject to United States federal income taxation on the income generated by us or entities not subject to United States federal income taxation on the income generated by us, so long as all of the entity’s owners are subject to such taxation. If a unitholder is not a person who fits the requirements to be an Eligible Holder, such unitholder will not receive distributions or allocations of income and loss on the unitholder’s units and the unitholder runs the risk of having the units redeemed by us at the lower of the unitholder’s purchase price cost or the then-current market price. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner.

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

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

Our partnership agreement limits our general partner’s fiduciary duties to holders of our common units, and restricts the remedies available to holders of our common 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;

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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;

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

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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

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

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

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

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

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

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

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

The unitholders will be unable initially to remove our general partner without its consent because the general partner and its affiliates own sufficient units to be able to prevent its removal. The vote of the holders of at least 66 2/3% of all outstanding units voting together as a single class is required to remove our general partner. Our general partner and its affiliates own 63% of our aggregate outstanding 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.

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

Our assets include a 100% ownership interest in East Tennessee, Ozark, Big Sandy and Saltville, a 49% limited liability company interest in Gulfstream and a 50% general partner interest in Market Hub. If a sufficient amount of our assets, such as our ownership interests in Gulfstream and Market Hub or other assets acquired in the future, are deemed to be “investment securities” within the meaning of the Investment Company Act of 1940, we would either have to register as an investment company under the Investment Company Act, obtain exemptive relief from the SEC or modify the organizational structure or contract rights to fall outside the definition of an investment company. Although general partner interests are typically not considered “securities” or “investment securities,” there is a risk that our 50% general partner interest in Market Hub could be deemed to be an investment security. In that event, it is possible that our ownership of this interest, combined with our 49% interest in Gulfstream or assets acquired in the future, could result in us being required to register under the Investment Company Act if we were not successful in obtaining exemptive relief or otherwise modifying the organizational structure or applicable contract rights. Registering as an investment company could, among other things, materially limit our ability to engage in transactions with affiliates, including the purchase and sale of certain securities or other property to or from our affiliates, restrict our ability to borrow funds or engage in other transactions involving leverage and require us to add additional directors who are independent of us or our affiliates. The occurrence of some or all of these events would adversely affect the price of the common units and could have an adverse effect on our business.

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

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

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

In recent years, the U.S. credit markets have experienced 50-year record lows in interest rates. Interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to

increase accordingly. As with other yield-oriented securities, our unit price is affected by the level of our cash distributions and implied distribution yield. Therefore, changes in interest rates may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse effect on our unit price and the ability to issue additional equity to make acquisitions, to incur debt or for other purposes.

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

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

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

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

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the ratio of taxable income to distributions may increase;

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

•

the market price of the common units may decline.

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

As of January 31, 2012, Spectra Energy and its affiliates hold an aggregate of 60,914,686 common units. The sale of any of these units in the public or private markets could have an adverse effect on the price of the common units or on any trading market that may develop.

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

If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price. As a result, our common unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. A common unitholder may also incur a tax liability upon a sale of their units. As of January 31, 2012, our general partner and its affiliates own approximately 63% of our outstanding common units.

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

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

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

•

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

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

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

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

Tax Risks to Common Unitholders

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

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

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35% and would likely pay state income tax at varying rates. Distributions would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to the common unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to a common unitholder, likely causing a substantial reduction in the value of our common units.

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

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

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

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

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

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

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

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

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

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

We 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 have adopted depreciation and amortization positions that may not conform to all aspects of existing U.S. Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to the common unitholder. It also could affect the timing of these tax benefits or the amount of gain from the sale of our common units and could have a negative effect on the value of our common units or result in audit adjustments to the tax returns.

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

When we issue additional units or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of the

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

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

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

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

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations. Recently, however, the U.S. Treasury Department issued proposed Treasury Regulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

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

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

Item 1B. Unresolved Staff Comments.

None.

Item 2. Properties.

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

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

Item 3. Legal Proceedings.

For information regarding legal proceedings, including regulatory and environmental matters, see Item 8. Financial Statements and Supplementary Data, Notes 6 and 14 of Notes to Consolidated Financial Statements.

Item 4. Mine Safety Disclosures.

Not applicable.

PART II

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

Our common units are listed on the NYSE under the symbol “SEP.” The following table sets forth the high and low closing sales prices for our common units during the periods indicated, as reported by the NYSE, and the amount of the quarterly cash distributions we paid on each of our common units.

Common Unit Data by Quarter


	Distributions Paid in the Quarter					Unit Price Range(a)
	Per Common Unit		Per Subordinated Unit			High		Low
2011
First Quarter	$	0.45	$	—		$	33.50	$	30.73
Second Quarter		0.46		—			34.93		29.64
Third Quarter		0.465		—			32.18		25.53
Fourth Quarter		0.47		—			32.00		26.35

2010
First Quarter		0.41		0.41			31.57		27.01
Second Quarter		0.42		0.42			34.20		22.58
Third Quarter		0.43		0.43			35.95		31.76
Fourth Quarter		0.44		(b	)		36.31		31.71

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

(b)	Subordination period ended on August 13, 2010.

As of January 31, 2012, there were 28 holders of record of our common units. A cash distribution to unitholders of $0.475 per limited partner unit was declared on January 23, 2012 and was paid on February 14, 2012, which is a $0.005 per limited partner unit increase over the cash distribution of $0.47 per limited partner unit paid on November 14, 2011.

Unit Performance Graph

The following graph reflects the comparative changes in the value from June 27, 2007, the first trading day of our common units on the NYSE, through December 31, 2011 of $100 invested in (1) Spectra Energy Partners’ common units, (2) the Standard & Poor’s 500 Stock Index, and (3) the Alerian MLP Index. The amounts included in the table were calculated assuming the reinvestment of distributions, at the time distributions were paid.

LOGO


	June 27, 2007		December 31,
	June 27, 2007		2007		2008		2009		2010		2011
Spectra Energy Partners	$	100.00	$	84.61	$	74.07	$	118.32	$	138.47	$	142.74
S&P 500		100.00		98.44		62.02		78.43		90.24		92.15
Alerian MLP Index		100.00		93.90		59.23		104.50		141.96		161.66

Market Repurchases

In the second quarter of 2010, we repurchased 48,000 common units to satisfy awards vested in July 2010 under the Long-Term Incentive Plan. We have not made any repurchases of subordinated or general partner units.

Distributions of Available Cash

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

Minimum Quarterly Distribution. The Minimum Quarterly Distribution, as set forth in the partnership agreement, is $0.30 per limited partner unit per quarter, or $1.20 per limited partner unit per year. The quarterly distribution as of January 23, 2012 is $0.475 per limited partner unit, or $1.90 per limited partner unit annualized. There is no guarantee that this distribution rate will be maintained or that we will pay the Minimum Quarterly Distribution on the units in any quarter. Even if our cash distribution policy is not modified or revoked, the amount of distributions paid under our policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of the partnership agreement.

General Partner Interest and Incentive Distribution Rights. Our general partner is entitled to 2% of all quarterly distributions since inception. This general partner interest is represented by 1,966,303 general partner units. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its current general partner interest. The general partner’s initial 2% interest in these distributions will be reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to maintain its 2% general partner interest. The general partner contributed $4.5 million in 2011, $5.9 million in 2010 and $4.4 million in 2009 to maintain its 2% interest as a result of the additional limited partner units issued following the Big Sandy acquisition, additional interest in Gulfstream and the Ozark acquisition, respectively.

The general partner also currently holds incentive distribution rights that entitle it to receive increasing percentages of the cash we distribute from operating surplus in excess of $0.345 per unit per quarter, up to a maximum of 50%. During 2011, the maximum incentive distribution right of 50% was achieved. The maximum distribution of 50% includes distributions paid to the general partner on its 2% general partner interest and assumes that the general partner maintains its general partner interest at 2%. The maximum distribution of 50% does not include any distributions that the general partner may receive on common units that it owns.

Equity Compensation Plans

For information related to our equity compensation plans, see Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.

Item 6. Selected Financial Data.

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

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


	2011		2010		2009		2008		2007
	(in millions, except per-unit amounts)
Statements of Operations
Operating revenues	$	205.0	$	197.7	$	178.9	$	124.9	$	121.1
Operating income		88.2		87.7		82.8		51.9		60.6
Equity in earnings of unconsolidated affiliates(a)		107.3		75.1		70.7		61.4		55.6
Net income(b)		172.0		147.9		135.9		101.3		202.9

Net Income per Limited Partner Unit(c)
Net income per limited partner unit — basic and diluted	$	1.63	$	1.70	$	1.71	$	1.40	$	0.68
Distributions paid per limited partner unit during the periods presented		1.845		1.70		1.51		1.34		0.30


	December 31,
	2011		2010		2009		2008		2007
	(in millions)
Balance Sheet
Total assets(a)	$	2,456.9	$	2,222.5	$	1,812.5	$	1,601.5	$	1,611.3
Long-term debt		499.4		655.8		390.0		390.0		400.0

(a)	During the fourth quarter of 2010, we purchased an additional 24.5% interest in Gulfstream which is accounted for as an equity method investment. The equity earnings related to the additional interest are recorded prospectively from the date of acquisition.

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

(c)	Reflective of general and limited partners’ interests in Net Income since the closing of our IPO on July 2, 2007.

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

INTRODUCTION

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

EXECUTIVE OVERVIEW

In 2011, we continued to consistently execute on our strategy. This included an ongoing focus on growth opportunities to support our cash distribution objectives. We completed the $390 million cash acquisition of Big Sandy on July 1, 2011 and put several organic growth projects into commercial service. Gulfstream’s Phase V and Market Hub’s expansion projects went into service during the second quarter of 2011. East Tennessee’s NET project was placed into service on September 1, 2011.

We reported net income of $172.0 million in 2011 compared with $147.9 million in 2010. Our results reflected increased equity earnings from Gulfstream resulting from the acquisition of an additional 24.5% interest in November 2010, partial year earnings from both the Big Sandy acquisition and the NET project, partially offset by lower revenue at Ozark and increased interest expense from our $500 million debt issuance in June 2011.

We increased the quarterly cash distributions each quarter in 2011 from $0.45 per limited partner unit for the fourth quarter of 2010, paid in February 2011, to $0.475 per limited partner unit for the fourth quarter of 2011, paid in February 2012.

During 2011, we took a number of steps to enhance our overall financial flexibility, liquidity and position to pursue future growth opportunities.

•

Received investment grade credit ratings in June 2011

•

Standard and Poor’s (BBB), Fitch Ratings (BBB), Moody’s Investor Service (Baa3);

•

Completed first-ever public debt offering of $500 million;

•

Credit facility renewed at $700 million, with 40% higher borrowing capacity;

•

Issued 7.2 million common units for $217.9 million in net proceeds; and

•

Established a commercial paper program to fund our short-term borrowing needs.

See “Liquidity and Capital Resources — Financing Cash Flows” for further discussion of these transactions.

Growth in our cash available for distribution in 2012 will be driven by full year benefits of the Big Sandy acquisition and the NET project. In 2012, we expect to invest approximately $30 million in expansion capital mainly at East Tennessee and Market Hub that will complete the projects put into commercial service in 2011.

We will rely upon cash flows from operations, including cash distributions received from Gulfstream and Market Hub, and various financing transactions, which may include issuances of short-term and long-term debt, to fund our liquidity and capital requirements for 2012. Given that we expect to continue to pursue expansion opportunities over the next several years, capital resources will continue to include long-term borrowings and possibly securing additional sources of capital including debt and/or equity. We expect to maintain an investment-grade capital structure and liquidity profile that supports our strategic objectives. Therefore, we will continue to monitor market requirements and our liquidity, and make adjustments to these plans as needed.

Business Strategy

Our primary business objective is to grow unitholder value over time by:

•

Optimizing our existing portfolio of reliable, fee-based assets. Optimization can be achieved through increased asset utilization, improved operating efficiencies, or rate and contract structures designed to meet our customers’ needs and maximize value for our investors.

•

Actively engaging in the marketplace for strategic acquisitions of assets that enhance our portfolio. We target potential acquisitions both in the area of our existing geographic footprint and asset mix, as well as those that may be in new regions or segments that fit our fee-based business profile. These could be either third party acquisitions, or assets that are dropped down from our General Partner, Spectra Energy.

•

Continuing to identify and develop new organic growth projects. We engage our customers on an ongoing basis to identify new project opportunities that meet their developing needs. Given current market dynamics, we believe there may be specific opportunities resulting from growing demand for gas-fired electric generation and industrial markets.

Significant Economic Factors for Our Business

The high percentage of our business derived from capacity reservation fees mitigates the risk of revenue fluctuations due to short-term changes in natural gas supply and demand conditions. However, all of our businesses can be negatively affected in the long term by sustained downturns in the economy in general, and are impacted by shifts in supply and demand dynamics, competition, the mix of services requested by our customers, and changes in regulatory requirements affecting our operations. Short-term contracts and interruptible service arrangements are a relatively smaller component of our revenue; however, these services can be impacted positively or negatively to varying degrees by natural gas price volatility and other factors beyond our control. We mitigate our exposure to natural gas prices by maximizing the contracting of our available transportation capacity with long-term, fixed-rate arrangements.

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

Supply and Demand Dynamics

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

The south atlantic, Florida and east south central markets, which are connected to our assets, are projected to continue to exhibit approximately double the U.S. lower 48 states average annual growth in natural gas demand of 1.5%. This demand growth is primarily driven by the increases in natural gas-fired electric generation.

Growth of Natural Gas Storage Facilities

Natural gas storage plays an important role in the natural gas transportation industry, due to the need to balance seasonal pricing, provide gas for power generation and to balance the difference in timing of natural gas

supplies and natural gas demand. The southeastern region of the United States has a large number of high-deliverability, salt-cavern storage facilities and the demand for this type of storage is expected to continue over time particularly to support growing natural gas fired electric generation. Natural gas storage prices have recently been challenged as a result of increasing natural gas supply and narrower seasonal price spreads. Gas supply and demand dynamics continue to change as a result of the development of new unconventional shale gas supplies. These market factors will continue to keep downward pressure on storage values in the near term.

Regulation

Government regulation of natural gas transportation, storage and gathering has a significant impact on our business. The natural gas transportation rates are regulated under the FERC rate-making policies. Our storage facility in Texas is subject to oversight by the RRC. Our gathering operations are subject to oversight by the Arkansas Public Service Commission and Oklahoma Corporation Commission. The FERC regulatory policies govern the rates that each pipeline is permitted to charge customers for interstate transportation and storage of natural gas. Under certain circumstances, we are permitted to enter into contracts with customers under “negotiated rates” and “market-based” rates that differ from the rates imposed by the FERC.

RESULTS OF OPERATIONS


	2011		2010			Increase (Decrease)		2009		Increase (Decrease)
	(in millions, except where noted)
Operating revenues	$	205.0	$	197.7		$	7.3	$	178.9	$	18.8
Operating, maintenance and other expenses		83.6		80.6			3.0		67.6		13.0
Depreciation and amortization		33.2		29.4			3.8		28.5		0.9

Operating income		88.2		87.7			0.5		82.8		4.9
Equity in earnings of unconsolidated affiliates		107.3		75.1			32.2		70.7		4.4
Other income and expenses, net		2.1		0.8			1.3		0.1		0.7
Interest income		0.5		0.1			0.4		0.2		(0.1	)
Interest expense		25.0		16.2			8.8		16.7		(0.5	)

Earnings before income taxes		173.1		147.5			25.6		137.1		10.4
Income tax expense (benefit)		1.1		(0.4	)		1.5		1.2		(1.6	)

Net income	$	172.0	$	147.9		$	24.1	$	135.9	$	12.0

Net cash provided by operating activities	$	220.1	$	184.8		$	35.3	$	159.7	$	25.1
Adjusted EBITDA(a)		121.4		117.1			4.3		111.3		5.8
Cash Available for Distribution(a)		212.4		174.5			37.9		158.1		16.4

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

2011 Compared to 2010

Operating Revenues. The Big Sandy acquisition in July 2011, and the placement into service of the NET project on September 1, 2011 increased operating revenues by $16.6 million and $7.7 million, respectively. These increases were partially offset by anticipated decreases in contract revenue of $12.8 million and a reduction in throughput-driven revenues of $3.3 million both at Ozark Gas Transmission.

Operating, Maintenance and Other. Operating expenses included $5.1 million resulting from the Big Sandy acquisition, of which $1.4 million related to transaction and transition costs. This was partially offset by relatively lower pipeline integrity costs.

Depreciation and Amortization. The increase was driven mainly by the acquisition of Big Sandy and the NET expansion project.

Equity in Earnings of Unconsolidated Affiliates. There was a $29.2 million increase as a result of doubling our ownership interest in Gulfstream from 24.5% to 49% in November 2010. The remaining increase in equity earnings resulted from our 50% interest in Market Hub. Additional discussion on the results of Gulfstream and Market Hub at 100% is found below in Results of Operations for Unconsolidated Affiliates.

Other Income and Expenses, Net. The increase in the equity portion of allowance for funds used during construction (AFUDC) resulted from higher capital expenditures in 2011 on the NET project.

Interest Expense. The increase is primarily due to the issuance of $500 million in new unsecured senior notes in June 2011.

Income Tax Expense (Benefit). The increase was driven by a favorable tax adjustment in 2010.

Results of Operations for Unconsolidated Affiliates

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


	2011		2010		Increase (Decrease)			2009		Increase (Decrease)
	(in millions)
*Gulfstream*
Operating revenues	$	273.4	$	273.6	$	(0.2	)	$	251.5	$	22.1
Operating, maintenance and other expenses		36.1		38.1		(2.0	)		33.1		5.0
Depreciation and amortization		35.4		35.0		0.4			34.5		0.5
Other income and expenses, net		—		0.9		(0.9	)		1.4		(0.5	)
Interest expense		69.9		69.8		0.1			61.3		8.5

Net income	$	132.0	$	131.6	$	0.4		$	124.0	$	7.6

Spectra Energy Partners’ share	$	64.7	$	35.5	$	29.2		$	30.4	$	5.1

Gulfstream’s Phase V expansion project went into service on April 1, 2011 and increased operating revenues by $7.7 million. This increase in revenue from Phase V was offset by relatively higher weather driven revenues in 2010 that did not recur at the same level in 2011. Expenses reflect favorable ad valorem tax adjustments in 2011.


	2011		2010		Increase (Decrease)			2009		Increase (Decrease)
	(in millions)
*Market Hub*
Operating revenues	$	123.3	$	118.5	$	4.8		$	115.5	$	3.0
Operating, maintenance and other expenses		26.9		25.2		1.7			22.6		2.6
Depreciation and amortization		10.8		14.5		(3.7	)		12.1		2.4
Gains on sale of other assets and other income and expenses		—		0.6		(0.6	)		—		0.6
Interest income		0.1		0.2		(0.1	)		0.3		(0.1	)
Interest expense		0.1		0.1		—			0.1		—
Income tax expense		0.2		0.2		—			0.2		—

Net income	$	85.4	$	79.3	$	6.1		$	80.8	$	(1.5	)

Spectra Energy Partners’ share	$	42.6	$	39.6	$	3.0		$	40.3	$	(0.7	)

Market Hub’s revenues increased as result of the commercial in-service of the expansion projects, partially offset by lower contract rates. Net income also reflects a decrease in depreciation expense in 2011 due to a change in the estimated useful life of storage facilities, as well as higher ad valorem taxes in 2011.

2010 Compared to 2009

Operating Revenues. The $18.8 million increase in 2010 was driven mostly by $13.0 million from a full year of revenues in 2010 from the Ozark assets acquired in second quarter 2009, and higher 2010 revenues of $5.3 million at East Tennessee primarily due to increased contracted volumes related to the Glade Spring expansion project.

Operating, Maintenance and Other. The $13.0 million increase in 2010 was driven mainly by:

•

a $7.6 million increase from a full year of expenses associated with the Ozark assets,

•

a $4.1 million increase in pipeline integrity costs,

•

a $2.3 million increase in benefit costs, including costs related to Ozark,

•

a $2.1 million increase as a result of lower pipeline fuel recoveries by East Tennessee, and

•

a $0.8 million increase due to 2010 transaction costs associated with the Gulfstream acquisition, partially offset by

•

a $2.9 million decrease as a result of 2009 transaction costs associated with the Ozark acquisition.

Equity in Earnings of Unconsolidated Affiliates. The $4.4 million increase in 2010 consisted of a $5.1 million increase in earnings from our 49% interest in Gulfstream net of a $0.7 million decrease in earnings from our 50% interest in Market Hub. During the fourth quarter of 2010, we purchased an additional 24.5% interest in Gulfstream from a subsidiary of Spectra Energy. The additional interest increased our ownership in Gulfstream to 49%. Additional discussion on the results of Gulfstream and Market Hub at 100% is found below in Results of Operations for Unconsolidated Affiliates.

Income Tax Expense (Benefit). Income tax benefit was $0.4 million in 2010 compared to an income tax expense of $1.2 million in 2009. The benefit in 2010 was primarily a result of favorable adjustments in 2010 for final 2009 state tax returns.

Results of Operations for Unconsolidated Affiliates

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

Gulfstream’s net income increased $7.6 million to $131.6 million in 2010 compared to $124.0 million in 2009. The increase was driven mainly by:

•

a $22.1 million increase in revenues mainly from the Phase III expansion contracts that were fully ramped up by June 2009, as well as short-term firm contracts and higher park and loan and interruptible transportation activity all due to colder than normal weather and higher demand through the year in Florida, partially offset by

•

an $8.5 million increase in interest expense attributable to the $300.0 million debt issued in May 2009 by Gulfstream, and

•

a $5.0 million increase in operating, maintenance and other expenses resulting from a $3.5 million increase in ad valorem tax expense related to assets placed in service in 2009 and a higher 2009 favorable valuation adjustment, and a $1.9 million increase in project costs due to the 2009 capitalization of previously expensed costs related to the Phase V expansion.

Market Hub’s net income decreased $1.5 million to $79.3 million in 2010 compared to $80.8 million in 2009. The decrease was driven mainly by:

•

a $4.3 million decrease in hub services revenues due to lower demand compared to the prior year, and

•

a $1.4 million increase in operating and maintenance expenses due mainly to lower capitalized overhead costs resulting from lower capital expenditures in 2010 and lower net fuel recovery, partially offset by

•

a $3.2 million increase in net earnings related to the continued phase-in of the Egan Cavern 3 storage expansion (comprised of $7.3 million revenues, $1.2 million operating, maintenance and other expenses and $2.9 million depreciation expense), and

•

a $0.6 million increase in other income and expenses, net primarily due to a 2010 right-of-way granted to a third party at Moss Bluff.

Matters Affecting Future Results

We plan to continue earnings growth through a consistent focus on executing our strategy of optimization, strategic acquisitions and organic growth that fit our business model.

Future earnings will be dependent on the success of our expansion plans in both the market and supply areas of the pipeline network, the ability to continue renewing service contracts and continued regulatory stability. See discussion in “Significant Economic Factors for Our Business” for additional information.

Our interstate pipeline operations are subject to pipeline safety regulation administered by PHMSA of the U.S. Department of Transportation. These laws and regulations require us to comply with a significant set of requirements for the design, construction, maintenance and operation of our interstate pipelines.

On January 3, 2012, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 was signed into law. This Act amends the Pipeline Safety Act in a number of significant ways, including:

•

Authorizing PHMSA to assess higher penalties for violations of its regulations,

•

Requiring operators of pipelines to verify maximum allowable operating pressure and report exceedances within five days,

•

Requiring PHMSA to study and report on the adequacy of soil cover requirements in HCAs, and

•

Requiring PHMSA to evaluate in detail whether integrity management requirements should be expanded to pipeline segments outside of HCAs (where the requirements currently apply).

In August 2011, PHMSA initiated an Advance Notice of Proposed Rulemaking announcing its consideration of substantial revisions in its regulations to increase pipeline safety. PHMSA also has issued an Advisory Bulletin which among other things, advises pipeline operators that if they are relying on design, construction, inspection, testing, or other data to determine the pressures at which their pipelines should operate, the records of that data must be traceable, verifiable and complete. These legislative and regulatory changes, when implemented, will impose additional costs on new pipeline projects as well as on existing operations. Because the extent of the new requirements and the timing of their application is still uncertain, we cannot reasonably determine the impacts that these changes will have on our operations, earnings, financial condition and cash flows at this time.

Adjusted EBITDA and Cash Available for Distribution

Adjusted EBITDA

We define our Adjusted Earnings Before Interest, Taxes, Depreciation and Amortization (EBITDA) as Net Income plus Interest Expense, Income Taxes and Depreciation and Amortization less our Equity in Earnings of Gulfstream and Market Hub, Interest Income, and Other Income and Expenses, Net, which primarily consists of non-cash AFUDC. Since Adjusted EBITDA excludes some, but not all, items that affect net income and is defined differently by companies in our industry, our definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies. Adjusted EBITDA is a non-GAAP measure and should not be considered an alternative to Net Income, Operating Income, cash from operations or any other measure of financial performance or liquidity in accordance with GAAP.

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

•

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

•

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

•

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

Significant drivers of variances in Adjusted EBITDA between the periods presented are substantially the same as those previously discussed under Results of Operations.

Cash Available for Distribution

We define Cash Available for Distribution (CAD) as our Adjusted EBITDA plus Cash Available for Distribution from Gulfstream and Market Hub and net preliminary project costs, less net cash paid for interest expense, net cash paid for income tax expense, and maintenance capital expenditures, excluding the impact of reimbursable projects. Cash Available for Distribution does not reflect changes in working capital balances. Cash Available for Distribution for Gulfstream and Market Hub is defined on a basis consistent with us. Cash Available for Distribution should not be viewed as indicative of the actual amount of cash that we plan to distribute for a given period.

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

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

Spectra Energy Partners

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


	2011		2010			2009
	(in millions)
Net income	$	172.0	$	147.9		$	135.9
Add:
Interest expense		25.0		16.2			16.7
Income tax expense (benefit)		1.1		(0.4	)		1.2
Depreciation and amortization		33.2		29.4			28.5
Less:
Equity in earnings of Gulfstream		64.7		35.5			30.4
Equity in earnings of Market Hub		42.6		39.6			40.3
Interest income		0.5		0.1			0.2
Other income and expenses, net		2.1		0.8			0.1

Adjusted EBITDA		121.4		117.1			111.3
Add:
Cash Available for Distribution from Gulfstream		81.0		43.0			38.2
Cash Available for Distribution from Market Hub		46.0		45.6			40.8
Preliminary project costs, net		0.1		—			0.4
Less:
Cash paid for interest expense, net		23.0		15.7			16.2
Cash paid for income tax expense		—		0.7			0.1
Maintenance capital expenditures		13.1		14.8			16.3

Cash Available for Distribution	$	212.4	$	174.5		$	158.1

Spectra Energy Partners

Reconciliation of Net Cash Provided by Operating Activities to Non-GAAP “Adjusted EBITDA” and “Cash Available for Distribution”


	2011			2010			2009
	(in millions)
Net cash provided by operating activities	$	220.1		$	184.8		$	159.7
Interest income		(0.5	)		(0.1	)		(0.2	)
Interest expense		25.0			16.2			16.7
Income tax expense — current		—			0.6			—
Distributions received from Gulfstream		(66.8	)		(33.4	)		(38.6	)
Distributions received from Market Hub		(49.5	)		(47.7	)		(35.7	)
Changes in working capital and other		(6.9	)		(3.3	)		9.4

Adjusted EBITDA		121.4			117.1			111.3
Add:
Cash Available for Distribution from Gulfstream		81.0			43.0			38.2
Cash Available for Distribution from Market Hub		46.0			45.6			40.8
Preliminary project costs, net		0.1			—			0.4
Less:
Cash paid for interest expense, net		23.0			15.7			16.2
Cash paid for income tax expense		—			0.7			0.1
Maintenance capital expenditures		13.1			14.8			16.3

Cash Available for Distribution	$	212.4		$	174.5		$	158.1

Gulfstream

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


	2011		2010		2009
	(in millions)
Net income	$	132.0	$	131.6	$	124.0
Add:
Interest expense		69.9		69.8		61.3
Depreciation and amortization		35.4		35.0		34.5
Less:
Other income and expenses, net		—		0.9		1.4

Adjusted EBITDA — 100%		237.3		235.5		218.4
Add:
Preliminary project costs, net		1.1		0.6		(1.3	)
Less:
Cash paid for interest expense, net		70.3		70.3		60.1
Maintenance capital expenditures		2.8		1.3		0.9

Cash Available for Distribution — 100%	$	165.3	$	164.5	$	156.1

Adjusted EBITDA — Spectra Energy Partners’ Share(a)	$	116.2	$	63.0	$	53.5
Cash Available for Distribution — Spectra Energy Partners’ Share(a)	$	81.0	$	43.0	$	38.2

(a)	During the fourth quarter of 2010, we purchased an additional 24.5% interest in Gulfstream which is accounted for as an equity method investment. The equity earnings related to the additional interest was recorded as of the date of the acquisition.

Market Hub

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


	2011			2010			2009
	(in millions)
Net income	$	85.4		$	79.3		$	80.8
Add:
Interest expense		0.1			0.1			0.1
Income tax expense		0.2			0.2			0.2
Depreciation and amortization		10.8			14.5			12.1
Less:
Interest income		0.1			0.2			0.3
Other income and expenses, net		—			0.6			—

Adjusted EBITDA — 100%		96.4			93.3			92.9
Less:
Cash paid (received) for interest expense, net		(0.1	)		(0.1	)		7.1
Cash paid for income tax expense		0.2			0.3			0.5
Maintenance capital expenditures		4.4			2.0			3.8

Cash Available for Distribution — 100%	$	91.9		$	91.1		$	81.5

Adjusted EBITDA — 50%	$	48.2		$	46.7		$	46.5
Cash Available for Distribution — 50%	$	46.0		$	45.6		$	40.8

Effective January 1, 2012, we have refined the calculation of Cash Available for Distribution. Interest expense will now be deducted from Adjusted EBITDA instead of Cash paid for interest expense, net. This change will remove the quarterly timing effects of cash interest payments during the year and include the impact of amortized debt costs. In addition, other non-cash amounts that affect net income will be an adjustment to Adjusted EBITDA, as appropriate.

The effects of these changes on Spectra Energy Partners and Gulfstream are as follows for the years ended December 31. These changes do not affect Market Hub’s Cash Available for Distribution.

Spectra Energy Partners


	2011			2010			2009
	(in millions)
Cash Available for Distribution, as previously reported	$	212.4		$	174.5		$	158.1
Add (Less):
Interest expense adjustment		(2.0	)		(0.5	)		(0.5	)
Change in Cash Available for Distribution from Gulfstream		—			1.1			(0.3	)
Other(a)		2.0			1.3			1.2

Cash Available for Distribution, as revised	$	212.4		$	176.4		$	158.5

(a)	Includes non-cash AFUDC and inventory write-down

Gulfstream


	2011			2010			2009
	(in millions)
Cash Available for Distribution, as previously reported	$	165.3		$	164.5		$	156.1
Add (Less):
Interest expense adjustment		0.4			0.5			(1.2	)
Other(a)		(0.3	)		(0.5	)		(0.3	)

Cash Available for Distribution, as revised	$	165.4		$	164.5		$	154.6

Cash Available for Distribution — Spectra Energy Partners’ Share, as previously reported(b)	$	81.0		$	43.0		$	38.2
Cash Available for Distribution — Spectra Energy Partners’ Share, as revised(b)	$	81.0		$	44.1		$	37.9

(a)	Primarily includes non-cash AFUDC

(b)	During the fourth quarter of 2010, we purchased an additional 24.5% interest in Gulfstream which is accounted for as an equity method investment. The equity earnings related to the additional interest was recorded as of the date of the acquisition.

The quarterly impacts for 2011 are as follows.

Spectra Energy Partners


	For the three months ended
	March 31			June 30		September 30			December 31		Total
	(in millions)
Cash Available for Distribution, as previously reported	$	69.7		$	35.4	$	69.3		$	38.0	$	212.4
Add (Less):
Interest expense adjustment		(2.3	)		0.9		(6.9	)		6.3		(2.0	)
Change in CAD from Gulfstream		(8.6	)		8.7		(8.7	)		8.6		—
Other(a)		—			0.1		—			1.9		2.0

Cash Available for Distribution, as revised	$	58.8		$	45.1	$	53.7		$	54.8	$	212.4

(a)	Includes non-cash AFUDC and inventory write-down

Gulfstream


	For the three months ended
	March 31			June 30		September 30			December 31		Total
	(in millions)
Cash Available for Distribution, as previously reported	$	59.4		$	22.7	$	60.0		$	23.2	$	165.3
Add (Less):
Interest expense adjustment		(17.2	)		17.7		(17.7	)		17.6		0.4
Other(a)		(0.3	)		—		—			—		(0.3	)

Cash Available for Distribution, as revised	$	41.9		$	40.4	$	42.3		$	40.8	$	165.4

Cash Available for Distribution — 49%, as previously reported	$	29.1		$	11.1	$	29.4		$	11.4	$	81.0
Cash Available for Distribution — 49%, as revised	$	20.5		$	19.8	$	20.7		$	20.0	$	81.0

(a)	Primarily includes non-cash AFUDC

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The application of accounting policies and estimates is an important process that continues to evolve as our operations change and accounting guidance is issued. We have identified a number of critical accounting policies and estimates that require the use of significant estimates and judgments.

We base our estimates and judgments on historical experience and on other various assumptions that we believe are reasonable at the time of application. These estimates and judgments may change as time passes and more information becomes available. If estimates are different than the actual amounts recorded, adjustments are made in subsequent periods to take into consideration the new information. We discuss our critical accounting policies and estimates and other significant accounting policies with our Audit Committee.

Regulatory Accounting

We account for our regulated operations at East Tennessee, Ozark Gas Transmission, Big Sandy and Saltville under accounting for regulated entities. Our equity investee Gulfstream, also utilizes this accounting. As a result, we record assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for non-regulated entities. Regulatory assets generally represent incurred costs that have been deferred because such costs are probable of future recovery in customer rates. Regulatory liabilities generally represent obligations to make refunds to customers or for instances where the regulator provides current rates that are intended to recover costs that are expected to be incurred in the future. We continually assess whether the regulatory assets are probable of future recovery by considering factors such as applicable regulatory changes and recent rate orders to other regulated entities. Based on this continual assessment, we believe our existing regulatory assets are probable of recovery. This assessment reflects the current political and regulatory climate at the state and federal levels, and is subject to change in the future. If future recovery of costs ceases to be probable, asset write-offs would be required to be recognized. Additionally, regulatory agencies can provide flexibility in the manner and timing of the depreciation of property, plant and equipment and amortization of regulatory assets. Total regulatory assets were $17.3 million as of December 31, 2011 and $16.0 million as of December 31, 2010. Total regulatory liabilities were $0.5 million as of December 31, 2011 and no regulatory liabilities as of December 31, 2010.

Impairment of Goodwill

We perform an annual goodwill impairment test and update the test if events or circumstances occur that would more likely than not reduce the fair value of a reporting unit below its carrying amount. No impairments of goodwill were recorded in 2011, 2010 or 2009.

We had goodwill balances of $461.7 million and $267.9 million at December 31, 2011 and 2010, respectively. The increase in 2011 resulted from the acquisition of Big Sandy.

We primarily use a discounted cash flow analysis to determine fair value for our reporting unit. Key assumptions in the determination of fair value include the use of an appropriate discount rate and estimated future cash flows. In estimating cash flows, we incorporate expected long-term growth rates in key markets served by our operations, regulatory stability, and the ability to renew contracts, as well as other factors that affect our revenue, expense and capital expenditure projections.

The long-term growth rates used for our reporting unit reflect continued expansion of our assets, driven by new natural gas supplies such as shale gas and increasing demand for natural gas transportation capacity on our pipeline systems primarily as a result of forecasted growth in natural gas fired electric generation plants. We assumed a long-term growth rate of 3% for our 2011 goodwill impairment analysis. Had we assumed a 100 basis point lower growth rate for our reporting unit, there would have been no impairment of goodwill.

We continue to monitor the effects of the economic downturn that global economies are currently facing on the long-term cost of capital utilized to calculate our reporting unit fair value. In evaluating our reporting unit for our 2011 goodwill impairment analysis, we assumed a weighted-average cost of capital that market participants would use in evaluating our business of 8.4%. Had we assumed a 100 basis point increase in the weighted-average cost of capital for our reporting unit, there would have been no impairment of goodwill.

Based on the results of our annual impairment testing, the fair value of our reporting unit at April 1, 2011 significantly exceeded its carrying value. No triggering events or changes in circumstances occurred during the period April 1, 2011 (our testing date) through December 31, 2011 that would warrant re-testing for goodwill impairment.

Revenue Recognition

Revenues from the transportation, storage and gathering of natural gas and storage of LNG are recognized when the service is provided. Revenues related to these services provided but not yet billed are estimated each month. These estimates are generally based on contract data, regulatory information and preliminary throughput and allocation measurements. Final bills for the current month are billed and collected in the following month. Differences between actual and estimated unbilled revenues are immaterial.

LIQUIDITY AND CAPITAL RESOURCES

Known Trends and Uncertainties

We will rely upon cash flows from operations, including cash distributions received from Gulfstream and Market Hub, and various financing transactions, which may include issuances of short-term and long-term debt, to fund our liquidity and capital requirements for 2012. As of December 31, 2011, we had negative net working capital of $204.3 million compared to negative $0.6 million as of December 31, 2010. The December 31, 2011 balance included the East Tennessee notes payable of $150.0 million, note payable on demand to Market Hub of $30.5 million and commercial paper of $27.0 million. The December 31, 2010 balance included $34.0 million for the note payable on demand to Market Hub.

We have access to a credit facility, with available capacity of $673.0 million at December 31, 2011, which is used to manage working capital requirements. Given that we expect to continue to pursue expansion opportunities over the next several years, capital resources may continue to include commercial paper, short-term borrowings under our current credit facility and possibly securing additional sources of capital including debt and/or equity.

In October 2011, we executed a new $700.0 million credit facility to replace our existing $500.0 million credit facility which was due to expire in July 2012. After executing the new credit facility, we established a commercial paper program providing for the issuance of up to $700.0 million of commercial paper to fund our short-term borrowing needs, including the initial funding of capital expenditures. Our new credit facility, which expires in October 2016, is available to repay our commercial paper, if necessary. Amounts outstanding under the commercial paper program reduce the borrowings available under our credit facility.

Cash flows from operations are fairly stable given that most of our revenues and those of our equity affiliates are derived from operations under firm contracts. However, total operating cash flows are subject to a number of factors, including, but not limited to, contract renewal rates and cash distributions from our equity affiliates, Gulfstream and Market Hub. The amount of cash distributed to us, and the amount of cash we may be required to fund is determined by our equity affiliates based on operating cash flows and other factors as determined by the management of our equity affiliates. While we participate on the management committees of these equity affiliates, determination of the amount of distributions and contributions, if any, are not within our control. We received total distributions from equity affiliates of $125.5 million in 2011, $87.2 million in 2010 and $144.8 million in 2009. The higher distributions in 2009 were primarily from net proceeds received by Gulfstream as a result of their $300.0 million debt issuance in May 2009. As discussed in Item 8. Financial Statements and Supplementary Data, Note 1 of Notes to the Consolidated Financial Statements, a portion of these distributions are classified within Operating Cash Flows and the remainder is classified as Investing Cash Flows. See Item 1A. Risk Factors for discussion of other factors that could affect our cash flows.

We project 2012 capital expenditures of $30 million to be used to complete expansion projects put into commercial service during 2011. As we execute on our strategic objectives around organic expansion and acquisitions, the timing and extent of our expenditures could vary significantly from year to year depending primarily on general economic conditions and market requirements. In addition, we intend to refinance the $150.0 million note payable at East Tennessee due in 2012. The Market Hub note matures in 2012 and we expect to renew it prior to its expiration date. As a result of our ongoing strong earnings performance expected in existing operations, we expect to maintain a capital structure and liquidity profile that supports our strategic objectives and therefore will continue to monitor market requirements and our liquidity and make adjustments to these plans as needed.

Operating Cash Flows

Net cash provided by operating activities increased $35.3 million to $220.1 million in 2011 compared to 2010. This increase was driven primarily by distributions received from Gulfstream related to the additional 24.5% interest acquired in November 2010.

Net cash provided by operating activities increased $25.1 million to $184.8 million in 2010 compared to 2009. This increase was driven by a full year of earnings from Ozark in 2010, as well as increased distributions received from Market Hub and collection of receivables primarily at Ozark in 2010.

Investing Cash Flows

Net cash flows used in investing activities totaled $286.0 million in 2011 compared to $507.8 million in 2010. The $221.8 million change was driven mainly by:

•

$199.5 million of net proceeds in 2011 from the liquidation of available-for-sale securities that were held as collateral for our term loan as compared to $209.0 million of net purchases in 2010 for the collateral securities, partially offset by

•

$389.6 million for the acquisition of Big Sandy in 2011 as compared to $256.6 million for an additional 24.5% interest in Gulfstream in 2010, and

•

a $72.6 million increase in capital expenditures primarily due to the NET expansion project at East Tennessee.

Net cash flows used in investing activities totaled $507.8 million in 2010 compared to $249.4 million in 2009. The $258.4 million change was driven mainly by:

•

$256.6 million associated with our acquisition of an additional 24.5% interest in Gulfstream in 2010,

•

$209.0 million of net purchases in 2010 of available-for-sale securities that are held as collateral for a term loan as compared to $31.6 million of proceeds in 2009 from the liquidation of such securities,

•

a $70.5 million distribution received from Gulfstream resulting from their $300.0 million debt issuance in 2009, and

•

a $5.5 million increase in capital expenditures primarily due to the NET project in 2010 at East Tennessee, partially offset by

•

the $294.5 million acquisition of Ozark in 2009, and

•

a $14.2 million decrease in investment expenditures in 2010 primarily due to cost savings for Market Hub’s multi-year expansion projects.

Capital and Investment Expenditures


	2011		2010		2009
	(in millions)
Capital Expenditures
Gas Transportation and Storage(a)	$	98.4	$	25.8	$	20.3
Investment Expenditures
Gulfstream(b)		3.8		5.9		9.8
Market Hub		13.5		16.6		26.9

Total capital and investment expenditures	$	115.7	$	48.3	$	57.0

(a)	Excludes the acquisitions of Big Sandy in 2011 and Ozark in 2009.

(b)	Excludes the acquisition of an additional 24.5% interest in Gulfstream in 2010.

Capital and investment expenditures for 2011 totaled $115.7 million and included $102.8 million for expansion projects and $12.9 million for maintenance and other projects. Expansion capital and investment expenditures in 2011 represented the East Tennessee NET project and cavern expansions at Market Hub, both of which went into commercial service during 2011.

We project 2012 capital and investment expenditures of approximately $49 million, of which $30 million is expected to be used to complete expansion projects put into service during 2011, and $19 million to be used for maintenance and other projects.

We continue to evaluate customers’ needs for incremental expansion opportunities at East Tennessee, Big Sandy, Gulfstream and Market Hub. In addition, we are assessing the needs of our Ozark customers for additional transportation services. We expect that significant natural gas infrastructure, including both natural gas transportation and storage with links to growing gas supplies and markets, will be needed over time to serve growth in gas-fired power generation, oil-to-gas conversions, industrial development and attachments to new gas supply.

Based on our financing activities in 2011, we have further enhanced our position to execute incremental organic growth and acquisition opportunities.

Financing Cash Flows

Net cash provided by financing activities totaled $39.3 million in 2011 compared to $338.2 million in 2010. The $298.9 million change was driven mainly by:

•

$20.6 million of net debt issuances in 2011, including net revolver borrowings and commercial paper, compared to $265.8 million of net issuances in 2010,

•

$43.4 million increase in distributions to partners in 2011 compared to the same period in 2010, as a result of increased distribution rates, limited partner units outstanding and higher incentive distribution rights, and

•

$217.9 million of proceeds from the 2011 issuance of common units used to fund a portion of the Big Sandy acquisition as compared to $220.8 million of net proceeds received from the issuance of units associated with the acquisition of the additional interest in Gulfstream in 2010, partially offset by

•

a $7.4 million payment on debt owed to a subsidiary of Spectra Energy assumed in the Gulfstream acquisition in 2010.

Net cash provided by financing activities totaled $338.2 million in 2010 compared to $71.0 million cash provided in 2009. The $267.2 million change was driven mainly by:

•

$265.8 million net issuances of long-term debt in 2010,

•

$220.8 million of net proceeds received from the issuance of units associated with the acquisition of an additional Gulfstream interest in 2010, and

•

$6.5 million of net proceeds on note payable to affiliates in 2010 versus $22.5 million of net payments in the same period in 2009, partially offset by

•

$212.2 million of net proceeds received from the issuance of units associated with the Ozark acquisition in 2009,

•

$27.5 million increase in distributions to partners in 2010 compared to the same period in 2009, as a result of increased distribution rates and incentive distribution rights in 2010, and

•

a $7.4 million payment on debt owed to a subsidiary of Spectra Energy assumed in the Gulfstream acquisition in 2010.

Acquisition of Big Sandy. On July 1, 2011, we completed the acquisition of Big Sandy from EQT for approximately $390 million in cash. On June 14, 2011, we issued 7.2 million common units to the public, representing limited partner interests, and 0.1 million general partner units to Spectra Energy resulting in net proceeds of $217.9 million. The proceeds from this offering were used to fund a portion of the purchase price of Big Sandy.

Acquisition of Additional Gulfstream Interest. In November 2010, we acquired an additional 24.5% interest in Gulfstream from a subsidiary of Spectra Energy for approximately $330.0 million. The transaction was initially funded by $256.6 million drawn on our available bank credit facility, issuance of $66.0 million in common and general partner units and the assumption of approximately $7.4 million in debt owed to a subsidiary of Spectra Energy. Following this transaction, we issued 6.9 million common units to the public, representing limited partner interests, and 0.1 million general partner units to Spectra Energy, resulting in net proceeds of $221.0 million that were used to repay the $7.4 million debt assumed in the acquisition and purchase $209.0 million of qualifying investment-grade securities used as collateral for $207.2 million of new term debt. The remaining $4.6 million was used for general partnership purposes.

In the fourth quarter of 2010, the credit facility was amended to allow up to $275.0 million of new term loans. We borrowed $207.2 million in new term loans and used the proceeds to repay revolver borrowings. The revolver borrowings were incurred to fund a portion of the cash payment of the Gulfstream acquisition. Our obligations under the term borrowings were secured by qualifying investment-grade securities. The term loans were repaid in 2011.

Ozark Acquisition. In May 2009, we acquired all of the ownership interests of NOARK from Atlas for approximately $294.5 million. The transaction was initially funded by $218.0 million drawn on our available bank credit facility, $70.0 million borrowed under a credit facility with a subsidiary of Spectra Energy and $6.5 million from cash on hand. This transaction was partially refinanced in the second quarter of 2009 through the

issuance of 9.8 million common units to the public, representing limited partner interests, and 0.2 million general partner units to Spectra Energy, resulting in net proceeds of $212.2 million that was used to repay $142.2 million drawn on our bank credit facility and $70.0 million drawn on the credit facility with a subsidiary of Spectra Energy. Effective with the $70.0 million repayment, the credit facility with the subsidiary of Spectra Energy was terminated.

New Debt Issuance, Available Credit Facility and Restrictive Debt Covenants. On June 9, 2011, we issued $500.0 million aggregate principal amount of unsecured senior notes, including $250.0 million 2.95% senior note due 2016 and $250.0 million 4.60% senior notes due 2021. The net proceeds from the offering were used to repay all of the outstanding borrowings under our term loan and a significant portion of the funds borrowed under our credit facility. The remaining balance of the proceeds was used for general partnership purposes.

In October 2011, we entered into a new $700.0 million revolving credit agreement which replaced our $500.0 million credit facility. Our new credit facility expires in 2016 and replaces the facility that was scheduled to expire in 2012. After executing the new credit agreement, we established a commercial paper program providing for the issuance of up to $700.0 million of commercial paper to fund our short-term borrowing needs, including the initial funding of capital expenditures. Our new credit facility is available to repay our commercial paper, if necessary. Amounts outstanding under the commercial paper program reduce the borrowings available under our credit facility. As of December 31, 2011, we had $673.0 million available under the revolving credit facility.

The credit agreement contains various financial and other covenants, including the maintenance of consolidated leverage ratio, as defined in the agreement. Failure to meet those covenants beyond applicable grace periods could result in accelerated due dates and/or termination of the agreement. As of December 31, 2011, we were in compliance with those covenants. In addition, the credit agreement allows for the acceleration of payments or termination of the agreement due to nonpayment, or in some cases, due to the acceleration of our other significant indebtedness or other significant indebtedness of some of our subsidiaries. The credit agreement does not contain provisions that trigger an acceleration of indebtedness based solely on the occurrence of an adverse change in our financial condition or results of operations.

As noted above, the terms of the credit agreement requires us to maintain a consolidated leverage ratio of adjusted consolidated indebtedness to adjusted consolidated earnings before Interest, taxes, depreciation and amortization, as defined in the agreement, of 5.0 or less. As of December 31, 2011, the ratio was 2.7.

Credit Ratings. In June 2011, we received senior unsecured credit ratings of BBB/Stable from Standard and Poor’s and Fitch Ratings and Baa3/Stable from Moody’s investor services. Our credit ratings are dependent upon, among other factors, our ability to generate sufficient cash to fund capital and investment expenditures, our results of operations, market conditions, the leverage of Spectra Energy and other factors. Our credit ratings could impact our ability to raise capital in the future, impact the cost of capital and, as a result, have an impact on our liquidity.

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

We have increased the quarterly cash distributions each quarter of 2011 from $0.45 per limited partner unit for the fourth quarter of 2010 to $0.475 per limited partner unit for the fourth quarter of 2011, or 6%. A cash distribution to our unitholders of $0.475 per limited partner unit was declared on January 23, 2012 and was paid on February 14, 2012.

Spectra Energy Partners’ board evaluates each individual quarterly distribution decision based on an assessment of growth in cash available to make distributions. Growth in our cash available to make distributions over time is dependent on incremental organic growth expansion, third party acquisitions or acquisitions from Spectra Energy. Our amount of Available Cash depends primarily upon our cash flows, including cash flow from financial reserves and working capital or other borrowings, and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record a net loss for financial accounting purposes and may not make cash distributions during periods when we record net earnings for financial accounting purposes.

Subordinated Unit Conversion. On August 13, 2010, all subordinated units were converted into common units on a one-for-one basis. Since there are no subordinated units, distributions are shared equally among the limited partner units owed by subsidiaries of Spectra Energy and limited partner units owned by other common unitholders.

Other Financing Matters. We have an effective shelf registration statement on file with the Securities and Exchange Commission (SEC) to register the issuance of unspecified amounts of limited partner common units and various debt securities.

Off Balance Sheet Arrangements

We do not have any off-balance sheet financing entities or structures with third parties, except for normal operating lease arrangements and financings entered into by equity investment pipeline operations. These debt obligations do not contain provisions requiring accelerated payment of the related obligation in the event of specified declines in credit ratings.

Gulfstream has $1,150.0 million aggregate principal amount of senior notes outstanding, none of which is included on our consolidated balance sheets.

Contractual Obligations

We enter into contracts that require payment of cash at certain specified periods based on certain specified minimum quantities and prices. The following table summarizes our contractual cash obligations for each of the periods presented. It is expected that the majority of these current liabilities will be paid in cash in 2012.

Contractual Obligations as of December 31, 2011


	Payments Due by Period
	Total		2012		2013 & 2014		2015 & 2016		2017 & Beyond
	(in millions)
Long-term debt, including current maturities(a)	$	799.9	$	177.2	$	37.8	$	283.7	$	301.2
Operating leases		3.0		0.1		0.2		0.2		2.5
Purchase obligations		0.6		0.6		—		—		—

Total contractual cash obligations	$	803.5	$	177.9	$	38.0	$	283.9	$	303.7

(a)	Excludes commercial paper and note payable to affiliates as both are current liabilities. See Note 12 of Notes to Consolidated Financial Statements. Amounts include estimated scheduled interest payments over the life of the associated debt.

Quantitative and Qualitative Disclosures About Market Risk

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

Interest Rate Risk

We are exposed to risk resulting from changes in interest rates as a result of our issuance of variable and fixed-rate debt and commercial paper. We manage our interest rate exposure by limiting our variable-rate exposures to percentages of total debt and by monitoring the effects of market changes in interest rates. We also enter into financial derivative instruments, including, but not limited to, interest rate swaps to manage and mitigate interest rate risk exposure. See Item 8. Financial Statements and Supplementary Data, Notes 1, 12 and 15 of Notes to Consolidated Financial Statements.

Based on a sensitivity analysis as of December 31, 2011, it was estimated that if short-term interest rates average 100 basis points higher (lower) in 2012 than in 2011, interest expense, net of offsetting impacts in interest income, would increase (decrease) by $0.6 million. Comparatively, based on a sensitivity analysis as of December 31, 2010, had short-term interest rates averaged 100 basis points higher (lower) in 2011 than in 2010, it was estimated that interest expense, net of offsetting interest income, would have fluctuated by $1.5 million. These amounts were estimated by considering the effect of the hypothetical short-term interest rates on variable-rate debt outstanding, adjusted for interest rate hedges, investments, and cash and cash equivalents outstanding as of December 31, 2011 and 2010.

In 2008, we entered into a series of two and three-year “pay fixed — receive floating” interest rate swap agreements with Spectra Energy to mitigate our exposure to variable interest rates on $140.0 million of loans outstanding under the revolving credit facility. In 2009, we entered into a series of three-year “pay fixed — receive floating” interest rate swap agreements with third parties to mitigate our exposure to variable interest rates on $40.0 million of loans outstanding under the revolving credit facility. In June 2010, our two-year interest rate swap agreements with Spectra Energy on $25.0 million of loans outstanding under the revolving credit facility expired. In 2011, our remaining floating-to-fixed interest rate swaps expired or were terminated in conjunction with the pay down of our credit facility. As of December 31, 2011, we did not have any derivatives outstanding.

Credit Risk

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

We had one customer that represented approximately 25% of the gross fair value of trade accounts receivable at December 31, 2011.

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

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

Market Hub, our 50% equity investment, also has gas imbalances created primarily by park-and-loan services. Increases in gas prices and gas price volatility can materially increase Market Hub’s credit risk related to gas loaned to customers. The highest amount of gas loaned out by Market Hub during 2011 was approximately 16.5 Bcf. The market value of that volume, assuming an average market price of $4.00 per MMBtu, would be $66.0 million. Market Hub’s credit exposure from gas loans is managed consistent with the program described above, and Market Hub obtains security deposits as necessary from third parties and affiliates to cover any excess exposure.

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

OTHER ISSUES

Global Climate Change. Policymakers at regional, federal and international levels continue to evaluate potential legislative and regulatory compliance mechanisms to achieve reductions in global GHG emissions in an effort to address the challenge of climate change. Certain of our assets and operations are subject to direct and indirect effects of current global climate change regulatory actions in their respective jurisdictions, and it is likely that other assets and operations will become subject to direct and indirect effects of current and possible future global climate change regulatory actions.

The current international climate framework, the United Nations-sponsored Kyoto Protocol, prescribes specific targets to reduce GHG emissions for developed countries for the 2008-2012 period. The Kyoto Protocol expires in 2012 and has not been signed by the United States. United Nations-sponsored international negotiations were held in Durban, South Africa in December 2011 with the intent of defining a future agreement for 2012 and beyond. An non-binding agreement was reached to develop a road map aimed at creating a global agreement on climate action to be implemented by 2020.

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

The United States is not a signatory to the Kyoto Protocol, nor has the federal government adopted a mandatory GHG emissions reduction requirement. However, the EPA issued a final Mandatory Greenhouse Gas Reporting rule in 2009 that required annual reporting of GHG emissions data from certain operations beginning in 2010. In November 2010, the EPA released additional requirements for natural gas system reporting that will expand the reporting requirements for GHG emissions in 2011. These reporting requirements are not anticipated to have a material impact on our consolidated results of operations, financial position or cash flows. The EPA also finalized a Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule in May 2010 to address how GHG emissions would be regulated under the existing Clean Air Act. Regulation began in 2011, and over time, certain facilities will be subject to this regulation. Some new construction and modification projects in the future may be subject to this regulation as well. At this time, it is not anticipated that the costs will be material.

In addition, several legislative proposals that would impose GHG emissions constraints have been considered by the U.S. Congress. To date, no such legislation has been enacted into law. A number of states are establishing or considering state or regional programs that would mandate reductions in GHG emissions. These regional programs include the Regional Greenhouse Gas Initiative which applies only to power producers in select northeastern states and the Midwestern Greenhouse Gas Reduction Accord which includes six midwestern states and one Canadian province. We expect some of our assets and operations could be affected either directly or indirectly by state or regional programs. However, as the key details of future GHG restrictions and compliance mechanisms remain undefined, the likely future effects on our business are highly uncertain.

Other. For additional information on other issues, see Item 8. Financial Statements and Supplementary Data, Notes 6 and 14 of Notes to Consolidated Financial Statements.

New Accounting Pronouncements

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

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

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

Item 8. Financial Statements and Supplementary Data.

Management’s Annual Report on Internal Control over Financial Reporting

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

The management of our General Partner, including our Chief Executive Officer and Chief Financial Officer, has conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2011 based on the framework in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that evaluation, management concluded that our internal control over financial reporting was effective at the reasonable assurance level as of December 31, 2011.

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

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of Spectra Energy Partners GP, LLC and Unitholders of Spectra Energy Partners, LP:

We have audited the accompanying consolidated balance sheets of Spectra Energy Partners, LP and subsidiaries (the “Company”) as of December 31, 2011 and 2010, and the related consolidated statements of operations, cash flows, and partners’ capital and comprehensive income for each of the three years in the period ended December 31, 2011. Our audits also included the financial statement schedule listed in the Index at Item 15. We also have audited the Company’s internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Controls over Financial Reporting. Our responsibility is to express an opinion on these financial statements and financial statement schedule and an opinion on the Company’s internal control over financial reporting 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 and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

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

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

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Spectra Energy Partners, LP and subsidiaries as of December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

/s/	Deloitte & Touche LLP

Houston, Texas

February 28, 2012

SPECTRA ENERGY PARTNERS, LP

CONSOLIDATED STATEMENTS OF OPERATIONS

(In millions, except per-unit amounts)


	Years Ended December 31,
	2011		2010			2009
Operating Revenues
Transportation of natural gas	$	182.4	$	169.0		$	150.7
Storage of natural gas and other		22.6		28.7			28.2

Total operating revenues		205.0		197.7			178.9

Operating Expenses
Operating, maintenance and other		28.4		32.6			24.7
Operating, maintenance and other — affiliates		43.7		40.3			35.6
Depreciation and amortization		33.2		29.4			28.5
Property and other taxes		11.5		7.7			7.3

Total operating expenses		116.8		110.0			96.1

Operating Income		88.2		87.7			82.8

Other Income and Expenses
Equity in earnings of unconsolidated affiliates		107.3		75.1			70.7
Other income and expenses, net		2.1		0.8			0.1

Total other income and expenses		109.4		75.9			70.8

Interest Income		0.5		0.1			0.2
Interest Expense		23.2		11.9			11.5
Interest Expense — Affiliates		1.8		4.3			5.2

Earnings Before Income Taxes		173.1		147.5			137.1
Income Tax Expense (Benefit)		1.1		(0.4	)		1.2

Net Income	$	172.0	$	147.9		$	135.9

Calculation of Limited Partners’ Interest in Net Income:
Net income	$	172.0	$	147.9		$	135.9
Less:
General partner’s interest in net income		20.3		10.6			5.7

Limited partners’ interest in net income	$	151.7	$	137.3		$	130.2

Weighted average limited partners units outstanding — basic and diluted		93.1		81.0			76.4
Net income per limited partner unit — basic and diluted	$	1.63	$	1.70		$	1.71
Distributions paid per limited partner unit during the periods presented	$	1.845	$	1.70		$	1.51

See Notes to Consolidated Financial Statements.

SPECTRA ENERGY PARTNERS, LP

CONSOLIDATED BALANCE SHEETS

(In millions)


	December 31,
	2011		2010
ASSETS
Current Assets
Cash and cash equivalents	$	0.8	$	27.4
Receivables, trade (net of allowance for doubtful accounts of $0.1 and $0.3 at December 31, 2011 and 2010, respectively)		22.3		18.4
Receivables — affiliates		1.3		0.9
Natural gas imbalance receivables		3.5		4.1
Natural gas imbalance receivables — affiliates		3.2		1.4
Inventory		7.0		3.8
Other		3.5		3.0

Total current assets		41.6		59.0

Investments and Other Assets
Investments in unconsolidated affiliates		727.2		728.6
Goodwill		461.7		267.9
Other investments		0.1		209.1

Total investments and other assets		1,189.0		1,205.6

Property, Plant and Equipment
Cost		1,439.3		1,148.3
Less accumulated depreciation and amortization		234.1		206.8

Net property, plant and equipment		1,205.2		941.5

Regulatory Assets and Deferred Debits		21.1		16.4

Total Assets	$	2,456.9	$	2,222.5

See Notes to Consolidated Financial Statements.

SPECTRA ENERGY PARTNERS, LP

CONSOLIDATED BALANCE SHEETS

(In millions)


	December 31,
	2011		2010
LIABILITIES AND PARTNERS’ CAPITAL
Current Liabilities
Accounts payable	$	4.7	$	3.9
Accounts payable — affiliates		16.0		9.9
Taxes accrued		7.1		3.9
Natural gas imbalance payables		5.0		2.8
Natural gas imbalance payables — affiliates		1.9		—
Note payable — affiliates		30.5		34.0
Current maturities of long-term debt		150.0		—
Commercial paper		27.0		—
Other		3.7		3.4
Other — affiliates		—		1.7

Total current liabilities		245.9		59.6

Long-term Debt		499.4		655.8

Deferred Credits and Other Liabilities
Deferred income taxes		8.0		9.0
Other		5.9		3.7

Total deferred credits and other liabilities		13.9		12.7

Commitments and Contingencies

Partners’ Capital
Common units (96.3 million and 89.2 million units issued and outstanding at December 31, 2011 and 2010, respectively)		1,653.6		1,458.7
General partner units (2.0 million and 1.8 million units outstanding at December 31, 2011 and December 31, 2010, respectively)		39.6		32.9
Accumulated other comprehensive income		4.5		2.8

Total partners’ capital		1,697.7		1,494.4

Total Liabilities and Partners’ Capital	$	2,456.9	$	2,222.5

See Notes to Consolidated Financial Statements.

SPECTRA ENERGY PARTNERS, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)


	Years Ended December 31,
	2011			2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	172.0		$	147.9		$	135.9
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		33.2			29.4			28.5
Deferred income tax expense (benefit)		1.1			(1.0	)		1.2
Equity in earnings of unconsolidated affiliates		(107.3	)		(75.1	)		(70.7	)
Distributions received from unconsolidated affiliates		116.3			81.1			74.3
Decrease (increase) in:
Receivables		(4.3	)		2.0			(4.8	)
Taxes receivable — affiliates		—			(0.1	)		(0.2	)
Other current assets		(0.1	)		0.1			(0.7	)
Increase (decrease) in:
Accounts payable		4.9			1.9			(1.0	)
Taxes accrued		2.9			(0.2	)		(0.2	)
Other current liabilities		(0.9	)		(1.2	)		(4.5	)
Other, assets		1.7			(0.1	)		1.3
Other, liabilities		0.6			0.1			0.6

Net cash provided by operating activities		220.1			184.8			159.7

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(98.4	)		(25.8	)		(20.3	)
Investment expenditures		(17.3	)		(22.5	)		(36.7	)
Acquisitions, net of cash acquired		(389.6	)		(256.6	)		(294.5	)
Distributions received from unconsolidated affiliates		9.2			6.1			70.5
Purchases of available-for-sale securities		(891.6	)		(239.0	)		—
Proceeds from sales and maturities of available-for-sale securities		1,091.1			30.0			31.6
Other		10.6			—			—

Net cash used in investing activities		(286.0	)		(507.8	)		(249.4	)

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from issuance of long-term debt		499.4			207.2			—
Payments for the redemption of long-term debt		(207.2	)		—			—
Net increase (decrease) in revolving credit facility borrowings		(298.6	)		58.6			—
Net increase in commercial paper		27.0			—			—
Proceeds from issuance of units		217.9			220.8			212.2
Proceeds from notes payable — affiliates		26.0			30.3			77.0
Payments on notes payable — affiliates		(29.5	)		(23.8	)		(99.5	)
Payments on notes assumed in acquisition — affiliates		—			(7.4	)		—
Distributions to partners		(189.3	)		(145.9	)		(118.4	)
Other		(6.4	)		(1.6	)		(0.3	)

Net cash provided by financing activities		39.3			338.2			71.0

Net increase (decrease) in cash and cash equivalents		(26.6	)		15.2			(18.7	)
Cash and cash equivalents at beginning of the period		27.4			12.2			30.9

Cash and cash equivalents at end of the period	$	0.8		$	27.4		$	12.2


Supplemental Disclosures
Cash paid for interest, net of amount capitalized	$	23.0		$	15.7		$	16.2
Cash paid for income taxes		—			0.7			0.1
Property, plant and equipment noncash accruals		2.8			0.8			0.7
Deemed contributions from General Partner for services provided		—			1.4			—

See Notes to Consolidated Financial Statements.

SPECTRA ENERGY PARTNERS, LP

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

AND COMPREHENSIVE INCOME

(In millions)


	Partners’ Capital									Accumulated Other Comprehensive Income (Loss)			Total
	Limited Partners						General Partner
	Common			Subordinated			General Partner
December 31, 2008	$	794.5		$	304.7		$	21.4		$	(2.2	)	$	1,118.4

Net income		93.9			36.3			5.7			—			135.9
Unrealized mark-to-market net loss on hedges		—			—			—			(4.9	)		(4.9	)
Reclassification of cash flow hedges into earnings		—			—			—			4.9			4.9

Total comprehensive income														135.9

Issuance of units		207.8			—			4.4			—			212.2
Attributed deferred tax expense		(0.1	)		—			—			—			(0.1	)
Distributions to partners		(81.4	)		(32.7	)		(4.3	)		—			(118.4	)
Other, net		0.3			0.2			—			—			0.5

December 31, 2009		1,015.0			308.5			27.2			(2.2	)		1,348.5

Net income		119.0			18.3			10.6			—			147.9
Unrealized mark-to-market net loss on hedges		—			—			—			(2.1	)		(2.1	)
Reclassification of cash flow hedges into earnings		—			—			—			4.6			4.6
Additional equity interest in Gulfstream’s other comprehensive income		—			—			—			2.5			2.5

Total comprehensive income														152.9

Excess purchase price over net acquired assets in Gulfstream acquisition		(147.3	)		—			(2.8	)		—			(150.1	)
Issuance of units		281.1			—			5.9			—			287.0
Attributed deferred tax benefit		0.5			0.1			—			—			0.6
Distributions to partners		(109.4	)		(27.2	)		(9.3	)		—			(145.9	)
Contributions from general partner		—			—			1.4			—			1.4
Conversion of subordinated units to common units		299.7			(299.7	)		—			—			—
Other, net		0.1			—			(0.1	)		—			—

December 31, 2010		1,458.7			—			32.9			2.8			1,494.4

Net income		151.7			—			20.3			—			172.0
Reclassification of cash flow hedges into earnings		—			—			—			1.7			1.7

Total comprehensive income														173.7

Issuance of units		213.6			—			4.5			—			218.1
Attributed deferred tax benefit		0.7			—			—			—			0.7
Distributions to partners		(171.2	)		—			(18.1	)		—			(189.3	)
Other, net		0.1			—			—			—			0.1

December 31, 2011	$	1,653.6		$	—		$	39.6		$	4.5		$	1,697.7

See Notes to Consolidated Financial Statements.

SPECTRA ENERGY PARTNERS, LP

Notes to Consolidated Financial Statements

INDEX


		Page
1.	Summary of Operations and Significant Accounting Policies		68
2.	Corrections of Immaterial Error		72
3.	Acquisitions		73
4.	Transactions with Affiliates		74
5.	Business Segments		75
6.	Regulatory Matters		77
7.	Net Income per Limited Partner Unit and Cash Distributions		78
8.	Marketable Securities		79
9.	Investments in Unconsolidated Affiliates		79
10.	Goodwill		80
11.	Property, Plant and Equipment		81
12.	Debt and Credit Facility		81
13.	Fair Value Measurements		83
14.	Commitments and Contingencies		84
15.	Risk Management and Hedging Activities		85
16.	Sale of Common Units		86
17.	Equity-Based Compensation		86
18.	Quarterly Financial Data (Unaudited)		87

1. Summary of Operations and Significant Accounting Policies

Nature of Operations. Spectra Energy Partners, LP, through its subsidiaries and equity affiliates, is engaged in the transportation and gathering of natural gas through interstate pipeline systems that are located in the southeastern quadrant of the United States, and the storage of natural gas in underground facilities that are located in southeast Texas, south central Louisiana and southwest Virginia. We are a Delaware master limited partnership (MLP) formed on March 19, 2007 and completed our initial public offering (IPO) on July 2, 2007. As of December 31, 2011, Spectra Energy Corp (Spectra Energy) and its subsidiaries collectively owned 64% of us and the remaining 36% was publicly owned.

Basis of Presentation. The Consolidated Financial Statements for our partnership reflect the consolidation of East Tennessee Natural Gas, LLC (East Tennessee), Ozark Gas Transmission, L.L.C. (Ozark Gas Transmission) and Ozark Gas Gathering, L.L.C. (Ozark Gas Gathering) (collectively, hereafter referred to as Ozark), Big Sandy Pipeline, LLC (Big Sandy) and Saltville Gas Storage L.L.C. (Saltville), of which we own 100% of each. Intercompany balances and transactions have been eliminated in consolidation.

We account for investments in 20% to 50%-owned affiliates under the equity method. Our 50% investment in Market Hub Partners Holding (Market Hub) and 49% investment in Gulfstream Natural Gas System, L.L.C. (Gulfstream) are accounted for under the equity method.

Our costs of doing business have been reflected in our financial accounting records for the periods presented. These costs include direct charges and allocations from Spectra Energy and its affiliates for business

services, such as payroll, accounts payable and facilities management; corporate services, such as finance and accounting, legal, human resources, investor relations, public and regulatory policy, and senior executives; and pension and other post-retirement benefit costs.

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

Fair Value Measurements. We measure the fair value of financial assets and liabilities by maximizing the use of observable inputs and minimizing the use of unobservable inputs. Fair value is the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date.

Cost-Based 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 or for instances where the regulator provides current rates that are intended to recover costs that are expected to be incurred in the future. Accordingly, we record assets and liabilities that result from the regulated ratemaking process that may not be recorded under GAAP for non-regulated entities. We continually assess whether regulatory assets are probable of future recovery by considering factors such as applicable regulatory changes and recent rate orders to other regulated entities. Based on this assessment, we believe our existing regulatory assets are probable of recovery. These regulatory assets and liabilities are classified in the Consolidated Balance Sheets mostly as Regulatory Assets and Deferred Debits and Current Liabilities. We evaluate our regulated assets, and consider factors such as regulatory changes and the effect of competition. If cost-based regulation ends or competition increases, we may have to reduce our asset balances to reflect a market basis less than cost and write-off the associated regulatory assets. See Note 6 for further discussion.

Revenue Recognition. Revenues from the transportation, gathering and storage of natural gas and the storage of liquefied natural gas (LNG) are recognized when the service is provided. Revenues related to these services provided but not yet billed are estimated each month. These estimates are generally based on contract data, regulatory information and preliminary throughput and allocation measurements. Final bills for the current month are billed and collected in the following month. Differences between actual and estimated unbilled revenues are immaterial.

We also have one long-term customer contract that has billed amounts that decline over the term of the contract. We recognize revenue on a straight line basis with the difference between the amount recognized and billed deferred in Other within Deferred Credits and Other Liabilities.

Customers accounting for 10% or more of consolidated revenues during 2011, 2010 or 2009 are as follows:


	% of Revenues
Customer	2011			2010			2009
EQT Corporation		12	%		(a	)		(a	)
Atmos Energy Corporation		(a	)		(a	)		10	%

(a)	Percentage less than 10%.

component is a non-cash item. AFUDC is capitalized as a component of Property, Plant and Equipment cost, with offsetting credits to the Consolidated Statements of Operations through Other Income and Expenses, Net for the equity component and Interest Expense for the interest expense component. After construction is completed, we are permitted to recover these costs through inclusion in the rate base and in the depreciation provision. The total amount of AFUDC included in the Consolidated Statements of Operations was $2.0 million in 2011 (an equity component of $1.7 million and an interest expense component of $0.3 million), $0.7 million in 2010 (an equity component of $0.6 million and an interest expense component of $0.1 million) and $0.1 million in 2009 (an equity component of $0.1 million).

Income Taxes. As a result of our MLP structure, we are not subject to federal income tax. Our federal taxable income or loss is reported on the respective income tax returns of our partners. However, we are subject to Tennessee income tax. Market Hub is liable to Spectra Energy for Texas income (margin) tax under a tax sharing agreement.

As of December 31, 2011, the difference between the tax basis and the reported amounts of Spectra Energy Partners’ assets and liabilities is $1.4 billion.

Cash and Cash Equivalents. Highly liquid investments with original maturities of three months or less at the date of acquisition, except for the investments that are pledged as collateral against long-term debt as discussed in Note 12, are considered cash equivalents.

Inventory. Inventory consists mainly of natural gas retained from shippers for fuel and also includes materials and supplies. Natural gas is recorded at the lower of cost or market. Materials and supplies are recorded at cost, using the average cost method.

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

Cash Flow Hedges. We have previously entered into interest rate swaps which were designated as effective cash flow hedges. For all hedge contracts, we prepare documentation of the hedge in accordance with accounting standards and assess whether the hedge contract is highly effective, both at inception and on a quarterly basis, in offsetting changes in cash flows or fair values of hedged items. Changes in the fair value of a derivative designated and qualified as a cash flow hedge, to the extent effective, are reported as Accumulated Other Comprehensive Income (Loss) (AOCI) until earnings are affected by the hedged transaction. As of December 31, 2011, we did not have any cash flow hedges outstanding.

Investments. We may actively invest a portion of our cash balances in various financial instruments, including taxable debt securities. In addition, we invest in short-term money market securities, some of which are restricted due to debt collateral requirements. We classify all short term money market securities that are pledged as collateral as available-for-sale (AFS). These AFS securities and other investments in money market securities are carried at fair value. Realized gains and losses and dividend and interest income related to these securities, including any amortization of discounts or premiums arising at acquisition, are included in earnings. The cost of securities sold is determined using the specific identification method. Purchases and sales of AFS securities are presented on a gross basis within Investing Cash Flows in the accompanying Consolidated Statements of Cash Flows. We had $209.0 million of investments in marketable securities pledged as collateral against long-term debt as discussed in Note 12 at December 31, 2010 and no investments at December 31, 2011. These investments are classified within Investments and Other Assets — Other Investments on the Consolidated Balance Sheet.

Goodwill. We perform our goodwill impairment test annually and evaluate goodwill when events or changes in circumstances indicate that its carrying value may not be recoverable. No impairments of goodwill were recorded in 2011, 2010 or 2009. See Note 10 for further discussion.

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 primarily use a discounted cash flow analysis to determine fair value for our reporting unit. Key assumptions in the determination of fair value include the use of an appropriate discount rate and estimated future cash flows. In estimating cash flows, we incorporate expected long-term growth rates in key markets served by our operations, regulatory stability, the ability to renew contracts, as well as other factors that affect our revenue, expense and capital expenditure projections.

Property, Plant and Equipment. Property, plant and equipment is stated at historical cost less accumulated depreciation. We capitalize all construction-related direct labor and material costs, as well as indirect construction costs. Indirect costs include general engineering, taxes and the cost of funds used during construction. The costs of renewals and betterments that extend the useful life or increase the expected output of property, plant and equipment are also capitalized. The costs of repairs, replacements and major maintenance projects that do not extend the useful life or increase the expected output of property, plant and equipment are expensed as incurred. Depreciation is generally computed over the asset’s estimated useful life using the straight-line method.

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

Preliminary Project Costs. Project development costs, including expenditures for preliminary surveys, plans, investigations, environmental studies, regulatory applications and other costs incurred for the purpose of determining the feasibility of capital expansion projects, are capitalized for rate-regulated enterprises when it is determined that recovery of such costs through regulated revenues of the completed project is probable. Any inception-to-date costs that were initially expensed are reversed and capitalized as Property, Plant and Equipment.

Long-Lived Asset Impairments. We evaluate whether long-lived assets, excluding goodwill, have been impaired when circumstances indicate the carrying value of those assets may not be recoverable. For such long-lived assets, an impairment exists when its carrying value exceeds the sum of estimates of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. When alternative courses of action to recover the carrying amount of a long-lived asset are under consideration, a probability-weighted approach is used in 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, an 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.

market conditions resulting from events such as changes in natural gas available to our systems, the condition of an asset, a change in our intent to utilize the asset or a significant change in contracted revenues or regulatory recoveries would generally require us to reassess the cash flows related to the long-lived assets.

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

Environmental Expenditures. We expense environmental expenditures related to conditions caused by past operations that do not generate current or future revenues. Environmental expenditures related to operations that generate current or future revenues are expensed or capitalized, as appropriate. Undiscounted liabilities are recorded when the necessity for environmental remediation becomes probable and the costs can be reasonably estimated, or when other potential environmental liabilities are reasonably estimable and probable.

Segment Reporting. 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 certain criteria are met. There is no such aggregation within our defined business segment. A description of our reportable segment, Gas Transportation and Storage, consistent with how business results are reported internally to management, and the disclosure of segment information is presented in Note 5.

Consolidated Statements of Cash Flows. Cash flows from borrowings and repayments under revolving credit facilities that had documented original maturities of 90 days or less are reported on a net basis as Net Increase (Decrease) in Revolving Credit Facilities Borrowings within financing activities.

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

New Accounting Pronouncements — 2011. There were no significant accounting pronouncements adopted during 2011, 2010 or 2009 that had a material impact on our consolidated results of operations, financial position or cash flows.

2. Corrections of Immaterial Error

During the third quarter of 2011, we identified errors in our previously issued Consolidated Statements of Cash Flows related to the accounting for rollovers of outstanding borrowings under our revolving bank credit facility. These rollovers, which are extensions of borrowings beyond their scheduled due dates that did not involve the exchange of cash, were previously accounted for as cash activities and resulted in the overstatement of both Proceeds from Issuance of Long-Term Debt and Payments for the Redemption of Long-Term Debt for the years ended December 31, 2010 and 2009. Cash and Cash Equivalents and Net Cash Provided By Financing Activities as previously reported are not affected by the errors. We evaluated materiality from both a qualitative and a quantitative perspective and concluded that the errors are immaterial to our previously issued Consolidated Statements of Cash Flows.

In addition to making this correction, effective with the third quarter of 2011, we have elected to present cash borrowings and repayments under our revolving bank credit facility on a net basis for all periods presented as Net Increase (Decrease) in Revolving Credit Facility Borrowings. As these periodic borrowings and

repayments are generally of significant amounts and had terms of 90 days or less, we believe our current presentation provides users with more meaningful and relevant information about our long-term debt financing activities.

The correction and change in presentation reflected on the Consolidated Statement of Cash Flows are as follows:


	2010						2009
Years Ended December 31, 2010	Proceeds From the Issuance of Long-Term Debt			Payments for the Redemption of Long-Term Debt			Proceeds From the Issuance of Long-Term Debt			Payments for the Redemption of Long-Term Debt
	(in millions)
As previously reported	$	3,364.5		$	3,098.7		$	3,159.0		$	3,159.0
Less non-cash activity		(2,858.6	)		(2,858.6	)		(2,919.0	)		(2,919.0	)

As corrected		505.9			240.1			240.0			240.0
Less revolving credit facility activity		(298.7	)		(240.1	)		(240.0	)		(240.0	)

Long-term debt activity	$	207.2		$	—		$	—		$	—

3. Acquisitions

Big Sandy. On July 1, 2011, we completed the acquisition of Big Sandy from EQT Corporation (EQT) for approximately $390 million in cash. Big Sandy’s primary asset is a 68-mile Federal Energy Regulatory Commission (FERC) regulated natural gas pipeline system in eastern Kentucky with capacity of approximately 0.2 billion cubic feet (Bcf) per day. The Big Sandy natural gas pipeline system connects Appalachian and Huron Shale natural gas supplies to markets in the mid-Atlantic and northeast portions of the United States. EQT is the main shipper on the pipeline, with over 80% of the pipeline’s capacity. With 100% fee-based revenues and a weighted average contract life of 14 years, the acquisition of Big Sandy strengthens our portfolio of fee-based natural gas assets and is consistent with our strategy of growth through third-party acquisitions.

The assets and liabilities of Big Sandy were recorded at their respective fair values as of the purchase date and the results of operations were included in the Consolidated Financial Statements beginning as of the effective date of the acquisition. Since Big Sandy records assets and liabilities resulting from the rate making process, the fair values of the individual assets and liabilities are considered to approximate their carrying values. Big Sandy is part of the Gas Transportation and Storage segment.

The following table summarizes the fair values of the assets and liabilities acquired as of July 1, 2011.


	Purchase Price Allocation
	(in millions)
Cash purchase price	$	390.0
Working capital adjustments		(0.4	)

Total purchase price		389.6

Property, plant and equipment		196.2
Current liabilities		(0.4	)

Total assets acquired/liabilities assumed	$	195.8

Goodwill	$	193.8

The purchase price is greater than the sum of fair values of the net assets acquired, resulting in goodwill as noted above. The goodwill reflects the value of strong cash flows from stable long-term contracts. Pro forma results of operations reflecting the acquisition of Big Sandy as if the acquisition had occurred as of the beginning of the periods presented in this report do not materially differ from actual reported results.

Gulfstream. On November 30, 2010, we acquired an additional 24.5% interest in Gulfstream from a subsidiary of Spectra Energy for approximately $330.0 million, consisting of approximately $66.0 million in newly issued units, the assumption of $7.4 million in debt owed to Spectra Energy Capital LLC, a subsidiary of Spectra Energy and $256.6 million in cash, which was funded through borrowings under our credit facility. The acquisition increased our interest in Gulfstream to 49%.

The Gulfstream acquisition represented a transaction between entities under common control, but did not represent a change in reporting entity as Gulfstream is accounted for as an equity method investment. Accordingly, the Consolidated Financial Statements and related information presented herein include the results of the acquisition of additional interest in Gulfstream as of the date of the acquisition.

The additional 24.5% interest in Gulfstream was recorded at the historical book value of Spectra Energy of $179.9 million, including $2.5 million of additional equity interest in Gulfstream’s other comprehensive income. The $150.1 million excess purchase price over the book value of net assets acquired was recorded as a reduction to Partners’ Capital, and the $66.0 million of common and general partner units issued were recorded as increases to Partners’ Capital.

Following the acquisition of Gulfstream, we issued 6.9 million of our common units to the public, representing limited partner interests. The net proceeds from this offering were approximately $221.0 million, including our general partner’s proportionate unit purchase after deducting the underwriting fees. The proceeds were used to repay the $7.4 million loan assumed in the Gulfstream acquisition. The remaining $209.0 million in net proceeds (other than proceeds from our general partner) were used to purchase qualifying investment grade securities, which were assigned as collateral to secure the new term loan of an approximately equal principal amount. The proceeds of the term loan were used to repay revolving borrowings, which were incurred to fund a portion of the consideration of the Gulfstream acquisition. The approximately $4.6 million in proceeds from our general partner’s proportionate unit purchase were used for general partnership purposes.

NOARK. In May 2009, we acquired all of the ownership interests of NOARK Pipeline System Limited Partnership (NOARK) from Atlas Pipeline Partners, L.P. (Atlas) for approximately $294.5 million. NOARK’s assets consist of 100% ownership interests in Ozark Gas Transmission, a 565-mile FERC regulated interstate natural gas transmission system, and Ozark Gas Gathering, a 365-mile, fee-based, natural gas gathering system whose operations are regulated by the applicable state commissions. The transaction was initially funded by $218.0 million drawn on our available bank credit facility, $70.0 million borrowed under a credit facility with a subsidiary of Spectra Energy and $6.5 million from cash on hand. This transaction was partially refinanced through the issuance of 9.8 million common units to the public, representing limited partner interests, and 0.2 million general partner units to Spectra Energy in 2009. See Note 16 for a discussion of the sale of common units.

4. Transactions with Affiliates

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

In addition, pursuant to an agreement with Spectra Energy, Spectra Energy and its affiliates perform centralized corporate functions for us, including legal, accounting, compliance, treasury, information technology and other areas. We reimburse Spectra Energy for the expenses to provide these services as well as other expenses it incurs on our behalf, such as salaries of personnel performing services for our benefit and the cost of

employee benefits and general and administrative expenses associated with such personnel, capital expenditures, maintenance and repair costs, taxes and direct expenses, including operating expenses and certain allocated operating expenses associated with the ownership and operation of the contributed assets. Spectra Energy and its affiliates charge such expenses based on the cost of actual services provided or using various allocation methodologies based on our percentage of assets, employees, earnings or other measures, as compared to Spectra Energy’s other affiliates.

Transactions with affiliates are summarized in the tables below:

Consolidated Statements of Operations


	2011		2010		2009
	(in millions)
Operating, maintenance and other expenses	$	43.7	$	40.3	$	35.6
Interest expense		1.8		4.3		5.2

Consolidated Balance Sheets


	December 31,
	2011		2010
	(in millions)
Receivables	$	1.3	$	0.9
Natural gas imbalance receivables		3.2		1.4
Current assets — other		0.4		0.5
Accounts payable		16.0		9.9
Natural gas imbalance payables		1.9		—
Note payable		30.5		34.0
Current liabilities — other		—		1.7

See also Notes 1, 9, 12, 13 and 15 for discussion of specific related party transactions.

5. Business Segments

Our Gas Transportation and Storage segment aligns our operations with the chief operating decision makers’ view of the business. This business segment is considered to be our sole reportable segment.

The Gas Transportation and Storage segment provides interstate transportation, storage and gathering services of natural gas, and the storage and redelivery of liquefied natural gas for customers in the southeastern quadrant of the United States. Substantially all of our operations are subject to the FERC and the Department of Transportation’s (DOT’s) rules and regulations. This segment includes East Tennessee, Ozark, Big Sandy and Saltville.

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

Gulfstream provides interstate natural gas pipeline transportation from Pascagoula, Mississippi and Mobile, Alabama across the Gulf of Mexico into Florida for customers in central and southern Florida. Gulfstream’s operations are subject to the rules and regulations of the FERC and DOT.

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

Management evaluates segment performance 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 income taxes.

Business Segment Data


	Total Revenues		Segment EBIT/ Consolidated Earnings Before Income Taxes		Depreciation and Amortization		Capital and Investment Expenditures		Segment/ Total Assets
	(in millions)
2011
Gas Transportation and Storage	$	205.0	$	99.7	$	33.2	$	98.4	$	1,806.7
Other		—		97.9		—		17.3		650.2

Total		205.0		197.6		33.2		115.7		2,456.9
Interest income		—		0.5		—		—		—
Interest expense		—		25.0		—		—		—

Total consolidated	$	205.0	$	173.1	$	33.2	$	115.7	$	2,456.9

2010
Gas Transportation and Storage	$	197.7	$	97.8	$	29.4	$	25.8	$	1,299.0
Other		—		65.8		—		22.5		923.5

Total		197.7		163.6		29.4		48.3		2,222.5
Interest income		—		0.1		—		—		—
Interest expense		—		16.2		—		—		—

Total consolidated	$	197.7	$	147.5	$	29.4	$	48.3	$	2,222.5

2009
Gas Transportation and Storage	$	178.9	$	96.7	$	28.5	$	20.3	$	1,286.7
Other		—		56.9		—		36.7		525.8

Total		178.9		153.6		28.5		57.0		1,812.5
Interest income		—		0.2		—		—		—
Interest expense		—		16.7		—		—		—

Total consolidated	$	178.9	$	137.1	$	28.5	$	57.0	$	1,812.5

6. Regulatory Matters

Regulatory Assets and Liabilities. We record assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for non-regulated entities. See Note 1 for further discussion.


	December 31,				Recovery/Refund Period Ends
	2011		2010		Recovery/Refund Period Ends
	(in millions)
Regulatory Assets(a)(b)
Regulatory asset related to income taxes(c)	$	9.9	$	9.2		(d	)
Vacation accrual (non-current)		1.8		1.7		2012
Deferred debt expense/premium		3.5		4.0		(e	)
Fuel tracker(f)		2.1		1.1		2012

Total Regulatory Assets	$	17.3	$	16.0

Regulatory Liabilities(b)
Fuel tracker(f)	$	0.5		—		2012

Total Regulatory Liabilities	$	0.5	$	—

(a)	Included in Regulatory Assets and Deferred Debits, unless otherwise noted.

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

(c)	Relates to tax gross-up of the AFUDC equity portion.

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

(e)	Prepayment penalty being amortized over the life of the retired debt.

(f)	Included in Current Assets and Current Liabilities.

Rate Related Information

East Tennessee. East Tennessee currently operates under the tariff rates approved by the FERC in November 2005.

Saltville. On September 1, 2008, Saltville placed into effect rates approved by the FERC as a result of a settlement with customers associated with a rate proceeding. This settlement included a rate moratorium until October 1, 2011. Following expiration of the moratorium, Saltville’s rates remain the same, subject to further negotiation or a future rate proceeding. Also pursuant to the settlement, Saltville is required to file a rate case by October 1, 2013.

Gulfstream. Gulfstream operates under rates approved by the FERC in 2007. In 2007, the FERC issued an order approving Gulfstream’s Phase III expansion project. That order also required Gulfstream to file a Cost and Revenue Study three years after the Phase III facilities go in service. Gulfstream filed the Cost and Revenue Study on November 1, 2011.

Ozark Gas Transmission. Ozark Gas Transmission operates under rates established as a result of an uncontested settlement agreement with customers approved by the FERC in 2000. In 2011, Ozark Gas Transmission filed a Cost and Revenue Study as a result of a FERC rate proceeding. A settlement agreement in the 2011 rate proceeding was approved by the FERC on October 1, 2011 and had no impact on results of operations, financial position, or cash flows.

Big Sandy. Big Sandy operates under rates approved by the FERC in 2006. That order required Big Sandy to file a Cost and Revenue Study within three years after its in-service date. Big Sandy filed the Cost and

Revenue Study on April 8, 2011. The Cost and Revenue Study was accepted by FERC for filing on October 26, 2011. There was no change to the currently effective rates and the rates will remain in effect subject to further negotiations or a future rate proceeding.

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

7. Net Income Per Limited Partner Unit and Cash Distributions

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


	2011		2010		2009
	(in millions, except per-unit amounts)
Net income	$	172.0	$	147.9	$	135.9
Less:
General partner’s interest in net income — 2%		3.4		3.0		2.7
General partner’s interest in net income attributable to incentive distribution rights		16.9		7.6		3.0

Limited partners’ interest in net income	$	151.7	$	137.3	$	130.2

Weighted average limited partner units outstanding — basic and diluted		93.1		81.0		76.4
Net income per limited partner unit — basic and diluted	$	1.63	$	1.70	$	1.71

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

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

•

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

•

provide for the proper conduct of business,

•

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

•

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

•

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

Subordinated Units. Our subordinated units, which were all held by wholly owned subsidiaries of Spectra Energy, were converted into common units on a one-for-one basis effective as of August 13, 2010. The conversion of the subordinated units did not impact the amount of cash distributions paid or the total number of outstanding units. The conversion had no impact on our calculation of net income per limited partner unit since the subordinated units were previously included in the net income per limited partner unit calculation. In addition, since there are no further subordinated units, future distributions are shared equally among the limited partner units owned by subsidiaries of Spectra Energy and limited partner units owned by other common unitholders.

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


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

To the extent these incentive distributions are made to the general partner, there will be more Available Cash proportionately allocated to the general partner than to holders of common units. Our distribution paid on February 14, 2012 was $0.475 per unit.

8. Marketable Securities

We may actively invest a portion of our cash balances in various financial instruments, including taxable debt securities. In addition, we invest in short-term money market securities, some of which are restricted due to debt collateral requirements. We classify all short term money market securities that are pledged as collateral as available-for-sale (AFS). We do not purchase marketable securities for speculative purposes, nor do we routinely sell marketable securities prior to their scheduled maturity dates. Therefore, we do not have any securities classified as trading securities. Initial investments in securities are classified as purchases of the respective type of securities (available-for-sale or held-to-maturity), and maturities of securities are classified within proceeds from sales and maturities of securities in the Consolidated Statements of Cash Flows. As of December 31, 2011, there were no marketable securities outstanding.

In the fourth quarter of 2010, we invested in commercial paper with a portion of the proceeds from the equity issuance related to the Gulfstream acquisition. These investments were pledged as collateral against new term loans that were used to repay revolving borrowings, which were used to fund a portion of the consideration of the additional interest in Gulfstream and are classified as Other Investments on the Consolidated Balance Sheet. There was $207.2 million of term loans outstanding and $209.0 million of commercial paper investments pledged as collateral at December 31, 2010 valued at fair value. See Note 3 for additional information on the acquisition of additional interest in Gulfstream. In June 2011, the term loan was repaid using proceeds from the issuance of unsecured senior notes, and the related investments were liquidated. See Note 12 for additional information on the repayment of the term loan.

9. Investments in Unconsolidated Affiliates

As of December 31, 2011, our investments in unconsolidated affiliates consisted of a 49% interest in Gulfstream and a 50% interest in Market Hub.

During the fourth quarter of 2010, we purchased an additional 24.5% interest in Gulfstream from a subsidiary of Spectra Energy, for a total interest of 49%. See Note 3 for further discussion. The equity earnings related to the additional 24.5% interest is included in our results from the date of the acquisition. In 2011, we received total distributions of $76.0 million from Gulfstream. Of these distributions, $66.8 million were included in Cash Flows from Operating Activities — Distributions Received From Unconsolidated Affiliates and $9.2 million were included in Cash Flows from Investing Activities — Distributions Received From Unconsolidated Affiliates. In 2010, we received total distributions of $39.5 million from Gulfstream. Of these distributions, $33.4 million were included in Cash Flows from Operating Activities — Distributions Received

From Unconsolidated Affiliates and $6.1 million were included in Cash Flows from Investing Activities — Distributions Received From Unconsolidated Affiliates. In 2009, we received total distributions of $109.1 million from Gulfstream primarily resulting from our share of the proceeds of a long-term debt issuance by Gulfstream. Of these distributions, $38.6 million were included in Cash Flows from Operating Activities — Distributions Received From Unconsolidated Affiliates and $70.5 million were included in Cash Flows from Investing Activities — Distributions Received From Unconsolidated Affiliates.

We received distributions from Market Hub of $49.5 million in 2011, $47.7 million in 2010 and $35.7 million in 2009, which were included in Cash Flows from Operating Activities — Distributions Received From Unconsolidated Affiliates.

Our share of cumulative undistributed earnings of Market Hub totaled $136.3 million and Gulfstream had no cumulative undistributed earnings at December 31, 2011.

As of December 31, 2011 and 2010, the carrying amounts of Gulfstream and Market Hub approximated the amount of underlying equity in their respective net assets.

Investments in Unconsolidated Affiliates


	December 31,
	2011		2010
	(in millions)
Gulfstream	$	360.0	$	368.1
Market Hub		367.2		360.5

Total	$	727.2	$	728.6

Equity in Earnings of Unconsolidated Affiliates


	2011		2010		2009
	(in millions)
Gulfstream	$	64.7	$	35.5	$	30.4
Market Hub		42.6		39.6		40.3

Total	$	107.3	$	75.1	$	70.7

10. Goodwill

All of our goodwill is in our Gas Transportation and Storage segment. There were no changes in goodwill between December 31, 2009 and 2010. Changes in the balance of goodwill from December 31, 2010 to December 31, 2011 follow (in millions):


Balance at December 31, 2010	$	267.9
Increase due to the acquisition of Big Sandy(a)		193.8

Balance at December 31, 2011	$	461.7

(a)	See Note 3 for further discussion.

No impairments of goodwill were recorded in 2011, 2010 or 2009. See Note 1 for discussion of goodwill impairment testing.

11. Property, Plant and Equipment


	Estimated Useful Life		December 31,
	Estimated Useful Life		2011			2010
	(years)		(in millions)
Plant
Natural gas transmission		15-100	$	1,296.2		$	991.2
Storage		17-35		113.8			113.9
Gathering and processing facilities		5-40		11.8			11.5
Equipment		5-15		6.0			5.8
Vehicles		5-15		3.2			3.4
Land		—		2.7			2.3
Construction in process		—		1.0			14.5
Other		5-33		4.6			5.7

Total property, plant and equipment				1,439.3			1,148.3
Total accumulated depreciation and amortization				(234.1	)		(206.8	)

Total net property, plant and equipment			$	1,205.2		$	941.5

Substantially all of our property, plant and equipment is regulated with estimated useful lives based on rates approved by the FERC. Composite weighted-average depreciation rates were 2.7% for 2011, 2.7% for 2010 and 2.8% for 2009. We had no material capital leases at December 31, 2011 or December 31, 2010.

12. Debt and Credit Facility

Summary of Debt and Related Terms


	Interest Rate			Year Due		December 31,
	Interest Rate			Year Due		2011			2010
						(in millions)

Unsecured Senior note payable		2.95	%		2016	$	250.0		$	—
Unsecured Senior note payable		4.60	%		2021		250.0			—
East Tennessee notes payable		5.71	%		2012		150.0			150.0
Commercial paper(a)		0.631	%		—		27.0			—
Credit facility — revolving(b)		(c	)		2016		—			298.6
Credit facility — term(b)(d)		(d	)		2013		—			207.2
Note payable — affiliate(b)		0.271	%		2012		30.5			34.0

Total debt						$	707.5		$	689.8
East Tennessee notes payable(e)							(150.0	)		—
Commercial paper							(27.0	)		—
Note payable — affiliate							(30.5	)		(34.0	)
Unamortized debt discount							(0.6	)		—

Total long-term debt						$	499.4		$	655.8

(a)	The weighted-average days to maturity was 6.59 days as of December 31, 2011.

(b)	Borrowings bearing interest based on a one-month London InterBank Offering Rate.

(c)	No revolving credit facility borrowings at December 31, 2011.

(d)	Secured by $209.0 million of investments classified as Other Investments on the Consolidated Balance Sheet. Term loan was repaid in 2011.

(e)	In 2011, the East Tennessee note payable was reclassified from non-current to current since the note matures in the year 2012.

Annual Maturities


	December 31, 2011
	(in millions)
2012	$	180.5
2013		—
2014		—
2015		—
2016		250.0
Thereafter		250.0

Total debt(a)	$	680.5

(a)	Excludes commercial paper of $27.0 million.

We have the ability under certain debt facilities to repay the obligations prior to scheduled maturities. Therefore, the actual timing of future cash repayments could be materially different than presented above.

Unsecured Senior Notes. On June 9, 2011, we issued $500.0 million aggregate principal amount of unsecured senior notes, including $250.0 million 2.95% senior notes due in 2016 and $250.0 million 4.60% senior notes due in 2021. Interest on the notes will be payable semi-annually in arrears on June 15 and December 15 of each year, commencing on December 15, 2011. Net proceeds from this offering were used to repay all of the outstanding borrowings under our term loan and a significant portion of the funds borrowed under the credit facility, with the remaining balance used for general partnership purposes.

These notes are governed by an indenture, dated as of June 9, 2011, between us and Wells Fargo Bank, National Association, the trustee, as supplemented. The aggregate principal amount of debt securities which may be issued under this indenture is unlimited. The debt securities may be issued from time to time in one or more additional series in fully registered forms. The indenture contains covenants that limit our ability to create liens on principal properties, engage in sale and leaseback transactions, merge or consolidate with another entity or sell, lease or transfer substantially all of our properties or assets to another entity.

We may redeem all or some of these notes, in whole or in part, at any time prior to the date that is one month prior to the maturity date of the 2016 notes or three months prior to the maturity date of the 2021 notes, at stated redemption prices. The notes rank equally in right of payment with all of our existing and future senior indebtedness, effectively junior in right of payment to our existing and future secured indebtedness to the extent of the value of the collateral securing that indebtedness and senior to any subordinated debt that we may incur.

East Tennessee Notes Payable. East Tennessee’s debt agreement contains financial covenants which limit the amount of debt that can be outstanding as a percentage of total capital. Failure to maintain the covenants could require East Tennessee to immediately pay down the outstanding balance. As of December 31, 2011, East Tennessee was in compliance with those covenants. In addition, the debt agreement allows for acceleration of payments or termination of the agreements due to nonpayment, or to the acceleration of other significant indebtedness of the borrower or some of its subsidiaries, if any. The debt agreement does not contain provisions that trigger an acceleration of indebtedness based solely on the occurrence of an adverse change in our financial condition or results of operations.

Credit Facility and Commercial Paper. Effective as of October 18, 2011, we entered into a $700 million revolving credit agreement which will mature on October 18, 2016. The credit agreement contains a sublimit of $250 million for issuances of letters of credit, $150 million of which may be denominated in alternative currencies. The credit agreement also provides for up to $350 million in additional revolving commitments, which may consist of incremental term loans that, at our election, automatically increase the aggregate amount of

the revolving commitments upon any prepayment thereof. After executing the credit agreement, we established a commercial paper program providing for the issuance of up to $700.0 million of commercial paper to fund our short-term borrowing needs, including the initial funding of capital expenditures. Our new credit facility is available to repay our commercial paper, if necessary. Amounts outstanding under the commercial paper program reduce the borrowings available under our credit facility. As of December 31, 2011, we had $673.0 million available under the revolving credit facility.

The credit agreement contains various financial and other covenants, including the maintenance of a consolidated leverage ratio, as defined in the agreement. Failure to meet those covenants beyond applicable grace periods could result in accelerated due dates and/or termination of the agreement. As of December 31, 2011, we were in compliance with those covenants. In addition, the credit agreement allows for the acceleration of payments or termination of the agreement due to nonpayment, or in some cases, due to the acceleration of our other significant indebtedness or other significant indebtedness of some of our subsidiaries. The credit agreement does not contain provisions that trigger an acceleration of indebtedness based solely on the occurrence of an adverse change in our financial condition or results of operations.

As noted above, the terms of the credit agreement requires us to maintain a consolidated leverage ratio of adjusted consolidated indebtedness to adjusted consolidated earnings before Interest, taxes, depreciation and amortization (EBITDA), as defined in the agreement, of 5.0 or less. As of December 31, 2011, the ratio was 2.7.

Adjusted EBITDA is a non-GAAP measure. Our definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies because our definition excludes some, but not all, items that affect net income and is defined differently by companies in our industry. Adjusted EBITDA should not be considered an alternative to net income, operating income, cash from operations or any other measure of financial performance or liquidity presented in accordance with GAAP.

Term Loan. As of December 31, 2010, the term loan had a balance of $207.2 million and was secured by qualifying investment-grade securities in an amount equal to or greater than the outstanding principal amount of the loan. The term loan was repaid in June 2011 with proceeds from the issuance of the unsecured senior notes.

13. Fair Value Measurements

As of December 31, 2011, there were no assets or liabilities measured at fair value on a recurring basis. The following table presents, for each of the fair value hierarchy levels, assets and liabilities that are measured at fair value on a recurring basis as of December 31, 2010:


Description	Consolidated Balance Sheet Caption	December 31, 2010
Description	Consolidated Balance Sheet Caption	Total		Level 1		Level 2		Level 3
		(in millions)
Corporate debt securities	Other investments	$	209.0	$	—	$	209.0	$	—

Total Assets		$	209.0	$	—	$	209.0	$	—

Interest rate swap liabilities	Current liabilities — other — affiliates(a)	$	2.0	$	—	$	2.0	$	—
Interest rate swap liabilities	Deferred credits and other liabilities — other		0.7		—		0.7		—

Total Liabilities		$	2.7	$	—	$	2.7	$	—

(a)	See Note 15 for further discussion.

Level 1

Level 1 valuations represent quoted unadjusted prices for identical instruments in active markets.

Level 2 Valuation Techniques

Fair values of our financial instruments, which included interest rate swaps and corporate debt securities that are actively traded in the secondary market, were determined based on market-based prices. These valuations included inputs such as quoted market prices of the exact or similar instruments or alternative pricing sources that included models or matrix pricing tools, with reasonable levels of price transparency. For interest rate swaps, we utilized data obtained from multiple sources for the determination of fair value. Both the future cash flows for the fixed-leg and floating-leg of our swaps were discounted to present value. In addition, credit default swap rates were used to develop the adjustment for credit risk embedded in our positions. We believed that since some of the inputs and assumptions for the calculations of fair value were derived from observable market data, a Level 2 classification was appropriate.

Level 3 Valuation Techniques

Level 3 valuation techniques include the use of pricing models, discounted cash flow methodologies or similar techniques where at least one significant model assumption or input is unobservable. Level 3 financial instruments also include those for which the determination of fair value requires significant management judgment or estimation.

Financial Instruments. The fair values of financial instruments that are recorded and carried at book value are summarized in the following table. Judgment is required in interpreting market data to develop the estimates of fair value. These estimates are not necessarily indicative of the amounts we could have realized in current markets. The fair values of our current maturities of long-term debt and long-term debt are determined based on market-based prices as described above in the Level 2 valuation technique, absent the impacts of hedging activities.


	December 31, 2011				December 31, 2010
Consolidated Balance Sheet Caption	Book Value		Approximate Fair Value		Book Value		Approximate Fair Value
	(in millions)
Current maturities of long-term debt(a)	$	150.0	$	154.3	$	—	$	—
Long-term debt	$	499.4	$	514.8	$	655.8	$	667.1

(a)	East Tennessee debt due in 2012.

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

During 2011 and 2010, there were no material adjustments to assets and liabilities measured at fair value on a nonrecurring basis.

14. Commitments and Contingencies

General Insurance. We are insured through Spectra Energy’s master insurance program for insurance coverages consistent with companies engaged in similar commercial operations with similar type properties. Our insurance program includes (1) commercial general and excess liability insurance for liabilities to third parties for bodily injury and property damage resulting from our operations; (2) workers’ compensation liability coverage to required statutory limits; (3) automobile liability insurance for all owned, non-owned and hired vehicles covering liabilities to third parties for bodily injury and property damage; (4) insurance policies in support of the indemnification provisions of Spectra Energy’s by-laws and (5) property insurance, including

machinery breakdown, on an all risk-replacement valued basis, onshore business interruption and extra expense. All coverages are subject to certain deductibles, terms and conditions common for companies with similar types of operations.

Environmental. We are subject to various federal, state and local laws and regulations regarding air and water quality, hazardous and solid waste disposal and other environmental matters. We believe there are no matters outstanding that upon resolution will have an adverse effect on our consolidated results of operations, financial position or cash flows.

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

Leases. We lease assets in several areas of operations. Rental expense for these leases was $2.1 million in 2011, $2.2 million in 2010 and $1.9 million in 2009. Future minimum rental payments under operating leases are $0.1 million for each year from 2012 through 2016.

15. Risk Management and Hedging Activities

We are exposed to the impact of changes in interest rates as a result of our issuance of variable and fixed-rate debt and commercial paper. We manage our interest rate exposure by limiting our variable-rate exposure and by monitoring the effects of market changes in interest rates.

In February 2009, we entered into a series of three-year interest rate swap agreements with third parties to mitigate our exposure to variable interest rates on $40.0 million of loans outstanding under the revolving credit facility. During the second quarter of 2010, our two-year interest rate swap agreements with Spectra Energy on $25.0 million of loans outstanding under the revolving credit facility expired, thereby reducing our total notional amount from $180.0 million as of December 31, 2009 to $155.0 million as of December 31, 2010. These interest rate swaps were designated as effective cash flow hedges. Through December 31, 2011, these hedges resulted in no ineffectiveness, and unrealized net losses on the agreements have been deferred in AOCI in the Consolidated Balance Sheets. In 2011, our remaining floating-to-fixed interest rate swaps expired or were terminated in conjunction with the pay down of our credit facility. As of December 31, 2011, we did not have any derivatives outstanding.

The effective portion of losses recognized in Other Comprehensive Income follows:


Cash Flow Hedging Derivatives	2011		2010			2009
	(in millions)
Interest rate swaps	$	—	$	(2.1	)	$	(4.9	)

The reclassifications from Other Comprehensive Income into income on derivatives follow:


Cash Flow Hedging Derivatives	Consolidated Statements of Operations Caption	2011		2010		2009
		(in millions)
Interest rate swaps	Interest expense	$	1.7	$	4.6	$	4.9

Credit Risk. Our principal customers for natural gas transportation, storage and gathering services are industrial end-users, marketers, exploration and production companies, local distribution companies and utilities located mainly throughout the southeastern quadrant of the United States. We have concentrations of receivables from natural gas utilities and their affiliates, industrial customers and marketers throughout these regions. These

concentrations of customers may affect our overall credit risk in that risk factors can negatively affect the credit quality of the entire sector. Where exposed to credit risk, we analyze the customers’ financial condition prior to entering into an agreement, establish credit limits and monitor the appropriateness of those limits on an ongoing basis. We also obtain cash deposits, letters of credit or other acceptable forms of security from customers to provide credit support, where appropriate, based on our financial analysis of the customer and the regulatory or contractual terms and conditions applicable to each contract.

16. Sale of Common Units

In 2009, we issued 9.8 million common units to the public, representing limited partner interests, and 0.2 million general partner units to Spectra Energy, and received net proceeds of $212.2 million. As further discussed in Note 3, we used the net proceeds from the offering to repay $142.2 million drawn on our available bank credit facility and $70.0 million drawn on the credit facility with a subsidiary of Spectra Energy.

In 2010, we issued 6.9 million common units to the public representing limited partner interests. The net proceeds from this offering were approximately $221.0 million, including our general partner’s proportionate unit purchase after deducting the underwriting discount. As further discussed in Note 3, we used the net proceeds from the offering to repay the $7.4 million loan assumed in the Gulfstream acquisition. The remaining $209.0 million in net proceeds (other than proceeds from our general partner’s unit purchase) was used to purchase qualifying investment grade securities. The approximately $4.6 million in proceeds from our general partner’s proportionate unit purchase were used for general partnership purposes.

On June 14, 2011, we issued 7.2 million common units to the public representing limited partner interests. The net proceeds from this offering were $217.9 million, including our general partner’s proportionate unit purchase of 0.1 million general partner units after deducting the underwriting discount and offering expenses. The net proceeds from this issuance were used to fund a portion of the purchase price of the Big Sandy acquisition, see Note 3 for additional information.

17. Equity-Based Compensation

Phantom units are granted under a Long-Term Incentive Plan to certain employees of Spectra Energy and vest over three years. We did not award phantom units in 2011 and 2010. We awarded 10,000 units in 2009. The total fair value of the units vested was not significant in 2011 and $2.4 million in 2010. The total fair value of the units vested was not significant in 2009.


	Phantom Unit Awards
	(in thousands)
Outstanding at December 31, 2010		12
Granted		—
Vested		(2	)
Forfeited		—

Outstanding at December 31, 2011		10

Awards expected to vest		9

We account for the phantom units as liability awards. Compensation expense for these awards of $0.1 million and $1.2 million was recorded in 2011 and 2010, respectively. As of December 31, 2011 and assuming no change in fair value, we expect to recognize an immaterial amount of future compensation cost related to phantom awards in 2012.

18. Quarterly Financial Data (Unaudited)

Our consolidated results of operations by quarter for the years ended December 31, 2011 and 2010 were as follows:


	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		Total
	(in millions, except per-unit amounts)
2011
Operating revenues	$	51.2	$	43.0	$	52.9	$	57.9	$	205.0
Operating income		25.1		15.3		23.2		24.6		88.2
Net income		48.9		37.6		43.5		42.0		172.0
Net income per limited partner unit(a)		0.50		0.36		0.40		0.38		1.63

2010
Operating revenues	$	50.5	$	47.4	$	49.0	$	50.8	$	197.7
Operating income		25.0		19.9		24.3		18.5		87.7
Net income		39.1		33.2		38.4		37.2		147.9
Net income per limited partner unit(a)		0.46		0.38		0.44		0.41		1.70

(a)	Quarterly net income per limited partner unit amounts are stand-alone calculations and may not be additive to full-year amounts due to rounding and changes in outstanding units.

SPECTRA ENERGY PARTNERS, LP

SCHEDULE II — CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS AND

RESERVES


	Balance at Beginning of Period		Additions:				Deductions(a)		Balance at End of Period
	Balance at Beginning of Period		Charged to Expense		Charged to Other Accounts		Deductions(a)		Balance at End of Period
	(in millions)
December 31, 2011:
Allowance for doubtful accounts	$	0.3	$	—	$	—	$	0.2	$	0.1
Other		—		—		—		—		—

	$	0.3	$	—	$	—	$	0.2	$	0.1

December 31, 2010:
Allowance for doubtful accounts	$	0.1	$	0.2	$	—	$	—	$	0.3
Other		—		—		—		—		—

	$	0.1	$	0.2	$	—	$	—	$	0.3

December 31, 2009:
Allowance for doubtful accounts	$	0.5	$	—	$	—	$	0.4	$	0.1
Other		—		—		—		—		—

	$	0.5	$	—	$	—	$	0.4	$	0.1

(a)	Principally cash payments and reserve reversals.

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

None.

Item 9A. Controls and Procedures.

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

Under the supervision and with the participation of the management of Spectra Energy Partners (DE) GP, LP (our General Partner), including the Chief Executive Officer and Chief Financial Officer, we have evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act) as of December 31, 2011, and, based upon this evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that these controls and procedures are effective at the reasonable assurance level.

Changes in Internal Control over Financial Reporting

Under the supervision and with the participation of the management of our General Partner, including the Chief Executive Officer and Chief Financial Officer, we have evaluated changes in internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the fiscal quarter ended December 31, 2011 and found no change that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.

Management’s Annual Report on Internal Control over Financial Reporting

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

Attestation Report of Independent Registered Public Accounting Firm

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

Item 9B. Other Information.

None.

PART III

Item 10. Directors, Executive Officers and Corporate Governance.

Management of Spectra Energy Partners, LP

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

Board of Directors and Officers

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

The Board of Directors of the General Partner annually review the independence of directors and affirmatively makes a determination that each director expected to be independent has no material relationship with the General Partner, either directly or indirectly as a partner, unitholder or officer of an organization that has a relationship with the General Partner. The members of the Audit Committee and Conflicts Committee each meet the independence and experience standards established by the NYSE and the Securities Exchange Act of 1934 (Exchange Act) as amended, to serve on an audit committee of a board of directors.

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

The General Partner does not receive any management fee or other compensation for its management of our partnership under the omnibus agreement with Spectra Energy, as amended (Omnibus Agreement) or otherwise. Under the terms of the Omnibus Agreement, we reimburse Spectra Energy up to $3.6 million annually for the provision of various general and administrative services for our benefit, which amount is adjusted for inflation until December 2013. We also reimburse Spectra Energy for direct expenses incurred on our behalf and expenses allocated to us as a result of becoming a public entity. The partnership agreement provides that the General Partner will determine the expenses that are allocable to us.

Meeting Attendance and Preparation

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

Directors and Executive Officers

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


Name	Age		Position with Spectra Energy Partners GP, LLC
Julie A. Dill		52	President, Chief Executive Officer and Director
Laura Buss Sayavedra		44	Vice President and Chief Financial Officer
Fred J. Fowler		66	Chairman
Steven D. Arnold		51	Director
Stewart A. Bliss		78	Director
Nora Mead Brownell		65	Director
Patrick J. Hester		60	Director
Theopolis Holeman		62	Director
R. Mark Fiedorek		49	Director
J.D. Woodward, III		62	Director

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

Julie A. Dill was elected to the Board of Directors of Spectra Energy Partners GP, LLC effective January 1, 2012. She also serves as its President and CEO. Ms. Dill served as Chair and President of Union Gas Limited from December 2006 through December 2011. Ms. Dill was Vice President of Investor Relations from 2004 to 2006 for Duke Energy Corporation. She served as Group Executive — Investor Relations and Chief Communications Officer from April 2006 until assuming her position with Union Gas in December 2006.

Laura Buss Sayavedra was named to her current position in July 2008. In January 2007, she was named Vice President, Strategic Development and Analysis for Spectra Energy Corp. She previously served at Duke Energy Gas Transmission as General Manager, Strategic Planning and Development from July 2005 to December 2006. She served as Vice President, Operations and Analytics of Duke Energy North America from May 2004 to June 2005 and Senior Director of Energy Marketing from January 2003 to April 2004.

Fred J. Fowler was elected to the Board of Directors of Spectra Energy Partners GP, LLC as its Chairman in December 2008. He retired as President and Chief Executive Officer of Spectra Energy Corp in December 2008, a position he held since its inception in January 2007. Mr. Fowler previously served as Group Executive and President of Duke Energy Gas Transmission from April 2006. He was President and Chief Operating Officer from November 2002 to April 2006. Mr. Fowler was elected to the board of EnCana Corp effective February 1, 2010. Mr. Fowler was elected to serve on the Pacific Gas and Electric Company board effective March 1, 2012. Mr. Fowler was elected serve as a director because of his extensive knowledge and experience of the energy industry and its participants, as well as a deep understanding of our assets, customers and regulatory environments.

Steven D. Arnold was elected to the Board of Directors of Spectra Energy Partners GP, LLC in May 2007 and serves on the Audit Committee and on the Conflicts Committee as Chairman. Mr. Arnold is engaged in private investment management and consulting services in Houston, Texas through 3 Lights Management Co., serving as its President since inception in 2000. Mr. Arnold has over 10 years of institutional investment management experience with Prudential Financial, Inc. Mr. Arnold currently serves on the Advisory Board of Avalon Advisors, LLC, in Texas. Mr. Arnold was elected to serve as a director because of his energy industry and financial expertise. Mr. Arnold brings a strong risk assessment and strategic expertise to the board.

Stewart A. Bliss was elected to the Board of Directors of Spectra Energy Partners GP, LLC in June 2007 and chairs the Audit Committee and serves on the Conflicts Committee. Mr. Bliss has been an independent financial consultant and senior business advisor in Denver, Colorado for many years, with expertise that also includes mergers and acquisitions. In early 2007, he served as interim director of the Colorado Department of Economic Development and International Trade. Mr. Bliss was a senior advisor with Green Manning & Bunch, Ltd., a Denver-based investment banking firm from 2000 until 2007. Until 2007, he served as lead director and chair of the audit committee on Kinder Morgan Inc.’s Board of Directors. Mr. Bliss currently is a Trustee of The Colorado School of Mines and a member of the board of The Colorado History Museum/Colorado Justice Center Building, Inc. Mr. Bliss was elected to serve as a director because he brings knowledge and experience of the energy industry as well as valuable knowledge on public company governance and audit issues.

Nora Mead Brownell was elected to the Board of Directors of Spectra Energy Partners GP, LLC in May 2007 and serves on our Audit Committee and the Conflicts Committee. In May 2001, Ms. Brownell was confirmed as Commissioner of the Federal Energy Regulatory Commission (FERC) where she served until the expiration of her term in June 2006. Prior to the FERC, Ms. Brownell served as a member of the Pennsylvania Public Utility Commission from 1997 to 2001. Ms. Brownell also currently serves on the Board of Directors of Comverge, Inc., an energy technology company, Ener1 Inc., a leading manufacturing of lithium-ion energy storage systems, and ONCOR, Inc., a regulated electric distribution and transmission company. Ms. Brownell is co-founder and principal of ESPY Energy Solutions, LLC, a woman-owned independent energy consulting company. Ms. Brownell was elected to serve as a director because she brings a diverse background that includes experience in business, finance and the regulatory arenas.

Patrick J. Hester was elected to the Board of Directors of Spectra Energy Partners GP, LLC in October 2008. He also serves as Associate General Counsel for Spectra Energy Corp’s Northeast region. Mr. Hester previously served as Vice President, Project Management and Development for Duke Energy Gas Transmission from 2005 until he assumed his current position and was Interim General Counsel for Spectra Energy from October 2008 to March 2009. Previously he was General Counsel for Duke Energy Gas Transmission-East from 2003. Mr. Hester was elected a director because of his engineering and project expertise in the gas transportation business. He brings a strong operational, legal and regulatory expertise to the Board.

Theopolis Holeman was elected to the Board of Directors of Spectra Energy Partners GP, LLC in September 2009. Mr. Holeman was named Group Vice President of Spectra Energy Corp’s U.S. Operations in October 2008, and is responsible for storage and operations, and environmental health and safety. Previously, Mr. Holeman served as Group Vice president of Power Delivery for Duke Energy Corporation. Mr. Holeman brings a strong operational expertise to the Board as well as knowledge of our assets.

R. Mark Fiedorek was elected to the Board of Directors of Spectra Energy Partners GP, LLC in December 2008. He also serves as Group Vice President of Spectra Energy Corp’s U.S. Transmission and Storage — Southeast. He served as Vice President of Asset Optimization and Marketer Services from 2002 until 2007 when he was named to his current position with Spectra Energy Corp. Mr. Fiedorek was elected as a director because he has served in a variety of senior positions at Spectra Energy Corp focusing on the natural gas transmission business, mainly in the supply, operations and marketer services areas.

J.D. Woodward, III was elected to the board in September 2009. Mr. Woodward is President of Woodward Development Inc., a real estate and energy investment firm and a managing member of Woodward-Apple Springs, LLC, an owner and operator of natural gas midstream assets in East Texas. He retired in 2006 from Atmos Energy as Senior Vice President of Non-Utility Operations. Mr. Woodward was selected to serve as a director because he understands the operations of a large corporation, with a particular focus on customer issues. Mr. Woodward is an experienced senior executive in the energy industry.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Exchange Act requires the General Partner’s directors and executive officers, and persons who own more than 10% of any class of our equity securities to file with the Securities and Exchange Commission (SEC) and the NYSE initial reports of ownership and reports of changes in ownership of our common units and other equity securities. Spectra Energy prepares and files these reports on behalf of the General Partner’s directors and executive officers. To our knowledge, all Section 16(a) reporting requirements applicable to the General Partner’s directors and executive officers were complied with during 2011.

Audit Committee

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

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

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

Conflicts Committee

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

Principles for Corporate Governance and Code of Business Ethics

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

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

Executive Sessions of the Board of Directors

As set forth in our Corporate Governance Guidelines and in accordance with NYSE listing standards, the Board of Directors of the General Partner holds executive sessions on a regular basis without the presence of management. Mr. Fowler, the non-management Chairman of the Board of Directors of the General Partner, presides over all executive sessions.

Communications by Unitholders

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

Report of the Audit Committee

The Audit Committee oversees our financial reporting process on behalf of the Board of Directors. Management has the primary responsibility for the financial statements and the reporting process including the systems of internal controls. The Audit Committee operates under a written charter approved by the Board of Directors. The charter, among other things, provides that the Audit Committee has authority to appoint, retain and oversee the independent auditor and is available on our website at www.spectraenergypartners.com/investorrelations/governance.

In this context, the Audit Committee:

•

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

•

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

•

received the written disclosures and the letter required by applicable requirements of the Public Company Accounting Oversight Board regarding Deloitte & Touche, LLP’s communications with the audit committee concerning independence from Spectra Energy Partners and its subsidiaries, and has discussed with Deloitte & Touche, LLP the firm’s independence;

•

discussed with Deloitte & Touche, LLP the matters required to be discussed by Statement on Auditing Standards No. 61, as amended (AICPA, Professional Standards, Vol. 1. AU section 380), as adopted by the Public Company Accounting Oversight Board in Rule 3200T;

•

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

•

based on the foregoing reviews and discussions, recommended to the Board of Directors that the audited financial statements be included in the annual report on Form 10-K for the year ended December 31, 2011, for filing with the SEC; and

•

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

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

Audit Committee

Steven D. Arnold

Stewart A. Bliss

Nora Mead Brownell

J.D. Woodward, III

February 20, 2012

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

Item 11. Executive Compensation.

COMPENSATION DISCUSSION AND ANALYSIS

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

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

Compensation paid or awarded by us in 2011 to our Chief Executive Officer (our principal executive officer) and our Chief Financial Officer (our principal financial officer, and together with our principal executive officer, our “named executive officers”) reflects the total compensation paid by Spectra Energy, which includes compensation that is allocated to us pursuant to Spectra Energy’s allocation methodology and subject to the terms of the Omnibus Agreement. The Compensation Committee of the Board of Directors of Spectra Energy (Compensation Committee) has ultimate decision making authority with respect to the compensation of our named executive officers other than with respect to awards of equity in our partnership, for which our Board retains control. The elements of compensation discussed below, other than our partnership equity based compensation, and Spectra Energy’s decisions with respect to determinations on payments, was not subject to approvals by the Board of Directors of our general partner. Compensation of our named executive officers was approved by the Compensation Committee, and awards under our long-term incentive plan were recommended by the Compensation Committee and approved by the Board of Directors of Spectra Energy Partners GP, LLC.

With respect to compensation objectives and decisions regarding our named executive officers for 2011, the Compensation Committee approved the cash compensation, and recommended equity based compensation, of our named executive officers based on its compensation philosophy, which includes rewarding both continued employment and performance through a combination of short-term cash incentives and long-term equity compensation. Senior management of Spectra Energy typically utilizes compensation consultants and reviews market data to determine relevant compensation levels and compensation program elements through the review of and, in certain cases, participation in, various relevant compensation surveys. Senior management then submits a proposal to the Compensation Committee for the compensation to be paid or awarded to executives and employees for consideration. Spectra Energy consulted with compensation consultants with respect to determining 2011 compensation for the named executive officers in a manner consistent with its current compensation philosophy. All compensation determinations are discretionary and are, as noted above, subject to Spectra Energy’s decision-making authority.

The elements of Spectra Energy’s compensation program discussed below are intended to provide a compensation package designed to drive performance and reward contributions in support of the business strategies of Spectra Energy and its affiliates at the corporate, partnership and individual levels. Accordingly, a significant portion of the compensation provided to our executive officers has been in the form of short-term and long-term incentives.

Committee Advisors

Since 2007, the Compensation Committee has retained ExeQuity, LLP, as its independent compensation consultant. ExeQuity reports directly to the Compensation Committee with respect to matters related to executive compensation, best practices and analysis of meeting materials prepared by management. ExeQuity generally confers with the Chair of the Compensation Committee and the Compensation Committee itself independently of management and discusses compensation matters with management on a limited basis at the direction of the Compensation Committee. In addition, ExeQuity meets with the Compensation Committee in executive session without the presence of management following each meeting. ExeQuity performs no other services for Spectra Energy other than its services as independent consultant to the Compensation Committee. In 2011, ExeQuity reviewed materials provided to the Committee by management, consulted with the Chair prior to meetings regarding agenda items and attended meetings of the Compensation Committee.

Elements of the Compensation Program

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

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


Component	Description	Rationale

Salary	Compensation paid in cash throughout the year.	Provides compensation for performing day-to-day responsibilities.

Short-Term Incentive	Annual cash payment based on the achievement of defined financial and operational performance goals.	Makes significant percentage of cash compensation contingent on specific financial targets and operational performance objectives. These objectives are considered to be appropriate measures of the business imperatives that are necessary to build a solid record of financial success and operational excellence.

Long-Term Incentive	Performance share units and phantom awards.	Rewards long-term company performance, aligns the interests of executives with unitholders and shareholders of Spectra Energy, creates equity ownership and provides retention incentive.

Retirement	Spectra Energy sponsored retirement and savings plans.	Provides retention incentives and rewards service through retirement-related payments and provides savings opportunities.

Factors Considered When Determining Total Compensation

Group Comparison. The Compensation Committee sets salaries and short-term and long-term incentive target levels based in part on what it believes to be the market median of compensation available to our

executives in the market. The market for highly talented executives is competitive, and we believe our success depends on our ability to attract and retain executives who are incented through our compensation programs to successfully execute our long term objectives. We believe that hiring objectives cannot be achieved unless we offer compensation opportunities that are competitive in the marketplace. Accordingly, we use comparable market median data as a starting point for determining the adequacy of the compensation opportunities provided to our executives. The Compensation Committee considers market trends from general industry survey data. Specifically, the Compensation Committee has chosen to use the Towers Watson 2011 Compensation Data Base^© General Industry Survey as a source of market information because the Compensation Committee believes that the survey provides a reliable indication of compensation practices in companies that are comparable in size as measured by revenues.

External Market Conditions and Individual Factors. In addition to using benchmark survey data, the Compensation Committee also takes into account external market conditions and individual factors when establishing the total compensation of both named executive officers. Some of these factors include the executive’s performance, level of experience, position, tenure and responsibilities, competitive pressures for that position within the industry, economic developments, the condition of labor markets and the financial and market performance of Spectra Energy Partners and Spectra Energy.

Risk Assessment of Total Compensation. The overall compensation mix of short-term and long-term compensation opportunities for our executives, as well as the components of these incentive opportunities are balanced to mitigate undue risk. No single measure of the short-term compensation program is greater than 25% of an individual’s targeted award for either named executive officer. Sixty percent of both executives’ long-term opportunity is contingent on the performance of Spectra Energy’s stock relative to its peers and stock ownership levels are required of both executives.

2011 Compensation Opportunities

The following table shows the 2011 target direct pay opportunities for our named executive officers.

2011 Target Pay Opportunity


Name	Salary		Short-Term Incentive Target Opportunity			Long-Term Incentive Target Opportunity			Total Target Pay Opportunity
Gregory J. Rizzo	$	334,383		50	%		100	%	$	835,958
Laura Buss Sayavedra	$	219,440		40	%		50	%	$	416,936

Salary. At the end of 2010, the Compensation Committee considered whether adjustments to salaries were appropriate and adjusted 2011 salaries of the named executive officers at that time, based upon job responsibilities, level of experience, individual performance, comparisons to the salaries of executives in similar positions obtained from market surveys and internal comparisons.

Short-Term Incentives. Short-term incentive opportunities, awarded under the Spectra Energy Executive Short-Term Incentive (STI) Plan for 2011, were designed to compensate executives for financial and operational performance during the year based on goals set at the beginning of the year. The threshold, target and maximum incentive opportunities for each participant in the STI Plan during 2011 were established as a percentage of base salary. Cash incentives were earned based on the achievement of corporate and business unit financial and operational goals as determined by the Compensation Committee. Target STI awards expressed as a percentage of base annual salary for our named executive officers in 2011 are reflected in the “2011 Target Pay Opportunity” table above.

Under guidelines adopted for the 2011 STI program, participants were eligible to receive up to 200% of the amount of their STI target. The maximum that could be earned for performance on financial or operational measures was 200% of target. The amount that could be paid for performance at a specified minimum level for any measure was 50% of the target amount. 100% of the target amount would be paid for performance at the target level. No compensation was to be earned if performance fell below a specified minimum level.

As shown in the following table, STI payments for our named executive officers were based on the achievement of financial and operational objectives related to management responsibilities for Spectra Energy and Spectra Energy Partners.

2011 Target Incentive Payment Opportunity


Measures	Percentage
Spectra Energy Ongoing EPS		20	%
Spectra Energy Transmission Return on Capital Employed		20	%
Spectra Energy Partners Distributable Cash		25	%
Environmental, Health and Safety Scorecards		10	%
Operational and Capital Project Scorecards		25	%

Determination of 2011 Short-Term Incentive Payments

At the end of the 2011 cycle, management prepared a report on the achievement of financial and operational goals. These results were reviewed and approved by the Compensation Committee in February 2012 along with any proposed adjustments based on individual performance for both named executive officers. Any adjustments based on individual performance were reviewed by the Compensation Committee, which then approved the final performance results and payment of incentives for both named executive officers.

The amounts set forth below show target amounts for achieving the threshold, target and maximum levels established for each financial goal as well as the actual result. The percentage of the target opportunity achieved is shown in parentheses. For each category, achievement of the Threshold, Target and Maximum amounts would result in the payment of 50%, 100% and 200%, respectively, of the target level. For instance, the short-term incentive payment for an executive associated with Spectra Energy’s EPS results was calculated as 20% of such executive’s target cash incentive opportunity multiplied by the actual percentage achieved, which was 148.00%.


Measures	Threshold			Target			Maximum			Actual
Spectra Energy Ongoing EPS	$	1.45		$	1.65		$	1.90			$ 1.77 (148.00%)
Spectra Energy Transmission Return on Capital Employed		10.6	%		11.0	%		11.8	%		11.5% (162.50%)
Spectra Energy Partners Distributable Cash*	$	201		$	208		$	223			$ 212.4 (129.33%)

*	In millions.

The Environmental, Health and Safety Scorecard achieved a payout percentage of 123.9% and the Operational and Capital Project Scorecard achieved a payout percentage of 141%. The following table is a summary of the payments made to our named executive officers.

2011 STI Awards


Name	Short-Term Incentive Award		Actual Payout as a Percent of Target Short-Term Incentive Award
Gregory J. Rizzo	$	225,656		135	%
Laura Buss Sayavedra	$	118,470		135	%

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

The Compensation Committee decided that its long term incentive program would consist of awards that result in share ownership when certain specific performance goals are achieved in combination with phantom units that vest over a three-year period. We believe that the combination of these two forms of awards are an effective means of creating a focus on returns to shareholders and retaining our executive talent in a competitive market.

For 2011, the performance share unit awards was increased from 50% to 60% of the target value of annual long-term compensation and are earned based on how Spectra Energy performs relative to a group of energy companies over a three-year period. The companies in Spectra Energy’s long-term incentive peer group are:


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

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


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

The Compensation Committee approved these payout levels after a review of similar plans in place by many of the companies in the peer group, after a review of the historical returns of the peer group and indices that track energy company performance, and after consultations with Spectra Energy’s outside compensation advisors. Once earned, half of the performance share units will be converted to shares of Spectra Energy common stock and half will be paid in cash, based on the fair market value of Spectra Energy common stock at the time of vesting. The payout design is intended to provide for stock accumulation while also allowing for some investment diversification.

Phantom units comprised the remaining 40% of annual long-term compensation grant value. These units will vest at the end of three years at which time they will be converted to shares of Spectra Energy common stock. Dividend equivalents accumulated from the date of grant will be paid in cash on the number of performance share units and phantom units at the time which these units vest.

The table below shows long-term incentive awards granted to our named executive officers in 2011:


Name	Expected Value of Long-Term Incentive/Equity Grants as a Percentage of Base Salary			Number of Performance Share Units Granted		Number of Phantom Units Granted
Gregory J. Rizzo		100	%		9,500		5,900
Laura Buss Sayavedra		50	%		3,100		1,900

Determination of 2009-2011 Performance Share Unit Awards. The 2009 performance share unit cycle commenced on January 1, 2009 and ended on December 31, 2011. The performance share units vest based on Spectra Energy’s total shareholder return for the three year period as compared to the total shareholder return for companies in Spectra Energy’s customized long-term incentive peer group, which is the same long-term incentive peer group used for the 2011 awards listed above. Spectra Energy’s total shareholder return for the three year period is 124.29% which is at the 69.3 percentile of the peer group. This results in a payout percentage of 164.33%. The following table lists the resulting number of 2009-2011 performance share units that vested and the amount of associated dividend equivalents:


Name	Vested Performance Share Units		Dividend Equivalent Payment
Gregory J. Rizzo		22,021	$	68,045
Laura Buss Sayavedra		7,231	$	22,344

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

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

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

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

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

100

Perquisites and Personal Benefits. Spectra Energy makes its private aircraft available to our executive officers for business use only and our executive officers are not allowed to initiate personal trips on corporate or chartered aircraft. However, executive officers are permitted to bring their spouse or personal guests on business-related flights when space is available. When the executive officer’s use of aircraft or a guest’s travel does not meet the Internal Revenue Service’s (IRS) standard for business use, the cost of that travel is imputed as income to the officer.

Compensation Committee Report

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

Steven D. Arnold

Stewart A. Bliss

Nora Mead Brownell

J.D. Woodward, III

101

EXECUTIVE COMPENSATION

The table below sets forth compensation of Spectra Energy Partners’ named executive officers for 2009, 2010 and 2011.

SUMMARY COMPENSATION TABLE


Name and Principal Position	Year		Salary ($)		Bonus ($)		Stock Awards ($)(1)		Option Awards ($)		Non-Equity Incentive Plan Compensation ($)(2)		Change in Pension Value and Nonqualified Deferred Compensation Earnings ($)(3)		All Other Compensation ($)(4)		Total ($)
Gregory J. Rizzo		2011		334,383		—		460,063		—		225,656		153,511		36,881		1,210,494
President and Chief Executive Officer		2010		324,644		—		469,518		—		231,509		87,086		35,979		1,148,736
President and Chief Executive Officer		2009		315,188		—		574,446		—		205,799		115,348		32,996		1,243,777

Laura Buss Sayavedra		2011		219,440		—		149,471		—		118,470		68,361		27,798		583,540
Vice President and Chief Financial Officer		2010		211,000		—		151,320		—		122,146		48,142		25,620		558,228
Vice President and Chief Financial Officer		2009		205,001		—		119,636		—		108,998		33,908		16,283		483,826

(1)

This column reflects the aggregate grant date fair value computed in accordance with the provisions of FASB ASC Topic 718 with respect to performance share units and phantom unit awards granted each year. The aggregate dollar amount was determined without regard to any estimate of forfeitures related to service-based vesting conditions. If the performance share units vested at the maximum level, the following represents the maximum value that would be payable on the performance share units based on the closing stock price of our common stock on the grant date of these awards for Mr. Rizzo and Ms. Sayavedra in the amount of $492,480, and $160,704, respectively.

(2)	This column includes amounts payable under the Spectra Energy STI Plan with respect to the 2011, 2010 and 2009 performance periods. Unless deferred, these amounts were paid in March 2012, March 2011 and March 2010, respectively.

(3)	This column includes the amounts listed below. These figures represent the change in value during the twelve month period ending December 31.


	Gregory J. Rizzo		Laura Buss Sayavedra
Change in actuarial present value of accumulated benefit under the Spectra Energy Retirement Cash Balance Plan for the period beginning on January 1, 2011 and ending on December 31, 2011	$	86,471	$	54,603
Change in actuarial present value of accumulated benefit under the Spectra Energy Executive Cash Balance Plan for the period beginning on January 1, 2011 and ending on December 31, 2011		67,040		13,758

Total	$	153,511	$	68,361

(4)	All Other Compensation column includes the following for 2011:


	Gregory J. Rizzo		Laura Buss Sayavedra
Matching contributions under the Spectra Energy Retirement Savings Plan	$	14,700	$	14,181
Premiums for life insurance coverage provided under Life Insurance Plans		2,928		428
Make-whole matching contribution credits under the Spectra Energy Executive Savings Plan		19,253		6,314
Charitable contributions made in the name of the Executive under Spectra Energy’s matching gift policy		—		6,875

Total	$	36,881	$	27,798

102

2011 GRANTS OF PLAN-BASED AWARDS

Name

Grant Date

Committee
Approval
Date

Estimated Possible Payouts
Under Non-Equity Incentive
Plan Awards(1)

Estimated Future Payouts
Under Equity Incentive Plan
Awards(2)

All Other
Stock
Awards:
Number
of Shares
of Stock
or Units
(#)(2)

Grant
Date
Fair
Value of
Stock
and
Option
Awards
($)(3)

Threshold
($)

Target
($)

Maximum
($)

Threshold
(#)

Target
(#)

Maximum
(#)

Gregory J. Rizzo

83,596

167,192

334,383

Gregory J. Rizzo

2/22/2011

2/21/2011

4,750

9,500

19,000

307,135

Gregory J. Rizzo

2/22/2011

2/21/2011

5,900

152,928

Laura Buss Sayavedra

43,888

87,776

175,552

Laura Buss Sayavedra

2/22/2011

2/21/2011

1,550

3,100

6,200

100,223

Laura Buss Sayavedra

2/22/2011

2/21/2011

1,900

49,248

(1)

The awards reflected in the Estimated Possible Payouts Under Non-Equity Incentive Plan Awards column were granted for the 2011 performance period under the terms of the Spectra Energy Corp Executive STI Plan. The actual amounts payable to each executive under the terms of such plan are disclosed in the Summary Compensation Table.

(2)	Awards reflected in these columns with a grant date of February 22, 2011 were made in units of Spectra Energy common stock and were granted under the terms of the Spectra Energy Corp 2007 Long-Term Incentive Plan, as amended and restated.

(3)	All awards reflected in this column were computed in accordance with FASB ASC Topic 718. The per share full grant date fair value of the phantom units and performance share units granted on February 22, 2011 is $25.92 and $32.33, respectively.

When Duke Energy spun-off its gas businesses to form Spectra Energy, equitable adjustments were made with respect to outstanding stock options and other forms of equity awards originally denominated in shares of Duke Energy common stock. All such awards were adjusted into two separate awards, one denominated in shares of Duke Energy common stock and one denominated in shares of Spectra Energy common stock. The number of shares of Spectra Energy common stock distributed to award holders was equal to the number of Spectra Energy shares that a shareholder of Duke Energy common stock would have received effective on the January 2, 2007 spin date (i.e., a ratio of 0.5 shares of Spectra Energy common stock for every one share of Duke Energy common stock). With respect to stock options, the per share option exercise price of the original Duke Energy stock option was proportionally allocated between the two types of stock options taking into account the distribution ratio and the relative per share trading prices following the distribution. The resulting Duke Energy and Spectra Energy awards continue to be subject to the vesting schedule under the original Duke Energy award agreement. For purposes of vesting of options and phantom units and the post-termination exercise periods applicable to the options, continued employment with Spectra Energy is considered to be continued employment with the issuer of the options or shares of phantom units. The adjustments preserved, but did not increase, the value of the equity awards.

103

OUTSTANDING EQUITY AWARDS AT 2011 FISCAL YEAR-END


	Option Awards							Stock Awards
Name	Number of Securities Underlying Unexercised Options (#) Exercisable		Number of Securities Underlying Unexercised Options (#) Unexercisable(1)	Option Exercise Price ($)(1)		Option Expiration Date		Number of Shares or Units of Stock That Have Not Vested (#)(2)			Market Value of Shares or Units of Stock That Have Not Vested ($)		Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested (#)(3)		Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested ($)
Gregory J. Rizzo(4)	SE	1,700			32.54
	DUK	3,400			21.54		4/1/2012
	SE	38,200			25.64		2/27/2017
									SE	27,200		836,400
									SEP	10,000		319,600


									Total			1,156,000

									SE					37,600		1,156,200
Laura Buss Sayavedra	SE	825			11.86		2/25/2013
	SE	10,100			25.64		2/27/2017
									SE	8,800		270,600
									SE					12,200		375,150

(1)

For options granted February 27, 2007, the exercise price is equal to the closing price of Spectra Energy common stock on the date of grant. For options granted prior to December 31, 2006, the exercise price for the original Duke Energy options is equal to the closing price of Duke Energy common stock on the date of grant. In connection with the spin-off of Spectra Energy effective January 2, 2007, all Duke Energy equity awards were adjusted to reflect the change in the price of Duke Energy common stock that occurred as a result of the spin-off, and an additional award denominated in Spectra Energy common shares was granted. The adjustments preserved, but did not increase, the value of the equity awards. The following chart indicates the original and adjusted exercise prices of each Duke Energy stock option. In addition, the chart indicates exercise prices for stock options granted on January 2, 2007 at Spectra Energy associated to each grant date at Duke Energy:


Date of Grant	Duke Energy Original Option Exercise Price		Duke Energy Adjusted Option Exercise Price		Spectra Energy Option Exercise Price Granted on January 2, 2007
April 1, 2002		37.80		21.54		32.54
February 25, 2003		13.77		7.85		11.86

(2)	Mr. Rizzo and Ms. Sayavedra received Spectra Energy phantom units on February 22, 2011, February 23, 2010 and February 24, 2009, which, subject to certain exceptions, vest on the third anniversary of the date of grant.

(3)

Mr. Rizzo and Ms. Sayavedra received Spectra Energy performance share units on February 22, 2011 and February 23, 2010 that, subject to certain exceptions, are eligible for vesting on December 31, 2013 and December 31, 2012, respectively. Pursuant to Instruction 3 to Item 402(f)(2) of Regulation S-K, performance share units are listed at the maximum number of units.

(4)	On February 26, 2009, Mr. Rizzo received a grant in the amount of 10,000 units, which, subject to certain exceptions, vest on the third anniversary of the date of grant.

104

2011 OPTION EXERCISES AND STOCK VESTED


	Option Awards		Stock Awards
Name	Number of Shares Acquired on Exercise(#)	Value Realized on Exercise($)(1)	Number of Shares Acquired on Vesting(#)		Value Realized on Vesting($)(2)
Gregory J. Rizzo
Spectra Energy				28,315		933,316
Duke Energy				988		18,159

Total						951,475

Laura Buss Sayavedra
Spectra Energy				9,252		305,213
Spectra Energy Partners				1,670		55,352
Duke Energy				242		4,448

Total						365,013

(1)

No options were exercised during 2011.

(2)

The value realized upon vesting of stock awards was calculated based on the closing price of a share of common stock or unit for the respective equity on the respective vesting date and includes cash payments to Mr. Rizzo and Ms. Sayavedra in the amount of $85,387 and $36,266, respectively, for dividend and distribution equivalents paid at the time of vesting on earned phantom and performance share units.

Spectra Energy Retirement Cash Balance Plan and Executive Cash Balance Plan

Spectra Energy provides pension benefits that are intended to assist its retirees with their retirement income needs. A more detailed description of the plans that comprise Spectra Energy’s pension program follows.

Both of the Spectra Energy Partners executive officers actively participated in pension plans sponsored by Spectra Energy or an affiliate in 2011. Officers participated in the Spectra Energy Retirement Cash Balance Plan (“RCBP”), which is a noncontributory, defined benefit retirement plan that is intended to satisfy the requirements for qualification under Section 401(a) of the Internal Revenue Code. The RCBP generally covers non-bargaining employees of Spectra Energy and affiliates. The RCBP provides benefits under a “cash balance account” formula.

Both of the Spectra Energy Partners executive officers participate in the RCBP and have satisfied the eligibility requirements to receive his or her account benefit upon termination of employment. The RCBP benefit is payable in the form of a lump sum in the amount credited to the hypothetical account at the time of benefit commencement. Payment is also available in the form of an annuity based on the actuarial equivalent of the account balance.

The amount credited to the hypothetical account is increased with monthly pay credits equal to (a) for participants with combined age and service of less than 35 points, 4% of eligible monthly compensation, (b) for participants with combined age and service of 35 to 49 points, 5% of eligible monthly compensation, (c) for participants with combined age and service of 50 to 64 points, 6% of eligible monthly compensation, and (d) for participants with combined age and service of 65 or more points, 7% of eligible monthly compensation. If the participant earns more than the Social Security wage base, the account is credited with additional pay credits equal to 4% of eligible compensation above the Social Security wage base. Interest credits are credited monthly, with the interest rate determined quarterly based on the 30-year Treasury rate.

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For the RCBP, eligible monthly compensation is equal to Form W-2 wages, plus elective deferrals under a 401(k) or cafeteria plan. Compensation does not include severance pay (including payment for unused vacation), expense reimbursements, allowances, cash or noncash fringe benefits, moving expenses, bonuses for performance periods in excess of one year, transition pay, long-term incentive compensation (including income resulting from any stock-based awards such as stock options, stock appreciation rights, phantom stock or restricted stock) and other compensation items to the extent described as not included for purposes of benefit plans or the RCBP.

The benefit of participants in the RCBP may not be less than determined under certain prior benefit formulas (including optional forms). In addition, the benefit under the RCBP is limited by maximum benefits and compensation limits under the Internal Revenue Code.

Both of the Spectra Energy Partners executive officers was eligible to participate in the Spectra Energy Executive Cash Balance Plan (“ECBP”), which is a noncontributory, defined benefit retirement plan that is not intended to satisfy the requirements for qualification under Section 401(a) of the Internal Revenue Code. Benefits earned under the ECBP are attributable to (a) compensation in excess of the annual compensation limit ($245,000 for 2011) under the Internal Revenue Code that applies to the determination of pay credits under the RCBP, (b) restoration of benefits in excess of a defined benefit plan maximum annual benefit limit ($195,000 for 2011) under the Internal Revenue Code that applies to the RCBP, and (c) supplemental benefits granted to a particular participant. Generally, benefits earned under the RCBP and the ECBP vest upon completion of three years of service, and, with certain exceptions, vested benefits generally become payable upon termination of employment with Spectra Energy.

Spectra Energy has established a grantor trust that is subject to the claims of our creditors into which funds related to the ECBP are deposited. Funds deposited into the trust are managed by an independent trustee subject to guidelines provided by us.

The following table provides information related to each plan that provides for payments or other benefits at, following or in connection with retirement, determined as of December 31, 2011.

PENSION BENEFITS


Name	Plan Name	Number of Years Credited Service (#)		Present Value of Accumulated Benefit ($)		Payments During Last Fiscal Year ($)
Gregory J. Rizzo	Spectra Energy Retirement Cash Balance Plan		32.34		587,922		—
Gregory J. Rizzo	Spectra Energy Executive Cash Balance Plan		32.34		342,552		—
Laura Buss Sayavedra	Spectra Energy Retirement Cash Balance Plan		16.15		230,575		—
Laura Buss Sayavedra	Spectra Energy Executive Cash Balance Plan		16.15		35,976		—

Spectra Energy Executive Savings Plan

Under the Spectra Energy Executive Savings Plan, participants can elect to defer a portion of their base salary, short-term incentive compensation and long-term incentive compensation (other than stock options). Participants also receive a company matching contribution in excess of the contribution limits prescribed by the IRS under the Spectra Energy Retirement Savings Plan. In general, payments are made following termination of employment or death in the form of a lump sum or installments, as selected by the participant. Participants may request an accelerated distribution upon an “unforeseeable emergency.” In general, participants may direct the deemed investment of base salary deferrals, short-term incentive deferrals and matching contributions among investments options available under the Spectra Energy Retirement Savings Plan, including in a Spectra Energy

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Common Stock Fund. Deferrals of equity awards are credited with earnings and losses based on the performance of the Spectra Energy Common Stock Fund. Spectra Energy has established a grantor trust that is subject to the claims of our creditors into which funds related to the Spectra Energy Executive Savings Plan are deposited. Funds deposited into the trust are managed by an independent trustee subject to guidelines provided by us.

The Spectra Energy Executive Savings Plan and the Spectra Energy Retirement Savings Plan became effective with the spin-off of Spectra Energy. These plans contain the same provisions as the predecessor plans sponsored by Duke Energy, and individual benefit accruals were transferred from the Duke Energy plans to the Spectra Energy plans effective with the spin-off of Spectra Energy. Participants received credit for investment in 0.5 of a share of Spectra Energy common stock for each share of Duke Energy common stock held in the Duke Energy Common Stock Fund.

NONQUALIFIED DEFERRED COMPENSATION


Name	Executive Contributions in Last FY ($)(1)		Registrant Contributions in Last FY($)(2)		Aggregate Earnings in Last FY ($)		Aggregate Withdrawals/ Distributions ($)		Aggregate Balance at Last FYE ($)
Gregory J. Rizzo Spectra Energy Executive Savings Plan		23,151		19,253		16,588		—		532,904
Laura Buss Sayavedra Spectra Energy Executive Savings Plan		3,995		6,314		1,329		—		21,268

(1)

The table reflects contributions made to the Spectra Energy Executive Savings Plan. Executive contributions credited to the plan in 2011 include amounts reported as “Salary” in the Summary Compensation Table as well as “Non-Equity Incentive Plan Compensation” paid in 2011 but reported in the table as compensation earned in 2010.

(2)	Reflects make-whole matching contribution credits made in 2011 under the plan with respect to elective salary deferrals made by executives during 2011.

Potential Payments Upon Termination of Employment or Change in Control

Under certain circumstances, both Spectra Energy Partners executive officers would be entitled to compensation in the event his or her employment terminates. The amount of the compensation is contingent upon a variety of factors, including the circumstances under which employment is terminated. The relevant agreements and terms of awards applicable to named executive officers are described below, followed by a table that quantifies the amount that would become payable to both Spectra Energy Partners executive officers as a result of his or her termination of employment. The amounts shown assume that such termination was effective as of December 31, 2011 and are estimates of the amounts that would be paid. The actual amounts that would be paid can only be determined at the time of named executive officer’s termination of employment.

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The following table summarizes the consequences under Spectra Energy and Spectra Energy Partners’ long-term incentive award agreements that would occur in the event of a change in control or the termination of employment of a Spectra Energy Partners executive officer, without giving effect to the change in control agreements described below.


Event		Consequences

Change in Control		Phantom Units — continue to vest Performance Share Units — award vests based on target performance

Termination with cause		Phantom and Performance Share Units — the executive’s right to unvested portion of award terminates immediately

Voluntary termination (not retirement eligible)		Phantom and Performance Share Units — the executive’s right to unvested portion of award terminates immediately

Involuntary termination without cause (not retirement eligible)		Phantom Units — prorated portion of award vests Performance Share Units — prorated portion of award vests based on actual performance after performance period ends

Voluntary termination or involuntary termination without cause (retirement eligible)		Phantom Units — prorated portion of award continues to vest Performance Share Units — prorated portion of award vests based on actual performance after performance period ends

Involuntary termination after a Change in Control		Phantom Units — award vests Performance Share Units — award vests based on target performance

Death or Disability		Phantom Units — award vests Performance Share Units — award vests based on target performance

Mr. Rizzo has entered into a Change in Control Agreement with Spectra Energy and it has an initial term of two years, after which the agreement automatically extends annually, unless six months prior written notice is provided.

The Change in Control Agreement provides for payments and benefits to the executive in the event of termination of employment within two years after a “change in control” of Spectra Energy, other than termination: 1) by Spectra Energy for “cause”; 2) by reason of death or disability; or 3) of the executive for other than “good reason” (each such term as defined in the agreements). Payments and benefits include: (1) a lump-sum cash payment equal to a pro-rata amount of the executive’s target cash incentive for the year in which the termination occurs; (2) a lump-sum cash payment equal to two times the sum of the executive’s annual base salary and target annual incentive opportunity in effect immediately prior to termination or, if higher, in effect immediately prior to the first occurrence of an event or circumstance constituting “good reason”; (3) continued medical, dental and basic life insurance coverage for a two-year period (or a lump sum cash payment of equivalent value); and (4) a lump-sum cash payment representing the amount Spectra Energy would have allocated or contributed to the executive’s qualified and nonqualified defined benefit pension plan and defined contribution savings plan accounts during the two years following the termination date, plus the unvested portion, if any, of the executive’s accounts as of the date of termination that would have vested during such two year period. In addition, under certain circumstances the agreement may provide for continued vesting of certain long-term incentive awards for two additional years.

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Under the Change in Control Agreement, the covered executive is also entitled to reimbursement of up to $50,000 for the cost of certain legal fees incurred in connection with claims under the agreements. In the event that any of the payments or benefits provided for in the Change in Control Agreement otherwise would constitute an “excess parachute payment” (as defined in Section 280G of the Internal Revenue Code), the amount of payments or benefits would be reduced to the maximum level that would not result in excise tax under Section 4999 of the Internal Revenue Code if such reduction would cause the executive to retain an after-tax amount in excess of what would be retained if no reduction were made. In the event a named executive officer becomes entitled to payments and benefits under a change in control agreement, he or she would be subject to a one-year noncompetition and nonsolicitation provision from the date of termination, in addition to certain confidentiality and cooperation provisions.

POTENTIAL PAYMENTS UPON TERMINATION OF

EMPLOYMENT OR A CHANGE IN CONTROL (“CIC”)


Name and Triggering Event(1)	Cash Severance Payment ($)(2)		Incremental Retirement Plan Benefit ($)(3)		Welfare and Similar Benefits ($)(4)		Stock Awards ($)(5)		Option Awards ($)		Total Payments ($)
Gregory J. Rizzo
Change in Control		—		—		—		602,533		—		602,533
Termination with cause		—		—		45,013		—		—		45,013
Voluntary or involuntary termination without cause		—		—		45,013		1,025,659		—		1,070,672
Involuntary or good reason termination after a CIC		1,003,149		165,809		74,731		1,861,356		—		3,105,045
Death or Disability		—		—		45,013		1,861,356		—		1,906,369

Laura Buss Sayavedra
Change in Control		—		—		—		195,485		—		195,485
Voluntary termination or involuntary termination with cause		—		—		8,440		—		—		8,440
Involuntary termination without cause		—		—		8,440		210,337		—		218,777
Involuntary or good reason termination after a CIC		—		—		8,440		484,194		—		492,634
Death or Disability		—		—		8,440		484,194		—		492,634

(1)	Amounts in the above table represent obligations of Spectra Energy under agreements currently in place at Spectra Energy, and valued as of December 31, 2011.

(2)

Amounts listed under “Cash Severance Payment” are payable under the terms of Mr. Rizzo’s change in control agreement. The severance benefits set forth above do not include accrued salary and cash incentive payments earned through December 31, 2011; however, such amounts are reflected in the Summary Compensation Table above.

(3)

Pursuant to Mr. Rizzo’s Change in Control Agreement, amounts listed under “Incremental Retirement Plan Benefit” represent the additional amounts that would be credited and vested in respect of the Spectra Energy Retirement Cash Balance Plan, Spectra Energy Executive Cash Balance Plan, Spectra Energy Retirement Savings Plan and the Spectra Energy Executive Savings Plan in the event he continued to be employed by Spectra Energy for two additional years, at his rate of base salary plus target bonus percentage in effect on December 31, 2011.

(4)	Amounts listed under “Welfare and Other Benefits” include the maximum accrued vacation allowed under Company policy and the amount that would be paid to Mr. Rizzo who has entered into a Change in Control Agreement in lieu of providing continued welfare benefits for 24 months.

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(5)

The amounts listed under “Stock Awards” would be the result of the acceleration of the vesting of previously awarded stock as a result of each event listed and any associated dividend or distribution equivalent payments due upon vesting. For Mr. Rizzo, who is retirement eligible, the amounts also include the continued vesting of previously awarded phantom units after the applicable termination event.

The amounts listed in the preceding table have been determined based on a variety of assumptions, and the actual amounts to be paid out can only be determined at the time of the Spectra Energy Partners executive officer’s termination of employment. The amounts described in the table do not include compensation to which both Spectra Energy Partners executive officers would be entitled without regard to his or her termination of employment, including (a) base salary and short-term incentives that have been earned but not yet paid, and (b) amounts that have been earned, but not yet paid, under the terms of the plans listed under the “Pension Benefits” and “Nonqualified Deferred Compensation” tables.

With respect to Mr. Rizzo, the amounts shown above do not reflect the fact that if, in the event that payments to the executive in connection with a change in control otherwise would result in an excise tax under Section 4999 of the Internal Revenue Code, such payments may be reduced to the extent necessary so that the excise tax does not apply.

The amounts shown above with respect to outstanding Spectra Energy and Spectra Energy Partners stock awards were calculated based on a variety of assumptions, including the following: (a) the Spectra Energy Partners executive officer terminated employment on the last day of 2011; (b) the price for Spectra Energy common stock of $30.75 and for Spectra Energy Partners units of $31.96, which were the closing prices on the last trading day of 2011; (c) the continuation of Spectra Energy’s dividend and Spectra Energy Partners’ distribution at the rate in effect on December 31, 2011; and (d) performance at the target level with respect to performance share units.

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DIRECTORS’ COMPENSATION

The following section provides information regarding payments to members of the board of directors of our general partner. Members of the board who are also employees of affiliates of our general partner do not receive additional compensation for serving on the board. The following is a description of the compensation program for non-employee directors of our general partner for 2011.

Director Compensation Program. Under the director compensation program approved by our general partner, each director receives an annual cash retainer of $65,000 and a grant of a number of common units equal to $50,000 divided by the closing price of our common units on the NYSE on the date of grant. Each Committee Chair also receives an annual cash retainer of $20,000. In addition, the Chairman of the Board receives an additional annual retainer of $60,000, 50% of which is paid in cash and 50% of which is paid in common units. The Chairman is also provided with office space and administrative support.

Charitable Giving Program. Members of the board of our general partner are eligible to participate in the Spectra Energy Foundation Matching Gifts Program under which Spectra Energy Corp will match contributions to qualifying institutions of up to $7,500 per director per calendar year. In 2011, the Spectra Energy Foundation made matching charitable contributions on behalf of Directors Arnold, Brownell and Bliss of up to $7,500.

Expense Reimbursement. Non-employee directors are reimbursed for expenses reasonably incurred in connection with attendance and participation at Board and Committee meetings.

The following table describes the compensation earned during 2011 by each individual who served as an outside director during 2011.

DIRECTOR COMPENSATION


Name	Fees Earned or Paid in Cash ($)		Stock Awards ($)(1)		Options Awards ($)		Change in Pension Value and Nonqualified Deferred Compensation Earnings ($)	All Other Compensation ($)(2)		Total ($)
Steven D. Arnold		85,000		50,000		—	—		5,500		140,500
Stewart A. Bliss		85,000		50,000		—	—		5,000		140,000
Nora Mead Brownell		65,000		50,000		—	—		7,500		122,500
Fred J. Fowler		95,000		80,000		—	—		—		175,000
J.D. Woodward, III		65,000		50,000		—	—		—		115,000

(1)	This column reflects the aggregate grant date fair value of the equity awarded computed in accordance with FASB ASC Topic 718.

(2)	This column reflects matching charitable contributions.

The value of all perquisites and other personal benefits or property received by each director in 2011 was less than $5,000 and are not included in the above table.

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Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.

The following table sets forth the beneficial ownership of Spectra Energy Partners’ units as of January 31, 2012 held by:

•

all of the directors of the General Partner;

•

each named executive officer of the General Partner; and

•

all directors and officers of the General Partner as a group.


Name of Beneficial Owner(1)	Common Units Beneficially Owned		Percentage of Common Units Beneficially Owned
Spectra Energy Corp(2)		60,914,686		63.2	%
Spectra Energy Transmission LLC		16,958,130		17.6	%
Spectra Energy Southeast Pipeline Corp.		43,956,556		45.6	%
Julie A. Dill		250		*
Fred J. Fowler		27,918		*
R. Mark Fiedorek		7,823		*
Patrick J. Hester		—		*
Theopolis Holeman		—		*
Laura Buss Sayavedra		4,661		*
Steven D. Arnold		35,448		*
Nora Mead Brownell		14,621		*
Stewart A. Bliss		9,948		*
J.D. Woodward, III		31,668		*
All directors and executive officers as a group (ten persons)		132,337		*

(*)	Less than 1% of units outstanding.

(1)	Unless otherwise indicated, the address for all beneficial owners in this table is 5400 Westheimer Court, Houston, TX 77056.

(2)	Spectra Energy is the ultimate parent company of each of Spectra Energy Transmission, Spectra Energy Southeast Pipeline Corp. and Spectra Energy Partners (DE) GP, LP and may, therefore, be deemed to beneficially own the units held by each of these entities.

The following table lists the beneficial owners of 5% or more of Spectra Energy Partners’ outstanding common units as of February 10, 2012. This information is based on the most recently available reports filed with the SEC.


	Shares of common stock
Name and Address of Beneficial Owner	Beneficially Owned	Percentage
Neuberger Berman Group LLC (1)	5,015,149		5.205	%
605 Third Avenue, New York, NY 10158
Tortoise Capital Advisors, L.L.C. (2)	4,970,580		5.2	%
11550 Ash Street, Suite 300, Leawood, Kansas 66211

(1)	According to the Schedule 13G/A filed by Neuberger Berman Group LLC on February 8, 2012, these units are beneficially owned by its clients, and it has shared voting power with respect to 4,014,859 units and shared dispositive power with respect to 5,015,149 units.

(2)	According to the Schedule 13G filed by Tortoise Capital Advisors, L.L.C. on February 10, 2012, these units are beneficially owned by its clients, and it has shared voting power with respect to 4,798,005 units and shared dispositive power with respect to 4,970,580 units.

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Equity Compensation Plan Information

The following table summarizes information about Spectra Energy Partners’ equity compensation plan as of December 31, 2011.


	Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights(1) (a)		Weighted -Average Exercise Price of Outstanding Options, Warrants and Rights (b)		Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column(a)) (c)
Equity compensation plans approved by unitholders		—		n/a		—
Equity compensation plans not approved by unitholders		—		n/a		760,689

Total		—		n/a		760,689

(1)	The long-term incentive plan currently permits the grant of awards covering an aggregate of 900,000 units.

Item 13. Certain Relationships and Related Transactions, and Director Independence.

Spectra Energy and its affiliates own 60,914,686 common units as of December 31, 2011, representing an aggregate 63% limited partner interest in Spectra Energy Partners. In addition, the General Partner owns a 2% general partner interest in Spectra Energy Partners and all of the incentive distribution rights.

Distributions and Payments to The General Partner and its Affiliates

The following table summarizes the distributions and payments made or to be made by Spectra Energy Partners to the General Partner and its affiliates in connection with the ongoing operation and any liquidation of Spectra Energy Partners. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm’s-length negotiations.

Operational Stage

Distributions of Available Cash to the General Partner and its affiliates

Spectra Energy Partners generally makes cash distributions 98% to its unitholders pro rata, including the General Partner and its affiliates, as the holders of an aggregate 60,914,686 common units, and 2% to the General Partner. In addition, if distributions exceed the minimum quarterly distribution and other higher target distribution levels, the General Partner will be entitled to increasing percentages of the distributions, up to 50% of the distributions above the highest target distribution level.

Payments to the General Partner and its affiliates

Spectra Energy Partners reimburses Spectra Energy and its affiliates for the payment of certain operating expenses and for the provision of various general and administrative services for the benefit of Spectra Energy Partners.

Withdrawal or removal the General Partner

If the General Partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests.

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Liquidation Stage

Liquidation

Upon Spectra Energy Partners’ liquidation, the partners, including the General Partner, will be entitled to receive liquidating distributions according to their respective capital account balances.

Omnibus Agreement

In connection with its IPO, Spectra Energy Partners entered into an omnibus agreement with Spectra Energy, its general partner and the general partner of its general partner. The omnibus agreement, as amended, addresses the following matters:

•

Spectra Energy Partners’ obligation to reimburse Spectra Energy for the payment of direct operating expenses it incurs on Spectra Energy Partners’ behalf in connection with Spectra Energy Partners’ business and operations;

•

Spectra Energy Partners’ obligation to reimburse Spectra Energy for providing it allocated corporate, general and administrative services, which reimbursement is capped at $3.6 million per year, subject to adjustment for inflation and increases in connection with expansions of operations through the acquisition or construction of new assets or businesses with the concurrence of Spectra Energy Partners’ Conflicts Committee; and

•

Spectra Energy’s obligation to indemnify Spectra Energy Partners’ for certain liabilities and Spectra Energy Partners’ obligation to indemnify Spectra Energy for certain liabilities.

The General Partner and its affiliates also receive payments from Spectra Energy Partners pursuant to the contractual arrangements described below under the caption “Contracts with Affiliates.”

Any or all of the provisions of the Omnibus Agreement, other than the indemnification provisions described below, is terminable by Spectra Energy at its option if the General Partner is removed without cause and units held by the General Partner and its affiliates are not voted in favor of that removal. The Omnibus Agreement (other than the indemnification provisions) will also terminate in the event of a change of control of Spectra Energy Partners, its general partner or the general partner of its general partner.

Reimbursement of Operating and General and Administrative Expense

Under the Omnibus Agreement, Spectra Energy Partners reimburses Spectra Energy for the payment of certain operating expenses and for the provision of various corporate, general and administrative services (which corporate, general and administrative expenses are capped at $3.6 million annually, subject to increases as described above) for Spectra Energy Partners’ benefit.

Pursuant to these arrangements, Spectra Energy performs centralized corporate functions for Spectra Energy Partners, including legal, accounting, compliance, treasury, insurance, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit and tax. Spectra Energy Partners reimburses Spectra Energy for the expenses to provide these services as well as other expenses it incurs on Spectra Energy Partners’ behalf, such as salaries of personnel performing services for Spectra Energy Partners’ benefit and the cost of Spectra Energy employee benefits and general and administrative expenses associated with such personnel; capital expenditures; maintenance and repair costs; taxes; and direct expenses, including operating expenses and certain allocated operating expenses, associated with the ownership and operation of the contributed assets.

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Competition

Neither Spectra Energy or any of its affiliates is restricted, under either Spectra Energy Partners’ partnership agreement or the Omnibus Agreement, from competing with Spectra Energy Partners. Spectra Energy and any of its affiliates may acquire, construct or dispose of additional transportation and storage or other assets in the future without any obligation to offer Spectra Energy Partners the opportunity to purchase or construct those assets.

Indemnification

Under the Omnibus Agreement, Spectra Energy agreed to indemnify Spectra Energy Partners for three years after the closing of the IPO, July 2, 2010, against certain potential environmental and toxic tort claims, losses and expenses associated with the operation of the assets and occurring before July 2, 2007, the closing date of the IPO. The maximum liability of Spectra Energy for this indemnification obligation was limited to $15.0 million and Spectra Energy did not have any obligation under this indemnification until aggregate losses exceed $250,000. Spectra Energy has no indemnification obligations with respect to environmental claims made as a result of additions to or modifications of environmental laws relating to pollution or protection of the environment or natural resources promulgated after July 2, 2007. Spectra Energy Partners has agreed to indemnify Spectra Energy against environmental liabilities related to Spectra Energy Partners’ assets to the extent Spectra Energy is not required to indemnify Spectra Energy Partners.

Additionally, Spectra Energy will indemnify Spectra Energy Partners for losses attributable to title defects, failures to obtain consents or permits necessary for the transfer of the contributed assets, retained assets and liabilities (including preclosing litigation relating to contributed assets) and income taxes attributable to pre-closing operations. Spectra Energy Partners will indemnify Spectra Energy for all losses attributable to the postclosing operations of the assets contributed to Spectra Energy Partners, to the extent not subject to Spectra Energy’s indemnification obligations.

Contracts with Affiliates

Gulfstream Limited Liability Company Agreement

In connection with the closing of the IPO, Spectra Energy contributed to Spectra Energy Partners 49.0% of its 50.0% interest in Gulfstream. In connection with the Gulfstream acquisition in the fourth quarter of 2010, Spectra Energy contributed an additional 24.5% of its interest in Gulfstream to Spectra Energy Partners. Currently, Spectra Energy Partners owns a 49% interest in Gulfstream, Spectra Energy owns a 1% interest and affiliates of The Williams Companies, Inc. (Williams) own a collective 50.0% interest. Gulfstream’s second amended and restated limited liability company agreement governs the ownership and management of Gulfstream and provides for quarterly distributions equal to 100% of its available cash, which is defined to include Gulfstream’s cash and cash equivalents on hand at the end of the quarter less any reserves that may be deemed appropriate by the Gulfstream management committee for the operation of its business (including reserves for its future maintenance capital expenditures and for its anticipated future credit needs) or for its compliance with laws or other agreements.

The management committee of Gulfstream makes the determinations related to Gulfstream’s available cash. The management committee is comprised of one representative from each of Spectra Energy Partners and Spectra Energy and two representatives from Williams. Each representative’s vote is equal to its members’ ownership interest in Gulfstream. In addition, following the acquisition, under the terms of the limited liability company agreement, Spectra Energy Partner’s affirmative vote is required for all decision that require more than a majority vote of the ownership interests in Gulfstream.

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,

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that member must first offer the other members the opportunity to acquire the interest that it proposes to sell on the same terms and conditions as proposed by such potential purchaser.

Market Hub General Partnership Agreement

In connection with the closing of the IPO, Spectra Energy contributed to Spectra Energy Partners 50.0% of its interest in Market Hub. Currently, Spectra Energy Partners owns a 50.0% interest in Market Hub and Spectra Energy owns a 50.0% interest. A partnership agreement governs the ownership and management of Market Hub and provides for quarterly distributions equal to 100% of its available cash, which is defined to include Market Hub’s cash and cash equivalents on hand at the end of the quarter less any reserves that may be deemed appropriate by the Market Hub management committee for the operation of its business (including reserves for its future maintenance capital expenditures and for its anticipated future credit needs) or for its compliance with law or other agreements.

A management committee comprised of an equal number of representatives of Spectra Energy and Spectra Energy Partners jointly make the determinations related to Market Hub’s available cash.

Storage and Transportation Related Arrangements

Spectra Energy Partners charges transportation and storage fees to Spectra Energy and its respective affiliates. Management anticipates continuing to provide these services to Spectra Energy and its respective affiliates in the ordinary course of business.

East Tennessee. East Tennessee is a party under a pipeline balancing agreement with Texas Eastern Transmission, LP (Texas Eastern), a Spectra Energy affiliate. The agreement was entered into in accordance with East Tennessee’s FERC gas tariff and provides for the monthly balancing of natural gas at receipt and delivery points with Texas Eastern interconnecting with East Tennessee’s pipeline system.

Market Hub. Texas Eastern has entered into a variety of storage service agreements with Moss Bluff and Egan. At Egan, interruptible service agreements were made under a FERC approved gas tariff, using rates negotiated at arms-length between the parties. At Moss Bluff, interruptible and firm storage service agreements are subject to the Statement of Operating Conditions on file with the FERC. Storage service agreements between Moss Bluff and Texas Eastern include rates negotiated at arms-length between the parties. In addition, each of Moss Bluff and Egan have entered into agreements with Texas Eastern as an interconnecting pipeline to provide for monthly gas balancing at receipt and delivery points between the parties.

Board Leadership and Risk Oversight

The board of our General Partner is currently led by our Chairman, Mr. Fowler. While our policies allow for the positions of the Office of Chairman and the Chief Executive Officer to be held by the same person we believe that leadership of the board of directors is best conducted by a separate Chairman. In exercising its duties to our unitholders, our board members should not be conflicted in any way. We have procedures that are specified in our partnership agreement to address potential conflicts, which include referring transactions that present a conflict to our Conflicts Committee. We believe that this board leadership structure is appropriate in maximizing the effectiveness of our board oversight and in providing perspective to our business that is independent from management.

The board has responsibility for oversight of our risk management process and receives regular reports from our executives and from Spectra Energy regarding the risks faced in our business. The board exercises its risk oversight responsibilities through the Audit Committee, with respect to financial reporting and compliance risks. In addition, the Compensation Committee of Spectra Energy provides oversight with respect to risks that may be created by our compensation programs. Spectra Energy’s management has undertaken, and the Compensation

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Committee has reviewed, an evaluation of the incentives to its employees to take risk that are created by its compensation programs. Based upon that evaluation, Spectra Energy has concluded that its compensation programs do not create risks that are reasonably likely to result in a material adverse affect on the Company.

Director Independence

See Item 10. Directors, Executive Officers and Corporate Governance for information about the independence of the General Partner’s board of directors and its committees.

Item 14. Principal Accounting Fees and Services.

The following table presents fees for professional services rendered by Deloitte & Touche LLP, and the member firms of Deloitte Touche Tohmatsu and their respective affiliates (collectively, Deloitte) for us for 2011 and 2010:


Type of Fees	2011		2010
	(in millions)
Audit Fees(a)	$	1.1	$	0.9
Audit-Related Fees(b)		0.2		0.1

Total Fees:	$	1.3	$	1.0

(a)

Audit Fees are fees billed or expected to be billed by Deloitte for professional services for the audit of our Consolidated Financial Statements included in our annual report on Form 10-K and review of financial statements included in our quarterly reports on Form 10-Q, services that are normally provided by Deloitte in connection with statutory, regulatory or other filings or engagements or any other service performed by Deloitte to comply with generally accepted auditing standards. Audit Fees also includes fees billed or expected to be billed by Deloitte for professional services for the audit of our internal controls under the requirements of Section 404 of the Sarbanes-Oxley Act of 2002 and related regulations.

(b)

Audit-Related Fees are fees billed by Deloitte for assurance and related services that are reasonably related to the performance of an audit or review of our financial statements, including assistance with acquisitions and divestitures and internal control reviews. Audit-Related Fees also include comfort and consent letters in connection with SEC filings and financing transactions.

To safeguard the continued independence of the independent auditor, the Audit Committee adopted a policy that prevents our independent auditor from providing services to us that are prohibited under Section 10A(g) of the Exchange Act, as amended. This policy also provides that independent auditors are only permitted to provide services to us and our subsidiaries that have been pre-approved by the Audit Committee. Pursuant to the policy, all audit services require advance approval by the Audit Committee. All other services by the independent auditor that fall within certain designated dollar thresholds, both per engagement as well as annual aggregate, have been pre-approved under the policy. Different dollar thresholds apply to the three categories of pre-approved services specified in the policy (Audit-Related services, Tax services and Other services). All services that exceed the dollar thresholds must be approved in advance by the Audit Committee. Pursuant to applicable provisions of the Exchange Act, as amended, the Audit Committee has delegated approval authority to the Chairman of the Audit Committee. The Chairman has presented all approval decisions to the full Audit Committee. All engagements performed by the independent auditor since July 2, 2007 were approved by the Audit Committee pursuant to its pre-approval policy.

117

PART IV

Item 15. Exhibits, Financial Statement Schedules.

(a) Consolidated Financial Statements, Supplemental Financial Data and Supplemental Schedules included in Part II of this annual report are as follows:

Spectra Energy Partners, LP:

Report of Independent Registered Public Accounting Firm

Consolidated Statements of Operations

Consolidated Balance Sheets

Consolidated Statements of Cash Flows

Consolidated Statements of Partners’ Capital and Comprehensive Income

Notes to Consolidated Financial Statements

Schedule II — Consolidated Valuation and Qualifying Accounts and Reserves

Separate Financial Statements of Subsidiaries not Consolidated Pursuant to Rule 3-09 of Regulation S-X:

Gulfstream Natural Gas System, L.L.C.:

Report of Independent Registered Public Accounting Firm

Statements of Operations

Balance Sheets

Statements of Cash Flows

Statements of Members’ Equity and Comprehensive Income

Notes to Financial Statements

Market Hub Partners Holding:

Report of Independent Registered Public Accounting Firm

Consolidated Statements of Operations

Consolidated Balance Sheets

Consolidated Statements of Cash Flows

Consolidated Statements of Partners’ Capital

Notes to Consolidated Financial Statements

All other schedules are omitted because they are not required or because the required information is included in the Consolidated Financial Statements or Notes.

118

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


	SPECTRA ENERGY PARTNERS, LP

	By:	Spectra Energy Partners (DE) GP, LP, its general partner

	By:	Spectra Energy Partners GP, LLC, its general partner

Date: February 28, 2012		/s/ JULIE A. DILL
		Julie A. Dill President and Chief Executive Officer Spectra Energy Partners GP, LLC

Date: February 28, 2012		/s/ LAURA BUSS SAYAVEDRA
		Laura Buss Sayavedra Vice President and Chief Financial Officer Spectra Energy Partners GP, LLC

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.


/s/ JULIE A. DILL (i) Julie A. Dill		President and Chief Executive Officer (Principal Executive Officer and Director)

/s/ LAURA BUSS SAYAVEDRA (ii) Laura Buss Sayavedra		Vice President and Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)

* (iii) Fred J. Fowler		Chairman of the Board of Directors

* Steven D. Arnold		Director

* Stewart A. Bliss		Director

* Nora Mead Brownell		Director

* R. Mark Fiedorek		Director

* Patrick J. Hester		Director

* Theopolis Holeman		Director

* J.D. Woodward, III		Director

119

Date: February 28, 2012

Julie A. Dill, by signing her name hereto, does hereby sign this document on behalf of the registrant and on behalf of each of the above-named persons previously indicated by asterisk pursuant to a power of attorney duly executed by the registrant and such persons, filed with the Securities and Exchange Commission as an exhibit hereto.


By:		/s/ JULIE A. DILL
		Julie A. Dill
		Attorney-In-Fact

120

FINANCIAL STATEMENTS OF

GULFSTREAM NATURAL GAS SYSTEM, L.L.C.

INDEX TO FINANCIAL STATEMENTS


	Page
Financial Statements:
Report of Independent Registered Public Accounting Firm		F-2
Statements of Operations for the years ended December 31, 2011, 2010 and 2009		F-3
Balance Sheets as of December 31, 2011 and 2010		F-4
Statements of Cash Flows for the years ended December 31, 2011, 2010 and 2009		F-5
Statements of Members’ Equity and Comprehensive Income for the years ended December 31, 2011, 2010 and 2009		F-6
Notes to Financial Statements		F-7

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Members of Gulfstream Natural Gas System, L.L.C.

We have audited the accompanying balance sheets of Gulfstream Natural Gas System, L.L.C., (the “Company”), as of December 31, 2011 and 2010, and the related statements of operations, cash flows, and members’ equity and comprehensive income for each of the three years in the period ended December 31, 2011. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with generally accepted auditing standards as established by the Auditing Standards Board (United States) and in accordance with the auditing standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such financial statements present fairly, in all material respects, the financial position of Gulfstream Natural Gas System, L.L.C. as of December 31, 2011 and 2010, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2011 in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Houston, Texas

February 23, 2012

F-2

GULFSTREAM NATURAL GAS SYSTEM, L.L.C.

STATEMENTS OF OPERATIONS


	Years Ended December 31,
	2011		2010		2009
	(In millions)

Operating Revenues	$	273.4	$	273.6	$	251.5

Operating Expenses
Operating, maintenance and other		4.7		5.5		4.5
Operating, maintenance and other — affiliates		17.7		15.1		14.6
Depreciation and amortization		35.4		35.0		34.5
Property and other taxes		13.7		17.5		14.0

Total operating expenses		71.5		73.1		67.6

Operating Income		201.9		200.5		183.9
Other Income and Expenses, net		—		0.9		1.4
Interest Expense		69.9		69.8		61.3

Net Income	$	132.0	$	131.6	$	124.0

See Notes to Financial Statements.

F-3

GULFSTREAM NATURAL GAS SYSTEM, L.L.C.

BALANCE SHEETS


	December 31,
	2011		2010
	(In millions)
ASSETS
Current Assets
Cash and cash equivalents	$	54.4	$	63.7
Receivables (allowance for doubtful accounts of zero at December 31, 2011 and 2010)		22.8		25.4
Inventory		7.5		6.3
Other		2.4		2.4

Total current assets		87.1		97.8

Property, Plant and Equipment
Cost		2,065.6		2,056.6
Less accumulated depreciation and amortization		281.8		247.0

Net property, plant and equipment		1,783.8		1,809.6

Regulatory Assets and Deferred Debits
Regulatory tax asset		23.6		24.2
Unamortized debt expense		6.2		7.2

Total regulatory assets and deferred debits		29.8		31.4

Total Assets	$	1,900.7	$	1,938.8


LIABILITIES AND MEMBERS’ EQUITY
Current Liabilities
Accounts payable	$	0.4	$	4.0
Accounts payable — affiliates		1.9		1.9
Taxes accrued		0.4		3.5
Interest accrued		10.0		10.0
Accrued liabilities		1.6		1.2
Fuel tracker liabilities		1.9		3.0
Other		0.7		0.6

Total current liabilities		16.9		24.2

Long-term Debt		1,149.1		1,149.0

Other Long-term Liabilities		—		0.4

Commitments and Contingencies

Members’ Equity
Members’ equity		725.7		754.9
Accumulated other comprehensive income		9.0		10.3

Total members’ equity		734.7		765.2

Total Liabilities and Members’ Equity	$	1,900.7	$	1,938.8

See Notes to Financial Statements.

F-4

GULFSTREAM NATURAL GAS SYSTEM, L.L.C.

STATEMENTS OF CASH FLOWS


	Years Ended December 31,
	2011			2010			2009
	(In millions)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	132.0		$	131.6		$	124.0
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		36.6			36.2			35.4
Allowance for funds used during construction — equity		(0.2	)		(0.4	)		(0.6	)
Reclassification adjustments from accumulated other comprehensive income into net income		(1.3	)		(1.3	)		(1.3	)
Decrease (increase) in:
Receivables		0.7			(3.2	)		(3.0	)
Other current assets		—			0.4			4.6
Increase (decrease) in:
Accounts payable		(0.4	)		(1.1	)		1.7
Taxes accrued		(3.1	)		1.4			(1.0	)
Interest accrued		—			—			1.8
Accrued liabilities		0.4			(1.0	)		1.7
Fuel tracker liabilities		(0.1	)		0.1			—
Other current liabilities		0.5			(0.2	)		(0.5	)
Other, assets		1.4			0.6			(3.4	)
Other, liabilities		(0.5	)		0.4			—

Net cash provided by operating activities		166.0			163.5			159.4

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(14.6	)		(21.6	)		(53.5	)

Net cash used in investing activities		(14.6	)		(21.6	)		(53.5	)

CASH FLOWS FROM FINANCING ACTIVITIES
Capital contributions from members		7.7			20.0			40.2
Distributions to members		(168.4	)		(161.2	)		(445.1	)
Proceeds from the issuance of long-term debt		—			—			299.0

Net cash used in financing activities		(160.7	)		(141.2	)		(105.9	)

Net increase (decrease) in cash and cash equivalents		(9.3	)		0.7			—
Cash and cash equivalents at beginning of period		63.7			63.0			63.0

Cash and cash equivalents at end of period	$	54.4		$	63.7		$	63.0

Supplemental Disclosures
Cash paid for interest, net of amount capitalized	$	70.0		$	70.3		$	60.1
Significant non-cash transaction:
Property, plant and equipment accruals	$	0.1		$	3.3		$	4.9

See Notes to Financial Statements.

F-5

GULFSTREAM NATURAL GAS SYSTEM, L.L.C.

STATEMENTS OF MEMBERS’ EQUITY AND COMPREHENSIVE INCOME


	Spectra Energy Corp			Spectra Energy Partners, LP			The Williams Companies, Inc.			Williams Partners, L.P.			Total
	(In millions)
Balance December 31, 2008	$	269.9		$	259.3		$	529.2		$	—		$	1,058.4
Net income		31.6			30.4			62.0			—			124.0
Reclassification of cash flow hedges into earnings		(0.3	)		(0.3	)		(0.7	)		—			(1.3	)

Total comprehensive income														122.7

Capital contributions from members		10.3			9.8			20.1			—			40.2
Distributions to members		(113.5	)		(109.0	)		(222.6	)		—			(445.1	)
Attributed deferred tax benefit		—			—			0.1			—			0.1

Balance December 31, 2009		198.0			190.2			388.1			—			776.3

Net income		30.3			35.5			37.8			28.0			131.6
Reclassification of cash flow hedges into earnings		(0.3	)		(0.3	)		(0.4	)		(0.3	)		(1.3	)

Total comprehensive income														130.3

Ownership change (See Footnote 2)		(183.1	)		183.1			(184.5	)		184.5			—
Capital contributions from members		4.0			6.0			5.6			4.4			20.0
Distributions to members		(41.1	)		(39.5	)		(51.4	)		(29.2	)		(161.2	)
Attributed deferred tax expense		(0.1	)		—			(0.1	)		—			(0.2	)

Balance December 31, 2010		7.7			375.0			195.1			187.4			765.2

Net income		1.3			64.7			12.9			53.1			132.0
Reclassification of cash flow hedges into earnings		—			(0.6	)		(0.1	)		(0.6	)		(1.3	)

Total comprehensive income														130.7

Ownership change		—			—			(178.2	)		178.2			—
Capital contributions from members		0.1			3.7			2.0			1.9			7.7
Distributions to members		(8.2	)		(76.0	)		(24.3	)		(59.9	)		(168.4	)
Attributed deferred tax expense		—			(0.3	)		(0.1	)		(0.1	)		(0.5	)

Balance December 31, 2011	$	0.9		$	366.5		$	7.3		$	360.0		$	734.7

See Notes to Financial Statements.

F-6

GULFSTREAM NATURAL GAS SYSTEM, L.L.C.

Notes to Financial Statements

1. Summary of Operations and Significant Accounting Policies

Nature of Operations. Gulfstream Natural Gas System, L.L.C. (collectively, “we”, “our”, “us” and “company”) owns an approximate 745-mile interstate natural gas pipeline system and is owned 1% by a subsidiary of Spectra Energy Corp (Spectra Energy), 49% by Spectra Energy Partners, LP (Spectra Energy Partners), 1% by The Williams Companies, Inc. (Williams) and 49% by Williams Partners L.P. (Williams Partners). We are operated under joint management by Spectra Energy, which provides the business functions, and Williams, which provides the technical functions. We transport natural gas that we receive from various onshore and offshore supply sources in the Mississippi and Alabama area, across the Gulf of Mexico, and deliver that natural gas to markets in central and southern Florida. Our interstate natural gas transmission operations are subject to the rules and regulations of the Federal Energy Regulatory Commission (FERC). We were formed on May 17, 1999 as a Delaware limited liability company.

Basis of Presentation. The financial statements reflect the results of operations, financial position and cash flows of our company. The financial statements do not include any of the assets, liabilities, revenues or expenses of the members. Transportation of natural gas Revenues and Other Revenues have been combined for the prior years to conform to our current presentation.

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

Cost-Based 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 or for instances where the regulator provides current rates that are intended to recover costs that are expected to be incurred in the future. Accordingly, we record assets and liabilities that result from the regulated ratemaking process that may not be recorded under GAAP for non-regulated entities. We continually assess whether regulatory assets are probable of future recovery by considering factors such as applicable regulatory changes and recent rate orders to other regulated entities. Based on this assessment, we believe our existing regulatory assets are probable of recovery. These regulatory assets and liabilities are classified in the Balance Sheets as Regulatory Assets and Deferred Debits and Current Liabilities. We evaluate our regulated assets, and consider factors such as regulatory changes and the effect of competition. If cost-based regulation ends or competition increases, we may have to reduce our asset balances to reflect a market basis less than cost and write-off the associated regulatory assets and liabilities. See Note 4 for further discussion.

Revenue Recognition. Revenues from the transportation of natural gas are recognized when the service is provided. Revenues related to these services provided but not yet billed are estimated each month. These estimates are generally based on contract data, regulatory information and preliminary throughput and allocation measurements. Final bills for the current month are billed and collected in the following month. Differences between actual and estimated unbilled revenues are immaterial.

F-7

Customers accounting for 10% or more of revenues during 2011, 2010 and 2009 are as follows:


	% of Revenues
Customer	2011			2010			2009
Florida Power & Light Company		53	%		53	%		52	%
Florida Power Corporation d/b/a Progress Energy Florida, Inc.		28			26			27

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 certain new regulated facilities, consists of two components, an equity component and an interest expense component. The equity component is a non-cash item. AFUDC is capitalized as a component of Property, Plant and Equipment cost, with offsetting credits to the Statements of Operations through Other Income and Expenses, Net for the equity component and Interest Expense for the interest expense component. After construction is completed, we are permitted to recover these costs through inclusion in the rate base and in the depreciation provision. The total amount of AFUDC included in the Statements of Operations was $0.5 million in 2011 (an equity component of $0.2 million and an interest expense component of $0.3 million), $0.9 million in 2010 (an equity component of $0.4 million and an interest expense component of $0.5 million) and $0.9 million in 2009 (an equity component of $0.6 million and an interest expense component of $0.3 million).

Income Taxes. We are not subject to income tax, but rather our taxable income or loss is reported on the respective income tax returns of our members. Accordingly, there is no federal tax provision in these financial statements. Since we are not responsible for the attributed income taxes, amounts related to the tax gross-up of AFUDC equity are carried in the individual capital accounts of our members.

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

Inventory. Inventory consists mainly of natural gas retained from shippers for fuel and also includes materials and supplies. Natural gas is recorded at the lower of cost or market. Materials and supplies are recorded at cost, using the average cost method.

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

Cash Flow Hedges. In 2005, we entered into derivative transactions that are hedges of the future cash flows of forecasted transactions (cash flow hedges). We are exposed to the impact of market fluctuations in interest rates. To protect from increasing interest rates and the resulting higher cost of the debt that was issued in 2005, we locked in existing interest rates by using financial derivatives (swaps) for hedge strategies. The total amount of the debt in 2005 was $850.0 million of which $500.0 million was hedged. The associated interest rate swaps were terminated on October 12, 2005, prior to the issuance of the related debt. These derivatives were initially recorded on the Balance Sheets at their fair value as Accumulated Other Comprehensive Income (AOCI). Deferred gains of $9.0 million in AOCI as of December 31, 2011 will continue to be amortized to interest expense over the term of the debt issued (November 2015). The total amortization for 2011, 2010 and 2009 was $1.3 million.

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 AOCI until earnings are affected by the hedged transaction. We discontinue hedge accounting prospectively when it is determined that a derivative no longer qualifies as an effective hedge, or when it is no longer probable that the hedged forecasted transaction will occur. When hedge accounting is discontinued because the derivative no longer qualifies as an effective hedge, the derivative is

F-8

subject to the mark-to-market model of accounting (MTM Model) prospectively. Gains and losses related to discontinued hedges that were previously accumulated in AOCI will remain in AOCI until the underlying contract is reflected in earnings; unless it is probable that the hedged forecasted transaction will not occur at which time associated deferred amounts in AOCI are immediately recognized in current earnings. All derivatives designated and accounted for as hedges are classified in the same category as the item being hedged in the Statements of Cash Flows. In addition, all components of each derivative gain or loss are included in the assessment of hedge effectiveness.

When available, quoted market prices or prices obtained through external sources are used to measure a contract’s fair value.

Property, Plant and Equipment. Property, plant and equipment is stated at historical cost less accumulated depreciation. We capitalize all construction-related direct labor and material costs, as well as indirect construction costs. Indirect costs include general engineering, taxes and the cost of funds used during construction. The costs of renewals and betterments that extend the useful life or increase the expected output of property, plant and equipment are also capitalized. The costs of repairs, replacements and major maintenance projects that do not extend the useful life or increase the expected output of property, plant and equipment are expensed as incurred. Depreciation is generally computed over the asset’s estimated useful life using the straight-line method.

Preliminary Project Costs. Project development costs, including expenditures for preliminary surveys, plans, investigations, environmental studies, regulatory applications and other costs incurred for the purpose of determining the feasibility of capital expansion projects, are capitalized for rate-regulated enterprises when it is determined that recovery of such costs through regulated revenues of the completed project is probable. Any inception-to-date costs that were initially expensed are reversed and capitalized as Property, Plant and Equipment.

Long-Lived Asset Impairments. We evaluate whether long-lived assets have been impaired when circumstances indicate the carrying value of those assets may not be recoverable. For such long-lived assets, an impairment exists when its carrying value exceeds the sum of estimates of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. When alternative courses of action to recover the carrying amount of a long-lived asset are under consideration, a probability-weighted approach is used in 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, an 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.

We assess 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 analyses and analyses from outside advisors. Significant changes in market conditions resulting from events such as changes in natural gas available to our systems, the condition of an asset, a change in our intent to utilize the asset or a significant change in contracted revenues or regulatory recoveries would generally require us to reassess the cash flows related to the long-lived assets.

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

F-9

New Accounting Pronouncements — 2011, 2010 and 2009. There were no significant accounting pronouncements adopted during 2011, 2010 or 2009 that had a material impact on our results of operations, financial position or cash flows.

2. Corrections of Error in Members’ Ownership

During 2011, we identified an error in our previously issued Statements of Members’ Equity and Comprehensive Income related to the change in ownership that occurred during 2010. In February 2010, Williams Partners bought a 24.5% interest in us from Williams and in November 2010, Spectra Energy Partners bought a 24.5% interest in us from Spectra Energy. The transfer of equity related to these transactions was not reflected in the Statement of Members’ Equity and Comprehensive Income. The other equity related activity, including allocations of Net income, Reclassification of cash flow hedges into earnings, Capital contributions from members, Distributions to members and Attributed deferred tax expense, in 2010 and total equity both on the Statements of Member’s Equity and Comprehensive Income and the Balance Sheets are not impacted by this error. In addition, the correct ownership percentages were disclosed in Footnote 1 in the 2010 financial statements.

The corrections of member balance on the Statements of Members’ Equity and Comprehensive Income for December 31, 2010 are as follow:


	Spectra Energy Corp			Spectra Energy Partners, LP		The Williams Companies, Inc			Williams Partners, L.P.		Total
	(in millions)
As previously reported	$	190.8		$	191.9	$	379.6		$	2.9	$	765.2
Less ownership transfer		(183.1	)		183.1		(184.5	)		184.5		—

As corrected	$	7.7		$	375.0	$	195.1		$	187.4	$	765.2

3. Transactions with Affiliates

Gulfstream Management & Operating Services, L.L.C. (GMOS), owned 50% by an affiliate of Spectra Energy and 50% by an affiliate of Williams, provides management, construction and operating services pursuant to agreements entered into with us and with affiliates of Spectra Energy and Williams. GMOS bills us for services rendered including labor and benefit costs, employee expenses, overhead costs and in some cases, third-party costs. Such amounts are reflected in the Statements of Operations as Operating, Maintenance and Other — Affiliates or in the Balance Sheets as Property, Plant and Equipment, as appropriate.

Transactions with affiliates are summarized in the tables below:

Statements of Operations


	2011		2010		2009
	(in millions)
Operating, maintenance and other — affiliates	$	17.7	$	15.1	$	14.6

Balance Sheets


	December 31,
	2011		2010
	(in millions)
Property, plant and equipment(a)	$	2.6	$	2.3
Current assets — other		0.6		1.9
Accounts payable — affiliates		1.9		1.9

(a)	Reflects additions to Property, Plant and Equipment billed from an affiliate in the respective year.

F-10

During 2011, Spectra Energy received a disproportionate distribution in relation to their ownership percentage based on an agreement between Spectra Energy and Spectra Energy Partners.

4. Regulatory Matters

Regulatory Assets and Liabilities. We record assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for non-regulated entities. See Note 1 for further discussion.

Regulatory Assets and Liabilities


	December 31,				Recovery/Refund Period Ends
	2011		2010		Recovery/Refund Period Ends
	(in millions)
Regulatory Assets(a)
Regulatory asset related to income taxes(b)	$	23.6	$	24.2		(c	)

Total Regulatory Assets	$	23.6	$	24.2

Regulatory Liabilities(a)
Fuel tracker(d)	$	1.9	$	3.0		2012

Total Regulatory Liabilities	$	1.9	$	3.0

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

(b)	Relates to tax gross-up of AFUDC equity portion and is included in Regulatory Assets and Deferred Debits.

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

(d)	Included in Current Liabilities.

Rate Related Information. We operate under rates approved by the FERC in 2007. In 2007, the FERC issued an order approving our Phase III expansion project. That order also required us to file a Cost and Revenue Study three years after our Phase III facilities went into service. We filed the Cost and Revenue Study on November 1, 2011 and a final FERC order is pending. The effects of this matter are not expected to have a material effect on our future results of operations, financial position or cash flows.

5. Property, Plant and Equipment


	Estimated Useful Life		December 31,
	Estimated Useful Life		2011			2010
	(Years)		(in millions)
Plant
Natural gas transmission		60	$	1,885.3		$	1,855.2
Rights of way		60		117.7			115.7
Land		—		16.3			16.0
Construction in process		—		1.6			25.4
Other		5-20		44.7			44.3

Total property, plant and equipment				2,065.6			2,056.6
Total accumulated depreciation and amortization				(281.8	)		(247.0	)

Total net property, plant and equipment			$	1,783.8		$	1,809.6

All of our property, plant and equipment is regulated with estimated useful lives based on rates approved by the FERC. The composite weighted-average depreciation rates were 1.7% for 2011 and 2010, and 1.8% for 2009.

F-11

Amortization expense of intangible assets totaled $2.2 million in 2011, 2010 and 2009. Amortization expense for 2012 through 2016 is estimated to be $2.2 million each year.

6. Debt

Summary of Debt and Related Terms


	Year Due		December 31,
	Year Due		2011			2010
			(in millions)
Unsecured note payable, 5.56%		2015	$	500.0		$	500.0
Unsecured note payable, 6.95%		2016		300.0			300.0
Unsecured note payable, 6.19%		2025		350.0			350.0
Unamortized debt discount				(0.9	)		(1.0	)

Total long-term debt			$	1,149.1		$	1,149.0

All scheduled debt payments correspond to the year due. The unsecured note payable due 2015 and 2016 are due within the next five years.

7. Fair Value Measurements

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


Description	Balance Sheet Caption		December 31, 2011
Description	Balance Sheet Caption		Total		Level 1		Level 2		Level 3
			(in millions)
Short-term money market securities		Cash and cash equivalents	$	24.7	$	24.7	$	—	$	—

Total Assets			$	24.7	$	24.7	$	—	$	—


Description	Balance Sheet Caption		December 31, 2010
Description	Balance Sheet Caption		Total		Level 1		Level 2		Level 3
			(in millions)
Short-term money market securities		Cash and cash equivalents	$	61.7	$	61.7	$	—	$	—

Total Assets			$	61.7	$	61.7	$	—	$	—

Level 1 valuations represent quoted unadjusted prices for identical instruments in active markets.

Financial Instruments. The fair value of our financial instruments, excluding derivatives, is summarized in the following table. Judgment is required in interpreting market data to develop the estimates of fair value. These estimates are not necessarily indicative of the amounts we could have realized in current markets. The fair values of our current long-term debt are determined based on market-based prices. These valuations included inputs such as quoted market prices of the exact or similar instruments or alternative pricing sources that included models or matrix pricing tools, with reasonable levels of price transparency.


	December 31,
	2011				2010
	Book Value		Approximate Fair Value		Book Value		Approximate Fair Value
	(in millions)
Long-term debt	$	1,149.1	$	1,332.1	$	1,149.0	$	1,262.4

F-12

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

During the 2011 and 2010 periods, there were no adjustments to assets measured at fair value on a nonrecurring basis.

8. Credit Risk

Our principal customers for natural gas transportation are utilities located throughout the state of Florida. We have concentrations of receivables from utilities throughout Florida. These concentrations of customers may affect our overall credit risk in that risk factors can negatively affect the credit quality of the entire sector. Where exposed to credit risk, we analyze the customers’ financial condition prior to entering into an agreement, establish credit limits and monitor the appropriateness of those limits on an ongoing basis. We also obtain parental guarantees, cash deposits or letters of credit from customers to provide credit support, where appropriate, based on our financial analysis of the customer and the regulatory or contractual terms and conditions applicable to each contract.

9. Commitments and Contingencies

General Insurance. We carry, either independently or through our owners, insurance consistent with companies engaged in similar commercial operations with similar type properties. Our insurance program includes (1) liability insurance covering our liabilities arising from bodily injury or property damage to third parties resulting from our operations including liabilities arising from the use of owned, non-owned and hired vehicles and (2) property insurance on an all-risk basis covering loss or damage to real and personal property owned or leased by our company. We also carry onshore business interruption insurance. All coverages are subject to certain deductibles, terms and conditions common for companies with similar types of operations. The cost of our general insurance will continue to fluctuate reflecting changing conditions of the insurance market.

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

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

10. Subsequent Event

We have evaluated significant events and transactions that occurred from January 1, 2012 through February 23, 2012 the date the financial statements were issued.

A distribution to members of $41.4 million was declared and paid on January 20, 2012.

F-13

CONSOLIDATED FINANCIAL STATEMENTS OF

MARKET HUB PARTNERS HOLDING

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS


	Page
Consolidated Financial Statements:
Report of Independent Registered Public Accounting Firm		F-15
Consolidated Statements of Operations for the years ended December 31, 2011, 2010 and 2009		F-16
Consolidated Balance Sheets as of December 31, 2011 and 2010		F-17
Consolidated Statements of Cash Flows for the years ended December 31, 2011, 2010 and 2009		F-18
Consolidated Statements of Partners’ Capital for the years ended December 31, 2011, 2010 and 2009		F-19
Notes to Consolidated Financial Statements		F-20

F-14

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners of Market Hub Partners Holding

We have audited the accompanying consolidated balance sheets of Market Hub Partners Holding and subsidiaries (the “Partnership”), as of December 31, 2011 and 2010, and the related consolidated statements of operations, cash flows, and partners’ capital for each of the three years in the period ended December 31, 2011. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with generally accepted auditing standards as established by the Auditing Standards Board (United States) and in accordance with the auditing standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Partnership 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 Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such financial statements present fairly, in all material respects, the financial position of Market Hub Partners Holding and subsidiaries as of December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011 in conformity with accounting principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP

Houston, Texas

February 28, 2012

F-15

MARKET HUB PARTNERS HOLDING

CONSOLIDATED STATEMENTS OF OPERATIONS

(In millions)


	Years Ended December 31,
	2011		2010		2009
Operating Revenues
Salt cavern storage	$	115.3	$	110.5	$	107.1
Salt cavern storage — affiliates		8.0		8.0		8.4

Total operating revenues		123.3		118.5		115.5

Operating Expenses
Operating, maintenance and other		9.4		8.4		8.6
Operating, maintenance and other — affiliates		12.0		12.6		10.8
Depreciation and amortization		10.8		14.5		12.1
Property and other taxes		5.5		4.2		3.2

Total operating expenses		37.7		39.7		34.7

Operating Income		85.6		78.8		80.8
Other Income and Expenses		—		0.6		—
Interest Income — Affiliates		0.1		0.2		0.3
Interest Expense		0.1		—		—
Interest Expense — Affiliates		—		0.1		0.1

Earnings Before Income Taxes		85.6		79.5		81.0
Income Tax Expense		0.2		0.2		0.2

Net Income	$	85.4	$	79.3	$	80.8

See Notes to Consolidated Financial Statements.

F-16

MARKET HUB PARTNERS HOLDING

CONSOLIDATED BALANCE SHEETS

(In millions)


	December 31,
	2011		2010
ASSETS
Current Assets
Cash and cash equivalents	$	4.4	$	3.7
Receivables (allowance for doubtful accounts of zero at December 31, 2011 and 2010)		9.8		10.8
Receivables — affiliates		2.0		1.0
Natural gas imbalance receivables		1.6		17.8
Natural gas imbalance receivables — affiliates		17.6		14.6
Notes receivable — affiliates		61.0		68.0
Other		1.2		1.4

Total current assets		97.6		117.3

Goodwill		200.5		200.5

Property, Plant and Equipment
Cost		618.1		588.9
Less accumulated depreciation and amortization		114.1		103.5

Net property, plant and equipment		504.0		485.4

Total Assets	$	802.1	$	803.2

LIABILITIES AND PARTNERS’ CAPITAL
Current Liabilities
Accounts payable	$	0.6	$	1.3
Accounts payable — affiliates		3.3		3.8
Taxes accrued		1.3		1.2
Natural gas imbalance payables		18.5		14.4
Natural gas imbalance payables — affiliates		0.7		18.0
Collateral liabilities		2.1		2.9
Collateral liabilities — affiliates		40.0		40.0
Other		0.1		0.1

Total current liabilities		66.6		81.7

Deferred Credits and Other Liabilities		0.6		—

Commitments and Contingencies

Partners’ Capital		734.9		721.5

Total Liabilities and Partners’ Capital	$	802.1	$	803.2

See Notes to Consolidated Financial Statements.

F-17

MARKET HUB PARTNERS HOLDING

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)


	Years Ended December 31,
	2011			2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	85.4		$	79.3		$	80.8
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		10.8			14.5			12.1
Decrease (increase) in:
Receivables		1.0			(0.5	)		(2.1	)
Receivables — affiliates		(1.0	)		0.4			0.3
Other current assets		0.2			(0.4	)		(0.8	)
Other, assets		—			0.2			(0.1	)
Increase (decrease) in:
Accounts payable		(0.8	)		0.3			0.2
Accounts payable — affiliates		(0.5	)		1.3			(6.9	)
Taxes accrued		0.1			—			(0.8	)
Interest accrued — affiliates		—			—			(7.0	)
Collateral liabilities		(0.8	)		0.5			(0.3	)
Collateral liabilities — affiliates		—			—			(40.0	)
Other current liabilities		—			(0.1	)		(1.7	)
Other, liabilities		0.6			—			—

Net cash provided by operating activities		95.0			95.5			33.7

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(29.3	)		(36.6	)		(59.2	)
Net increase in advances payable — affiliates		—			—			0.1
Collections from notes receivable — affiliates		59.0			47.1			59.0
Issuances of notes receivable — affiliates		(52.0	)		(60.1	)		(14.0	)

Net cash used in investing activities		(22.3	)		(49.6	)		(14.1	)

CASH FLOWS FROM FINANCING ACTIVITIES
Distributions to partners		(99.0	)		(95.5	)		(71.5	)
Capital contributions from partners		27.0			33.1			53.8

Net cash used in financing activities		(72.0	)		(62.4	)		(17.7	)

Net increase (decrease) in cash and cash equivalents		0.7			(16.5	)		1.9
Cash and cash equivalents at beginning of period		3.7			20.2			18.3

Cash and cash equivalents at end of period	$	4.4		$	3.7		$	20.2

Supplemental Disclosures
Cash paid (received) for interest — affiliates	$	(0.1	)	$	(0.1	)	$	7.1
Cash paid for income taxes		0.2			0.3			0.5
Significant non-cash transactions:
Deemed contributions from parent		—			—			(1.1	)
Property, plant and equipment noncash accruals		0.5			0.4			0.1

See Notes to Consolidated Financial Statements.

F-18

MARKET HUB PARTNERS HOLDING

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

(In millions)


	Spectra Energy Corp			Spectra Energy Partners, LP			Total
Balance December 31, 2008	$	320.2		$	320.2		$	640.4
Net income		40.4			40.4			80.8
Capital contributions from partners		26.9			26.9			53.8
Distributions to partners		(35.7	)		(35.8	)		(71.5	)
Deemed contributions from parent		0.6			0.5			1.1

Balance December 31, 2009		352.4			352.2			704.6
Net income		39.7			39.6			79.3
Capital contributions from partners		16.5			16.6			33.1
Distributions to partners		(47.8	)		(47.7	)		(95.5	)

Balance December 31, 2010		360.8			360.7			721.5
Net income		42.7			42.7			85.4
Capital contributions from partners		13.5			13.5			27.0
Distributions to partners		(49.5	)		(49.5	)		(99.0	)

Balance December 31, 2011	$	367.5		$	367.4		$	734.9

See Notes to Consolidated Financial Statements.

F-19

MARKET HUB PARTNERS HOLDING

Notes to Consolidated Financial Statements

1. Summary of Operations and Significant Accounting Policies

Nature of Operations. Market Hub Partners Holding (collectively, “we,” “our,” and “us”), owns and operates two natural gas storage facilities: Moss Bluff, located near Houston, Texas and Egan, located in Acadia Parish, Louisiana. Our facilities provide producers, end-users, power generators, local distribution companies, pipelines and energy marketers with high deliverability storage services, including hub services, such as park and loan services, wheeling and title transfer. Our Egan facilities are subject to the rules and regulations of the Federal Energy Regulatory Commission (FERC). Moss Bluff is subject to oversight by the Railroad Commission of Texas as an intrastate storage company. Moss Bluff, as a Hinshaw pipeline, must also comply with certain requirements under the FERC regulations.

Until July 2, 2007, we were a Delaware limited liability company that was wholly owned by Spectra Energy Corp (Spectra Energy). On July 2, 2007, immediately prior to the closing of Spectra Energy Partners, LP (Spectra Energy Partners) initial public offering (IPO), we were converted to a Delaware general partnership and Spectra Energy contributed 50% of its 100% ownership of us to Spectra Energy Partners.

Basis of Presentation. The Consolidated Financial Statements reflect the consolidated results of operations, financial position and cash flows of us and our subsidiaries. The Consolidated Financial Statements do not include any of the assets, liabilities, revenues or expenses of our partners. Hub Services and Other Revenues have been reclassified to Salt Cavern Storage Revenues for the prior years to conform to our current presentation.

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

Revenue Recognition. Revenues from the storage of natural gas are recognized when the service is provided. Revenues related to these services provided but not yet billed are estimated each month. These estimates are generally based on contract data, regulatory information and preliminary storage and allocation measurements. Final bills for the current month are billed and collected in the following month. Differences between actual and estimated unbilled revenues are immaterial.

There were no customers that accounted for 10% or more of consolidated revenues during 2011, 2010 or 2009.

Income Taxes. With the exception of the State of Texas, we are not subject to income tax, but rather our taxable income or loss is reported on the respective income tax returns of our partners. Accordingly, there is no federal tax provision in these financial statements; however, the State of Texas requires us to pay state margin tax.

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

Inventory. Inventory consists primarily of natural gas held in storage and is recorded at the lower of cost or market value, using the average cost method and is included in Other Current Assets on the Consolidated Balance Sheets.

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

F-20

Goodwill. We perform our goodwill impairment test annually and evaluate goodwill when events or changes in circumstances indicate that its carrying value may not be recoverable. No impairments of goodwill were recorded in 2011, 2010 or 2009.

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 exceeds our fair value, the second step of the process involves a comparison of the fair value and the carrying value of the goodwill. If the carrying value of the goodwill exceeds the implied fair value of that goodwill, an impairment loss is recognized in an amount equal to the excess. Additional impairment tests are performed between the annual reviews if events or changes in circumstances make it more likely than not that our fair value is below our carrying amount.

We primarily use a discounted cash flow analysis to determine fair value. Key assumptions in the determination of fair value include the use of an appropriate discount rate and estimated future cash flows. In estimating cash flows, we incorporate expected long-term growth rates in key markets served by our operations, regulatory stability and the ability to renew contracts, as well as other factors that affect our revenue, expense and capital expenditure projections.

Property, Plant and Equipment. Property, plant and equipment is stated at historical cost less accumulated depreciation. We capitalize all construction-related direct labor and material costs, as well as indirect construction costs, including general engineering and taxes. The costs of renewals and betterments that extend the useful life or increase the expected output of property, plant and equipment are also capitalized. The cost of repairs, replacements and major maintenance projects that do not extend the useful life or increase the expected output of property, plant and equipment are expensed as incurred. Depreciation is generally computed over the asset’s estimated useful life using the straight-line method.

When we retire regulated property, plant and equipment, we charge the original cost plus the cost of retirement, less salvage value, to accumulated depreciation and amortization. When we retire or sell properties, the cost is removed from the property account and the related accumulated depreciation and amortization accounts are reduced. Any gain or loss is recorded in earnings, unless otherwise required by the applicable regulatory body.

New Accounting Pronouncements. There were no significant accounting pronouncements adopted during 2011, 2010 or 2009 that had a material impact on our consolidated results of operations, financial position or cash flows.

2. Transactions with Affiliates

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

Operating, maintenance and other expenses include reimbursement of costs incurred by affiliates on behalf of us and allocations from Spectra Energy affiliates for various services provided by them and other costs. Affiliates charge such expenses based on the cost of actual services provided or using various allocation methodologies based on our percentage of assets, employees, earnings or other measures as compared to other affiliates.

Transactions with affiliates are summarized in the tables below:

Consolidated Statements of Operations


	2011		2010		2009
	(in millions)
Salt cavern storage	$	8.0	$	8.0	$	8.4
Operating, maintenance and other		12.0		12.6		10.8
Interest Income		0.1		0.2		0.3
Interest Expense		—		0.1		0.1

F-21

Consolidated Balance Sheets


	December 31,
	2011		2010
	(in millions)
Receivables	$	2.0	$	1.0
Natural gas imbalance receivables		17.6		14.6
Notes receivable		61.0		68.0
Current assets — other		0.2		0.4
Accounts payable		3.3		3.8
Natural gas imbalance payables		0.7		18.0
Collateral liabilities		40.0		40.0

During 2010, we had a $40.0 million security deposit from an affiliate for a gas loan contract with that affiliate. This contract terminated on April 30, 2011 and was replaced by a similar contract with termination date of April 30, 2012. We are required to pay a market rate of interest on the security deposit. Security deposits were $40.0 million at December 31, 2011 and 2010, and are classified as Collateral Liabilities — Affiliates on the Consolidated Balance Sheets.

Effective as of August 15, 2007, we received payment of advances receivable of $80.0 million and entered into five-year promissory notes with Spectra Energy Partners and Spectra Energy Capital, LLC, (Spectra Capital), a wholly owned subsidiary of Spectra Energy, to loan them up to $50.0 million each. The notes mature on August 15, 2012, however, any borrowings under the agreement are payable on demand. Increases and decreases in note balances generally result from the movement of funds to provide for our operations and capital expenditures. The promissory notes bear interest based on a one month London InterBank Offering Rate (LIBOR), and the interest rate at December 31, 2011 was 0.271%. As of December 31, 2011 and 2010, Spectra Energy Partners and Spectra Capital each had $30.5 million and $34.0 million of borrowings outstanding under the notes, respectively.

We received capital contributions from our partners of $27.0 million in 2011, $33.1 million in 2010 and $53.8 million in 2009. We made distributions to our partners of $99.0 million in 2011, $95.5 million in 2010 and $71.5 million in 2009.

In accordance with our formation agreements, we transferred certain balances to Spectra Energy and Spectra Energy Partners. These balances were primarily comprised of advances from Spectra Energy totaling $1.1 million in 2009. These liabilities are classified in the Consolidated Statements of Partners’ Capital as Deemed Contributions from Parent. These transactions were classified as noncash for purposes of the Consolidated Statements of Cash Flows.

3. Property, Plant and Equipment


	Estimated Useful Life		December 31,
	Estimated Useful Life		2011			2010
	(years)		(in millions)
Salt cavern storage facilities		15-50	$	598.8		$	550.7
Land		—		12.4			12.4
Construction in process		—		4.5			23.3
Other		5-40		2.4			2.5

Total property, plant and equipment				618.1			588.9
Total accumulated depreciation				(114.1	)		(103.5	)

Total net property, plant and equipment			$	504.0		$	485.4

F-22

The composite weighted-average depreciation rates were 2.1% for 2011, 3.0% for 2010 and 2.9% for 2009.

During 2011, we completed an analysis for our non-regulated storage assets to determine the appropriate remaining useful lives. This study resulted in a change of our estimates of useful lives for calculating depreciation from 40 years to 50 years for salt cavern storage facilities. This change was effective January 1, 2011 and made on a prospective basis. As a result of this change, depreciation expense decreased for the full year of 2011 by $4.8 million as compared to 2010.

4. Credit Risk and Financial Instruments

Credit Risk. Our principal customers for high deliverability natural gas storage services are pipelines, local distribution companies, producers, end-users, power generators and energy marketers. We have concentrations of receivables from these industry sectors. These concentrations of customers may affect our overall credit risk in that risk factors can negatively affect the credit quality of a particular sector. Where exposed to credit risk, we analyze the customers’ financial condition prior to entering into an agreement, establish credit limits and monitor the appropriateness of those limits on an ongoing basis. We also obtain parental guarantees, cash deposits, letters of credit or other acceptable forms of security from customers, where appropriate, based on our financial analysis of the customer and the regulatory or contractual terms and conditions applicable to each contract.

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

5. Commitments and Contingencies

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

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

6. Subsequent Event

We have evaluated significant events and transactions that occurred from January 1, 2012 through February 28, 2012, the date the consolidated financial statements were issued.

A distribution to partners of $18.0 million was declared and paid on January 27, 2012.

F-23

Exhibit Index


Exhibit No.		Exhibit Description
2.1		Asset Purchase Agreement, dated December 13, 2007, between Spectra Energy Virginia Pipeline Company and East Tennessee Natural Gas, LLC (filed as Exhibit 10.2 to Spectra Energy Partners, LP’s Form 8-K dated December 14, 2007).

2.2		Securities Purchase Agreement, dated as of April 7, 2009, among Spectra Energy Partners OLP, LP, Atlas Pipeline Mid-Continent LLC, Atlas Pipeline Partners, L.P, solely as guarantor of Atlas Pipeline Mid-Continent LLC, and Spectra Energy Partners, L.P., solely as guarantor of Spectra Energy Partners OLP, LP (filed as Exhibit 10.1 to Spectra Energy Partners, LP’s Form 8-K dated April 8, 2009).

2.3		Contribution Agreement, dated November 30, 2010, by and among Spectra Energy Partners, LP, Spectra Energy Partners (DE) GP, LP and Spectra Energy Southeast Pipeline Corporation (filed as Exhibit No. 2.1 to Spectra Energy Partners, LP’s Form 8-K dated November 30, 2010).

2.4		Purchase and Sale Agreement dated as of May 11, 2011, by and among Equitrans, L.P. and, solely for the purpose of Sections 1.8, 1.9, 4.17 and 9.15, EQT Corporation, Spectra Energy Partners, LP and, solely for the purpose of Section 9.16, Spectra Energy Capital, LLC (Filed as Exhibit No. 2.1 to Spectra Energy Partners, LP’s Form 8-K dated May 11, 2011).

2.5		First Amendment to Purchase and Sale Agreement, dated as of June 30, 2011, by and among Equitrans, L.P. and, solely for the purpose of Sections 1.8, 1.9, 4.17 and 9.15, EQT Corporation, Spectra Energy Partners, LP and, solely for the purpose of Section 9.16, Spectra Energy Capital, LLC (Filed as Exhibit No. 2.1 to Spectra Energy Partners, LP’s Form 8-K dated July 1, 2011).

3.1		First Amended and Restated Agreement of Limited Partnership of Spectra Energy Partners, LP (filed as Exhibit 3.1 to Spectra Energy Partners, LP’s Form 8-K dated July 9, 2007).

3.2		Amendment No. 1 to First Amended and Restated Agreement of Limited Partnership of Spectra Energy Partners, LP, dated April 11, 2008 (filed as Exhibit 10.1 to Spectra Energy Partners, LP’s Form 10-Q on May 14, 2008).

3.3		Certificate of Limited Partnership of Spectra Energy Partners, LP (filed as Exhibit 3.1 to Spectra Energy Partner, LP’s Form S-1 on March 30, 2007, file no. 333-141687).

3.4		First Amended and Restated Agreement of Limited Partnership Agreement of Spectra Energy Partners (DE) GP, LP (filed as Exhibit 3.2 to Spectra Energy Partners, LP’s Form 8-K dated July 9, 2007).

3.5		Certificate of Limited Partnership of Spectra Energy Partners (DE) GP, LP (filed as Exhibit 3.3 to Spectra Energy Partner, LP’s Form S-1 on March 30, 2007, file no. 333-141687).

3.6		First Amended and Restated Limited Liability Agreement of Spectra Energy Partners GP, LLC (filed as Exhibit 3.3 to Spectra Energy Partners, LP’s Form 8-K dated July 9, 2007).

3.7		Certificate of Formation of Spectra Energy Partners GP, LLC (filed as Exhibit 3.5 to Spectra Energy Partner, LP’s Form S-1 on March 30, 2007, file no. 333-141687).

4.1		Indenture, dated as of June 9, 2011, between Spectra Energy Partners, LP, as Issuer and Wells Fargo Bank, National Association, as Trustee (Filed as Exhibit No. 4.1 to Spectra Energy Partners, LP’s Form 8-K dated June 9, 2011).

4.2		First Supplemental Indenture, dated as of June 9, 2011, between Spectra Energy Partners, LP, as Issuer and Wells Fargo Bank, National Association, as Trustee (Filed as Exhibit No. 4.2 to Spectra Energy Partners, LP’s Form 8-K dated June 9, 2011).

4.3		Form of 2.95% Senior Notes due 2016 (Included in Exhibit 4.2 to Spectra Energy Partners, LP’s Form 8-K dated June 9, 2011).


Exhibit No.		Exhibit Description

4.4		Form of 4.60% Senior Notes due 2021 (Included in Exhibit 4.2 to Spectra Energy Partners, LP’s Form 8-K dated June 9, 2011).

10.1		Contribution, Conveyance and Assumption Agreement, dated July 2, 2007, by and among Spectra Energy Partners, LP, Spectra Energy Partners OLP, LP, Spectra Energy Partners GP, LLC, Spectra Energy Partners OLP GP, LLC, Spectra Energy Partners (DE) GP, LP, Spectra Energy Transmission, LLC, Spectra Energy Southeast Pipeline Corporation, East Tennessee Natural Gas, LLC, Egan Hub Storage, LLC, Moss Bluff Hub, LLC and Market Hub Partners Holding, LLC (filed as Exhibit 10.1 to Spectra Energy Partners, LP’s Form 8-K dated July 9, 2007).

10.2		Omnibus Agreement, dated July 2, 2007, by and among Spectra Energy Partners, LP, Spectra Energy Partners (DE) GP, LP, Spectra Energy Partners GP, LLC and Spectra Energy Corp (filed as Exhibit 10.2 to Spectra Energy Partners, LP’s Form 8-K dated July 9, 2007).

+10.3		Long Term Incentive Plan of Spectra Energy Partners, LP (filed as Exhibit 10.3 to Spectra Energy Partners, LP’s Form 8-K dated July 9, 2007).

+10.4		Form of Phantom Unit Award Agreement under the Spectra Energy Partners, LP Long-Term Incentive Plan (filed as Exhibit 4.3 to Spectra Energy Partners, LP’s Form S-8 on July 2, 2007).

10.5		General Partnership Agreement of Market Hub Partners Holding (filed as Exhibit 10.4 to Spectra Energy Partners, LP’s Form 8-K dated July 9, 2007).

10.6		Contribution Agreement, dated December 13, 2007, by and among Spectra Energy Transmission, LLC, Spectra Energy Partners (DE) GP, LP and Spectra Energy Partners, LP (filed as Exhibit 10.8 to Spectra Energy Partners, LP’s 10-K/A on May 14, 2009).

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 (filed as Exhibit 10.4 to Spectra Energy Partners, LP’s Form S-1/A on June 13, 2007, file no. 333-141687).

10.8		Second Amended and Restated Limited Liability Company Agreement of Gulfstream Natural Gas System, L.L.C. (filed as Exhibit 10.6 to Spectra Energy Partners, LP’s Form S-1/A on June 4, 2007, file no. 333-141687).

10.9		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 (filed as Exhibit 10.11 to Spectra Energy Partners, LP’s Form 10-K/A on May 14, 2009).

10.10		Amendment No. 1, dated as of April 4, 2008, to the Omnibus Agreement entered into and effective as of July 2, 2007 (filed as Exhibit 10.12 to Spectra Energy Partners, LP’s Form 10-K on February 28, 2011).

10.11		Amendment No. 1, dated as of June 1, 2010, to the Omnibus Agreement entered into and effective as of July 2, 2007 (filed as Exhibit No. 10.1 to Spectra Energy Partners, LP’s Form 8-K dated June 4, 2010).

10.12		Amendment to Limited Liability Company Agreement of Gulfstream Natural Gas System, L.L.C., dated as of March 22, 2010 (filed as Exhibit No. 10.14 to Spectra Energy Partners, LP’s Form 10-K on February 28, 2011).

10.13		Credit Agreement, dated as of October 18, 2011, among Spectra Energy Partners, LP, the Initial Lenders and Issuing Banks named therein, and Citibank, N.A., as Administrative Agent (filed as Exhibit No. 10.1 to Form 8-K of Spectra Energy Partners, LP on October 20, 2011).

10.14		Second Amendment to Limited Liability Company Agreement of Gulfstream Natural Gas System, L.L.C., dated as of September 9, 2011 (filed as Exhibit No. 10.2 to Spectra Energy Partners, LP’s Form 10-Q on November 8, 2011).


Exhibit No.		Exhibit Description

*12.1		Computation of Ratio of Earnings to Fixed Charges.

*21.1		Subsidiaries of the Registrant.

*23.1		Consent of Deloitte & Touche LLP

*23.2		Consent of Deloitte & Touche LLP

*23.3		Consent of Deloitte & Touche LLP

*24.1		Power of Attorney.

*31.1		Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

*31.2		Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

*32.1		Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

*32.2		Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

*101.INS		XBRL Instance Document.

*101.SCH		XBRL Taxonomy Extension Schema.

*101.CAL		XBRL Taxonomy Extension Calculation Linkbase.

*101.DEF		XBRL Taxonomy Extension Definition Linkbase.

*101.LAB		XBRL Taxonomy Extension Label Linkbase.

*101.PRE		XBRL Taxonomy Extension Presentation Linkbase.

*	Filed herewith.

+	Denotes management contract or compensatory plan or arrangement.