10-K 1 sep-2013123110xk.htm 10-K SEP-2013.12.31 10-K
 
 
 
 
 
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, 2013
or
¨    TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from              to             
Commission file number 001-33556
 SPECTRA ENERGY PARTNERS, LP
(Exact name of registrant as specified in its charter)
Delaware
  
41-2232463
(State or other jurisdiction of
incorporation or organization)
  
(I.R.S. Employer Identification No.)
 
 
5400 Westheimer Court, Houston, Texas
  
77056
(Address of principal executive offices)
  
(Zip Code)
713-627-5400
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class
  
Name of Each Exchange on Which Registered
Common Units Representing Limited Partner Interests
  
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None.
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  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, 2013: $2,113,000,000.
At January 31, 2014, there were 284,223,690 Common Units and 5,800,483 General Partner Units outstanding.
 
 
 
 
 



SPECTRA ENERGY PARTNERS, LP
FORM 10-K FOR THE YEAR ENDED
DECEMBER 31, 2013
TABLE OF CONTENTS
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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, provincial, federal and foreign 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 and oil 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 and foreign currency exchange 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 oil 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 and costs 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. and Canadian pipeline, storage, gathering and other related infrastructure projects and the effects of competition;
the performance of natural gas transmission, storage and gathering facilities, and crude oil transportation and storage;
the extent of success in connecting natural gas and oil supplies to transmission and gathering systems and in connecting to expanding gas and oil markets;
the effects of accounting pronouncements issued periodically by accounting standard-setting bodies;
conditions of the capital markets during the periods covered by 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, LP, through its subsidiaries and equity affiliates, is engaged in the transmission, storage and gathering of natural gas, the transportation and storage of crude oil, and the transportation of natural gas liquids (NGLs), through interstate pipeline systems with over 17,000 miles of transmission and transportation pipelines and the storage of natural gas in underground facilities with aggregate working gas storage capacity of approximately 164 billion cubic feet (Bcf) in the United States. We are a Delaware master limited partnership (MLP) formed in 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 transmission, gathering and storage assets, and crude oil transportation and storage assets, in central, southern and eastern United States as well as western Canada. Through our investments in DCP Sand Hills Pipeline, LLC (Sand Hills) and DCP Southern Hills Pipeline, LLC (Southern Hills), we also are engaged in the transportation of NGLs. Our assets are strategically located in geographic regions of the United States and Canada where demand, primarily for natural gas used in electricity generation, and crude oil, 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 and our liquids crude oil transportation and storage operations are regulated by either the Federal Energy Regulatory Commission (FERC), the U.S. Department of Transportation (DOT), or the National Energy Board

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(NEB) with the exception of Moss Bluff intrastate storage operations and Ozark gathering facilities which are subject to oversight by various state commissions.
Our operations and activities are managed by our general partner, Spectra Energy Partners (DE) GP, LP, which in turn is managed by its general partner, Spectra Energy Partners GP, LLC, (the General Partner). The General Partner is wholly owned by a subsidiary of Spectra Energy Corp (Spectra Energy). Spectra Energy is a separate, publicly traded entity which trades on the NYSE under the symbol “SE.” As of December 31, 2013, Spectra Energy and its subsidiaries collectively owned 84% of us and the remaining 16% was publicly owned.
Acquisitions
In 2009, we acquired all of the ownership interests of NOARK Pipeline System, Limited Partnership (NOARK) from Atlas Pipeline Partners, L.P. 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).
In 2010, we acquired an additional 24.5% interest in Gulfstream Natural Gas System, LLC (Gulfstream) from a subsidiary of Spectra Energy. Following the acquisition, we owned a 49% interest in Gulfstream. Gulfstream owns a 745-mile interstate natural gas transportation system which extends from Pascagoula, Mississippi and Mobile, Alabama across the Gulf of Mexico and into Florida.
In 2011, we completed the acquisition of Big Sandy Pipeline, L.L.C (Big Sandy) from EQT Corporation. Big Sandy’s primary asset is an approximately 70-mile natural gas pipeline system in eastern Kentucky with capacity of approximately 0.2 Trillion British thermal units per day (TBtu/d).
In October 2012, we acquired a 39% ownership interest in Maritimes & Northeast L.L.C. (M&N US) from Spectra Energy. M&N US owns an approximately 350-mile mainline interstate natural gas transportation system in the United States which extends from the Canadian border near Baileyville, Maine to northeastern Massachusetts. The pipeline's location and key interconnects with our transmission system link regional natural gas supplies to the northeast U.S. markets.
On March 14, 2013, Spectra Energy acquired 100% of the ownership interests in the Express-Platte crude oil pipeline system (Express-Platte) from third-parties. On August 2, 2013, we acquired a 40% ownership interest in the U.S. portion of Express-Platte (Express US) and a 100% ownership interest in the Canadian portion of Express-Platte (Express Canada) (collectively, Express-Platte) from subsidiaries of Spectra Energy (the Express-Platte acquisition). Express-Platte, which begins in Hardisty, Alberta, and terminates in Wood River, Illinois, is comprised of both the Express and Platte crude oil pipelines. The Express pipeline carries crude oil to U.S. refining markets in the Rockies area, including Montana, Wyoming, Colorado and Utah. The Platte pipeline, which interconnects with the Express pipeline in Casper, transports crude oil predominantly from the Bakken shale and western Canada to refineries in the Midwest. The completion of the acquisition expands our growth platform to include the rapidly growing North American crude oil transportation and storage market and diversifies our profile of steady, fee-based cash flows with an escalating-fee asset.
On November 1, 2013, we acquired ownership interests in Spectra Energy’s remaining U.S. transmission, storage and liquids assets, including Spectra Energy’s remaining 60% interest in Express US (the U.S. Assets Dropdown). The pipeline systems include Texas Eastern Transmission, LP (Texas Eastern), Algonquin Gas Transmission, LLC (Algonquin), the remaining ownership interest in Express US, an additional 39% interest in M&N US, 33% interests in both Sand Hills and Southern Hills, an additional 1% interest in Gulfstream and a 24.95% interest in Southeast Supply Header, LLC (SESH). The natural gas and crude oil storage businesses include Bobcat Gas Storage (Bobcat), the remaining 50% interest in Market Hub Partners Holding (Market Hub), a 49% interest in Steckman Ridge, LP (Steckman Ridge), and Texas Eastern's and Express-Platte's storage facilities.
For more information on our acquisitions, see Item 8. Financial Statements and Supplementary Data, Note 2 of Notes to Consolidated Financial Statements.
Businesses
We currently manage our business in two reportable segments: U.S. Transmission, and Liquids. The remainder of our business operations is presented as “Other,” and consists mainly of certain corporate costs. The following sections describe the operations of each of our businesses. For financial information on our business segments, see Note 4 of Notes to Consolidated Financial Statements.

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As the Express-Platte acquisition and the U.S. Assets Dropdown represented transfers of entities under common control, the Consolidated Financial Statements and related information presented herein have been recast. As a result of these transactions, we realigned our reportable segments structure. Amounts presented herein for segment information have been recast for all periods presented to conform to our current segment reporting presentation. See Note 2 of Notes to Consolidated Financial Statements for further discussion of the transactions.
U.S. Transmission
Our U.S. Transmission business primarily provides transportation and storage of natural gas for customers in various regions of the northeastern and southeastern United States. Our pipeline systems consist of approximately 14,000 miles of pipelines with eight primary transmission systems: Texas Eastern, Algonquin, East Tennessee Natural Gas, LLC (East Tennessee), M&N US, Ozark, Big Sandy, Gulfstream and SESH. The pipeline systems in our U.S. Transmission business receive natural gas from major North American producing regions for delivery to their respective markets. A majority of contracted transportation volumes are under long-term firm service agreements, where customers reserve capacity in the pipeline. Interruptible services, where customers can use capacity if it is available at the time of the request, are generally provided on a short-term or seasonal basis.
U.S. Transmission provides natural gas storage services through Saltville Gas Storage Company L.L.C. (Saltville), Market Hub, Steckman Ridge, Bobcat and Texas Eastern’s facilities. Gathering services are provided through Ozark Gas Gathering. In the course of providing transportation services, U.S. Transmission also processes natural gas on our Texas Eastern system.
Demand on the natural gas pipeline and storage systems is seasonal, with the highest throughput occurring during colder periods in the first and fourth calendar quarters, and storage injections occurring primarily during the summer periods. Actual throughput and storage injections/withdrawals do not have a significant effect on revenues or earnings.
Most of U.S. Transmission’s pipeline and storage operations are regulated by the FERC and are subject to the jurisdiction of various federal, state and local environmental agencies.

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Texas Eastern
On November 1, 2013, we acquired Texas Eastern in the U.S. Assets Dropdown. The Texas Eastern natural gas transmission system extends approximately 1,700 miles from producing fields in the Gulf Coast region of Texas and Louisiana to Ohio, Pennsylvania, New Jersey and New York. It consists of two parallel systems, one with three large-diameter parallel pipelines and the other with one to three large-diameter pipelines. Texas Eastern’s onshore system consists of approximately 8,600 miles of pipeline and associated compressor stations (facilities that increase the pressure of gas to facilitate its pipeline transmission). Texas Eastern also owns and operates two offshore Louisiana pipeline systems, which extend approximately 100 miles into the Gulf of Mexico and include approximately 400 miles of pipeline. Texas Eastern has two storage facilities in Pennsylvania held through joint ventures and one 100%-owned and operated storage facility in Maryland. Texas Eastern’s total working capacity in these three facilities is 74 Bcf. In addition, Texas Eastern’s system is connected to Steckman Ridge, a 12 Bcf joint venture storage facility in Pennsylvania, and three affiliated storage facilities in Texas and Louisiana, aggregating 72 Bcf, owned by Market Hub and Bobcat.
New Jersey-New York Expansion. The New Jersey-New York expansion project is an 800 million cubic feet per day expansion of the Texas Eastern pipeline system consisting of a new 16-mile pipeline extension into lower Manhattan, New York and other associated facility upgrades. The project is designed to transport gas produced in the U.S. Gulf Coast, Mid-Continent, Rockies and Marcellus Shale regions into New York City. The project was placed into service during the fourth quarter of 2013.
 

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Algonquin
On November 1, 2013, we acquired Algonquin in the U.S. Assets Dropdown. The Algonquin natural gas transmission system connects with Texas Eastern’s facilities in New Jersey and extends approximately 250 miles through New Jersey, New York, Connecticut, Rhode Island and Massachusetts where it connects to Maritimes & Northeast Pipeline. The system consists of approximately 1,125 miles of pipeline with associated compressor stations.
 

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East Tennessee
East Tennessee’s natural gas transmission system crosses Texas Eastern’s system at two locations in Tennessee and consists of two mainline systems totaling approximately 1,500 miles of pipeline in Tennessee, Georgia, North Carolina and Virginia, with associated compressor stations. East Tennessee has a liquefied natural gas (LNG, natural gas that has been converted to liquid form) storage facility in Tennessee with a total working capacity of 1 Bcf. East Tennessee also connects to the Saltville storage facilities in Virginia that have a working gas capacity of approximately 5 Bcf.
Maritimes & Northeast Pipeline
On October 31, 2012 we acquired 39% of M&N US from Spectra Energy. On November 1, 2013, Spectra Energy contributed its remaining 39% ownership in M&N US to us in the U.S. Assets Dropdown. M&N US is owned 78% directly by us, with affiliates of Emera, Inc. and Exxon Mobil Corporation directly owning the remaining 13% and 9% interests, respectively. M&N US is an approximately 350-mile mainline interstate natural gas transmission system which extends from the border of Canada near Baileyville, Maine to northeastern Massachusetts. M&N US is connected to the Canadian portion of the Maritimes & Northeast Pipeline system, Maritimes & Northeast Pipeline Limited Partnership, which is owned 78% by Spectra Energy. M&N US facilities include compressor stations, with a market delivery capability of approximately 0.8 Bcf/d of natural gas. The pipeline’s location and key interconnects with our transmission system link regional natural gas supplies to the northeast U.S. markets.

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Ozark
We acquired Ozark in 2009. Ozark Gas Transmission consists of an approximately 530-mile natural gas transmission system extending from southeastern Oklahoma through Arkansas to southeastern Missouri. Ozark Gas Gathering consists of a 365-mile natural gas gathering system, with associated compressor stations, that primarily serves Arkoma basin producers in eastern Oklahoma.
 

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Big Sandy
We acquired Big Sandy in 2011. Big Sandy is an approximately 70-mile natural gas transmission system, with associated compressor stations, located in eastern Kentucky. Big Sandy’s interconnection with the Tennessee Gas Pipeline system links the Huron Shale and Appalachian Basin natural gas supplies to the mid-Atlantic and northeast markets.

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Gulfstream
We acquired 24.5% of Gulfstream in 2010 to increase our ownership to 49%. On November 1, 2013, Spectra Energy contributed its remaining 1% ownership in Gulfstream to us in the U.S. Assets Dropdown. Gulfstream owns a 745-mile interstate natural gas transmission system, with associated compressor stations, operated jointly by us and The Williams Companies, Inc. (Williams). Gulfstream transports natural gas from Mississippi, Alabama, Louisiana and Texas, crossing the Gulf of Mexico to markets in central and southern Florida. Gulfstream is owned 50% directly by us and 50% by affiliates of Williams. Our investment in Gulfstream is accounted for under the equity method of accounting.

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SESH
On November 1, 2013, Spectra Energy contributed a portion of its ownership in SESH to us in the U.S. Assets Dropdown. SESH, a 290-mile natural gas transmission system, with associated compressor stations, is operated jointly by Spectra Energy and CenterPoint Southeastern Pipelines Holding, LLC (CenterPoint). SESH extends from the Perryville Hub in northeastern Louisiana where the emerging shale gas production of eastern Texas, northern Louisiana and Arkansas, along with conventional production, is reached from five major interconnections. SESH extends to Alabama, interconnecting with 14 major north-south pipelines and three high-deliverability storage facilities. SESH is owned 24.95% directly by us and 25.05 % directly by Spectra Energy, with the remaining 50% owned by CenterPoint and Enable Midstream Partners, LP, collectively. Current plans are for Spectra Energy to contribute another 24.95% of its ownership interest in SESH to us at least 12 months after the initial November 1, 2013 U.S. Assets Dropdown, and to contribute its remaining 0.1% ownership interest at least 12 months thereafter. Our investment in SESH is accounted for under the equity method of accounting.
Market Hub
On November 1, 2013, Spectra Energy contributed its 50% ownership in Market Hub to us in the U.S. Assets Dropdown. We now own 100% of Market Hub, which owns and operates two natural gas storage facilities, Moss Bluff and Egan, with a total storage capacity of approximately 50 Bcf. The Moss Bluff facility consists of four salt dome storage caverns located in southeast Texas, with access to five pipeline systems including the Texas Eastern system. The Egan facility consists of four salt dome storage caverns located in south central Louisiana, with access to eight pipeline systems, including the Texas Eastern system.
Saltville
In 2008, we acquired Saltville. Saltville owns and operates natural gas storage facilities in Virginia with a total storage capacity of approximately 5 Bcf, interconnecting with East Tennessee’s system. This salt cavern facility offers high-deliverability capabilities and is strategically located near markets in Tennessee, Virginia and North Carolina.  

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Bobcat
On November 1, 2013 Spectra Energy contributed Bobcat to us in the U.S. Assets Dropdown. Bobcat, a 22 Bcf salt dome facility acquired in 2010, is strategically located on the Gulf Coast near Henry Hub, interconnecting with five major interstate pipelines, including Texas Eastern.
Steckman Ridge
On November 1, 2013, Spectra Energy contributed substantially all of its ownership in Steckman Ridge to us in the U.S. Assets Dropdown. Steckman Ridge is a 12 Bcf depleted reservoir storage facility located in south central Pennsylvania that interconnects with the Texas Eastern and Dominion Transmission, Inc. systems. Steckman Ridge, which began operations in 2009, is operated by us and owned 49% by us, 1% by Spectra Energy, and 50% by NJR Steckman Ridge Storage Company. Current plans are for Spectra Energy to contribute its remaining 1% ownership interest to us at least 12 months after the initial November 1, 2013 U.S. Assets Dropdown. Our investment in Steckman Ridge is accounted for under the equity method of accounting.
Competition
Our U.S. Transmission businesses compete with similar facilities that serve our supply and market areas in the transportation and storage of natural gas. The principal elements of competition are location, rates, terms of service, and flexibility and reliability of service.
The natural gas we transport in our transmission business competes with other forms of energy available to our customers and end-users, including electricity, coal, propane and fuel oils. Factors that influence the demand for natural gas include price changes, the availability of natural gas and other forms of energy, levels of business activity, long-term economic conditions, conservation, legislation, governmental regulations, the ability to convert to alternative fuels, weather and other factors.
Customers and Contracts
In general, our U.S. Transmission pipelines provide transportation and storage services for local distribution companies (LDCs, companies that obtain a major portion of their revenues from retail distribution systems for the delivery of natural gas for ultimate consumption), electric power generators, exploration and production companies, and industrial and commercial customers, as well as energy marketers. Transportation and storage services are generally provided under firm agreements where customers reserve capacity in pipelines and storage facilities. The vast majority of these agreements provide for fixed reservation charges that are paid monthly regardless of the actual volumes transported on the pipelines or injected or withdrawn from our storage facilities, plus a small variable component that is based on volumes transported, injected or withdrawn, which is intended to recover variable costs.
We also provide interruptible transportation and storage services where customers can use capacity if it is available at the time of the request. Interruptible revenues depend on the amount of volumes transported or stored and the associated market rates for this interruptible service. New projects placed into service may initially have higher levels of interruptible services at inception. Storage operations also provide a variety of other value-added services including natural gas parking, loaning and balancing services to meet our customers’ needs.  
Liquids
Our Liquids business provides transportation and storage of crude oil and transportation of NGLs for customers in central and southern United States and Canada. Our Liquids pipeline system contains more than 3,200 miles of pipelines with three primary systems: Express-Platte, Sand Hills and Southern Hills.
Most of Liquids’ pipeline and storage operations are regulated by the FERC and the NEB, and are subject to the jurisdiction of various federal, state and local environmental agencies.

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Express-Platte
On August 2, 2013, we acquired 40% of the U.S. portion and 100% of the Canadian portion of Express-Platte from Spectra Energy in the Express-Platte acquisition. On November 1, 2013, we acquired the remaining 60% of the U.S. portion in the U.S. Assets Dropdown. The Express-Platte pipeline system, an approximately 1,700-mile crude oil transportation system, which begins in Hardisty, Alberta, and terminates in Wood River Illinois, is comprised of both the Express and Platte crude oil pipelines. The Express pipeline carries crude oil to U.S. refining markets in the Rockies area, including Montana, Wyoming, Colorado and Utah. The Platte pipeline, which interconnects with the Express pipeline in Casper, Wyoming transports crude oil predominantly from the Bakken shale and western Canada to refineries in the Midwest.

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Sand Hills / Southern Hills
In November 2012, Spectra Energy acquired direct one-third ownership interests in Sand Hills and Southern Hills. On November 1, 2013, Spectra Energy contributed its ownership in Sand Hills and Southern Hills to us in the U.S. Assets Dropdown. DCP Midstream, LLC (DCP Midstream), a 50% owned equity affiliate of Spectra Energy, and Phillips 66 also each own a direct one-third interest in each of the two pipelines. Our investments in Sand Hills and Southern Hills are accounted for under the equity method of accounting.
The Sand Hills pipeline consists of approximately 720 miles of pipeline with an initial capacity of 200,000 barrels of NGLs per day (Bbls/d) that provides NGL transportation from the Permian Basin and Eagle Ford shale region to the premium NGL markets on the Gulf Coast. The Southern Hills pipeline consists of approximately 800 miles of NGL pipeline. The Southern Hills pipeline is connected to several DCP Midstream processing plants and third-party producers and provides NGL transportation from the Mid-Continent to Mont Belvieu, Texas. The Sand Hills and Southern Hills pipelines were placed in service in the second quarter of 2013.
Competition
Our crude oil transportation business competes with pipelines, rail, truck and barge facilities that transport crude oil from production areas to refinery markets. The principal elements of competition are location, rates, terms of service, flexibility and reliability of service.
In transporting NGLs, Sand Hills and Southern Hills compete with a number of major interstate and intrastate pipelines, including those affiliated with major integrated oil companies, and rail and truck fleet operations. In general, Sand Hills and Southern Hills compete with these entities in terms of transportation fees, reliability and quality of customer service.

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Customers and Contracts
Customers on the Express-Platte system are primarily refineries located in the Rocky Mountain and Midwestern states of the United States. Other customers include oil producers and marketing entities. Express capacity is typically contracted under long-term committed contracts where customers reserve capacity and pay commitment charges based on a contracted volume even if they do not ship. A small amount of Express capacity and all Platte capacity is used by uncommitted shippers who only pay for the pipeline capacity that is actually used in a given month.
The Sand Hills and Southern Hills pipelines provide takeaway capacity from DCP Midstream and third-party plants, in the Permian and Eagle Ford basins for Sand Hills, and in the Midcontinent for Southern Hills, to fractionation facilities along the Texas Gulf Coast and the Mont Belvieu market hub. Sand Hills and Southern Hills generate the majority of their revenues from fee-based arrangements. The revenues earned by Sand Hills and Southern Hills are for long-term contracts relating to the transportation of NGLs and generally are not dependent on commodity prices.
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, pumps, 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. The price of equipment and materials may vary however, perhaps substantially, from year to year.
Regulations
Most of our U.S. gas transmission, crude oil transportation pipeline and storage operations are regulated by the FERC. The FERC regulates natural gas transmission and crude oil transportation in U.S. interstate commerce including the establishment of rates for services. The FERC also regulates the construction of U.S. interstate natural gas pipelines and storage facilities, including the extension, enlargement and abandonment of facilities. In addition, certain operations are subject to oversight by state regulatory commissions. To the extent that the natural gas intrastate pipelines that transport or store natural gas in interstate commerce provide services under Section 311 of the Natural Gas Policy Act of 1978, they are subject to FERC regulations. 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 transmission 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.
Express-Platte pipeline system rates and tariffs are subject to regulation by the NEB in Canada and the FERC in the United States. In addition, the Platte pipeline also operates as an intrastate pipeline in Wyoming and is subject to jurisdiction by the Wyoming Public Service Commission.

Express Canada is regulated by the NEB pursuant to a framework for light-handed regulation under which the NEB acts on a complaints-basis for rates associated with that business. The NEB has jurisdiction for regulating rates, the terms and conditions of service, and the construction and abandonment of facilities.
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 in 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-

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service is permitted under the current income tax allowance policy. Some entities 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 various U.S. federal, state and local laws and regulations, as well as Canadian federal and provincial regulations regarding air and water quality, hazardous and solid waste disposal and other environmental matters.
Environmental laws and regulations affecting our U.S. based operations 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 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 primarily because of the presence of liquid hydrocarbons (condensate) in our offshore pipeline.
The Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), which imposes liability for remediation costs associated with environmentally contaminated sites. Under CERCLA, any individual or entity that currently owns or in the past owned or operated a disposal site can be held liable and required to share in remediation costs, as well as transporters or generators of hazardous substances sent to a disposal site. We have disposed of waste at many different sites and therefore have CERCLA liabilities.
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 Toxic Substances Control Act, which requires that polychlorinated biphenyl (PCB) contaminated materials be managed in accordance with a comprehensive regulatory regime. Because of the historical use of lubricating oils containing PCBs, the internal surfaces of some of our pipeline systems are contaminated with PCBs, and liquids and other materials removed from these pipelines must be managed in compliance 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.
Environmental laws and regulations affecting our Canadian-based operations include, but are not limited to:
The Canadian Environmental Protection Act, which, among other things, requires the reporting of greenhouse gas (GHG) emissions from our operations in Canada. Additional regulations to be promulgated under this Act may require the reduction of GHGs, nitrogen oxides, sulphur oxides, volatile organic compounds and particulate matter.
For more information on environmental matters, including possible liability and capital costs, see Part II. Item 8. Financial Statements and Supplementary Data, Notes 5 and 16 of Notes to Consolidated Financial Statements.
Except to the extent discussed in Notes 5 and 16, compliance with international, federal, state, provincial 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.
Geographic Regions
For a discussion of our Canadian operations and the risks associated with them, see Notes 4 and 15 of Notes to Consolidated Financial Statements.

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Employees
We do not have any employees. We are managed by the directors and officers of our general partner. As of December 31, 2013, our general partner and its affiliates have approximately 2,200 employees performing services for our operations, and are solely responsible for providing the employees and other personnel necessary to conduct our operations.
Our Partnership Agreement
Set forth below is a summary of the provisions of our partnership agreement that relate to available cash and operating surplus:
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 or a part of our assets are subject; and
(3) provide funds for minimum quarterly distributions and cumulative common unit arrearages for any one or more of the next four quarters;
provided, however, that our general partner may not establish cash reserves pursuant to clause (b)(3) immediately above unless our general partner has determined that the establishment of reserves will not prevent us from distributing the minimum quarterly distribution on all common units and any cumulative common unit arrearages thereon for that quarter; and provided, further, that disbursements made by us or any of our subsidiaries or cash reserves established, increased or reduced after the end of that quarter but on or before the date of determination of Available Cash for that quarter shall be deemed to have been made, established, increased or reduced, for purposes of determining Available Cash, within that quarter if our general partner so determines.
Operating Surplus. For any period prior to liquidation, on a cumulative basis and without duplication:
(a) the sum of:
(1) all cash receipts of our partnership and our subsidiaries for the period beginning on the closing date of our initial public offering and ending with the last day of the period, other than cash receipts from interim capital transactions; and
(2) an amount equal to the sum of (A) two times the amount needed for any one quarter for us to pay the minimum quarterly distribution on all units (including the general partner units) and (B) two times the amount in excess of the minimum quarterly distribution for any quarter to pay a distribution on all Common Units at the same per unit amount as was distributed on the Common Units in excess of the minimum quarterly distribution in the immediately preceding quarter, provided the amount in (B) will be deemed to be Operating Surplus only to the extent that the distribution paid in respect of such amounts is paid on Common Units, less

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(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 website at http://www.spectraenergypartners.com. Such reports are accessible at no charge through our website 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 material 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 $87 million per quarter, or $348 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 to, and the volumes contracted by customers for natural gas transmission, storage and gathering services and crude oil transportation;
the overall demand for natural gas in the southeastern, mid-Continent, and Northeast regions of the United States, and the quantities of natural gas available for transport, especially from the Gulf of Mexico, Appalachian and mid-Continent areas, as well as the overall demand for crude oil in central and southern United States and Canada;
regulatory action affecting the demand for natural gas and crude oil, the supply of natural gas and crude oil, 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 our equity investments, 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. 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.
Our equity investments generated approximately 37% of the distributable cash flow in 2013. Spectra Energy operates Steckman Ridge. Spectra Energy shares operations of SESH with CenterPoint and shares operations of Gulfstream with Williams.The operations of Sand Hills and Southern Hills are conducted by DCP Midstream. 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 our equity investments 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. The equity affiliates are not prohibited from incurring indebtedness by the terms of their respective limited liability

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company agreement and general partnership agreements. If they 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, oil transportation pipeline systems and certain of our storage facilities and related assets are subject to regulation by the FERC and the NEB, which could have an adverse effect on our ability to establish transmission, 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, oil transportation pipeline systems and certain of our storage facilities and related assets are subject to regulation by the FERC and the NEB. The regulators have authority to regulate natural gas pipeline transmission and oil pipeline transportation services, including; 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 and the NEB 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 transmission, oil 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 transmission 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 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 2013, 46% of U.S. Transmission’s firm revenues were derived from such negotiated rate contracts. These negotiated rate contracts are not subject to adjustment for increased costs which could be produced by inflation or other factors relating to the specific facilities being used to perform the services. It is possible that the costs to perform services under these negotiated rate contracts will exceed the negotiated rates. If this occurs, it could decrease cash flows from U.S. Transmission.
Increased competition from alternative natural gas transmission, 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 transmission, storage and gathering of natural gas. Some of these competitors may expand or construct transmission, 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 transmission, storage and gathering assets are location, 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 transmission, 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 our pipelines and storage facilities 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 transmission, 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.

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The lack of availability of natural gas and oil resources may cause customers to seek alternative energy resources, which could materially affect our revenues, earnings and cash flows.
Our natural gas and oil businesses are dependent on the continued availability of natural gas and oil production and reserves. Prices for natural gas and oil, regulatory limitations on the development of natural gas and oil supplies or a shift in supply sources could adversely affect development of additional reserves and production that are accessible by our pipeline and gathering assets. Lack of commercial quantities of natural gas and oil available to these assets could cause customers to seek alternative energy resources, thereby reducing their reliance on our services, which in turn would materially affect our revenues, earnings and cash flows, including our ability to make distributions.
We may be unable to secure renewals of long-term transportation agreements, which could expose our transportation volumes and revenues to increased volatility.
We may be unable to secure renewals of long-term transportation agreements in the future for our natural gas transmission and crude oil transportation businesses as a result of economic factors, lack of commercial gas supply available to our systems, changing gas supply flow patterns in North America, increased competition or changes in regulation. Without long-term transportation agreements, our revenues and contract volumes would be exposed to increased volatility. The inability to secure these agreements would materially affect our business, earnings, financial condition and cash flows.
If third-party pipelines and other facilities interconnected to our pipelines become unavailable to transport natural gas, our revenues and Available Cash could be adversely affected.
We depend upon third-party pipelines and other facilities that provide delivery options to and from our pipelines and storage facilities. Because we do not own these third-party pipelines or facilities, their continuing operation is not within our control. If these or any other pipeline connection were to become unavailable for current or future volumes of natural gas due to repairs, damage to the facility, lack of capacity or any other reason, our ability to operate efficiently and continue shipping natural gas to end-markets could be restricted, thereby reducing revenues. Any temporary or permanent interruption at any key pipeline interconnect could have an adverse effect on our business, results of operations, financial condition or cash flows, including our ability to make distributions.
If we do not complete expansion projects or make and integrate acquisitions our future growth may be limited.
A principal focus of our strategy is to continue to grow the cash distributions on our units by expanding our business. Our ability to grow depends on our ability to complete expansion projects and make acquisitions that result in an increase in cash generated. We may be unable to complete successful, accretive expansion projects or acquisitions for any of the following reasons:
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.
We rely on access to short-term and long-term capital markets to finance capital requirements and support liquidity needs, and access to those markets can be affected, particularly if we or our rated subsidiaries are unable to maintain an investment-grade credit rating, which could affect our cash flows or restrict business.
Our business is financed to a large degree through debt. The maturity and repayment profile of debt used to finance investments often does not correlate to cash flows from assets. Accordingly, we rely on access to both short-term and long-term capital markets as a source of liquidity for capital requirements not satisfied by cash flows from operations and to fund investments originally financed through debt. Our senior unsecured long-term debt is currently rated investment-grade by various rating agencies. If the rating agencies were to rate us or our rated subsidiaries below investment-grade, our borrowing costs would increase, perhaps significantly. Consequently, we would likely be required to pay a higher interest rate in future financings and our potential pool of investors and funding sources could decrease.
We maintain a revolving credit facility to provide back-up for our commercial paper program, for borrowings and/or letters of credit. This facility requires us to maintain a consolidated leverage ratio of consolidated indebtedness to consolidated earnings from continuing operations before interest, taxes, and depreciation and amortization (EBITDA), as defined in the

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agreement. Failure to maintain this covenant could preclude us from issuing commercial paper or letters of credit or borrowing under the revolving credit facility which could affect cash flows or restrict business. Furthermore, if Spectra Energy Partner’s short-term debt rating were to be below tier 2 (for example, A-2 for Standard and Poor’s, P-2 for Moody’s Investor Service and F2 for Fitch Ratings), access to the commercial paper market could be significantly limited. Although this would not affect our ability to draw under our credit facility, borrowing costs could be significantly higher.
If we are not able to access capital at competitive rates, our ability to finance operations and implement our strategy may be affected. Restrictions on our ability to access financial markets may also affect our ability to execute our business plan as scheduled. An inability to access capital may limit our ability to pursue improvements or acquisitions that we may otherwise rely on for future growth. Any downgrade or other event negatively affecting the credit ratings of our subsidiaries could make their costs of borrowing higher or access to funding sources more limited, which in turn could increase our need to provide liquidity in the form of capital contributions or loans to such subsidiaries, thus reducing the liquidity and borrowing availability of the consolidated group.
The enactment of climate change legislation or the adoption of regulations under the existing Clean Air Act 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 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; however, at the Copenhagen Climate Change Summit in 2009, the U.S. indicated it would reduce carbon dioxide emissions by 17% below 2005 levels by 2020 and United Nations-sponsored international negotiations held in Durban, South Africa in 2011 resulted in a non-binding agreement 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. The Supreme Court decision in Massachusetts v. EPA in 2007 established that GHGs were pollutants subject to regulation under the Clean Air Act. Pursuant to federal regulations, we are currently subject to an obligation to report our GHG emissions at our largest emitting facilities, but are not generally subject to limits on emissions of GHGs, (except to the extent that some GHGs consist of volatile organic compounds and nitrous oxides that are subject to emission limits). 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. Public interest groups are increasingly focusing on the emission of methane associated with natural gas development and transmission as a source of 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 2010, the EPA issued the Prevention of Significant Deterioration (PSD) and Title V Greenhouse Gas Tailoring Rule (Tailoring Rule). Beginning in 2011, the Tailoring Rule required that construction of new or modification of existing major sources of GHG emissions be subject to the PSD air permitting program (and later, the Title V permitting program), although the regulation also significantly increased the emissions thresholds that would subject facilities to these regulations. In 2012, these regulations, along with other GHG regulations and determinations issued by the EPA, were upheld by the D.C. Circuit Court of Appeals. In 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 additional permitting requirements 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 transmission 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;

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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 DOT. 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 were introduced in Congress to 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. In January  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,
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).
Many of these legislative changes, such as increasing penalties, have been completed, while others are substantially in progress with resolution expected by 2015. In particular, PHMSA is designing an Integrity Verification Process intended to create standards to verify maximum allowable operating pressure, and to improve and expand integrity management processes. There remains uncertainty as to how these standards will be implemented, but it is expected that the changes will impose additional costs on new pipeline projects as well as on existing operations. 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.
In Canada, our pipeline operations are subject to pipeline safety regulation overseen by the NEB. Applicable legislation and regulation require us to comply with a significant set of requirements for the design, construction, maintenance and operation of our pipeline. Among other obligations, this regulatory framework imposes requirements to monitor and maintain the integrity of our pipeline.
As in the United States, several legislative changes addressing pipeline safety in Canada have recently come into force. The changes evidence an increased focus on the implementation of management systems to address key areas such as emergency management, integrity management, safety, security and environmental protection. Other legislative changes have created authority for the NEB to impose administrative monetary penalties for non-compliance with the regulatory regime it
administers.
Compliance with these legislative changes may impose additional costs on new Canadian pipeline projects as well as on
existing operations. Failure to comply with applicable regulations could result in a number of consequences which may have a
material effect on our operations, earnings, financial condition and cash flows.

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Restrictions in our credit facility may limit our ability to make distributions and may limit our ability to capitalize on acquisition and other business opportunities.
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;
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.
We are involved in numerous legal proceedings, the outcome of which are uncertain, and resolutions adverse to us could negatively affect our earnings, financial condition and cash flows.
We are subject to numerous legal proceedings. Litigation is subject to many uncertainties, and we cannot predict the outcome of individual matters with assurance. It is reasonably possible that the final resolution of some of the matters in which we are involved could require additional expenditures, in excess of established reserves, over an extended period of time and in a range of amounts that could have a material effect on our earnings and cash flows.
Protecting against potential terrorist activities requires significant capital expenditures and a successful terrorist attack could affect our business.
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,

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we may experience increased capital and operating costs to implement increased security for our facilities and pipelines, such as additional physical facility and pipeline security, and additional security personnel. Moreover, any physical damage to high profile facilities resulting from acts of terrorism may not be covered, or covered fully, by insurance. We may be required to expend material amounts of capital to repair any facilities, the expenditure of which could adversely affect our business and cash flows.
Changes in the insurance markets attributable to terrorist attacks may make certain types of insurance more difficult for us to obtain. Moreover, the insurance that may be available to us may be significantly more expensive than our existing insurance coverage. Instability in the financial markets as a result of terrorism or war could also affect our ability to raise capital.
Reductions in demand for natural gas and oil and low market prices of commodities adversely affect our operations and cash flows.
Our regulated businesses are generally economically stable, not significantly affected in the short term by changing commodity prices. However, our businesses can all be negatively affected in the long term by sustained downturns in the economy or long-term conservation efforts, which could affect long-term demand and market prices for natural gas, oil and NGLs. These factors are beyond our control and could impair the ability to meet long-term goals.
Most of our revenues are based on regulated tariff rates, which include the recovery of certain fuel costs. However, lower overall economic output would reduce the volume of natural gas and NGLs transported or gathered, and the volume of oil transported, resulting in lower earnings and cash flows. Transmission revenues could be affected by long-term economic declines, resulting in the non-renewal of long-term contracts at the time of expiration. Lower demand for natural gas and oil, along with lower prices for natural gas, oil and NGLs, could result from multiple factors that affect the markets where we operate, including:
weather conditions, such as abnormally mild winter or summer weather, resulting in lower energy usage for heating or cooling purposes, respectively;
supply of and demand for energy commodities, including any decrease in the production of natural gas and oil could negatively affect our processing and transmission businesses due to lower throughput;
capacity and transmission service into, or out of, our markets; and
petrochemical demand for NGLs.
Our business is subject to extensive regulation that affects our operations and costs.
Our U.S. assets and operations are subject to regulation by various federal, state and local authorities, including regulation by the FERC and by various authorities under federal, state and local environmental laws. Our operations in Canada are subject to regulation by the NEB, and by federal and provincial authorities under environmental laws. Regulation affects almost every aspect of our business, including, among other things, the ability to determine terms and rates for services provided by some of our businesses, make acquisitions, construct, expand and operate facilities, issue equity or debt securities, and make distributions.
In addition, regulators in the United States have taken actions to strengthen market forces in the gas pipeline industry, which have led to increased competition. In a number of key markets, natural gas pipeline and storage operators are facing competitive pressure from a number of new industry participants, such as alternative suppliers, as well as traditional pipeline competitors. Increased competition driven by regulatory changes could have a material effect on our business, earnings, financial condition and cash flows.
As a result of the acquisition of Express-Platte, we are engaged in crude oil transportation, which is a new line of business for us. We cannot provide assurance that our expansion into this line of business will succeed.
In August 2013, we acquired a 40% ownership interest in Express US and 100% ownership of Express Canada, an approximately 1,700 mile crude oil transportation network that carries crude oil to refineries in the Rocky Mountain and Midwest regions of the U.S. In connection with the U.S. Assets Dropdown, we acquired the remaining 60% ownership interest in Express US. Operation of crude oil pipeline is a new line of business for us, as our operations were previously focused on the transportation, gathering and storage of natural gas. Operating a crude oil pipeline system requires different operating strategies and different managerial expertise than our current operations, and a crude oil pipeline system is subject to additional or different regulations. Failure to timely and successfully develop this new line of business in conjunction with our existing operations may have a material adverse effect on our business, financial condition and results of operations.

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Execution of our capital projects subjects us to construction risks, increases in labor and material costs, and other risks that may affect our financial results.
A significant portion of our growth is accomplished through the construction of new pipelines and storage facilities as well as the expansion of existing facilities. Construction of these facilities is subject to various regulatory, development, operational and market risks, including:
the ability to obtain necessary approvals and permits by regulatory agencies on a timely basis and on acceptable terms and to maintain those approvals and permits issued and satisfy the terms and conditions imposed therein;
the availability of skilled labor, equipment, and materials to complete expansion projects;
potential changes in federal, state and local statutes and regulations, including environmental requirements, that may prevent a project from proceeding or increase the anticipated cost of the project;
impediments on our ability to acquire rights-of-way or land rights on a timely basis and on acceptable terms; and
ability to construct projects within anticipated costs, including the risk of cost overruns resulting from inflation or increased costs of equipment, materials or labor, weather, geologic conditions or other factors beyond our control, that may be material; and.
general economic factors that affect the demand for natural gas infrastructure.
Any of these risks could prevent a project from proceeding, delay its completion or increase its anticipated cost. As a result, new facilities may not achieve their expected investment return, which could affect our earnings, financial position and cash flows.
Market-based storage operations are subject to commodity price risk, which could result in a decrease in our earnings and reduced cash flows.
We have market-based rates for some of our storage operations and sell our storage services based on natural gas market spreads and volatility. If natural gas market spreads or volatility deviate from historical norms or there is significant growth in the amount of storage capacity available to natural gas markets relative to demand, our approach to managing our market-based storage contract portfolio may not protect us from significant variations in storage revenues, including possible declines, as contracts renew.
Our operations are subject to numerous environmental laws and regulations, compliance with which may require significant capital expenditures, increase our cost of operations and affect or limit our business plans, or expose us to environmental liabilities.
Our natural gas transmission, storage and gathering activities are subject to stringent and complex federal, state and local environmental laws and regulations, including air emissions, water quality, wastewater discharges, solid waste and hazardous waste. These laws and regulations can result in increased capital, operating and other costs. These laws and regulations generally require us to obtain and comply with a wide variety of environmental licenses, permits, inspections and other approvals. Compliance with environmental laws and regulations can require significant expenditures, including expenditures for cleanup costs and damages arising out of contaminated properties. We currently estimate that compliance with major Clean Air Act regulatory programs will cause us to incur capital expenditures of approximately $450 million through 2020 to obtain permits, evaluate offsite impacts of our operations, install pollution control equipment, and otherwise assure compliance.
The precise nature of these compliance obligations at each of our facilities has not been finally determined and may depend in part on future regulatory changes. In addition, compliance with new and emerging environmental regulatory programs is likely to significantly increase our operating costs compared to historical levels. Failure to comply with environmental regulations may result in the imposition of fines, penalties and injunctive measures affecting our operating assets. In addition, changes in environmental laws and regulations or the enactment of new environmental laws or regulations could result in a material increase in our cost of compliance with such laws and regulations. We may not be able to obtain or maintain from time to time all required environmental regulatory approvals for our operating assets or development projects. If there is a delay in obtaining any required environmental regulatory approvals, if we fail to obtain or comply with them or if environmental laws or regulations change or are administered in a more stringent manner, the operations of facilities or the development of new facilities could be prevented, delayed or become subject to additional costs. No assurance can be made that the costs that may be incurred to comply with environmental regulations in the future will not have a material effect on our earnings and cash flows.

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Natural gas transmission and storage, NGL transmission, and crude oil transportation and storage 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 gathering and processing, transmission and storage activities, and crude oil transportation and storage, such as leaks, explosions, mechanical problems, activities of third parties and damage to pipelines, facilities and equipment caused by hurricanes, tornadoes, floods, fires and other 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, industrial sites and other public gathering areas, the level of damage resulting from these risks could be greater. 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. Therefore, should any of these risks materialize, it could have a material effect on our business, earnings, financial condition and cash flows.
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. 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.
We are exposed to the credit risk of our customers.
We are exposed to the credit risk of our customers in the ordinary course of our business. Generally, our customers are rated investment-grade, are otherwise considered creditworthy or provide us security to satisfy credit concerns. Approximately 90% of our credit exposures for transmission, storage and gathering services are with customers who have an investment-grade rating (or the equivalent based on our evaluation) or are secured by collateral. However, we cannot predict to what extent our business would be impacted by deteriorating conditions in the economy, including possible declines in our customers’ creditworthiness. As a result of future capital projects for which natural gas producers may be the primary customer, the percentage of our customers who are rated investment-grade may decline. While we monitor these situations carefully and take appropriate measures when deemed necessary, it is possible that customer payment defaults, if significant, could have a material effect on our earnings and cash flows.
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;

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our general partner has limited its liability and reduced its fiduciary duties, and has also restricted the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty. By purchasing common units, unitholders will be deemed to have consented to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable law;
our general partner determines the amount and timing of asset purchases and sales, borrowings, issuances of additional partnership securities and reserves, each of which can affect the amount of cash that is distributed to unitholders;
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;
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 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 transmission, 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 may 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 distributable cash flow.
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 distributable cash flow. In addition, under

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Delaware partnership law, our general partner has unlimited liability for our obligations, such as our debts and environmental liabilities, except for contractual obligations that are expressly made without recourse to our general partner. To the extent our general partner incurs obligations on our behalf, we are obligated to reimburse or indemnify it. If we are unable or unwilling to reimburse or indemnify our general partner, our general partner may take actions to cause us to make payments of these obligations and liabilities. Any such payments could reduce the amount of our cash otherwise available for distribution.
Our partnership agreement limits our general partner’s fiduciary duties to holders of our common units, and restricts the remedies available to holders of our common units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
Our partnership agreement contains provisions that reduce the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty laws. For example, our partnership agreement:
permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting us, our affiliates or any limited partner;
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 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

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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, 2014, our general partner and its affiliates own 84% of our aggregate outstanding common units.
Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.
Our partnership agreement restricts unitholders’ voting rights by providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.
If we are deemed an “investment company” under the Investment Company Act of 1940, it would adversely affect the price of our common units and could have an adverse effect on our business.
Our assets include 100% ownership interests in various pipelines, as well as 50%, 24.95%, 49%, 33% and 33% equity interests in Gulfstream, SESH, Steckman Ridge, Sand Hills and Southern Hills, respectively. If a sufficient amount of our assets that are comprised of equity investments, 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 49% general partner interest in Steckman Ridge could be deemed to be an investment security. In that event, it is possible that our ownership of this interest, combined with all of our current equity investments 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

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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 distributable cash flow 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.
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, 2014, Spectra Energy and its affiliates hold an aggregate of 237,416,307 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, 2014, our general partner and its affiliates own approximately 84% 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.

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Unitholders may have liability to repay distributions that were wrongfully distributed to them.
Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to the unitholder if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable for the obligations of the assignor to make contributions to the partnership that are known to the substituted limited partner at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the partnership agreement.
Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.
Tax Risks to Common Unitholders
Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service (IRS) treats us as a corporation or we become subject to a material amount of entity-level taxation for state tax purposes, it would substantially reduce the amount of distributable cash flow.
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 distributable cash flow 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.
If the tax authorities contest the federal income tax positions we take, it may adversely affect the market for our common units, and the cost of any tax authority contest would reduce our distributable cash flow.
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 our conclusions. 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 distributable cash flow.
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.

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Tax gain or loss on disposition of our common units could be more or less than expected.
If the common unitholder sells its common units, the unitholder will recognize a gain or loss equal to the difference between the amount realized and the common unitholder’s tax basis in those common units. Because distributions in excess of the common unitholder’s allocable share of our net taxable income decrease the common unitholder’s tax basis in the common units, the amount, if any, of such prior excess distributions with respect to the units the unitholder sells will, in effect, become taxable income to the unitholder if the unitholder sells such units at a price greater than the tax basis, even if the price the unitholder receives is less than the original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes the share of our nonrecourse liabilities, if the common unitholder sells the units, the common unitholder may incur a tax liability in excess of the amount of cash the unitholder receives from the sale.
Tax-exempt entities and foreign persons face unique tax issues from owning common units that may result in adverse tax consequences to them.
Investment in common units by tax-exempt entities, such as individual retirement accounts (IRAs), other retirement plans and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file United States federal tax returns and pay tax on their share of our taxable income. If the unitholder is a tax-exempt entity or a foreign person, the unitholder should consult a tax advisor before investing in our common units.
We treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.
Because we cannot match transferors and transferees of common units and because of other reasons, we have adopted depreciation and amortization positions that may not conform to all aspects of existing U.S. Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to the common unitholder. It also could affect the timing of these tax benefits or the amount of gain from the sale of our common units and could have a negative effect on the value of our common units or result in audit adjustments to the tax returns.
We have adopted certain valuation methodologies that may result in a shift of income, gain, loss and deduction between the general partner and the unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.
When we issue additional units or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of the unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the general partner, which may be unfavorable to such unitholders. Moreover, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to tangible and intangible assets, and allocations of income, gain, loss and deduction between the general partner and certain of the unitholders.
A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to the unitholders. It also could affect the amount of gain from the unitholders’ sale of common units and could have a negative effect on the value of the common units or result in audit adjustments to unitholders’ tax returns without the benefit of additional deductions.
The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of the partnership for federal income tax purposes.
We will be considered to have terminated the partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. Our termination would, among other things, result in the closing of the taxable year for all unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income.

35


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.

36


Item 1B. Unresolved Staff Comments.
None.
Item 2. Properties.

At December 31, 2013, we had over 100 primary facilities located in the United States and Canada. We generally own sites associated with our major pipeline facilities, such as compressor stations. However, we generally operate our transmission pipelines using rights of way pursuant to easements to install and operate pipelines, but we do not own the land. None of our properties were secured by mortgages or other material security interests at December 31, 2013.
Our principal executive offices are located at 5400 Westheimer Court, Houston, Texas 77056, which is a facility leased by Spectra Energy. We also maintain offices in, among other places, Calgary, Alberta; Waltham, Massachusetts; Tampa, Florida; and Nashville, Tennessee. For a description of material properties, see Item 1. Business.
Item 3. Legal Proceedings.
We have no material pending legal proceedings that are required to be disclosed hereunder. See Note 16 of Notes to Consolidated Financial Statements for discussions of other legal proceedings.
Item 4. Mine Safety Disclosures.
Not applicable.

37


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 (a)
 
per Common Unit
 
High
 
Low
2013
 
 
 
 
 
First Quarter
$
0.495

 
$
40.08

 
$
31.59

Second Quarter
0.50125

 
47.23

 
34.42

Third Quarter
0.50875

 
47.73

 
40.00

Fourth Quarter
0.51625

 
46.75

 
41.02

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

__________
(a) Unit prices represent the intra-day high and low price.
As of January 31, 2014, there were approximately 36 holders of record of our common units. A cash distribution to unitholders of $0.54625 per limited partner unit was declared on February 4, 2014 and was paid on February 28, 2014, which is a $0.03 per limited partner unit increase over the cash distribution of $0.51625 per limited partner unit paid on November 14, 2013.

38


Unit Performance Graph
The following graph reflects the comparative changes in the value from January 1, 2009 through December 31, 2013 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.
 
 
January 1,
2009
 
December 31,
2009
 
2010
 
2011
 
2012
 
2013
Spectra Energy Partners
 
$
100.00

 
$
159.73

 
$
186.93

 
$
192.71

 
$
200.12

 
$
305.91

S&P 500
 
100.00

 
126.46

 
145.51

 
148.59

 
172.37

 
228.19

Alerian MLP Index
 
100.00

 
176.41

 
239.66

 
272.92

 
286.01

 
364.90

Distributions of Available Cash
General. Our partnership agreement requires that, within 60 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 February 4, 2014 is $0.54625 per limited partner unit, or $2.185 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 5,800,483 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. Our general partner contributed $159 million in 2013, $4 million in 2012 and $5 million in 2011 to maintain its 2% interest.
Our 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%. The maximum incentive distribution right of 50% was achieved in 2013, 2012 and 2011. The maximum distribution of 50% includes distributions paid to our general partner on its 2% general partner interest and assumes that our general partner maintains its

39


general partner interest at 2%. The maximum distribution of 50% does not include any distributions that our 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.
As the Express-Platte acquisition and the U.S. Assets Dropdown represented transfers of entities under common control, the Consolidated Financial Statements and related information presented herein have been recast to include the historical results of Express-Platte since March 14, 2013, the date of Spectra Energy's acquisition of Express-Platte, and the U.S. Assets Dropdown for all periods presented. See Note 2 of Notes to Consolidated Financial Statements for further discussion of the transactions. 
 
2013
 
2012
 
2011
 
2010
 
2009
 
(Unaudited)
 
(in millions, except per-unit amounts)
Statements of Operations
 
 
 
 
 
 
 
 
 
Operating revenues
$
1,965

 
$
1,754

 
$
1,746

 
$
1,678

 
$
1,554

Operating income
973

 
897

 
880

 
834

 
806

Net income—noncontrolling interests
16

 
15

 
15

 
15

 
18

Net income—controlling interests (a)
1,070

 
580

 
570

 
507

 
459

Limited Partner Unit Data
 
 
 
 
 
 
 
 
 
Net income per limited partner unit—basic and diluted (b)
$
7.15

 
$
5.60

 
$
5.82

 
$
6.04

 
$
5.85

Distributions paid per limited partner unit
2.02125

 
1.93

 
1.845

 
1.70

 
1.51

_________
(a)
Includes a $354 million benefit related to the elimination of accumulated deferred income tax liabilities in 2013. See Note 6 of Notes to Consolidated Financial Statements for further discussion.
(b)
Weighted average limited partners units outstanding used in the calculation of net income per limited partner unit for periods prior to the November 1, 2013 U.S. Assets Dropdown has not been recast. See Note 7 of Notes to Consolidated Financial Statements for further discussion.
 
December 31,
 
2013
 
2012
 
2011
 
2010
 
2009
 
(Unaudited)
(in millions)
Balance Sheets
 
 
 
 
 
 
 
 
 
Total assets
$
16,794

 
$
13,885

 
$
12,445

 
$
11,837

 
$
10,538

Long-term debt including capital leases, less current maturities
5,178

 
3,105

 
2,073

 
2,569

 
2,026

Notes payable—affiliates

 
4,185

 
3,911

 
3,720

 
3,781


40


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.
As the Express-Platte acquisition and the U.S. Assets Dropdown represented transfers of entities under common control, the Consolidated Financial Statements and related information presented herein have been recast to present results as if the related assets had been owned historically. As a result of these transactions, we realigned our reportable segments structure. Amounts presented herein for segment information have been recast for all periods presented to conform to our current segment reporting presentation. See Note 2 of Notes to Consolidated Financial Statements for further discussion of the transactions.
EXECUTIVE OVERVIEW
During 2013, we successfully advanced one of our primary business strategies of actively engaging in the marketplace for strategic acquisitions of assets that enhance our portfolio. We accomplished this by completing two significant dropdowns of assets from Spectra Energy during 2013. On August 2, 2013, we acquired a 40% ownership interest in the Express US and a 100% ownership interest in Express Canada from Spectra Energy. On November 1, 2013, we completed the closing of the first transaction of the U.S. Assets Dropdown from Spectra Energy, which consisted of substantially all of Spectra Energy’s remaining interests in its subsidiaries that own U.S. transmission and storage and liquids assets, including its remaining 60% interest in Express US. These dropdowns significantly increase our size, geographic footprint and asset mix. See Note 2 of Notes to Consolidated Financial Statements for further discussion of the dropdowns.
We reported net income from controlling interests of $1,070 million in 2013 compared with $580 million in 2012 and $570 million in 2011. Earnings increased mainly due to the elimination of deferred income tax liabilities related to the U.S. Assets Dropdown, which resulted in a tax benefit in 2013. Distributable cash flow was $315 million in 2013 compared with $229 million in 2012 and $212 million in 2011.
We increased our quarterly cash distribution each quarter in 2013, from $0.495 per limited partner unit for the fourth quarter of 2012 which was paid in February 2013, to $0.54625 per unit for the fourth quarter of 2013 which was paid on February 28, 2014. With the closing of the U.S. Assets Dropdown, we increased our quarterly distribution paid by three cents per unit in the first quarter of 2014, and intend to increase our quarterly distribution by at least one cent per unit each quarter through 2015. The declaration and payment of distributions is subject to the sole discretion of our Board of Directors and depends upon many factors, including the financial condition, earnings and capital requirements of our operating subsidiaries, covenants associated with certain debt obligations, legal requirements, regulatory constraints, our partnership agreement and other factors deemed relevant by our Board of Directors.
We will rely upon cash flows from operations, including cash distributions received from our equity investments, and various financing transactions, which may include issuances of short-term and long-term debt, to fund our liquidity and capital requirements for 2014. 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 unit issuances. 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.
Our Strategy. Our strategy is to create superior and sustainable value for our investors, customers, employees and communities by delivering natural gas, liquids, and crude oil infrastructure to premium markets.  We will grow our business through organic growth, greenfield expansions, and strategic acquisitions with a focus on safety, reliability and customer responsiveness and profitability.  We intend to accomplish this by:
Building off the strength of our asset base
Maximizing that base through sector leading operations and service
Effectively executing the projects we have secured
Securing new growth opportunities that add value for our investors within each of our business segments
Expanding our value chain participation into complementary infrastructure assets

41


Natural gas supply dynamics continue to rapidly change and strengthen, and there is growing long-term potential for natural gas to be an effective solution for meeting the energy needs of North America.  This causes us to be optimistic about future growth opportunities.  Identified opportunities include natural gas-fired generation, growth in industrial markets, LNG exports from North America, and significant new liquids pipeline infrastructure.  With our advantage of providing access from strong supply regions to growing natural gas, NGL and crude oil markets, we expect to continue expanding our assets and operations to meet these needs.
Crude oil supply dynamics also continue to evolve as North American production increases.  Growing North American crude oil production is displacing imports from overseas and driving increased demand for crude oil transportation and logistics.  As such, we remain confident about our ability to grow our crude oil pipeline segment and capture future opportunities.
Successful execution of our strategy will be determined by such key factors as the continued production and the consumption of natural gas, NGLs and crude oil within the U.S., our ability to provide creative solutions for customers energy needs as they evolve, and continued cost control and successful execution on capital projects.
We continue to be actively engaged in the national discussions in the U.S. regarding energy policy and have taken a lead role in shaping policy as it relates to pipeline safety.
Significant Economic Factors for Our Business. Our regulated businesses are generally economically stable and are not significantly affected in the short-term by changing commodity prices. However, all of our businesses can be negatively affected in the long term by sustained downturns in the economy or prolonged decreases in the demand for crude oil, natural gas and/or NGLs, all of which are beyond our control and could impair our ability to meet long-term goals.
Most of our revenues are based on regulated tariff rates, which include the recovery of certain fuel costs. Lower overall economic output would cause a decline in the volume of natural gas gathered and processed at our plants, resulting in lower earnings and cash flows. This decline would mostly affect gathering revenues, potentially in the short term. Transmission revenues could be affected by long-term economic declines that result in the non-renewal of long-term contracts at the time of expiration. Pipeline transportation and storage customers continue to renew most contracts as they expire.
Our combined key natural gas markets—the northeastern and the southeastern United States—are projected to continue to exhibit higher than average annual growth in natural gas demand versus the North American and continental United States average growth rates through 2019. This demand growth is primarily driven by the natural gas-fired electric generation sector. The natural gas industry is currently experiencing a significant shift in the sources of supply, and this dramatic change is affecting our growth strategies. Traditionally, supply to our markets has come from the Gulf Coast region, both onshore and offshore. The national supply profile is shifting to new sources of gas from natural gas shale basins in the Rockies, Mid-Continent, Appalachia, Texas and Louisiana. These supply shifts are shaping the growth strategies that we will pursue, and therefore, will affect the nature of the projects anticipated in the capital and investment expenditure increases discussed below in “Liquidity and Capital Resources.” Recent community and political pressures have arisen around the production processes associated with extracting natural gas from the natural gas shale basins. Although we continue to believe that natural gas will remain a viable energy solution for the U.S., these pressures could increase costs and/or cause a slowdown in the production of natural gas from these basins, and therefore, could negatively affect our growth plans.
Our key crude oil markets include the Rocky Mountain and Midwest states with growing connectivity to the Gulf Coast and west coast of the United States. Growth in our business is dependent on growing crude oil supply from North American sources and the ability of that supply to displace imported crude oil from overseas. Any changes in market dynamics that adversely affect the availability and cost-competitiveness of North American crude oil supply would have a negative effect on our current business and associated growth opportunities.
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.
The increase in natural gas supply has resulted in declines in the price of natural gas in North America. As a result, there has been a shift to extracting gas in richer, "wet" gas areas, like the Marcellus shale. This has depressed activity in "dry" fields like the Fayetteville shale where our Ozark gathering and transmission assets are located. As the balance of supply and demand evolves, we expect activity in these areas to push prices higher. However, should the activity in the region continue to decline, our businesses there may be subject to possible impairment. The supply increase has also had a negative impact on the seasonal price spreads historically seen between the summer and winter months. As a result, the value of storage assets and contracts has declined in recent years, negatively affecting the results of our storage facilities. Should these market factors continue to keep

42


downward pressure on the seasonality spread and re-contracting, we could be subject to further reduced value and possible impairment of our storage assets.
Our businesses in the United States and Canada are subject to regulations on the federal, state and provincial levels. Regulations applicable to the natural gas transmission, crude oil transportation and storage industries have a significant effect on the nature of the businesses and the manner in which they operate. Changes to regulations are ongoing and we cannot predict the future course of changes in the regulatory environment or the ultimate effect that any future changes will have on our businesses. Additionally, investments and projects located in Canada expose us to risks related to Canadian laws, taxes, economic conditions, fluctuations in currency rates, political conditions and policies of the Canadian government. During the past several years, the Canadian dollar has fluctuated compared to the U.S. dollar, which affected earnings to varying degrees for brief periods. Changes in the exchange rate or any other factors are difficult to predict and may affect our future results.
Our strategic objectives include a critical focus on capital expansion projects that will require access to capital markets. An inability to access capital at competitive rates could affect our ability to implement our strategy. Market disruptions or a downgrade in our credit ratings may increase the cost of borrowings or affect our ability to access one or more sources of liquidity.
During the past few years, capital expansion projects have been exposed to cost pressures associated with the availability of skilled labor, the pricing of materials and challenges associated with ensuring the protection of our environment and continual safety enhancements to our facilities. We maintain a strong focus on project management activities to address these pressures as we move forward with planned expansion opportunities. Significant cost increases could negatively affect the returns ultimately earned on current and future expansions.
For further information related to management’s assessment of our risk factors, see Part I. Item 1A. Risk Factors.
RESULTS OF OPERATIONS
 
 
2013
 
2012
 
2011
 
(in millions)
Operating revenues
$
1,965

 
$
1,754

 
$
1,746

Operating expenses
992

 
858

 
872

Gains on sales of other assets and other, net

 
1

 
6

Operating income
973

 
897

 
880

Equity in earnings of unconsolidated affiliates
89

 
86

 
86

Other income and expenses, net
58

 
28

 
27

Interest income
1

 
1

 
1

Interest expense
383

 
407

 
408

Earnings before income taxes
738

 
605

 
586

Income tax expense (benefit)
(348
)
 
10

 
1

Net income
1,086

 
595

 
585

Net income—noncontrolling interests
16

 
15

 
15

Net income—controlling interests
$
1,070

 
$
580

 
$
570

 
 
 
 
 
 
2013 Compared to 2012
Operating Revenues. The $211 million increase was mainly driven by:
revenues from Express-Platte acquired in March 2013, and
higher revenues from expansion projects primarily at Texas Eastern, partially offset by
lower recoveries of electric power and other costs passed through to customers,
lower storage revenues, and
lower processing revenues associated with pipeline operations.

43


Operating Expenses. The $134 million increase was driven by:
operating costs from Express-Platte,
expansion projects primarily at Texas Eastern,
higher governance cost,
higher depreciation due to the acquisition of Express-Platte and expansion projects,
higher employee benefit costs, ad valorem taxes, net of lower software amortization, and
transaction costs related to the U.S. Assets Dropdown, partially offset by
lower electric power and other costs passed through to customers.
Other Income and Expenses, Net. The $30 million increase was primarily due to higher allowance for funds used during construction (AFUDC) resulting from increased capital spending on expansion projects.
Income Tax Expense (Benefit). Deferred income tax liabilities were eliminated and recorded as a benefit to Income Tax Expense (Benefit) in connection with the U.S. Assets Dropdown and resulting changes in tax status of certain entities.
2012 Compared to 2011
Operating Revenues. The $8 million increase was driven by:
revenues from Big Sandy acquired in July 2011,
higher revenues from expansion projects, and
higher recoveries of electric power and other costs passed through to customers, partially offset by
lower storage revenues,
contract reductions at Ozark Gas Transmission and Texas Eastern, and
lower processing revenues associated with pipeline operations caused by lower prices.
Operating Expenses. The $14 million decrease was driven by:
lower equipment repairs and maintenance expenses, pipeline integrity costs, employee benefits and other costs, and
lower project development costs, partially offset by
higher depreciation from expansion projects and the acquisition of Big Sandy in July 2011 and
higher electric power and other costs passed through to customers.
Other Income and Expenses, Net. The $1 million increase was primarily due to higher AFUDC resulting from increased capital spending on expansion projects.
For a more detailed discussion of earnings drivers, see the segment discussions that follow.
Segment Results
Management evaluates segment performance based on consolidated EBITDA. Cash, cash equivalents and investments are managed centrally, so the gains and losses on foreign currency remeasurement, and interest and dividend income, are excluded from the segments’ EBITDA. We consider segment EBITDA to be a good indicator of each segment’s operating performance from its continuing operations, as it represents the results of our operations without regard to financing methods or capital structures. Our segment EBITDA may not be comparable to similarly titled measures of other companies because other companies may not calculate EBITDA in the same manner.
Our U.S. Transmission business primarily provides transmission and storage of natural gas for customers in various regions of the northeastern and southeastern United States. Our Liquids business primarily provides transportation of oil and NGLs for customers in central and southern United States and Canada.

44


Segment EBITDA is summarized in the following table. Detailed discussions follow.
EBITDA by Business Segment
 
2013
 
2012
 
2011
 
(in millions)
U.S. Transmission
$
1,279

 
$
1,251

 
$
1,223

Liquids
132

 

 

Total reportable segment EBITDA
1,411

 
1,251

 
1,223

Other
(27
)
 
(9
)
 
(9
)
Total reportable segment and other EBITDA
1,384

 
1,242

 
1,214

Depreciation and amortization
262

 
231

 
221

Interest expense
383

 
407

 
408

Interest income and other
(1
)
 
1

 
1

Earnings from continuing operations before income taxes
$
738

 
$
605

 
$
586

The amounts discussed below are after eliminating intercompany transactions.
U.S. Transmission
 
2013
 
2012
 
Increase (Decrease)
 
2011
 
Increase (Decrease)
 
(in millions)
Operating revenues
$
1,727

 
$
1,754

 
$
(27
)
 
$
1,746

 
$
8

Operating expenses
 
 
 
 
 
 
 
 
 
Operating, maintenance and other
594

 
618

 
(24
)
 
642

 
(24
)
Other income and expenses
146

 
114

 
32

 
113

 
1

Gains on sales of other assets and other, net

 
1

 
(1
)
 
6

 
(5
)
EBITDA
$
1,279

 
$
1,251

 
$
28

 
$
1,223

 
$
28

 
 
 
 
 
 
 
 
 
 
2013 Compared to 2012
Operating Revenues. The $27 million decrease was driven by:
a $42 million decrease in recoveries of electric power and other costs passed through to customers,
a $24 million decrease due to lower storage revenues as a result of lower contract renewal rates, and
an $8 million decrease from lower processing revenues associated with pipeline operations, partially offset by
a $48 million increase from expansion projects primarily at Texas Eastern.
Operating Expenses. The $24 million decrease was driven by:
a $42 million decrease in electric power and other costs passed through to customers, partially offset by
a $6 million increase from expansion projects primarily at Texas Eastern, and
a $10 million increase due to higher employee benefit costs and ad valorem taxes, net of lower software amortization.
Other Income and Expenses. The $32 million increase was primarily due to higher AFUDC resulting from increased capital spending on expansion projects.
EBITDA. The $28 million increase was driven by higher earnings from the expansions at Texas Eastern partially offset by lower storage revenues, higher operating costs, and lower processing revenues.

45


2012 Compared to 2011
Operating Revenues. The $8 million increase was driven by:
a $51 million increase from expansion projects and the acquisition of Big Sandy in July 2011, and
a $12 million increase in recoveries of electric power and other costs passed through to customers, partially offset by
a $29 million decrease from lower storage revenues and contract reductions at Texas Eastern and Ozark Gas Transmission, and
a $24 million decrease in processing revenues associated with pipeline operations caused by lower prices.
Operating Expenses. The $24 million decrease was driven by:
a $32 million decrease due to lower equipment repair and maintenance expenses, pipeline integrity costs, employee benefits and other costs, net of accelerated software amortization, and
a $6 million decrease from project development costs expensed in 2011, partially offset by
a $12 million increase in electric power and other costs passed through to customers.
Gains on Sales of Other Assets and Other, net.  The $5 million decrease was driven by 2011 customer settlements.
EBITDA. The $28 million increase was driven by increased earnings from expansions and lower operating costs, partially offset by expected lower storage revenues, contract reductions at Texas Eastern and Ozark Gas Transmission and lower processing revenues associated with pipeline operations.
Matters Affecting Future U.S. Transmission Results
We plan to continue earnings growth through capital efficient projects, such as transportation and storage expansion to support a two-pronged “supply push” / “market pull” strategy, as well as continued focus on optimizing the performance of the existing operations through organizational efficiencies and cost control. “Supply push” is when producers agree to pay to transport specified volumes of natural gas in order to support the construction of new pipelines or the expansion of existing pipelines. “Market pull” is taking gas away from established liquid supply points and building pipeline transportation capacity to satisfy end-user demand in new markets or demand growth in existing markets.
Future earnings growth will be dependent on the success of our expansion plans in both the market and supply areas of the pipeline network, which includes, among other things, shale gas exploration and development areas, the ability to continue renewing service contracts and continued regulatory stability. Natural gas storage prices have recently been challenged as a
result of increasing natural gas supply and narrower seasonal price spreads. As a result, the value of storage assets and contracts has declined in recent years, negatively affecting the results of our storage facilities. Should these market factors continue to keep downward pressure on the seasonality spread and re-contracting, we could be subject to further reduced value and possible impairment for our storage assets.
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.
In January 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 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).
In 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,

46


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 effects these changes will have on our operations, earnings, financial condition and cash flows at this time.
Liquids
 
2013
 
2012
 
Increase (Decrease)
 
2011
 
Increase (Decrease)
 
(in millions)
Operating revenues
$
238

 
$

 
$
238

 
$

 
$

Operating expenses
 
 
 
 
 
 
 
 
 
Operating, maintenance and other
109

 

 
109

 

 

Other income and expenses
3

 

 
3

 

 

EBITDA
$
132

 
$

 
$
132

 
$

 
$

 
 
 
 
 
 
 
 
 
 
Express pipeline receipts, MBbl/d (a,b)
207

 

 
207

 

 

Platte PADD II deliveries, MBbl/d (b)
168

 

 
168

 

 

_________
(a)    Thousand barrels per day.
(b)    Data includes activity since March 14, 2013, the date of the acquisition of Express-Platte by Spectra Energy.
Our Liquids segment is comprised of Express-Platte and our investments in Sand Hills and Southern Hills. Results of Express-Platte represent results since March 14, 2013, the date of Spectra Energy's acquisition. Results of Sand Hills and Southern Hills represent results since November 15, 2012, the date of Spectra Energy’s acquisition of both entities.
2013 Compared to 2012
Operating Revenues. The $238 million increase was attributable to Express-Platte.
Operating Expenses. The $109 million increase was attributable to Express-Platte.
Other Income and Expenses. The $3 million increase was attributable to our equity earnings in Sand Hills and Southern Hills.
EBITDA. The $132 million increase was primarily driven by the earnings from Express-Platte.
Matters Affecting Future Liquids Results
We plan to continue earnings growth by maximizing throughput on all sections of the pipeline systems. On the Express-Platte system, this entails connecting where possible to rail or barge terminals to extend the market reach of the pipeline to refinery-customers beyond the end of the pipeline. This also includes optimizing pipeline and storage operations and expanding terminal operations where appropriate. On the Southern Hills and Sand Hills NGL pipelines, volumes will continue to increase as NGL supply increases behind the system and new extraction plants are connected to the pipeline.  Extensions may be added to the lines and pumps may be added to increase capacity.   
Future earnings growth will be dependent on the success in renewing existing contracts or in securing new supply and market for all pipelines. This will require ongoing increases in supply of both crude oil and NGL and continued access to attractive markets. For the NGL pipelines, continued growth is dependent on successful execution of expansion projects to attach new supply.
See Matters Affecting Future U.S. Transmission Results for discussions of the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 and PHMSA, which are also applicable to the Liquids segment.

47


Other
 
2013
 
2012
 
Increase (Decrease)
 
2011
 
Increase (Decrease)
 
(in millions)
Operating expenses
$
27

 
$
9

 
$
18

 
$
9

 
$

EBITDA
$
(27
)
 
$
(9
)
 
$
(18
)
 
$
(9
)
 
$

2013 Compared to 2012
Operating Expenses. The $18 million increase was driven by higher governance costs and transaction costs related to the U.S. Assets Dropdown, which was effective on November 1, 2013.
Distributable Cash Flow
We define Distributable Cash Flow as EBITDA plus
net cash from equity investments, less
interest expense,
equity AFUDC,
distributions to noncontrolling interests, and
maintenance capital expenditures, excluding the effect of reimbursable projects.
Distributable Cash Flow does not reflect changes in working capital balances. Distributable Cash Flow should not be viewed as indicative of the actual amount of cash that we plan to distribute for a given period.
Distributable Cash Flow is the primary financial measure used by our management and by external users of our financial statements to assess the amount of cash that is available for distribution. The effects of the U.S. Assets Dropdown and the Express-Platte acquisition have been excluded from the Distributable Cash Flow calculation for periods prior to the dropdown transactions in order to reflect the true amount of the cash that was available for distribution.
Distributable Cash Flow 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 generally accepted accounting principles (GAAP) in the United States. Distributable Cash Flow excludes some, but not all, items that affect Net Income and Operating Income and these measures may vary among other companies. Therefore, Distributable Cash Flow as presented may not be comparable to similarly titled measures of other companies.
Significant drivers of variances in Distributable Cash Flow 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.

48


Reconciliation of Net Income to Non-GAAP “Distributable Cash Flow”
 
2013
 
2012
 
2011
 
(in millions)
Net Income
$
1,086

 
$
595

 
$
585

Add:
 
 
 
 
 
Interest expense
383

 
407

 
408

Income tax expense (benefit) (a)
(348
)
 
10

 
1

Depreciation and amortization
262

 
231

 
221

Foreign currency loss
2

 

 

Less:
 
 
 
 
 
Interest income
1

 
1

 
1

EBITDA
1,384

 
1,242

 
1,214

Add:
 
 
 
 
 
Net cash from equity investments
28

 
19

 
21

Less:
 
 
 
 
 
Interest expense
383

 
407

 
408

Distributions to noncontrolling interests
19

 
18

 
18

Maintenance capital expenditures
228

 
241

 
258

Equity AFUDC
58

 
27

 
17

Adjustment (b)
409

 
339

 
322

Distributable Cash Flow
$
315

 
$
229

 
$
212

________
(a)
Tax benefit in 2013 is due to the elimination of deferred income tax liabilities related to the U.S. Assets Dropdown.
(b)
Removes the results of the U.S. Assets Dropdown for the periods prior to the dropdown (January 1, 2011 to October 31, 2013) and the results of Express-Platte for the periods prior to the dropdown (March 14, 2013 to August 1, 2013).
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 certain of our operations under accounting for regulated entities. 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, regulatory 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 $254 million as of December 31, 2013 and $212 million as of December 31, 2012. Total regulatory liabilities were $66 million as of December 31, 2013 and $62 million as of December 31, 2012.

49


Impairment of Goodwill
We had goodwill balances of $3.2 billion at December 31, 2013 and $2.8 billion at December 31, 2012. The increase in goodwill in 2013 was primarily the result of the Express-Platte acquisition.
As permitted under the accounting guidance on testing goodwill for impairment, we perform either a qualitative assessment or a quantitative assessment of each of our reporting units based on management’s judgment. With respect to our qualitative assessments, we consider events and circumstances specific to us, such as macroeconomic conditions, industry and market considerations, cost factors and overall financial performance, when evaluating whether it is more likely than not that the fair values of our reporting units are less than their respective carrying amounts.
In connection with our quantitative assessments, we primarily use a discounted cash flow analysis to determine fair values of those reporting units. The long-term growth rate used for our quantitative assessment reflect continued expansion of our assets, driven by new natural gas supplies such as shale gas in North America, increasing demand for natural gas transmission capacity on our pipeline systems primarily as a result of forecasted growth in natural gas-fired power plants and increasing demand for crude oil and NGL transportation capacity on our pipeline systems. We assumed a long-term growth rate of 2.5% for our 2013 quantitative goodwill impairment analysis. Had we assumed a 100 basis point lower growth rate for the reporting unit that we quantitatively assessed, there would have been no impairment of goodwill. We continue to monitor the effects of the global economic downturn with respect to the long-term cost of capital utilized to calculate our reporting units’ fair values. For our 2013 quantitative goodwill impairment analysis, we assumed weighted-average costs of capital of 5.4% that market participants would use. Had we assumed a 100 basis point increase in the weighted-average cost of capital for the reporting unit that we quantitatively assessed, there would have been no impairment of goodwill.
Based on the results of our annual goodwill impairment testing, no indicators of impairment were noted and the fair values of our reporting units at April 1, 2013 (our testing date) were substantially in excess of their carrying values. No triggering events or changes in circumstances occurred during the period April 1, 2013 through December 31, 2013 that would warrant re-testing for goodwill impairment.
Revenue Recognition
Revenues from the transmission, storage and gathering of natural gas, and from the transportation of crude oil are generally 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
As of December 31, 2013, we had negative net working capital of $770 million. This balance includes commercial paper liabilities of $338 million and current maturities of long-term debt of $445 million. We will rely upon cash flows from operations, including cash distributions received from our equity affiliates, and various financing transactions, which may include issuances of debt and/or equity securities, to fund our liquidity and capital requirements for 2014. We have access to a revolving credit facility, with available capacity of $1.7 billion at December 31, 2013. 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 expect to be self-funding and plan 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.
Cash flows from operations are fairly stable given that most of our revenues and those of our equity affiliates are derived from operations under firm contracts. However, total operating cash flows are subject to a number of factors, including, but not limited to, contract renewal rates and cash distributions from our equity affiliates. The amount of cash distributed to us by our equity affiliates and the amount of cash we may be required to fund, is determined by our equity affiliates based on their operating cash flows and other factors as determined by their management. 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 $180 million in 2013, $106 million in 2012 and $107 million in 2011. See Item 1A. Risk Factors for discussion of other factors that could affect our cash flows.

50


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. 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 for each of the periods presented:
 
2013
 
2012
 
2011
 
(in millions)
Net cash provided by (used in):
 
 
 
 
 
Operating activities
$
1,029

 
$
891

 
$
761

Investing activities
(3,689
)
 
(1,880
)
 
(901
)
Financing activities
2,733

 
1,016

 
110

Net increase (decrease) in cash and cash equivalents
73

 
27

 
(30
)
Cash and cash equivalents at beginning of the period
48

 
21

 
51

Cash and cash equivalents at end of the period
$
121

 
$
48

 
$
21

Operating Cash Flows
Net cash provided by operating activities increased $138 million to $1,029 million in 2013 compared to 2012. This increase was driven primarily by:
earnings related to the acquisition of Express-Platte in 2013.
Net cash provided by operating activities increased $130 million to $891 million in 2012 compared to 2011. This increase was primarily due to:
changes in working capital.
Investing Cash Flows
Net cash flows used in investing activities increased $1,809 million to $3,689 million in 2013 compared to 2012. This increase was driven mainly by:
a $2,234 million increase in acquisitions in 2013, partially offset by
a $144 million decrease in capital and investment expenditures in 2012, and
$141 million of net proceeds from available-for-sale securities in 2013 compared to $141 million of net purchases in 2012.
Net cash flows used in investing activities increased $979 million to $1,880 million in 2012 compared to 2011. This increase was driven mainly by:
$141 million of net purchases of available-for-sale securities in 2012 compared to $202 million of net proceeds in 2011, and
a $697 million increase in capital and investment expenditures in 2012, primarily the initial investment in Sand Hills and Southern Hills, partially offset by
a $319 million net cash outlay for the acquisition of M&N US in 2012 compared to a $390 million net cash outlay for the acquisition of Big Sandy in 2011.

51


Capital and Investment Expenditures by Business Segment
 
2013
 
2012
 
2011
 
(in millions)
U.S. Transmission (a)
$
1,000

 
$
930

 
$
746

Liquids (b)
299

 
513

 

Total consolidated
$
1,299

 
$
1,443

 
$
746

_________ 
(a)
Excludes the $2,210 million net cash outlay for the U.S. Assets Dropdown in 2013 and the $390 million acquisition of Big Sandy in 2011.
(b)
Excludes the $343 million net cash outlay for the acquisition of Express-Platte in 2013.
Capital and investment expenditures for 2013 totaled $1,299 million and included $1,078 million for expansion projects and $221 million for maintenance and other projects. We project 2014 capital and investment expenditures of approximately $1.2 billion, including $0.9 billion of expansion capital expenditures and $0.3 billion for maintenance and upgrades of existing plants, pipelines and infrastructure to serve growth. Given our objective of growth through acquisitions, 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.
On August 2, 2013, we acquired a 40% ownership interest in Express US and a 100% ownership interest in Express Canada from subsidiaries of Spectra Energy for $410 million in cash and 7.2 million of newly issued common and general partner units. See Note 2 of Notes to Consolidated Financial Statements for further discussion.
On November 1, 2013, we completed the closing of substantially all of the U.S. Assets Dropdown, including Spectra Energy’s remaining 60% interest in the U.S. portion of Express-Platte. We paid Spectra Energy aggregate consideration with the issuance of approximately 171.1 million newly issued partnership units and $ 2.3 billion in cash. See Note 2 of Notes to Consolidated Financial Statements for further discussion.
In October 2012, we acquired a 39% ownership interest in M&N US from Spectra Energy for approximately $319 million in cash and approximately $56 million in newly issued common and general partner units. See Note 2 of Notes to Consolidated Financial Statements for further discussion.
In July 2011, we completed the acquisition of Big Sandy for approximately $390 million in cash. See Note 2 of Notes to Consolidated Financial Statements for further discussion.
Capital expansion projects are developed and executed using results-proven project management processes. We evaluate the strategic fit and commercial and execution risks, and continuously measure performance compared to plan. Ongoing communications between project teams and senior leadership ensure we maintain the right focus and deliver the expected results. 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.
Expansion capital expenditures included several key projects placed into service in 2013, including:
New Jersey-New York Expansion—An 800 million cubic feet per day (MMcf/d) expansion of the Texas Eastern pipeline system consisting of a new 16-mile pipeline extension into lower Manhattan, New York and other associated facility upgrades. The project is designed to transport gas produced in the U.S. Gulf Coast, Mid-Continent, Rockies and Marcellus Shale regions into New York City and was placed into service during the fourth quarter of 2013.
Sand Hills—Approximately 720 miles of NGL pipeline constructed by DCP Midstream, with an initial capacity of 200,000 Bbls/d, transporting NGLs from Permian Basin and Eagle Ford shale regions to NGL markets on the Gulf Coast. Phase I was completed in the fourth quarter of 2012, with initial service from Eagle Ford shale region to Mont Belvieu. Phase II provides service from the Permian Basin to the Eagle Ford shale region. This project was placed into service during the second quarter of 2013.
Southern Hills—Approximately 800 miles of NGL pipeline also constructed by DCP Midstream, connecting several DCP Midstream processing plants and anticipated third-party producers, providing NGL transportation from the Mid-Continent to Mont Belvieu. This project was placed into service during the second quarter of 2013.

52


Significant 2014 expansion projects expenditures are expected to include:
TEAM 2014—A 600 MMcf/d expansion of the Texas Eastern pipeline system consisting of new pipeline construction. The project is designed to transport gas produced in the Marcellus Shale to U.S. markets in the northeast, midwest and Gulf Coast. In-service is scheduled by the second half of 2014.
Kingsport—An additional 86 MMcf/d on the East Tennessee system to support a customer's multi-year project to convert five coal-fired power plant boilers to natural gas. Approximately 25 MMcf/d of the project was placed in service in November 2013 and the remainder is scheduled to be in-service in the first quarter of 2015.
OPEN—A 550 MMcf/d expansion of the Texas Eastern pipeline system consisting of new pipeline, a new compressor station and other associated facility upgrades. The project is designed to transport gas produced in the Utica Shale and Marcellus Shale to U.S. markets in the Midwest, Southeast and Gulf Coast. In-service is scheduled for the fourth quarter of 2015.
Sabal Trail—A 1,100 MMcf/d of new capacity to access onshore shale gas supplies. Facilities include a new 465-mile pipeline, laterals and various compressor stations. In-service is expected by the second quarter of 2017.
AIM—A 342 MMcf/d expansion of the Algonquin system consisting of replacement pipeline, new pipeline, new and modified meter station facilities and additional compression at existing stations. The project is designed to transport gas from existing interconnects in New Jersey and New York to LDC marked in the northeast. In-service is expected by the fourth quarter of 2016.
Financing Cash Flows
Net cash provided by financing activities increased $1,717 million to $2,733 million in 2013 compared to 2012. This change was driven mainly by:
a $1,682 million net increase in long-term debt issuances in 2013 compared to 2012, mostly to fund the U.S. Assets Dropdown from Spectra Energy,
$523 million of net contributions from parent in 2013 compared to $240 million of net contributions in 2012, and
a $69 million increase in proceeds from issuance of units in 2013, partially offset by
a $307 million net decrease in proceeds from issuances of commercial paper in 2013.
Net cash provided by financing activities increased $906 million to $1,016 million in 2012 compared to 2011. This change was driven mainly by:
a $299 million decrease in 2011 of our revolving credit facility borrowings outstanding,
a $288 million net increase in long term debt issuances in 2012,
$240 million of net contributions from parent in 2012 compared to a $109 million of net contributions in 2011, and
a $282 million increase in proceeds from issuances of commercial paper in 2012, partially offset by
a $70 million decrease in proceeds from the issuance of units in 2012.
Significant Financing Activities—2013
Debt Issuances. The following long-term debt issuances were completed during 2013 to fund a portion of the cash consideration for the U.S. assets acquisition from Spectra Energy which closed on November 1, 2013:
 
Amount
 
Interest Rate
 
Due Date
 
(in millions)
Spectra Energy Partners, LP
$
1,000

 
4.75
%
 
2024
Spectra Energy Partners, LP
500

 
2.95
%
 
2018
Spectra Energy Partners, LP
400

 
5.95
%
 
2043
Spectra Energy Partners, LP
400

 
variable

 
2018
Common Unit Issuances. On November 1, 2013, we issued 167.6 million common units and 3.4 million general partner units to Spectra Energy in connection with the U.S. Assets Dropdown, valued at $7.4 billion. See Note 2 of Notes to Consolidated Financial Statements for further discussion of the U.S. Assets Dropdown.

53


In November 2013, we entered into an equity distribution agreement under which we may sell and issue common units up to an aggregate amount of $400 million. The continuous offering program allows us to offer and sell common units, representing limited partner interests, at prices deemed appropriate through a sales agent. Sales of common units, if any, will be made by means of ordinary brokers’ transactions on the New York Stock Exchange, in block transactions, or as otherwise agreed to between the sales agent and us. We intend to use the net proceeds from sales under the program for general partnership purposes, which may include debt repayment, future acquisitions, capital expenditures and additions to working capital. Beginning in November, we issued 0.6 million common units to the public in 2013 under this program, for total net proceeds of $24 million.
In August 2013, we issued 7.1 million common units and 0.1 million general partner units to Spectra Energy in connection with the acquisition of Express-Platte, valued at $319 million. See Note 2 of Notes to Consolidated Financial Statements for further discussion of the acquisition of Express-Platte.
In April 2013, we issued 5.2 million common units to the public representing limited partner interests and 0.1 million general partner units. The net proceeds from this offering were $193 million. The net proceeds from this issuance were temporarily invested in restricted available-for-sale securities until the Express-Platte dropdown, at which time the funds were partially used to pay for a portion of the transaction. See Note 2 of Notes to Consolidated Financial Statements for a discussion of the Express-Platte transaction.
Significant Financing Activities—2012
Debt Issuances. The following long-term debt issuances were completed during 2012:
 
Amount
 
Interest Rate
 
Due Date
 
(in millions)
Algonquin
$
350

 
3.51
%
 
2024
Texas Eastern
500

 
2.80
%
 
2022
East Tennessee
200

 
3.10
%
 
2024
Common Unit Issuance. In November 2012, we issued 5.5 million common units to the public representing limited partner interests, and 0.1 million general partner units to Spectra Energy. The total net proceeds from this offering were $148 million and were restricted for the purpose of funding capital expenditures and acquisitions.
Significant Financing Activities—2011
Debt Issuances. The following long-term debt issuances completed during 2011:
 
Amount
 
Interest Rate
 
Due Date
 
(in millions)
Spectra Energy Partners, LP
$
250

 
2.95
%
 
2016
Spectra Energy Partners, LP
250

 
4.60
%
 
2021
Common Unit Issuance. In June 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. Total net proceeds of $218 million were used to fund a portion of the acquisition of Big Sandy.
Available Credit Facility and Restrictive Debt Covenants
 
Expiration
Date
 
Total
Credit Facility
Capacity
 
Commercial
Paper Outstanding at
December 31,
2013
 
Available
Credit Facility
Capacity
 
 
 
(in millions)
Spectra Energy Partners, LP
2018
 
$
2,000

 
$
338

 
$
1,662

On November 1, 2013, we amended and restated our credit agreement. The credit facility was increased to $2.0 billion and expires in 2018.

54


The issuances of commercial paper, letters of credit and revolving borrowings reduce the amount available under the credit facility. As of December 31, 2013, there were no letters of credit issued under the credit facility or revolving borrowings outstanding.
The credit agreement contains various 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, 2013, 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 of us or of some of our subsidiaries. The credit agreement does not contain provisions that trigger an acceleration of indebtedness based solely on the occurrence of a material adverse change in our financial condition or results of operations.
As noted above, the terms of the amended and restated credit agreement requires us to maintain a consolidated leverage ratio of consolidated indebtedness to consolidated earnings before interest, taxes, depreciation and amortization, as defined in the agreement, of 5.0 or less, provided that for three fiscal quarters subsequent to certain acquisitions (such as the November 1, 2013 U.S. Assets Dropdown from Spectra Energy), the ratio may be 5.5 or less. As of December 31, 2013, the consolidated leverage ratio was 4.4 after giving effect to the impact of the U.S, Assets Dropdown.
Term Loan Agreement. On November 1, 2013, we entered into and borrowed $400 million under a senior unsecured five-year term loan agreement. A portion of the proceeds from the borrowing was used to pay Spectra Energy for the U.S. Assets Dropdown.
Cash Distributions. The partnership agreement requires that, within 60 days after the end of each quarter, we distribute all of our Available Cash, as defined, to unitholders of record on the applicable record date.
We increased the quarterly cash distributions each quarter of 2013 from $0.495 per limited partner unit for the fourth quarter of 2012 to $0.54625 per limited partner unit for the fourth quarter of 2013, or 10%. The cash distribution for the fourth quarter of 2013 was declared on February 4, 2014 and was paid on February 28, 2014.
Our Board of Directors 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.
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 and another registration statement on file with the SEC to register the issuance of $500 million, in the aggregate, of limited partner units and various debt securities over time. This registration statement has $476 million available as of December 31, 2013.
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.
Contractual Obligations
We enter into contracts that require payment of cash at certain periods based on certain specified minimum quantities and prices. The following table summarizes our contractual cash obligations for each of the periods presented. The table below excludes all amounts classified as Total Current Liabilities on the December 31, 2013 Consolidated Balance Sheet other than Current Maturities of Long-Term Debt. It is expected that the majority of these current liabilities will be paid in cash in 2014.

55


Contractual Obligations as of December 31, 2013
 
Payments Due by Period
 
Total
 
2014
 
2015 &
2016
 
2017 &
2018
 
2019 &
Beyond
 
(in millions)
Long-term debt, including current maturities (a)
$
8,155

 
$
671

 
$
742

 
$
1,696

 
$
5,046

Operating leases (b)
161

 
15

 
30

 
24

 
92

Purchase obligations (c)
180

 
150

 
30

 

 

Total contractual cash obligations
$
8,496

 
$
836

 
$
802

 
$
1,720

 
$
5,138

_________
(a)
See Note 13 of Notes to Consolidated Financial Statements. Amounts include estimated scheduled interest payments over the life of the associated debt.
(b)
See Note 16.
(c)
Purchase obligations reflected in the Consolidated Balance Sheets have been excluded from the above table.
Quantitative and Qualitative Disclosures About Market Risk
We are exposed to market risks associated with interest rates 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.
Credit Risk
Credit risk represents the loss that we would incur if a counterparty fails to perform under its contractual obligations. Our exposure generally relates to receivables and unbilled revenue for services provided, as well as volumes owed by customers for imbalances or gas loaned by us generally under park and loan services and no-notice services. Our principal customers for natural gas transmission, storage and gathering services are industrial end-users, marketers, exploration and production companies, LDCs and utilities located throughout the United States. The principal customers for our integrated oil transportation pipeline are Canadian and United States producers that use Express-Platte to connect to refineries located in the U.S. Rocky Mountain and Midwest regions. 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.
Where exposed to credit risk, we analyze the customers’ financial condition prior to entering into an agreement, establish credit limits and monitor the appropriateness of these limits on an ongoing basis. We also obtain parental guarantees, cash deposits or letters of credit from customers to provide credit support, where appropriate, based on our financial analysis of the customer and the regulatory or contractual terms and conditions applicable to each contract. Approximately 90% of our credit exposures for transmission, 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. However, we cannot predict to what extent our business would be impacted by deteriorating conditions in the economy, including possible declines in our customers’ creditworthiness. As a result of future capital projects for which natural gas producers may be the primary customer, the percentage of our customers who are rated investment-grade may decline.
We had no net exposure to any customer that represented greater than 10% of the gross fair value of trade accounts receivable at December 31, 2013.
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.
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.
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,

56


but not limited to, interest rate swaps to manage and mitigate interest rate risk exposure. At December 31, 2013, there were no interest rate swaps outstanding. See also Notes 1, 13 and 15 of Notes to Consolidated Financial Statements.
Based on a sensitivity analysis as of December 31, 2013, it was estimated that if short-term interest rates average 100 basis points higher (lower) in 2014 than in 2013, interest expense, net of offsetting impacts in interest income, would increase (decrease) by $6 million. Comparatively, based on a sensitivity analysis as of December 31, 2012, had short-term interest rates averaged 100 basis points higher (lower) in 2013 than in 2012, it was estimated that interest expense, net of offsetting interest income, would have fluctuated by $8 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, 2013 and 2012.
OTHER ISSUES
Global Climate Change. Policymakers at regional, federal, provincial 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 Warsaw, Poland in November 2013 to continue laying the groundwork for a new global agreement on climate action to come into effect by 2020. An agreement was reached at the 2012 climate negotiations to amend the Kyoto Protocol extending it to 2020 when a potential new agreement could take effect.
In 2011, the Canadian government withdrew from the Kyoto Protocol. In 2008, the Canadian government outlined a
regulatory framework mandating GHG reductions from large final emitters. Regulatory design details from the Canadian
government remain forthcoming. The materiality of any potential compliance costs is unknown at this time as the final form
of the regulation and compliance options have yet to be determined by policymakers
In 2007, the province of Alberta adopted legislation which requires existing large emitters (facilities releasing 100,000
metric tons or more of GHG emissions annually) to reduce their annual emissions intensity by 12% beginning July 1, 2007. Express Canada is currently not impacted by this legislation. However, in 2013 the Alberta Minister of Environment indicated that the government is reviewing the legislation and considering increasing its stringency.
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 PSD and Tailoring Rule. Beginning in January 2011, the Tailoring Rule required that construction of new or modification of existing major sources of GHG emissions be subject to the PSD air permitting program (and later, the Title V permitting program) although the regulation also significantly increased the emission 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. 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 additional permitting 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

57


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 federal, provincial 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 Notes 5 and 16 of Notes to Consolidated Financial Statements.
New Accounting Pronouncements
There were no significant accounting pronouncements issued during 2013, 2012 or 2011 that had or will have 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.

58


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, 2013 based on the 1992 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, 2013.
Deloitte & Touche LLP, our independent registered public accounting firm, has audited and issued a report on the effectiveness of our internal control over financial reporting. Their report is included herein.

59


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:
Houston, Texas
We have audited the accompanying consolidated balance sheets of Spectra Energy Partners, LP and subsidiaries (the “Partnership”) as of December 31, 2013 and 2012, and the related consolidated statements of operations, comprehensive income, cash flows and equity for each of the three years in the period ended December 31, 2013. Our audits also included the financial statement schedule listed in the index at Item 15. We also have audited the Partnership’s internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Partnership’s management is responsible for these financial statements and financial statement schedules, 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 Partnership’s internal control over financial reporting based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Spectra Energy Partners, LP and subsidiaries as of December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein. Also, in our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on the criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

60


As discussed in Note 2 to the financial statements on August 2, 2013 the Partnership acquired a 40% ownership interest in Express US and a 100% ownership interest in Express Canada from subsidiaries of Spectra Energy. Also on November 1, 2013 the Partnership completed the closing of substantially all of the U.S. Assets Dropdown, excluding a 25.05% ownership interest in Southeast Supply Header, LLC and a 1% ownership interest in Steckman Ridge, LP. As the Express-Platte acquisition and the U.S. Assets Dropdown represented transfers of entities under common control, the Consolidated Financial Statements and related information have been recast to present results as if the related assets had been owned historically.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
February 28, 2014

61


SPECTRA ENERGY PARTNERS, LP
CONSOLIDATED STATEMENTS OF OPERATIONS
(In millions, except per-unit amounts)
 
 
Years Ended December 31,
 
 
2013
 
2012
 
2011
 
Operating Revenues
 
 
 
 
 
 
Transportation of natural gas
$
1,470

 
$
1,465

 
$
1,412

 
Transportation of crude oil
224

 

 

 
Storage of natural gas and other
271

 
289

 
334

 
Total operating revenues
1,965

 
1,754

 
1,746

 
Operating Expenses
 
 
 
 
 
 
Operating, maintenance and other
603

 
522

 
550

 
Depreciation and amortization
262

 
231

 
221

 
Property and other taxes
127

 
105

 
101

 
Total operating expenses
992

 
858

 
872

 
Gains on Sales of Other Assets and Other, net

 
1

 
6

 
Operating Income
973

 
897

 
880

 
Other Income and Expenses
 
 
 
 
 
 
Equity in earnings of unconsolidated affiliates
89

 
86

 
86

 
Other income and expenses, net
58

 
28

 
27

 
Total other income and expenses
147

 
114

 
113

 
Interest Income
1

 
1

 
1

 
Interest Expense
383

 
407

 
408

 
Earnings Before Income Taxes
738

 
605

 
586

 
Income Tax Expense (Benefit)
(348
)
(a)
10

 
1

 
Net Income
1,086

 
595

 
585

 
Net Income—Noncontrolling Interests
16

 
15

 
15

 
Net Income—Controlling Interests
$
1,070

 
$
580

 
$
570

 
Calculation of Limited Partners’ Interest in Net Income:
 
 
 
 
 
 
Net income—Controlling Interests
$
1,070

 
$
580

 
$
570

 
Less: General partner’s interest in net income
83

 
37

 
29

 
Limited partners’ interest in net income
$
987

 
$
543

 
$
541

 
Weighted average limited partners units outstanding — basic and diluted
138

(b)
97

(b)
93

(b)
Net income per limited partner unit — basic and diluted
$
7.15

(b)
$
5.60

(b)
$
5.82

(b)
Distributions paid per limited partner unit
$
2.02125

 
$
1.93

 
$
1.845

 
_________
(a)
Includes a $354 million benefit related to the elimination of accumulated deferred income tax liabilities. See Note 6 for further discussion.
(b)
Weighted average limited partners units outstanding used in the calculation of net income per limited partner unit for periods prior to the November 1, 2013 U.S. Assets Dropdown has not been recast. See Note 7 for further discussion.






See Notes to Consolidated Financial Statements.

62


SPECTRA ENERGY PARTNERS, LP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In millions)
 
 
Years Ended December 31,
 
2013
 
2012
 
2011
Net Income
$
1,086

 
$
595

 
$
585

Other comprehensive income (loss):
 
 
 
 
 
Foreign currency translation adjustments
(7
)
 

 

Unrealized mark-to-market net loss on hedges

 

 
2

Reclassification of cash flow hedges into earnings
(1
)
 
(1
)
 
(1
)
Total other comprehensive income (loss)
(8
)
 
(1
)
 
1

Total Comprehensive Income
1,078

 
594

 
586

Less: Comprehensive Income—Noncontrolling Interests
16

 
15

 
15

Comprehensive Income—Controlling Interests
$
1,062

 
$
579

 
$
571







































See Notes to Consolidated Financial Statements.

63


SPECTRA ENERGY PARTNERS, LP
CONSOLIDATED BALANCE SHEETS
(In millions)
 
 
December 31,
 
2013
 
2012
ASSETS
 
 
 
Current Assets
 
 
 
Cash and cash equivalents
$
121

 
$
48

Receivables (net of allowance for doubtful accounts of $1 and $0 at December 31, 2013 and 2012, respectively)
355

 
265

Inventory
42

 
35

Other
47

 
29

Total current assets
565

 
377

Investments and Other Assets
 
 
 
Investments in and loans to unconsolidated affiliates
1,396

 
1,136

Goodwill
3,215

 
2,814

Other investments — restricted funds

 
141

Other
2

 
6

Total investments and other assets
4,613

 
4,097

Property, Plant and Equipment
 
 
 
Cost
14,592

 
12,220

Less accumulated depreciation and amortization
3,229

 
3,026

Net property, plant and equipment
11,363

 
9,194

Regulatory Assets and Deferred Debits
253

 
217

Total Assets
$
16,794

 
$
13,885


See Notes to Consolidated Financial Statements.

64


SPECTRA ENERGY PARTNERS, LP
CONSOLIDATED BALANCE SHEETS
(In millions)
 
 
December 31,
 
2013
 
2012
LIABILITIES AND EQUITY
 
 
 
Current Liabilities
 
 
 
Accounts payable
$
231

 
$
76

Commercial paper
338

 
336

Note payable—affiliate

 
17

Taxes accrued
44

 
35

Interest accrued
61

 
38

Current maturities of long-term debt
445

 
18

Other
216

 
145

Total current liabilities
1,335

 
665

Notes Payable—Affiliates

 
4,185

Long-term Debt
5,178

 
3,105

Deferred Credits and Other Liabilities
 
 
 
Deferred income taxes
34

 
104

Other
106

 
92

Total deferred credits and other liabilities
140

 
196

Commitments and Contingencies

 

Equity
 
 
 
Partners’ Capital
 
 
 
Common units (284.1 million and 103.6 million units issued and outstanding at December 31, 2013 and 2012, respectively)
9,778

 
5,483

General partner units (5.8 million and 2.1 million units outstanding at December 31, 2013 and 2012, respectively)
241

 
141

Accumulated other comprehensive income
(5
)
 
3

Total partners’ capital
10,014

 
5,627

Noncontrolling interests
127

 
107

Total equity
10,141

 
5,734

Total Liabilities and Equity
$
16,794

 
$
13,885


See Notes to Consolidated Financial Statements.

65


SPECTRA ENERGY PARTNERS, LP
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
 
Years Ended December 31,
 
2013
 
2012
 
2011
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
 
 
 
Net income
$
1,086

 
$
595

 
$
585

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
 
 
Depreciation and amortization
266

 
240

 
223

Deferred income tax expense (benefit)
(354
)
 
6

 
(2
)
Equity in earnings of unconsolidated affiliates
(89
)
 
(86
)
 
(86
)
Distributions received from unconsolidated affiliates
97

 
90

 
91

Decrease (increase) in:
 
 
 
 
 
Receivables
(11
)
 
11

 
(9
)
Other current assets
(73
)
 
3

 
(11
)
Increase (decrease) in:
 
 
 
 
 
Accounts payable
96

 
15

 
(3
)
Taxes accrued
6

 
3

 
(11
)
Other current liabilities
50

 
28

 
(17
)
Other, assets
(61
)
 
(25
)
 
(7
)
Other, liabilities
16

 
11

 
8

Net cash provided by operating activities
1,029

 
891

 
761

CASH FLOWS FROM INVESTING ACTIVITIES
 
 
 
 
 
Capital expenditures
(1,019
)
 
(930
)
 
(744
)
Investments in and loans to unconsolidated affiliates
(280
)
 
(513
)
 
(2
)
Acquisitions, net of cash acquired
(2,553
)
 
(319
)
 
(390
)
Distributions received from unconsolidated affiliates
83

 
16

 
16

Purchases of held-to-maturity securities
(51
)
 

 

Proceeds from sales and maturities of held-to-maturity securities
55

 

 

Purchases of available-for-sale securities
(5,865
)
 
(630
)
 
(892
)
Proceeds from sales and maturities of available-for-sale securities
6,006

 
489

 
1,094

Loan to unconsolidated affiliate
(71
)
 

 

Other
6

 
7

 
17

Net cash used in investing activities
(3,689
)
 
(1,880
)
 
(901
)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
 
 
 
Proceeds from issuance of long-term debt
2,287

 
1,049

 
509

Payments for the redemption of long-term debt
(46
)
 
(490
)
 
(238
)
Net decrease in revolving credit facilities borrowings

 

 
(299
)
Net increase in commercial paper
2