10-K 1 d457040d10k.htm FORM 10-K Form 10-K
Table of Contents
Index to Financial Statements

 

 

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, 2012

or

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

SECURITIES EXCHANGE ACT OF 1934

For the transition period from              to             

Commission file number 001-33556

 

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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, 2012: $1,074,000,000.

At January 31, 2013, there were 103,633,733 Common Units and 2,114,975 General Partner Units outstanding.

 

 

 


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Index to Financial Statements

SPECTRA ENERGY PARTNERS, LP

FORM 10-K FOR THE YEAR ENDED

DECEMBER 31, 2012

TABLE OF CONTENTS

 

Item

        Page  
   PART I.   
1.   

Business

     4   
  

General

     4   
  

Initial Public Offering

     4   
  

Acquisitions

     4   
  

Business Strategies

     5   
  

Industry Overview

     6   
  

Gas Transportation and Storage

     6   
  

East Tennessee

     6   
  

Saltville

     7   
  

Ozark

     7   
  

Big Sandy

     8   
  

Gulfstream

     11   
  

Market Hub

     12   
  

Maritimes & Northeast Pipeline

     14   
  

Revenue Contract Summary

     15   
  

Supplies and Raw Materials

     15   
  

Regulations

     16   
  

Environmental Matters

     16   
  

Employees

     17   
  

Glossary

     17   
  

Additional Information

     18   
1A.   

Risk Factors

     19   
1B.   

Unresolved Staff Comments

     37   
2.   

Properties

     37   
3.   

Legal Proceedings

     37   
4.   

Mine Safety Disclosures

     37   
   PART II.   
5.   

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

     38   
6.   

Selected Financial Data

     40   
7.   

Management’s Discussion and Analysis of Financial Condition and Results of Operations

     41   
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

     89   
9A.   

Controls and Procedures

     89   
9B.   

Other Information

     90   
   PART III.   
10.   

Directors, Executive Officers and Corporate Governance

     91   
11.   

Executive Compensation

     96   
12.   

Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters

     113   
13.   

Certain Relationships and Related Transactions, and Director Independence

     114   
14.   

Principal Accounting Fees and Services

     119   
   PART IV.   
15.   

Exhibits, Financial Statement Schedules

     120   
Signatures      121   
Exhibit Index   

 

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

This document includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements represent management’s intentions, plans, expectations, assumptions and beliefs about future events. 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 are subject to risks, uncertainties and other factors, many of which are outside our control and could cause actual results to differ materially from the results expressed or implied by those forward-looking statements. Factors used to develop these forward-looking statements and 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 U.S. pipeline, storage, gathering and other related 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.

 

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PART I

Item 1. Business.

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

General

Spectra Energy Partners, through its subsidiaries and equity affiliates, is engaged in the transportation and gathering of natural gas through interstate pipeline systems with over 3,500 miles of pipelines and the storage of natural gas in underground facilities with aggregate working gas storage capacity of approximately 57 billion cubic feet (Bcf) in the United States. 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 own and operate natural gas transportation and storage assets in Texas, Oklahoma, Arkansas, Tennessee, Virginia, Florida, Alabama, Louisiana, Georgia, Kentucky, Mississippi, Missouri, North Carolina, Maine, Massachusetts, New Hampshire and the Gulf of Mexico. Our assets are strategically located in geographic regions of the United States where demand — primarily for natural gas for electricity generation — is expected to increase steadily. We have 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. 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, 2012, Spectra Energy and its subsidiaries collectively owned 61% of us and the remaining 39% 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.

 

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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.

In 2011, we completed the acquisition of Big Sandy Pipeline, L.L.C (Big Sandy) from EQT Corporation (EQT) for approximately $390.0 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).

On October 31, 2012, we acquired a 38.76% ownership interest in Maritimes & Northeast L.L.C (M&N US) from Spectra Energy for approximately $318.7 million in cash and approximately $56.2 million in newly issued common and general partner units. As of December 31, 2012, M&N US has debt outstanding of $429.0 million, 38.76% of which is $166.3 million. M&N US owns a FERC-regulated, 338-mile mainline interstate natural gas transportation system in the United States which extends from the Canadian border near Baileyville, Maine to northeastern Massachusetts and has market delivery capability of approximately 0.8 Bcf per day of natural gas. M&N US’ cash flows are backed by an average contract life of approximately 20 years and over 90% fee-based revenues which further enhances our profile of steady, fee-based cash flows. M&N US’ pipeline location and key interconnects with Spectra Energy’s transmission system link regional natural gas supplies to the northeast U.S. and Atlantic Canadian markets.

For financial information on our acquisitions, see Item 8. Financial Statements and Supplementary Data, Note 2 of Notes to Consolidated Financial Statements.

Business Strategies

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

 

   

Actively engaging in the marketplace for strategic acquisitions of assets that enhance our portfolio, including drop downs from our General Partner. 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 lines of businesses that fit our fee-based business profile. These could be either third party acquisitions or assets that are dropped down from the owner of 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.

Our current business strategy emphasizes developing and expanding our existing business while remaining focused on the safe, reliable, effective and efficient operation of our current assets. We are well positioned to pursue opportunities for accretive acquisitions. We intend to execute our growth strategy by maintaining a capital structure that balances our outstanding debt and equity in a manner that supports our investment grade credit ratings.

 

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Industry Overview

The midstream natural gas industry is the link between the exploration and production of natural gas and the delivery to end-use markets. Operators within this industry create value at various stages along the natural gas value chain by gathering raw natural gas from producers at the wellhead and then routing the separated dry gas for delivery to end-use markets or to the next intermediate stage of the value chain. The services provided by us and our equity affiliates are generally classified into the categories described below.

 

   

Natural Gas Transportation. Natural gas transportation consists of moving pipeline-quality natural gas from gathering systems, processing or treating plants and other pipelines and delivering it to wholesalers, end users, local distribution companies and other pipelines.

 

   

Natural Gas Storage. Natural gas can be injected into underground storage facilities which provide balancing services to customers in supply areas and also provide timely supply to market centers that do not have a ready supply of locally produced natural gas.

 

   

Gathering. At the initial stages of the midstream value chain, a network of typically smaller diameter pipelines known as gathering systems directly connect to wellheads in the production area. These gathering systems transport raw, or untreated, natural gas to a central location for treating and processing.

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

 

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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 32 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).

In January 2013, East Tennessee executed agreements with Eastman Chemical Company (Eastman) to provide an additional 86 MMcf/d of gas service for 25 years to Eastman’s Kingsport, Tennessee, facility. The combined capital cost is approximately $120 million and includes modifying existing East Tennessee facilities and building a new 6.4-mile pipeline extension. The first project will provide service of 25 MMcf/d and is expected to begin in November 2013. The Kingsport Expansion Project, which will provide 61 MMcf/d of additional capacity, is anticipated to be in service during the first quarter of 2015. Coupled with Eastman’s current contracts, East Tennessee will provide 121 MMcf/d of firm capacity to the Kingsport facility when the projects are completed. The projects are subject to approvals by the boards of directors of Spectra Energy, Spectra Energy Partners and Eastman, as well as regulatory approvals.

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

 

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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 52 receipt points and 30 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 eastern 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 83% of the pipeline’s capacity. The system has capacity of approximately 0.2 Bcf/d of natural gas.

 

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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 2012 was EQT, a natural gas production and midstream company, which accounted for 19% of its revenues.

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 and storage revenues typically remain relatively constant over the term of the contracts. Fee-based gathering service contracts 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 electric powered compressors and all power costs are paid by the shippers.

As of December 31, 2012, East Tennessee and Saltville firm transportation and storage contracts had a weighted average remaining life of approximately nine and six years, respectively. Big Sandy’s contracts had a weighted average remaining life of approximately 13 years. Ozark, excluding gathering contracts, had a weighted average remaining life of approximately three years. In 2012, 98% of East Tennessee and Saltville, 97% of Big Sandy, and 84% 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. Fee-based gathering service contracts represent 2% of Gas Transportation and Storage operating revenues in 2012.

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

Saltville continues to operate under rates approved by the FERC in a 2008 settlement. Pursuant to the settlement, Saltville is required to file a rate case by October 1, 2013.

Ozark continues to operate under rates approved by the FERC in 2000. In 2011, Ozark reached a settlement agreement with customers in a FERC rate proceeding that included a rate moratorium until October 1, 2012 and a requirement to file a rate case by October 1, 2015.

Big Sandy operates under rates approved by the FERC in 2006.

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 (shale and tight-sands) 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.

 

 

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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 and the Fayetteville Express Pipeline LLC.

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.

 

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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 eight receipt points and 24 delivery points and has market delivery capability of 1.3 Bcf/d of natural gas. 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 2012, Florida Power & Light Company and Florida Power Corporation d/b/a Progress Energy Florida, Inc. accounted for approximately 53% and 29%, respectively, of Gulfstream’s revenues. On July 2, 2012 Progress Energy Florida, Inc. completed a merger with Duke Energy.

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.

 

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As of December 31, 2012, Gulfstream’s firm transportation and storage contracts had a weighted average remaining life of 17 years. In 2012, 98% 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 eight 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 Kinder Morgan, Inc. 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

 

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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 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.

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.

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 2012, 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, 2012, 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 2012 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.

 

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Maritimes & Northeast Pipeline

General

 

LOGO

We own a 38.76% interest in the 338-mile mainline M&N US interstate natural gas transportation system, which extends from the border of Canada near Baileyville, Maine, to northeastern Massachusetts. Spectra Energy and affiliates of Emera, Inc. and Exxon Mobil Corporation own the remaining 38.77%, 12.92% and 9.55% interests, respectively. M&N US is connected to the Canadian portion of the Maritimes & Northeast Pipeline system which is owned by Spectra Energy and affiliates of Exxon Mobil Corporation and Emera, Inc. M&N US’ facilities include seven compressor stations and a market delivery capability of approximately 0.8 Bcf/d of natural gas. The pipeline’s location and key interconnects with Spectra Energy’s transmission system link regional natural gas supplies to the northeast U.S. and Atlantic Canadian markets.

Customer, Contracts and Supply

In 2012, Repsol Energy North America Corporation accounted for approximately 87% of M&N US’ revenues.

M&N US 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 M&N US’ current shippers have negotiated rates.

As of December 31, 2012, M&N US’ firm transportation contracts had a weighted average remaining life of 20 years. In 2012, 99% of M&N US’ revenues were derived from capacity reservation charges under firm contracts, with the remainder derived from variable usage fees under firm and interruptible transportation contracts.

 

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M&N US receives gas supply from reserves located offshore Nova Scotia and onshore New Brunswick through the Canadian portion of the Maritimes & Northeast Pipeline system and regasified liquefied natural gas from the Canaport LNG import facility in Saint John, New Brunswick via the Brunswick Pipeline owned by Emera, Inc.

Competition

M&N US’ most direct competitor is Portland Natural Gas Transmission System, owned by TransCanada Pipelines and Gaz Metro. Within the New England area, M&N US competes with other pipelines that transport and supply natural gas to the end-user. M&N US’ competitors attempt to either attract new supply or attach new load to their pipelines, including those that are currently connected to markets served by M&N US.

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.

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 2% 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, 2012:

 

     Revenue Composition %     Weighted Average
Remaining Firm
Contract Life (in
years)(a)
 
     Firm Contracts     Interruptible
Contracts
    Volume-
based
Fees
   

Asset

   Capacity
Reservation Fees
    Variable
Fees
       

East Tennessee

     99     1             9   

Ozark

          

Transmission

     84        14        2               3   

Gathering

                          100        n/a   

Big Sandy

     97        3                      13   

Saltville

     93        6        1               6   

Gulfstream

     98        2                      17   

Market Hub

     89        1        10               2   

M&N US.

     99               1               20   

 

(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, 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.

 

 

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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.

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) amended parts of the Clean

 

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Water Act and other statutes as they pertain to the prevention of and response to oil spills. The 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 12 of Notes to Consolidated Financial Statements.

Except to the extent discussed in Note 12, 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 128 people who spend a majority of their time operating the East Tennessee, Ozark, Big Sandy and Saltville facilities, and five people who are primarily dedicated to us. Market Hub and M&N US are operated by Spectra Energy pursuant to an operating and maintenance agreement and the employees who operate the Market Hub and M&N US 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

 

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(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.

 

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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 $32 million per quarter, or $128 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:

 

   

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

 

   

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

 

   

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

 

   

changes in environmental, safety and other laws and regulations;

 

   

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

 

   

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:

 

   

the level of capital expenditures to complete construction projects;

 

   

the cost and form of payment of acquisitions;

 

   

debt service requirements and other liabilities;

 

   

fluctuations in working capital needs;

 

   

the ability to borrow funds and access capital markets;

 

   

restrictions on distributions contained in debt agreements; and

 

   

the amount of cash reserves established by our general partner.

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, Market Hub and M&N US, 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, Market Hub and M&N US. 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.

 

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Market Hub, Gulfstream and M&N US generated approximately 54.9% of the cash available for distribution in 2012. Spectra Energy operates Market Hub and M&N US 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, Market Hub and M&N US 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. Gulfstream, Market Hub nor M&N US is prohibited from incurring indebtedness by the terms of their respective limited liability company agreement and general partnership agreements. If Gulfstream, Market Hub or M&N US 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 2012, 80% of Gas Transportation and Storage’s, Gulfstream’s and M&N US’ 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, M&N US’ 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, M&N US 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

 

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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, Market Hub or M&N US 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.

 

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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 2012 is attributable to firm capacity reservation fees that are set to expire on or prior to December 31, 2015. For Gas Transportation and Storage, Market Hub and M&N US, those portions were 30%, 75% and 8%, 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:

 

   

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

 

   

the growth in demand for natural gas in our markets;

 

   

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

 

   

whether our business strategy continues to be successful; and

 

   

the effects of state regulation on customer contracting practices.

Any failure to extend or replace a significant portion of our existing contracts may have 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 non-conventional 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, 2012, the three largest customers for Gas Transportation and Storage were EQT Corporation, Tennessee Valley Authority, and Atmos Energy Corporation; for Gulfstream were Florida Power & Light Company, Florida Power Corporation d/b/a Progress Energy Florida, Inc. and TECO Energy and its affiliates; for Market Hub were AGL Resources Inc., Northern Indiana Public Service and J.P. Morgan Ventures Energy Corporation; and for M&N US were Repsol Energy North America Corporation, Emera Energy Inc. and Shell Energy North America, L.P. In 2012, these customers accounted for approximately 37%, 88%, 25% and 96% of the operating revenues for Gas Transportation and Storage, Gulfstream, Market Hub and M&N US, 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

 

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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:

 

   

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

 

   

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

 

   

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

 

   

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

 

   

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

 

   

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

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:

 

   

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;

 

   

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;

 

   

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

 

   

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

 

   

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

 

   

customer losses at the acquired business.

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

 

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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 expired in 2012 and had 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.

The United States is a party to the Durban agreement. In the interim period before 2020, the Kyoto Protocol will continue in effect, although it is expected that not all of the current parties will choose to commit for this extended period.

In the United States, climate change action is evolving at state, regional and federal levels. Pursuant to federal law, we are currently subject to an obligation to report our GHG emissions, but are not currently subject to limits on emissions of GHGs. In addition, a number of U.S. states have joined regional GHG 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.

In May 2010, the EPA issued the Prevention of Significant Deterioration (PSD) and Title V Greenhouse Gas Tailoring Rule (Tailoring Rule). This regulation establishes that the construction of new or modification of existing major sources of GHG emissions would become subject to the PSD air permitting program (and later, the Title V permitting program) beginning in January 2011, although the regulation also significantly increases

 

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the emissions thresholds that would subject facilities to these regulations. In June 2012, these regulations, along with other GHG regulations and determinations issued by the EPA, were upheld by the D.C. Circuit of Appeals. In July 2012, the EPA determined in Step 3 of the Tailoring Rule process that it would maintain the current GHG emissions thresholds for PSD and Title V applicability. This rule has also been appealed. We anticipate that in the future, new capital projects or modification of existing projects could be subject to a permit requirement related to GHG emissions that may result in delays in completing such projects.

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:

 

   

perform ongoing assessments of pipeline integrity;

 

   

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

 

   

improve data collection, integration and analysis;

 

   

repair and remediate the pipeline as necessary; and

 

   

implement preventive and mitigating actions.

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

We 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:

 

   

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),

 

   

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).

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 has begun 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.

Transmission, storage and gathering activities involve numerous risks that may result in accidents or otherwise affect our operations.

There are a variety of hazards and operating risks inherent in natural gas transmission, storage, and gathering activities, such as leaks, explosions, mechanical problems, and natural disasters that could cause substantial financial losses. In addition, these risks could result in significant injury, loss of life, significant damage to property, environmental pollution and impairment of operations, any of which could result in substantial losses. For pipeline and storage assets located near populated areas, including residential areas, commercial business centers, marine environment (including the Gulf of Mexico), industrial sites and other public gathering areas, the level of damage resulting from these risks could be greater. Furthermore, our operations include 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. Additional risks are present related to our 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.

We do not maintain insurance coverage against all of these risks and losses, and any insurance coverage we might maintain may not fully cover the damages caused by those risks and losses. 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. Moreover, we do not maintain offshore business interruption insurance. Therefore, should any of these risks materialize, it could have an adverse effect on our business, earnings, 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:

 

   

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

 

   

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

 

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incur additional indebtedness or guarantee other indebtedness;

 

   

grant liens or make certain negative pledges;

 

   

make certain loans or investments;

 

   

engage in transactions with affiliates;

 

   

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

 

   

make a disposition of assets; or

 

   

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

The credit facility contains covenants requiring us to maintain certain financial ratios and tests. The ability to comply with the covenants and restrictions contained in the credit facility may be affected by events beyond our control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. If we violate any of the restrictions, covenants, ratios or tests in our credit facility, the lenders will be able to accelerate the maturity of all borrowings under the credit facility and demand repayment of amounts outstanding, the lenders’ commitment to make further loans to us may terminate, and the operating partnership 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.

 

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

Risks Inherent in an Investment in Us

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

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

 

   

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

 

   

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

 

   

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

 

   

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

 

   

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

 

   

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

 

   

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

 

   

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

 

   

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

 

   

in some instances, our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make 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;

 

   

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

 

   

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

 

   

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

 

   

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

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

Neither our partnership agreement nor the omnibus agreement among us, Spectra Energy and others prohibits affiliates of our general partner, including Spectra Energy, DCP Midstream, LLC and DCP Midstream Partners, LP, from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, Spectra Energy and its affiliates may acquire, construct or dispose of additional transportation, 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 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, these 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

 

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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;

 

   

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

 

   

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

 

   

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

 

   

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

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

 

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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. As of January 31, 2013, our general partner and its affiliates own 61% 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.

 

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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% and 38.76% limited liability company interest in Gulfstream and M&N US, respectively and a 50% general partner interest in Market Hub. If a sufficient amount of our assets, such as our ownership interests in Gulfstream, Market Hub and M&N US 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 and our 38.76% interest in M&N US 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 common 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:

 

   

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

 

   

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

 

   

the ratio of taxable income to distributions may increase;

 

   

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

 

   

the market price of the common units may decline.

 

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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, 2013, Spectra Energy and its affiliates hold an aggregate of 62,721,269 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, 2013, our general partner and its affiliates own approximately 61% 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:

 

   

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.

 

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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

 

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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.

 

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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 unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, the unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.

Because a unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of the loaned units, the unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing and lending their units.

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. 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.

 

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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 5 and 12 of Notes to Consolidated Financial Statements.

Item 4. Mine Safety Disclosures.

Not applicable.

 

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PART II

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

Our common units are listed on the NYSE under the symbol “SEP.” The following table sets forth the high and low intra-day 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  
     Per Common Unit      High      Low  

2012

        

First Quarter

   $ 0.475       $ 33.27       $ 31.00   

Second Quarter

     0.48         32.84         29.36   

Third Quarter

     0.485         32.86         30.07   

Fourth Quarter

     0.49         32.20         27.15   

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   

As of January 31, 2013, there were 33 holders of record of our common units. A cash distribution to unitholders of $0.495 per limited partner unit was declared on January 28, 2013 and was paid on February 14, 2013, which is a $0.005 per limited partner unit increase over the cash distribution of $0.49 per limited partner unit paid on November 14, 2012.

 

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Unit Performance Graph

The following graph reflects the comparative changes in the value from January 1, 2008 through December 31, 2012 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

 

     January 1,
2008
     December 31,  
      2008      2009      2010      2011      2012  

Spectra Energy Partners

   $ 100.00       $ 87.55       $ 139.84       $ 163.65       $ 168.71       $ 175.20   

S&P 500

     100.00         63.00         79.68         91.68         93.61         108.59   

Alerian MLP Index

     100.00         63.08         111.29         151.19         172.17         180.43   

Distributions of Available Cash

General. Our partnership agreement requires that, within 45 days after the end of each quarter, 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 28, 2013 is $0.495 per limited partner unit, or $1.98 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 2,114,975 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 $3.1 million in 2012, $4.5 million in 2011 and $5.9 million in 2010 to maintain its 2% interest as a result of the November 2012 unit issuance and additional limited partner units issued following the Big Sandy acquisition and additional interest in Gulfstream, respectively.

 

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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.

 

     2012      2011      2010      2009      2008  
     (in millions, except per-unit amounts)  
     (Unaudited)  

Statements of Operations

              

Operating revenues

   $ 236.8       $ 205.0       $ 197.7       $ 178.9       $ 124.9   

Operating income

     118.2         88.2         87.7         82.8         51.9   

Equity in earnings of unconsolidated affiliates(a)

     107.6         107.3         75.1         70.7         61.4   

Net income

     193.5         172.0         147.9         135.9         101.3   

Net Income per Limited Partner Unit

              

Net income per limited partner unit — basic and diluted

   $ 1.69       $ 1.63       $ 1.70       $ 1.71       $ 1.40   

Distributions paid per limited partner unit during the periods presented

     1.93         1.845         1.70         1.51         1.34   

 

     December 31,  
     2012      2011      2010      2009      2008  
     (in millions)  
     (Unaudited)  

Balance Sheet

              

Total assets(a)

   $ 2,805.7       $ 2,456.9       $ 2,222.5       $ 1,812.5       $ 1,601.5   

Long-term debt

     699.6         499.4         655.8         390.0         390.0   

 

(a) During the fourth quarter of 2010, we purchased an additional 24.5% interest in Gulfstream and during the fourth quarter of 2012 we purchased a 38.76% interest in M&N US. Both transactions are accounted for as an equity method investment and the equity earnings are recorded prospectively from the date of acquisition.

 

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

INTRODUCTION

Management’s Discussion and Analysis should be read in conjunction with Item 8. Financial Statements and Supplementary Data. Listed below is a general outline of our discussion and analysis:

• EXECUTIVE OVERVIEW

- Includes a summary of our business performance, our highlights, an outlook for next year; our business strategy, and significant economic factors for our business;

• RESULTS OF OPERATIONS

- Includes a year-over-year analysis of our results of operations for our business, a discussion about matters affecting future results, and also includes our cash available for distribution calculation;

• CRITICAL ACCOUNTING POLICIES AND ESTIMATES

- Includes a discussion of critical accounting policies and estimates that require the use of significant estimates and judgments;

• LIQUIDITY AND CAPITAL RESOURCES

- Includes a discussion of known trends and uncertainties, available liquidity, an analysis of our cash flow activities, off balance sheet arrangements, contractual obligations, and quantitative and qualitative disclosures about market risk;

• OTHER ISSUES

- Additional discussion about factors that could impact our business.

EXECUTIVE OVERVIEW

We reported net income of $193.5 million in 2012 compared with $172.0 million in 2011. Cash available for distribution was $229.3 million in 2012 compared with $212.4 million in 2011. Our increase in net income and cash available for distribution was mainly the result of the addition of the Big Sandy pipeline and East Tennessee’s Northeastern Tennessee (NET) assets to our portfolio in July and September 2011, respectively.

In October 2012, we continued to execute on our growth strategy by expanding our geographic reach to the northeast U.S. markets with the acquisition of a 38.76% ownership interest in Maritimes & Northeast Pipeline, L.L.C (M&N US) from Spectra Energy for approximately $318.7 million in cash and approximately $56.2 million in newly issued common and general partner units.

We increased the quarterly cash distributions each quarter in 2012 from $0.475 per limited partner unit for the fourth quarter of 2011, paid in February 2012, to $0.495 per limited partner unit for the fourth quarter of 2012, paid on February 14, 2013.

In January 2013, East Tennessee executed agreements with Eastman Chemical Company (Eastman) to provide an additional 86 million cubic feet per day (Mmcf/d) of gas service for 25 years to Eastman’s Kingsport, Tennessee, facility. The combined capital cost is approximately $120 million and includes modifying existing East Tennessee facilities and building a new 6.4-mile pipeline extension. The first project will provide service of 25 Mmcf/d and is expected to begin in November 2013. The Kingsport Expansion Project, which will provide 61 Mmcf/d of additional capacity, is anticipated to be in service during the first quarter of 2015. Coupled with Eastman’s current contracts, East Tennessee will provide 121 Mmcf/d of firm capacity to the Kingsport facility

 

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when the projects are completed. The projects are subject to approvals by the boards of directors of Spectra Energy, Spectra Energy Partners and Eastman, as well as regulatory approvals.

We will rely upon cash flows from operations, including cash distributions received from Gulfstream, Market Hub and M&N US, and various financing transactions, which may include issuances of short-term and long-term debt, to fund our liquidity and capital requirements for 2013. 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:

 

   

Actively engaging in the marketplace for strategic acquisitions of assets that enhance our portfolio, including drop downs from our General Partner. 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 lines of businesses that fit our fee-based business profile. These could be either third party acquisitions, or assets that are dropped down from the owner of 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 non-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, industrials,

 

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marketers, producers and power generators, increase or decrease their demand for our services as a result of these changes.

The market areas our assets currently serve are projected to continue to exhibit strong demand for natural gas with an average annual growth of 2.2%, as compared to the growth rate of 1.4% in the U.S. lower 48 states. This demand growth is primarily driven by expected 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 non-conventional 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

 

     2012      2011      Increase
(Decrease)
    2010     Increase
(Decrease)
 
     (in millions, except where noted)  

Operating revenues

   $ 236.8       $ 205.0       $ 31.8      $ 197.7      $ 7.3   

Operating, maintenance and other expenses

     81.3         83.6         (2.3     80.6        3.0   

Depreciation and amortization

     37.3         33.2         4.1        29.4        3.8   
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

 

Operating income

     118.2         88.2         30.0        87.7        0.5   

Equity in earnings of unconsolidated affiliates

     107.6         107.3         0.3        75.1        32.2   

Other income and expenses, net

     0.3         2.1         (1.8     0.8        1.3   

Interest income

     0.1         0.5         (0.4     0.1        0.4   

Interest expense

     31.3         25.0         6.3        16.2        8.8   
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

 

Earnings before income taxes

     194.9         173.1         21.8        147.5        25.6   

Income tax expense (benefit)

     1.4         1.1         0.3        (0.4     1.5   
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

 

Net income

   $ 193.5       $ 172.0       $ 21.5      $ 147.9      $ 24.1   
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

 

Net cash provided by operating activities

   $ 240.8       $ 220.1       $ 20.7      $ 184.8      $ 35.3   

Adjusted EBITDA(a)

     155.5         121.4         34.1        117.1        4.3   

Cash Available for Distribution(a)

     229.3         212.4         16.9        176.4        36.0   

 

(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).

 

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2012 Compared to 2011

Operating Revenues. Operating revenues increased $20.3 million due to the acquisition of Big Sandy in July 2011 and $15.3 million due to the NET project placed in commercial service in September 2011. These increases were partially offset by lower revenues at Ozark in 2012. Low natural gas prices and the decision by some producers to delay production in the Fayetteville Shale for the near-term, have negatively affected Ozark revenues.

Operating, Maintenance and Other. The increased costs related to the acquisition of Big Sandy and 2012 transaction costs related to the M&N US dropdown were more than offset by 2011 transaction costs associated with the acquisition of Big Sandy, expenses related to securing SEP’s initial credit rating, and 2011 non-recurring unfavorable inventory and ad valorem tax adjustments.

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

Equity in Earnings of Unconsolidated Affiliates. Equity in earnings of unconsolidated affiliates of $107.6 million for the year ended December 31, 2012 were in line with $107.3 million for the year ended December 31, 2011. The following schedule summarizes the components of equity in earnings of unconsolidated affiliates and our ownership interest for the years ended 2012, 2011, and 2010.

 

     2012     2011     Increase
(Decrease)
    2010     Increase
(Decrease)
 
     (in millions, except where noted)  

Gulfstream

          

Net Income

   $ 129.3      $ 132.0      $ (2.7   $ 131.6      $ 0.4   

Ownership Interest(a)

     49     49            49       

Equity in Earnings of Unconsolidated Affiliates(a)

   $ 63.3      $ 64.7      $ (1.4   $ 35.5      $ 29.2   

Market Hub

          

Net Income

   $ 80.7      $ 85.4      $ (4.7   $ 79.3      $ 6.1   

Ownership Interest

     50     50            50       

Equity in Earnings of Unconsolidated Affiliates

   $ 40.3      $ 42.6      $ (2.3   $ 39.6      $ 3.0   

Maritimes & Northeast Pipeline L.L.C(b)

          

Net Income

   $ 10.2        (b)    $ 10.2        (b)      (b) 

Ownership Interest

     38.76     (b)      38.76     (b)      (b) 

Equity in Earnings of Unconsolidated Affiliates

   $ 4.0        (b)    $ 4.0        (b)      (b) 
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total Equity in Earnings of Unconsolidated Affiliates

   $ 107.6      $ 107.3      $ 0.3      $ 75.1      $ 32.2   

 

(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 are recorded prospectively from the date of acquisition.
(b) M&N US was acquired on October 31, 2012 and is accounted for as an equity method investment. Equity earnings are recorded prospectively from the date of acquisition. Net income is from acquired date to December 31, 2012.

The increase in equity earnings of $4.0 million from the acquisition of 38.76% interest in M&N US was mostly offset by lower equity earnings from Market Hub due to expected lower rates on contract renewals and lower equity earnings at Gulfstream driven by higher operating, maintenance and other expenses due to favorable ad valorem tax adjustments in 2011 and higher pipeline integrity costs in 2012.

Other Income and Expenses, Net. The decrease is primarily due to a higher equity portion of allowance for funds used during construction (AFUDC) on the NET project in 2011.

 

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Interest Expense. The increase is due to the issuance of $500.0 million in senior unsecured notes in June 2011.

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 $3.0 million increase in equity earnings resulted from our 50% interest in Market Hub. Market Hub’s revenues increased as a result of the commercial in-service of the expansion projects, partially offset by lower contract rates. Market Hub’s 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.

Other Income and Expenses, Net. The increase in the equity portion of 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 senior unsecured notes in June 2011.

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

Matters Affecting Future Results

We plan to continue earnings growth through a consistent focus on executing our strategy of strategic acquisitions, including drop downs from our general partner 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 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,

 

   

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, Market Hub and M&N US, 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, Market Hub and M&N US and net preliminary project costs, less interest expense, cash paid for income tax expense, and maintenance capital expenditures, excluding the impact of reimbursable projects, and other non-cash items affecting net income. 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 for M&N US includes an adjustment for amortizing bond payments. These bond payments are paid out in second and fourth quarters of each year using operating cash

 

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flows. Spectra Energy Partners, Gulfstream and Market Hub do not make similar bond payments. 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.

Spectra Energy Partners

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

 

     2012     2011(a)     2010(a)  
     (in millions)  

Net income

   $ 193.5      $ 172.0      $ 147.9   

Add:

      

Interest expense

     31.3        25.0        16.2   

Income tax expense (benefit)

     1.4        1.1        (0.4

Depreciation and amortization

     37.3        33.2        29.4   

Less:

      

Equity in earnings of Gulfstream

     63.3        64.7        35.5   

Equity in earnings of Market Hub

     40.3        42.6        39.6   

Equity in earnings of M&N US.

     4.0                 

Interest income

     0.1        0.5        0.1   

Other income and expenses, net

     0.3        2.1        0.8   
  

 

 

   

 

 

   

 

 

 

Adjusted EBITDA

     155.5        121.4        117.1   

Add:

      

Cash Available for Distribution from Gulfstream

     78.8        81.0        44.1   

Cash Available for Distribution from Market Hub

     45.0        46.0        45.6   

Cash Available for Distribution from M&N US

     2.1                 

Preliminary project costs, net

            0.1          

Less:

      

Interest expense

     31.3        25.0        16.2   

Cash paid for income tax expense

                   0.7   

Maintenance capital expenditures

     21.3        13.1        14.8   

Other

     (0.5     (2.0     (1.3
  

 

 

   

 

 

   

 

 

 

Cash Available for Distribution

   $ 229.3      $ 212.4      $ 176.4   
  

 

 

   

 

 

   

 

 

 

 

(a) Cash Available for Distribution for 2011 and 2010 has been revised to reflect the refinement to our definition that was effective January 1, 2012 as disclosed in our 2011 Form 10-K.

 

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Spectra Energy Partners

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

 

     2012     2011(a)     2010(a)  
     (in millions)  

Net cash provided by operating activities

   $ 240.8      $ 220.1      $ 184.8   

Interest income

     (0.1     (0.5     (0.1

Interest expense

     31.3        25.0        16.2   

Income tax expense — current

                   0.6   

Distributions received from Gulfstream

     (63.3     (66.8     (33.4

Distributions received from Market Hub

     (44.3     (49.5     (47.7

Distributions received from M&N US

     (4.0              

Changes in working capital and other

     (4.9     (6.9     (3.3
  

 

 

   

 

 

   

 

 

 

Adjusted EBITDA

     155.5        121.4        117.1   

Add:

      

Cash Available for Distribution from Gulfstream

     78.8        81.0        44.1   

Cash Available for Distribution from Market Hub

     45.0        46.0        45.6   

Cash Available for Distribution from M&N US

     2.1                 

Preliminary project costs, net

            0.1          

Less:

      

Interest expense

     31.3        25.0        16.2   

Cash paid for income tax expense

                   0.7   

Maintenance capital expenditures

     21.3        13.1        14.8   

Other

     (0.5     (2.0     (1.3
  

 

 

   

 

 

   

 

 

 

Cash Available for Distribution

   $ 229.3      $ 212.4      $ 176.4   
  

 

 

   

 

 

   

 

 

 

 

(a) Cash Available for Distribution for years 2011 and 2010 has been revised to reflect the refinement to our definition that was effective January 1, 2012 as disclosed in our 2011 Form 10-K.

Gulfstream

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

 

     2012      2011(a)      2010(a)  
     (in millions)  

Net income

   $ 129.3       $ 132.0       $ 131.6   

Add:

        

Interest expense

     70.2         69.9         69.8   

Depreciation and amortization

     35.6         35.4         35.0   

Less:

        

Other income and expenses, net

                     0.9   
  

 

 

    

 

 

    

 

 

 

Adjusted EBITDA — 100%

     235.1         237.3         235.5   

Add:

        

Preliminary project costs, net

     0.6         1.1         0.6   

Less:

        

Interest expense

     70.2         69.9         69.8   

Maintenance capital expenditures

     4.6         2.8         1.3   

Other

             0.3         0.5   
  

 

 

    

 

 

    

 

 

 

Cash Available for Distribution — 100%

   $ 160.9       $ 165.4       $ 164.5   
  

 

 

    

 

 

    

 

 

 

Adjusted EBITDA — Spectra Energy Partners’ Share(b)

   $ 115.2       $ 116.2       $ 63.0   

Cash Available for Distribution — Spectra Energy Partners’ Share(b)

   $ 78.8       $ 81.0       $ 44.1   

 

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(a) Cash Available for Distribution for years 2011 and 2010 has been revised to reflect the refinement to our definition that was effective January 1, 2012 as disclosed in our 2011 Form 10-K.
(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.

Market Hub

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

 

     2012     2011     2010  
     (in millions)  

Net income

   $ 80.7      $ 85.4      $ 79.3   

Add:

      

Interest expense (benefit)

     (0.1     0.1        0.1   

Income tax expense

     0.3        0.2        0.2   

Depreciation and amortization

     11.4        10.8        14.5   

Less:

      

Interest income

     0.2        0.1        0.2   

Other income and expenses, net

                   0.6   
  

 

 

   

 

 

   

 

 

 

Adjusted EBITDA — 100%

     92.1        96.4        93.3   

Less:

      

Interest benefit

     (0.1     (0.1     (0.1

Cash paid for income tax expense

     0.2        0.2        0.3   

Maintenance capital expenditures

     2.1        4.4        2.0   
  

 

 

   

 

 

   

 

 

 

Cash Available for Distribution — 100%

   $ 89.9      $ 91.9      $ 91.1   
  

 

 

   

 

 

   

 

 

 

Adjusted EBITDA — 50%

   $ 46.1      $ 48.2      $ 46.7   

Cash Available for Distribution — 50%

   $ 45.0      $ 46.0      $ 45.6   

Maritimes & Northeast Pipeline US

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

 

     2012  

Net income

   $ 10.2   

Add:

  

Interest expense

     6.5   

Income tax expense

     0.4   

Depreciation and amortization

     4.3   

Less:

  

Other income and expenses, net

     0.1   
  

 

 

 

Adjusted EBITDA — 100%

     21.3   

Less:

  

Interest expense

     6.5   

Cash paid for amortizing bond payments

     10.2   

Cash paid for income tax expense

       

Maintenance capital expenditures

       

Other

     (0.8
  

 

 

 

Cash Available for Distribution — 100%

   $ 5.4   
  

 

 

 

Adjusted EBITDA — Spectra Energy Partners’ Share(a)

   $ 8.3   

Cash Available for Distribution — Spectra Energy Partners’ Share(a)

   $ 2.1   

 

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(a) During the fourth quarter of 2012, we acquired 38.76% interest of M&N US which is accounted for as an equity method investment. The equity earnings related to the acquired interest was recorded as of the date of the acquisition.

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 investees Gulfstream and M&N US, also utilize this accounting. As a result, we record assets and liabilities that result from the regulated ratemaking process that may not be recorded under GAAP for non-regulated entities. Regulatory assets generally represent incurred costs that have been deferred because such costs are probable of future recovery in customer rates. Regulatory liabilities generally represent obligations to make refunds to customers 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 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 $16.2 million as of December 31, 2012 and $17.3 million as of December 31, 2011. Total regulatory liabilities were $0.2 million as of December 31, 2012 and $0.5 million as of December 31, 2011.

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 2012, 2011 or 2010.

We perform the annual review for goodwill impairment at the reporting unit level, which we have determined to be our one reportable operating segment, Gas Transportation and Storage.

We had a goodwill balance of $461.7 million at December 31, 2012 and 2011. 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 rate used for our reporting unit reflects 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

 

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pipeline systems primarily as a result of forecasted growth in natural gas fired electric generation plants. We assumed a long-term growth rate of 3.0% for our 2012 quantitative 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 2012 quantitative goodwill impairment analysis, we assumed a weighted-average cost of capital that market participants would use in evaluating our business of 6.7%. 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, 2012 (our testing date) was substantially in excess of its carrying value. No triggering events or changes in circumstances occurred during the period April 1, 2012 through December 31, 2012 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, Market Hub and M&N US, and various financing transactions, which may include issuances of short-term and long-term debt, to fund our liquidity and capital requirements for 2013. As of December 31, 2012, we had negative net working capital of $330.8 million compared to negative $204.3 million as of December 31, 2011. The December 31, 2012 balance included commercial paper of $336.4 million and the note payable on demand to Market Hub of $17.0 million. The December 31, 2011 balance included the East Tennessee notes payable of $150.0 million, a note payable on demand to Market Hub of $30.5 million and commercial paper of $27.0 million.

We have access to a revolving credit facility, with available capacity of $363.6 million at December 31, 2012. This facility is used principally to back-stop our commercial paper program, which is used to manage working capital requirements and for temporary funding of our capital expenditures. We also have $140.7 million of investments in commercial paper, funded with our proceeds from the November 2012 equity issuance, which may only be used to fund capital expenditures and acquisitions. 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 December 2012, East Tennessee issued $200.0 million aggregate principal amount of 3.10% senior unsecured notes due in 2024, replacing the $150.0 million aggregate principal notes due in 2012. In August 2012, we executed a new five-year promissory note payable agreement with Market Hub to borrow up to $50.0 million, replacing our existing note payable.

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

 

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number of factors, including, but not limited to, contract renewal rates and cash distributions from our equity affiliates, Gulfstream, Market Hub and M&N US. 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 $126.9 million in 2012, $125.5 million in 2011 and $87.2 million in 2010. 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.

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. Therefore we will continue to monitor market requirements and our liquidity and make adjustments to these plans, as needed.

Cash Flow Analysis

The following table summarizes the changes in cash flows by operating, investing and financing for each of the periods presented:

 

     Years Ended December 31,  
     2012     2011     2010  
     (in millions)  

Net cash provided by (used in):

      

Operating activities

   $ 240.8      $ 220.1      $ 184.8   

Investing activities

     (501.0     (286.0     (507.8

Financing activities

     280.0        39.3        338.2   
  

 

 

   

 

 

   

 

 

 

Net increase (decrease) in cash and cash equivalents

     19.8        (26.6     15.2   

Cash and cash equivalents at beginning of the period

     0.8        27.4        12.2   
  

 

 

   

 

 

   

 

 

 

Cash and cash equivalents at end of the period

   $ 20.6      $ 0.8      $ 27.4   
  

 

 

   

 

 

   

 

 

 

Operating Cash Flows

Net cash provided by operating activities increased $20.7 million to $240.8 million in 2012 compared to 2011. This increase was driven primarily by increased earnings from the acquisition of Big Sandy and the completion of the NET project, both in 2011.

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.

Investing Cash Flows

Net cash flows used in investing activities totaled $501.0 million in 2012 compared to $286.0 million in 2011. The $215.0 million change was driven mainly by:

 

   

$140.7 million of net purchases of available-for-sale securities using funds from the November 2012 equity issuance as compared to $199.5 million of net proceeds in 2011, partially offset by

 

   

$318.7 million for the acquisition of 38.76% ownership interest in M&N US in 2012 as compared to $389.6 million for the acquisition of Big Sandy in 2011, and

 

   

a $56.1 million decrease in capital expenditures in 2012 due to the NET project at East Tennessee that went into commercial service in September 2011.

 

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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 project at East Tennessee.

Capital and Investment Expenditures

 

     2012      2011      2010  
     (in millions)  

Capital Expenditures

        

Gas Transportation and Storage(a)

   $ 42.3       $ 98.4       $ 25.8   

Investment Expenditures

        

Gulfstream(b)

             3.8         5.9   

Market Hub

     14.9         13.5         16.6   

M&N US(c)

                       
  

 

 

    

 

 

    

 

 

 

Total capital and investment expenditures

   $ 57.2       $ 115.7       $ 48.3   
  

 

 

    

 

 

    

 

 

 

 

(a) Excludes the acquisitions of Big Sandy in 2011.
(b) Excludes the acquisition of an additional 24.5% interest in Gulfstream in 2010.
(c) Excludes the acquisition of a 38.76% interest in October 2012.

Capital and investment expenditures for 2012 totaled $57.2 million and included $26.6 million for expansion projects and $30.6 million for maintenance and other projects, including the impact of reimbursable projects.

We project 2013 capital and investment expenditures of approximately $24 million, of which $19 million to be used for maintenance and other projects. The projected 2013 capital expenditures do not include the East Tennessee Eastman project announced in January 2013 as it is subject to board of director and regulatory approvals. Given our objective of growth through acquisitions and drop downs, we anticipate that we will continue to invest significant amounts of capital to acquire assets. Expansion capital expenditures may vary significantly based on investment opportunities.

We continue to evaluate customers’ needs for incremental expansion opportunities at East Tennessee, Big Sandy, Gulfstream, Market Hub and M&N US. 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.

Financing Cash Flows

Net cash provided by financing activities totaled $280.0 million in 2012 compared to $39.3 million in 2011. The $240.7 million change was driven mainly by:

 

   

$359.4 million of net debt issuances in 2012, including the net increase in the East Tennessee note payable and commercial paper borrowings used to fund the acquisition of a 38.76% in M&N US,

 

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compared to $20.6 million of net issuances in 2011, including net revolver borrowings and commercial paper, partially offset by

 

   

$148.2 million of net proceeds from the 2012 issuance of common units as compared to $217.9 million in 2011, and

 

   

a $24.6 million increase in distributions to partners in 2012 as a result of increases in distribution rates, limited partner units outstanding and incentive distribution rights.

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.

Acquisition of M&N US. On October 31, 2012, we acquired a 38.76% ownership interest in M&N US from Spectra Energy for approximately $318.7 million in cash and approximately $56.2 million in newly issued common and general partner units. As of December 31, 2012, M&N US has debt outstanding of $429.0 million, 38.76% of which is $166.3 million.

Common Unit Issuance. In November 2012, we issued 5.5 million common units to the public representing limited partner interests. The net proceeds from this offering were $148.2 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 may only be used to fund capital expenditures and acquisitions. Pending such use, the net proceeds of this offering will be held as cash or invested in short term securities, or a combination of both.

Acquisition of Big Sandy. In July 2011, we completed the acquisition of Big Sandy from EQT for approximately $390.0 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 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

 

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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.

New Debt Issuance, Available Credit Facility and Restrictive Debt Covenants. On December 6, 2012, East Tennessee issued $200.0 million aggregate principal amount of 3.10% senior unsecured notes due in 2024. A portion of the net proceeds from the offering were used to repay the $150.0 million note payable due in 2012 at East Tennessee. The remaining balance of the proceeds was used for general partnership purposes.

On August 15, 2012, we entered into a new five-year promissory note payable agreement with our equity affiliate, Market Hub, to borrow up to $50.0 million, replacing our existing note payable. The note matures on August 15, 2017, however, any borrowings under the agreement are payable on demand to Market Hub. The promissory note bears interest based on 30-day LIBOR rates. As of December 31, 2012, we had $17.0 million of borrowings outstanding under the note.

In June 2011, we issued $500.0 million aggregate principal amount of senior unsecured 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. As of December 31, 2012, we had $363.6 million available under the revolving credit facility.

The issuance of commercial paper, letters of credit and revolving borrowings reduce the amount available under the credit facility. As of December 31, 2012, there were no letters of credit issued under the credit facility or revolving borrowings outstanding.

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, 2012, 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, 2012, the ratio was 3.7.

Credit Ratings. On January 31, 2013 our credit ratings are BBB/Stable from Standard & Poor’s and Fitch Ratings and Baa3/Stable from Moody’s Investors Service. 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.

 

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We increased the quarterly cash distributions each quarter of 2012 from $0.475 per limited partner unit for the fourth quarter of 2011 to $0.495 per limited partner unit for the fourth quarter of 2012, or 4.2%. A cash distribution to our unitholders of $0.495 per limited partner unit was declared on January 28, 2013 and was paid on February 14, 2013.

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. In 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 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.

As of December 31, 2012, Gulfstream had $1,150.0 million aggregate principal amounts of senior notes outstanding and M&N US had a $429.0 million aggregate principal amount of a senior note 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 2013.

Contractual Obligations as of December 31, 2012

 

     Payments Due by Period  
     Total      2013      2014 &
2015
     2016 &
2017
     2018 &
Beyond
 
     (in millions)  

Long-term debt, including current maturities(a)

   $ 896.7       $ 25.1       $ 50.1       $ 288.8       $ 532.7   

Operating leases

     3.0         0.2         0.3         0.2         2.3   

Purchase obligations

     0.5         0.5                           
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total contractual cash obligations

   $ 900.2       $ 25.8       $ 50.4       $ 289.0       $ 535.0   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(a) Excludes commercial paper and note payable to affiliates as both are current liabilities. See Note 10 of Notes to Consolidated Financial Statements. Amounts include estimated scheduled interest payments over the life of the associated debt.

 

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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, 10 and 13 of Notes to Consolidated Financial Statements.

Based on a sensitivity analysis as of December 31, 2012, it was estimated that if short-term interest rates average 100 basis points higher (lower) in 2013 than in 2012, interest expense, net of offsetting impacts in interest income, would increase (decrease) by $1.9 million. Comparatively, based on a sensitivity analysis as of December 31, 2011, had short-term interest rates averaged 100 basis points higher (lower) in 2012 than in 2011, it was estimated that interest expense, net of offsetting interest income, would have fluctuated by $0.6 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, 2012 and 2011.

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, 2012, 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 throughout 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 10% of the gross fair value of trade accounts receivable at December 31, 2012.

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

 

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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 2012 was approximately 11.8 Bcf. The market value of that volume, assuming an average market price of $3.75 per MMBtu, would be $44.3 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 expired in 2012 and had not been ratified by the United States. United Nations-sponsored international negotiations were held in Doha, Qatar in December 2012 with the intent of laying the groundwork for a new global agreement on climate action to come into effect by 2020. An agreement was reached to amend the Kyoto Protocol extending it to 2020 when a potential new agreement could take effect.

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 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 has not ratified the Kyoto Protocol, nor has the federal government adopted a mandatory GHG emissions reduction requirement for our sector. The EPA issued a final Mandatory Greenhouse Gas Reporting rule in 2009 that required annual reporting of GHG emissions data from certain of our U.S. operations beginning in 2010. In 2010, the EPA released additional requirements for natural gas system reporting that have expanded the reporting requirements for GHG emissions starting in 2011. These reporting requirements have not had and are not anticipated to have a material impact on our consolidated results of operations, financial position or cash flows. In 2010, the EPA issued the Prevention of Significant Deterioration (PSD) and Title V Greenhouse Gas Tailoring Rule (Tailoring Rule). This regulation establishes that, beginning in January 2011, the construction of new or the modification of existing major sources of GHG emissions would become subject to the PSD air permitting program (and later, the Title V permitting program). This regulation also significantly increased the emission thresholds that would determine what facilities will become subject to these regulations. In June 2012,

 

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these regulations, along with other GHG regulations and determinations issued by the EPA, were upheld by the D.C. Circuit of Appeals. A petition for a rehearing en banc with the full D.C. Circuit has been filed by the parties challenging these regulations. In July 2012, the EPA determined in Step 3 of the Tailoring Rule process that it would maintain the current GHG emissions thresholds for PSD and Title V applicability. This rule has also been appealed. We anticipate that in the future, new capital projects or modification of existing projects could be subject to a permit requirement related to GHG emissions that may result in delays in completing such 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. A number of states in the United 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, the Western Climate Initiative which includes California and the Midwestern Greenhouse Gas Reduction Accord which includes six midwestern states. 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.

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 continue to monitor the development of greenhouse gas regulatory policies.

Other. For additional information on other issues, see Item 8. Financial Statements and Supplementary Data, Notes 5 and 12 of Notes to Consolidated Financial Statements.

New Accounting Pronouncements

There were no significant accounting pronouncements adopted during 2012, 2011 or 2010 that had a material impact on our consolidated results of operations, financial position or cash flows.

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

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

 

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Item 8. Financial Statements and Supplementary Data.

Management’s Annual Report on Internal Control over Financial Reporting

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

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, 2012 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, 2012.

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

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors 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, 2012 and 2011, and the related consolidated statements of operations, comprehensive income, cash flows and partners’ capital for each of the three years in the period ended December 31, 2012. 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, 2012, 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 Control 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, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

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

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

 

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In our opinion, 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, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, 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 27, 2013

 

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SPECTRA ENERGY PARTNERS, LP

CONSOLIDATED STATEMENTS OF OPERATIONS

(In millions, except per-unit amounts)

 

     Years Ended December 31,  
     2012      2011      2010  

Operating Revenues

        

Transportation of natural gas

   $ 217.7       $ 182.4       $ 169.0   

Storage of natural gas and other

     19.1         22.6         28.7   
  

 

 

    

 

 

    

 

 

 

Total operating revenues

     236.8         205.0         197.7   
  

 

 

    

 

 

    

 

 

 

Operating Expenses

        

Operating, maintenance and other

     22.2         28.4         32.6   

Operating, maintenance and other — affiliates

     46.8         43.7         40.3   

Depreciation and amortization

     37.3         33.2         29.4   

Property and other taxes

     12.3         11.5         7.7   
  

 

 

    

 

 

    

 

 

 

Total operating expenses

     118.6         116.8         110.0   
  

 

 

    

 

 

    

 

 

 

Operating Income

     118.2         88.2         87.7   
  

 

 

    

 

 

    

 

 

 

Other Income and Expenses

        

Equity in earnings of unconsolidated affiliates

     107.6         107.3         75.1   

Other income and expenses, net

     0.3         2.1         0.8   
  

 

 

    

 

 

    

 

 

 

Total other income and expenses

     107.9         109.4         75.9   
  

 

 

    

 

 

    

 

 

 

Interest Income

     0.1         0.5         0.1   

Interest Expense

     31.3         23.2         11.9   

Interest Expense — Affiliates

             1.8         4.3   
  

 

 

    

 

 

    

 

 

 

Earnings Before Income Taxes

     194.9         173.1         147.5   

Income Tax Expense (Benefit)

     1.4         1.1         (0.4
  

 

 

    

 

 

    

 

 

 

Net Income

   $ 193.5       $ 172.0       $ 147.9   
  

 

 

    

 

 

    

 

 

 

Calculation of Limited Partners’ Interest in Net Income:

        

Net income

   $ 193.5       $ 172.0       $ 147.9   

Less:

        

General partner’s interest in net income

     28.9         20.3         10.6   
  

 

 

    

 

 

    

 

 

 

Limited partners’ interest in net income

   $ 164.6       $ 151.7       $ 137.3   
  

 

 

    

 

 

    

 

 

 

Weighted average limited partners units outstanding — basic and diluted

     97.3         93.1         81.0   

Net income per limited partner unit — basic and diluted

   $ 1.69       $ 1.63       $ 1.70   

Distributions paid per limited partner unit during the periods presented

   $ 1.93       $ 1.845       $ 1.70   

See Notes to Consolidated Financial Statements.

 

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SPECTRA ENERGY PARTNERS, LP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In millions)

 

     Year Ended December 31,  
     2012     2011      2010  

Net Income

   $ 193.5      $ 172.0       $ 147.9   

Other comprehensive income:

       

Unrealized mark-to-market net loss on hedges

                    (2.1

Reclassification of cash flow hedges into earnings

     (0.6     1.7         4.6   

Additional equity interest in Gulfstream’s other comprehensive income

                    2.5   
  

 

 

   

 

 

    

 

 

 

Total Comprehensive Income

   $ 192.9      $ 173.7       $ 152.9   
  

 

 

   

 

 

    

 

 

 

See Notes to Consolidated Financial Statements.

 

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SPECTRA ENERGY PARTNERS, LP

CONSOLIDATED BALANCE SHEETS

(In millions)

 

     December 31,  
     2012      2011  

ASSETS

     

Current Assets

     

Cash and cash equivalents

   $ 20.6       $ 0.8   

Receivables, trade (net of allowance for doubtful accounts of $0.1 at both December 31, 2012 and 2011)

     23.5         22.3   

Receivables — affiliates

     0.1         1.3   

Natural gas imbalance receivables

     4.4         3.5   

Natural gas imbalance receivables — affiliates

     1.2         3.2   

Inventory

     2.8         7.0   

Other

     2.7         3.5   
  

 

 

    

 

 

 

Total current assets

     55.3         41.6   
  

 

 

    

 

 

 

Investments and Other Assets

     

Investments in unconsolidated affiliates

     921.2         727.2   

Goodwill

     461.7         461.7   

Other investments

     141.4         0.1   
  

 

 

    

 

 

 

Total investments and other assets

     1,524.3         1,189.0   
  

 

 

    

 

 

 

Property, Plant and Equipment

     

Cost

     1,475.9         1,439.3   

Less accumulated depreciation and amortization

     269.6         234.1   
  

 

 

    

 

 

 

Net property, plant and equipment

     1,206.3         1,205.2   
  

 

 

    

 

 

 

Regulatory Assets and Deferred Debits

     19.8         21.1   
  

 

 

    

 

 

 

Total Assets

   $ 2,805.7       $ 2,456.9   
  

 

 

    

 

 

 

See Notes to Consolidated Financial Statements.

 

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SPECTRA ENERGY PARTNERS, LP

CONSOLIDATED BALANCE SHEETS

(In millions)

 

     December 31,  
     2012      2011  

LIABILITIES AND PARTNERS’ CAPITAL

     

Current Liabilities

     

Accounts payable

   $ 4.2       $ 4.7   

Accounts payable — affiliates

     10.2         16.0   

Taxes accrued

     8.8         7.1   

Natural gas imbalance payables

     5.6         5.0   

Natural gas imbalance payables — affiliates

     0.8         1.9   

Note payable — affiliates

     17.0         30.5   

Current maturities of long-term debt

             150.0   

Commercial paper

     336.4         27.0   

Other

     3.1         3.7   
  

 

 

    

 

 

 

Total current liabilities

     386.1         245.9   
  

 

 

    

 

 

 

Long-term Debt

     699.6         499.4   
  

 

 

    

 

 

 

Deferred Credits and Other Liabilities

     

Deferred income taxes

     9.4         8.0   

Other

     5.0         5.9   
  

 

 

    

 

 

 

Total deferred credits and other liabilities

     14.4         13.9   
  

 

 

    

 

 

 

Commitments and Contingencies

     

Partners’ Capital

     

Common units (103.6 million and 96.3 million units issued and outstanding at December 31, 2012 and 2011, respectively)

     1,659.5         1,653.6   

General partner units (2.1 million and 2.0 million units outstanding at December 31, 2012 and 2011, respectively)

     42.2         39.6   

Accumulated other comprehensive income

     3.9         4.5   
  

 

 

    

 

 

 

Total partners’ capital

     1,705.6         1,697.7   
  

 

 

    

 

 

 

Total Liabilities and Partners’ Capital

   $ 2,805.7       $ 2,456.9   
  

 

 

    

 

 

 

See Notes to Consolidated Financial Statements.

 

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SPECTRA ENERGY PARTNERS, LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

 

     Years Ended December 31,  
     2012     2011     2010  

CASH FLOWS FROM OPERATING ACTIVITIES

      

Net income

   $ 193.5      $ 172.0      $ 147.9   

Adjustments to reconcile net income to net cash provided by operating activities:

      

Depreciation and amortization

     39.0        33.2        29.4   

Deferred income tax expense (benefit)

     1.4        1.1        (1.0

Equity in earnings of unconsolidated affiliates

     (107.6     (107.3     (75.1

Distributions received from unconsolidated affiliates

     111.6        116.3        81.1   

Decrease (increase) in:

      

Receivables

     (0.3     (4.3     2.0   

Taxes receivable — affiliates

                   (0.1

Other current assets

     5.8        (0.1     0.1   

Increase (decrease) in:

      

Accounts payable

     (3.6     4.9        1.9   

Taxes accrued

     1.7        2.9        (0.2

Other current liabilities

     0.1        (0.9     (1.2

Other, assets

     (0.1     1.7        (0.1

Other, liabilities

     (0.7     0.6        0.1   
  

 

 

   

 

 

   

 

 

 

Net cash provided by operating activities

     240.8        220.1        184.8   
  

 

 

   

 

 

   

 

 

 

CASH FLOWS FROM INVESTING ACTIVITIES

      

Capital expenditures

     (42.3     (98.4     (25.8

Investment expenditures

     (14.9     (17.3     (22.5

Acquisitions, net of cash acquired

     (318.7     (389.6     (256.6

Distributions received from unconsolidated affiliates

     15.3        9.2        6.1   

Purchases of available-for-sale securities

     (630.1     (891.6     (239.0

Proceeds from sales and maturities of available-for-sale securities

     489.4        1,091.1        30.0   

Other

     0.3        10.6          
  

 

 

   

 

 

   

 

 

 

Net cash used in investing activities

     (501.0     (286.0     (507.8
  

 

 

   

 

 

   

 

 

 

CASH FLOWS FROM FINANCING ACTIVITIES

      

Proceeds from issuance of long-term debt

     200.0        499.4        207.2   

Payments for the redemption of long-term debt

     (150.0     (207.2       

Net increase (decrease) in revolving credit facility borrowings

            (298.6     58.6   

Net increase in commercial paper

     309.4        27.0          

Proceeds from issuance of units

     148.2        217.9        220.8   

Proceeds from notes payable — affiliates

     5.0        26.0        30.3   

Payments on notes payable — affiliates

     (18.5     (29.5     (23.8

Payments on notes assumed in acquisition — affiliates

                   (7.4

Distributions to partners

     (213.9     (189.3     (145.9

Other

     (0.2     (6.4     (1.6
  

 

 

   

 

 

   

 

 

 

Net cash provided by financing activities

     280.0        39.3        338.2   
  

 

 

   

 

 

   

 

 

 

Net increase (decrease) in cash and cash equivalents

     19.8        (26.6     15.2   

Cash and cash equivalents at beginning of the period

     0.8        27.4        12.2   
  

 

 

   

 

 

   

 

 

 

Cash and cash equivalents at end of the period

   $ 20.6      $ 0.8      $ 27.4   
  

 

 

   

 

 

   

 

 

 

Supplemental Disclosures

      

Cash paid for interest, net of amount capitalized

   $ 29.4      $ 23.0      $ 15.7   

Cash paid for income taxes

                   0.7   

Property, plant and equipment noncash accruals

     0.3        2.8        0.8   

Deemed contributions from General Partner for services provided

                   1.4   

Units issued as partial consideration for acquisitions

     56.2               66.0   

See Notes to Consolidated Financial Statements.

 

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SPECTRA ENERGY PARTNERS, LP

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

(In millions)

 

     Partners’ Capital     Accumulated
Other
Comprehensive
Income (Loss)
    Total  
   Limited Partners     General
Partner
     
   Common     Subordinated        

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   

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   

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   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income

     164.6               28.9               193.5   

Reclassification of cash flow hedges into earnings

                          (0.6     (0.6

Excess purchase price over net acquired assets in Maritimes & Northeast Pipeline L.L.C. acquisition

     (172.4            (3.5            (175.9

Issuance of units

     200.6               4.2               204.8   

Attributed deferred tax benefit

     (0.1                          (0.1

Distributions to partners

     (186.9            (27.0            (213.9

Other, net

     0.1                             0.1   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

December 31, 2012

   $ 1,659.5      $      $ 42.2      $ 3.9      $ 1,705.6   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

See Notes to Consolidated Financial Statements.

 

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SPECTRA ENERGY PARTNERS, LP

Notes to Consolidated Financial Statements

INDEX

 

          Page  

1.

   Summary of Operations and Significant Accounting Policies      69   

2.

   Acquisitions      73   

3.

   Transactions with Affiliates      75   

4.

   Business Segments      76   

5.

   Regulatory Matters      77   

6.

   Net Income per Limited Partner Unit and Cash Distributions      78   

7.

   Marketable Securities      79   

8.

   Investments in Unconsolidated Affiliates      80   

9.

   Property, Plant and Equipment      82   

10.

   Debt and Credit Facility      82   

11.

   Fair Value Measurements      85   

12.

   Commitments and Contingencies      86   

13.

   Risk Management and Hedging Activities      86   

14.

   Sale of Common Units      87   

15.

   Equity-Based Compensation      88   

16.

   Quarterly Financial Data (Unaudited)      88   

1. Summary of Operations and Significant Accounting Policies

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

Nature of Operations. Spectra Energy Partners, LP, through its subsidiaries and equity affiliates, is engaged in the transportation and gathering of natural gas through interstate pipeline systems located throughout 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 on July 2, 2007. As of December 31, 2012, Spectra Energy Corp (Spectra Energy) and its subsidiaries collectively owned 61% of us and the remaining 39% 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. These investments include our 50% investment in Market Hub Partners Holding (Market Hub), 49% investment in Gulfstream Natural Gas System, L.L.C. (Gulfstream) and 38.76% investment in Maritimes & Northeast Pipeline, L.L.C. (M&N US).

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

 

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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 5 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 2012, 2011 or 2010 are as follows:

 

     % of Revenues  

Customer

   2012     2011     2010  

EQT Corporation

     19     12     (a

Tennessee Valley Authority

     10        (a     (a

 

(a) Percentage less than 10%.

Allowance for Funds Used During Construction (AFUDC). AFUDC, which represents the estimated debt and equity costs of capital funds necessary to finance the construction 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 Consolidated Statements of Operations through Other Income and Expenses, Net for

 

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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 $0.2 million in 2012 (an equity component of $0.2 million), $2.0 million in 2011 (an equity component of $1.7 million and an interest expense component of $0.3 million) and $0.7 million in 2010 (an equity component of $0.6 million and an interest expense 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 and New Hampshire income tax. Market Hub is liable to Spectra Energy for Texas income (margin) tax under a tax sharing agreement. As of December 31, 2012, the difference between the tax basis and the reported amounts of Spectra Energy Partners’ assets and liabilities is $1.8 billion.

Cash and Cash Equivalents. Highly liquid investments with original maturities of three months or less at the date of acquisition, except for any investments that are considered restricted funds, 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. Most 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, 2012, 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 and short-term money market securities. We classify all short term money market securities that are restricted or 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 Cash Flows From Investing Activities in the accompanying Consolidated Statements of Cash Flows. See also Notes 7 and 14 for additional information.

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 2012, 2011 or 2010.

We perform the annual review for goodwill impairment at the reporting unit level, which we have determined to be our one reportable operating segment, Gas Transportation and Storage.

We perform either a qualitative assessment or a quantitative assessment of our reporting unit based on management’s judgment. With respect to the qualitative assessment, we consider events and circumstances

 

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specific to us, such as macroeconomic conditions, industry and market considerations, cost factors and overall financial performance, when evaluating whether it was more likely than not that the fair value of our reporting unit was less than its carrying amount.

In connection with the quantitative assessment, 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. If the carrying amount of the reporting unit exceeds its fair value, a comparison of the fair value and carrying value of the goodwill of that reporting unit needs to be performed. 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.

As of December 31, 2012, goodwill was $461.7 million and there were no changes to the goodwill balance during 2012 or 2011.

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 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.

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,

 

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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 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 4.

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 Facility Borrowings within Cash Flows From 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. There were no significant accounting pronouncements adopted during 2012, 2011 or 2010 that had a material impact on our consolidated results of operations, financial position or cash flows.

2. Acquisitions

M&N US. On October 31, 2012, we acquired a 38.76% ownership interest in M&N US from Spectra Energy for approximately $318.7 million in cash and approximately $56.2 million in newly issued common and general units. As of December 31, 2012, M&N US has debt outstanding of $429.0 million, 38.76% of which is $166.3 million. M&N US owns a Federal Energy Regulatory Commission (FERC) regulated mainline interstate natural gas transportation system in the United States which extends from the Canadian border near Baileyville, Maine to northeastern Massachusetts. As of December 31, 2012, M&N US’ firm transportation and storage contracts had a weighted average remaining life of 20 years. In 2012, 99% of M&N US’ revenues were derived from capacity reservation charges under firm contracts, with the remainder derived from variable usage fees under firm and interruptible transportation contracts. M&N US’ pipeline location and key interconnects with Spectra Energy’s transmission system link regional natural gas supplies to the northeast U.S. and Atlantic Canadian markets.

 

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The M&N US acquisition represented a transaction between entities under common control, but did not represent a change in reporting entity. Accordingly, the Consolidated Financial Statements and related information presented herein include the results of the acquisition of M&N US as of the date of the acquisition.

The 38.76% interest in M&N US was recorded at the historical book value of Spectra Energy of $199.1 million. The $175.9 million excess purchase price over the book value of net assets acquired was recorded as a reduction to Partners’ Capital, and the $56.2 million of common and general partner units issued were recorded as increases to Partners’ Capital.

Big Sandy. On July 1, 2011, we completed the acquisition of Big Sandy from EQT Corporation (EQT) for approximately $390.0 million in cash. Big Sandy’s primary asset is a 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 the strategic location of the pipeline and the opportunity to expand and grow the business. 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.

 

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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.

3. 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

 

     2012      2011      2010  
     (in millions)  

Operating, maintenance and other expenses

   $ 46.8       $ 43.7       $ 40.3   

Interest expense

             1.8         4.3   

Consolidated Balance Sheets

 

     December 31,  
     2012      2011  
     (in millions)  

Receivables

   $ 0.1       $ 1.3   

Natural gas imbalance receivables

     1.2         3.2   

Current assets — other

     0.4         0.4   

Accounts payable

     10.2         16.0   

Natural gas imbalance payables

     0.8         1.9   

Note payable

     17.0         30.5   

See also Notes 1, 8, 10, 11 and 13 for discussion of specific related party transactions.

 

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4. 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, Market Hub and M&N US 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.

M&N US owns an interstate natural gas pipeline that extends from the Canadian border near Baileyville, Maine to northeastern Massachusetts. M&N US pipeline links regional gas supplies with Northeast U.S. and Atlantic Canadian markets. M&N US’ operations are 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.

 

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Business Segment Data

 

     Total
Revenues
     Segment EBIT/
Consolidated
Earnings
Before
Income Taxes
     Depreciation
and
Amortization
     Capital and
Investment
Expenditures
     Segment/
Total
Assets
 
     (in millions)  

2012

              

Gas Transportation and Storage

   $ 236.8       $ 127.3       $ 37.3       $ 42.3       $ 1,715.0   

Other

             98.8                 14.9         1,090.7   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

     236.8         226.1         37.3         57.2         2,805.7   

Interest income

             0.1                           

Interest expense

             31.3                           
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total consolidated

   $ 236.8       $ 194.9       $ 37.3       $ 57.2       $ 2,805.7   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

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   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

5. 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
 
     2012      2011     
     (in millions)         

Regulatory Assets(a)(b)

        

Regulatory asset related to income taxes(c)

   $ 9.8       $ 9.9         (d

Vacation accrual

     2.1         1.8         (e

Deferred debt expense/premium

     2.9         3.5         (f

Fuel tracker(g)

     1.4         2.1         2013   
  

 

 

    

 

 

    

Total Regulatory Assets

   $ 16.2       $ 17.3      
  

 

 

    

 

 

    

Regulatory Liabilities(b)

        

Fuel tracker(g)

   $ 0.2       $ 0.5         2013   
  

 

 

    

 

 

    

Total Regulatory Liabilities

   $ 0.2       $ 0.5      
  

 

 

    

 

 

    

 

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(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) Recoverable in future periods.
(f) Prepayment penalty being amortized over the life of the retired debt.
(g) 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 a 2005 settlement.

Saltville. Saltville continues to operate under rates approved by the FERC in a 2008 settlement. 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 went into service. Gulfstream filed the Cost and Revenue Study and the FERC accepted the filing on August 6, 2012. There were no changes to rates.

Ozark Gas Transmission. Ozark continues to operate under rates approved by the FERC in 2000. In 2011, Ozark reached a settlement agreement with customers in a FERC rate proceeding that included a rate moratorium until October 1, 2012 and a requirement to file a rate case by October 1, 2015.

Big Sandy. Big Sandy operates under rates approved by the FERC in 2006.

M&N US. M&N US operates under rates approved by the FERC in a 2010 settlement.

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.

6. Net Income Per Limited Partner Unit and Cash Distributions

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

 

     2012      2011      2010  
     (in millions, except per-unit
amounts)
 

Net income

   $ 193.5       $ 172.0       $ 147.9   

Less:

        

General partner’s interest in net income — 2%

     3.9         3.4         3.0   

General partner’s interest in net income attributable to incentive distribution rights

     25.0         16.9         7.6   
  

 

 

    

 

 

    

 

 

 

Limited partners’ interest in net income

   $ 164.6       $ 151.7       $ 137.3