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
Item | Page | |
1. | ||
1A. | ||
1B. | ||
2. | ||
3. | ||
4. | ||
5. | ||
6. | ||
7. | ||
7A. | ||
8. | ||
9. | ||
9A. | ||
9B. | ||
10. | ||
11. | ||
12. | ||
13. | ||
14. | ||
15. | ||
2
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.
3
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
4
(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.
5
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.
6
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.
7
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.
8
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.
9
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.
10
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.
11
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.
12
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.
13
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.
14
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.
15
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.
16
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-
17
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.
18
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
19
(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.
20
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
21
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.
22
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
23
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; |
24
• | 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.
25
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,
26
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.
27
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.
28
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; |
29
• | 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
30
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
31
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
32
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. |
33
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.
34
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 | 309 | 27 | ||||||||
Increase (decrease) in notes payable—affiliates | 17 | (3 | ) | (3 | ) | ||||||
Distributions to noncontrolling interests | (19 | ) | (18 | ) | (18 | ) | |||||
Contributions from noncontrolling interests | 23 | — | — | ||||||||
Proceeds from issuance of units | 217 | 148 | 218 | ||||||||
Distributions to partners | (266 | ) | (214 | ) | (189 | ) | |||||
Contribution from parent | 523 | 240 | 109 | ||||||||
Other | (5 | ) | (5 | ) | (6 | ) | |||||
Net cash provided by 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 | |||||
Supplemental Disclosures | |||||||||||
Cash paid for interest, net of amount capitalized | $ | 348 | $ | 391 | $ | 398 | |||||
Cash paid for income taxes | — | 1 | 1 | ||||||||
Property, plant and equipment noncash accruals | 74 | 28 | 21 | ||||||||
Units issued as partial consideration for acquisitions | 7,751 | 56 | — | ||||||||
See Notes to Consolidated Financial Statements.
66
SPECTRA ENERGY PARTNERS, LP
CONSOLIDATED STATEMENTS OF EQUITY
(In millions)
Partners’ Capital | Accumulated Other Comprehensive Income (Loss) | Noncontrolling Interests | Total | ||||||||||||||||
Common | General Partner | ||||||||||||||||||
December 31, 2010 | $ | 4,658 | $ | 95 | $ | 3 | $ | 113 | $ | 4,869 | |||||||||
Net income | 541 | 29 | — | 15 | 585 | ||||||||||||||
Other comprehensive income (loss) | — | — | 1 | — | 1 | ||||||||||||||
Net transfer from parent | 69 | 2 | — | — | 71 | ||||||||||||||
Attributed deferred tax benefit | — | 8 | — | — | 8 | ||||||||||||||
Issuance of units | 214 | 4 | — | — | 218 | ||||||||||||||
Distributions to partners | (171 | ) | (18 | ) | — | — | (189 | ) | |||||||||||
Distributions to noncontrolling interests | — | — | — | (18 | ) | (18 | ) | ||||||||||||
December 31, 2011 | 5,311 | 120 | 4 | 110 | 5,545 | ||||||||||||||
Net income | 543 | 37 | — | 15 | 595 | ||||||||||||||
Other comprehensive income (loss) | — | — | (1 | ) | — | (1 | ) | ||||||||||||
Net transfer to parent | (385 | ) | (8 | ) | — | — | (393 | ) | |||||||||||
Attributed deferred tax benefit | — | 15 | — | — | 15 | ||||||||||||||
Issuance of units | 201 | 4 | — | — | 205 | ||||||||||||||
Distributions to partners | (187 | ) | (27 | ) | — | — | (214 | ) | |||||||||||
Distributions to noncontrolling interests | — | — | — | (18 | ) | (18 | ) | ||||||||||||
December 31, 2012 | 5,483 | 141 | 3 | 107 | 5,734 | ||||||||||||||
Net income | 987 | 83 | — | 16 | 1,086 | ||||||||||||||
Other comprehensive income (loss) | — | — | (8 | ) | — | (8 | ) | ||||||||||||
Purchase price under net acquired assets in Express-Platte acquisition | 20 | — | — | — | 20 | ||||||||||||||
Excess purchase price over net acquired assets in U.S. Assets Dropdown | (70 | ) | (1 | ) | — | — | (71 | ) | |||||||||||
Net transfer to parent | (4,224 | ) | (133 | ) | — | — | (4,357 | ) | |||||||||||
Attributed deferred tax benefit | — | 33 | — | — | 33 | ||||||||||||||
Issuance of units | 7,810 | 159 | — | — | 7,969 | ||||||||||||||
Distributions to partners | (225 | ) | (41 | ) | — | — | (266 | ) | |||||||||||
Contributions from noncontrolling interests | — | — | — | 23 | 23 | ||||||||||||||
Distributions to noncontrolling interests | — | — | — | (19 | ) | (19 | ) | ||||||||||||
Other, net | (3 | ) | — | — | — | (3 | ) | ||||||||||||
December 31, 2013 | $ | 9,778 | $ | 241 | $ | (5 | ) | $ | 127 | $ | 10,141 | ||||||||
See Notes to Consolidated Financial Statements.
67
SPECTRA ENERGY PARTNERS, LP
Notes to Consolidated Financial Statements
INDEX
Page | ||
1. | ||
2. | ||
3. | ||
4. | ||
5. | ||
6. | ||
7. | ||
8. | ||
9. | ||
10. | ||
11. | ||
12. | ||
13. | ||
14. | ||
15. | ||
16. | ||
17. | ||
18. | ||
19. | ||
1. Summary of Operations and Significant Accounting Policies
The terms “we,” “our,” “us” and “Spectra Energy Partners” as used in this report refer collectively to Spectra Energy Partners, LP and its subsidiaries unless the context suggests otherwise. These terms are used for convenience only and are not intended as a precise description of any separate legal entity within Spectra Energy Partners.
Nature of Operations. Spectra Energy Partners, 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. We are a Delaware master limited partnership (MLP). As of December 31, 2013, Spectra Energy Corp (Spectra Energy) and its subsidiaries collectively owned 84% of us and the remaining 16% was publicly owned.
Basis of Presentation. The accompanying Consolidated Financial Statements include our accounts and the accounts of our majority-owned subsidiaries, after eliminating intercompany transactions and balances.
On August 2, 2013, we acquired a 40% ownership interest in the U.S. portion of the Express-Platte crude oil pipeline system (Express US) and a 100% ownership interest in the Canadian portion of the pipeline system (Express Canada)(collectively, Express-Platte) from subsidiaries of Spectra Energy (the Express-Platte acquisition). On November 1, 2013, we acquired substantially all of Spectra Energy's remaining U.S. transmission, storage and liquid assets, including Spectra Energy's remaining 60% interest in Express US (the U.S. Assets Dropdown).
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 for further discussion of the transactions.
68
Our costs of doing business have been reflected in our financial accounting records for the periods presented. These costs include direct charges and allocations from Spectra Energy and its affiliates for business services, such as payroll, accounts payable and facilities management; corporate services, such as finance and accounting, legal, human resources, investor relations, public and regulatory policy, and senior executives; and pension and other post-retirement benefit costs.
Use of Estimates. To conform with generally accepted accounting principles (GAAP) in the United States, we make estimates and assumptions that affect the amounts reported in the Consolidated Financial Statements and Notes to Consolidated Financial Statements. Although these estimates are based on our best available knowledge at the time, actual results could differ.
Fair Value Measurements. We measure the fair value of financial assets and liabilities by maximizing the use of observable inputs and minimizing the use of unobservable inputs. Fair value is the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date.
Cost-Based Regulation. The economic effects of regulation can result in a regulated company recording assets for costs that have been or are expected to be approved for recovery from customers or recording liabilities for amounts that are expected to be returned to customers or for instances where the regulator provides current rates that are intended to recover costs that are expected to be incurred in the future. Accordingly, we record assets and liabilities that result from the regulated ratemaking process that may not be recorded under GAAP for non-regulated entities. We continually assess whether regulatory assets are probable of future recovery by considering factors such as applicable regulatory changes and recent rate orders to other regulated entities. Based on this assessment, we believe our existing regulatory assets are probable of recovery. These regulatory assets and liabilities are mostly classified in the Consolidated Balance Sheets as Regulatory Assets and Deferred Debits and Current Liabilities. We evaluate our regulated assets, and consider factors such as regulatory changes and the effect of competition. If cost-based regulation ends or competition increases, we may have to reduce our asset balances to reflect a market basis less than cost and write-off the associated regulatory assets. See Note 5 for further discussion.
Foreign Currency Translation. The Canadian dollar has been determined to be the functional currency of Express Canada based on an assessment of the economic circumstances of those operations. Assets and liabilities of Express Canada are translated into U.S. dollars at current exchange rates. Translation adjustments resulting from fluctuations in exchange rates are included as a separate component of Other Comprehensive Income (Loss) on the Consolidated Statements of Comprehensive Income. Revenue and expense accounts of these operations are translated at average monthly exchange rates prevailing during the periods. Gains and losses arising from transactions denominated in currencies other than the functional currency are included in the results of operations of the period in which they occur. Foreign currency transaction losses totaled $2 million in 2013 and are included in Other Income and Expenses, Net on the Consolidated Statements of Operations. There were no foreign currency transaction losses in 2012 and 2011.
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. We also have certain customer contracts with billed amounts that decline annually over the terms of the contracts. Differences between the amounts billed and recognized are deferred on the Consolidated Balance Sheets. There were no customers accounting for 10% or more of consolidated revenues during 2013 or 2011. National Grid plc accounted for 10% of consolidated revenues in 2012.
Allowance for Funds Used During Construction (AFUDC). AFUDC, which represents the estimated debt and equity costs of capital funds necessary to finance the construction and expansion of certain new regulated facilities, consists of two components, an equity component and an interest expense component. The equity component is a non-cash item. After construction is completed, we are permitted to recover these costs through inclusion in the rate base and in the depreciation provision. AFUDC is capitalized as a component of Property, Plant and Equipment - Cost on the Consolidated Balance Sheets, with offsetting credits to the Consolidated Statements of Operations through Other Income and Expenses, Net for the equity component and Interest Expense for the interest expense component. The total amount of AFUDC included in the Consolidated Statements of Operations was $96 million in 2013 (an equity component of $58 million and an interest expense component of $38 million), $46 million in 2012 (an equity component of $27 million and an interest expense component of $19 million) and $25 million in 2011 (an equity component of $17 million and an interest expense component of $8 million).
Income Taxes. As a result of our MLP structure, we are not subject to federal income tax. Our federal taxable income or loss is reported on the respective income tax returns of our partners. However, we are subject to Canadian foreign income tax and Tennessee and New Hampshire income tax. Market Hub Partners Holding (Market Hub) is liable to Spectra Energy for
69
Texas income (margin) tax under a tax sharing agreement. As of December 31, 2013, the difference between the tax basis and the reported amounts of Spectra Energy Partners’ assets and liabilities is $11.5 billion.
We are subject to cost-based regulation and consequently record a regulatory tax asset in connection with the tax gross up of AFUDC equity. The corresponding deferred tax liability is recognized as an Attributed Deferred Income Tax Benefit in the Consolidated Statements of Equity since we are a pass-through entity.
Cash and Cash Equivalents. Highly liquid investments with original maturities of three months or less at the date of acquisition, except for any investments that were pledges as collateral against long-term debt as discussed in Note 13 and any investments that are considered restricted funds, are considered cash equivalents.
Inventory. Inventory consists mainly of natural gas retained from shippers for fuel and also includes materials and supplies. Natural gas is recorded at the lower of cost or market. Materials and supplies are recorded at cost, using the average cost method.
Natural Gas Imbalances. The Consolidated Balance Sheets include in-kind balances as a result of differences in gas volumes received and delivered for customers. Since settlement of certain imbalances is in-kind, changes in the balances do not have an effect on our Consolidated Statements of Operations or Consolidated Statements of Cash Flows. Receivables includes $147 million and $81 million as of December 31, 2013 and December 31, 2012, respectively, and Other Current Liabilities includes $116 million and $77 million as of December 31, 2013 and December 31, 2012, respectively, related to all gas imbalances. Most natural gas volumes owed to or by us are valued at natural gas market index prices as of the balance sheet dates.
Cash Flow Hedges. We have previously entered into interest rate swaps which were designated as effective cash flow hedges. For all hedge contracts, we prepare documentation of the hedge in accordance with accounting standards and assess whether the hedge contract is highly effective, both at inception and on a quarterly basis, in offsetting changes in cash flows or fair values of hedged items. Changes in the fair value of a derivative designated and qualified as a cash flow hedge, to the extent effective, are reported as Accumulated Other Comprehensive Income (AOCI) on our Consolidated Balance Sheets until earnings are affected by the hedged transaction. As of December 31, 2013, we did not have any cash flow hedges outstanding.
Investments. We may actively invest a portion of our available cash and restricted funds balances in various financial instruments, including taxable or tax-exempt debt securities. In addition, we invest in short-term money market securities, some of which are restricted due to debt collateral requirements. Investments in available-for-sale (AFS) securities are carried at fair value and investments in held-to-maturity (HTM) securities are carried at cost. Investments in money market securities are also accounted for at fair value. Realized gains and losses, and dividend and interest income related to these securities, including any amortization of discounts or premiums arising at acquisition, are included in earnings. The costs of securities sold are determined using the specific identification method. Purchases and sales of AFS and HTM securities are presented on a gross basis within Cash Flows From Investing Activities in the accompanying Consolidated Statements of Cash Flows. See also Notes 10 and 14 for additional information.
Goodwill. We perform our goodwill impairment test annually and evaluate goodwill when events or changes in circumstances indicate that its carrying value may not be recoverable. No impairments of goodwill were recorded in 2013, 2012 or 2011. See Note 9 for further discussion.
We perform our annual review for goodwill impairment at the reporting unit level, which is identified by assessing whether the components of our operating segments constitute businesses for which discrete financial information is available, whether segment management regularly reviews the operating results of those components and whether the economic and regulatory characteristics are similar. We determined that our reporting units are equivalent to our reportable segments.
As permitted under 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 the fair values of those reporting units. Key assumptions in the determination of fair value included the use of an appropriate discount rate and estimated future cash flows. In estimating cash flows, we incorporate expected long-term growth rates in key markets served by our operations, regulatory stability, the ability to renew contracts, commodity prices (where appropriate) and foreign currency exchange rates, as well as other factors that affect our reporting units’ revenue, expense and capital expenditure
70
projections. If the carrying amount of the reporting unit exceeds its fair value, a comparison of the fair value and carrying value of the goodwill of that reporting unit needs to be performed. If the carrying value of the goodwill of a reporting unit exceeds the implied fair value of that goodwill, an impairment loss is recognized in an amount equal to the excess. Additional impairment tests are performed between the annual reviews if events or changes in circumstances make it more likely than not that the fair value of a reporting unit is below its carrying amount.
Property, Plant and Equipment. Property, plant and equipment is stated at historical cost less accumulated depreciation. We capitalize all construction-related direct labor and material costs, as well as indirect construction costs. Indirect costs include general engineering, taxes and the cost of funds used during construction. The costs of renewals and betterments that extend the useful life or increase the expected output of property, plant and equipment are also capitalized. The costs of repairs, replacements and major maintenance projects that do not extend the useful life or increase the expected output of property, plant and equipment are expensed as incurred. Depreciation is generally computed over the asset’s estimated useful life using the straight-line method.
When we retire regulated property, plant and equipment, we charge the original cost plus the cost of retirement, less salvage value, to accumulated depreciation and amortization. When we sell entire regulated operating units, or retire non-regulated properties, the cost is removed from the property account and the related accumulated depreciation and amortization accounts are reduced. Any gain or loss is recorded in earnings, unless otherwise required by the applicable regulatory body.
Preliminary Project Costs. Project development costs, including expenditures for preliminary surveys, plans, investigations, environmental studies, regulatory applications and other costs incurred for the purpose of determining the feasibility of capital expansion projects, are capitalized for rate-regulated enterprises when it is determined that recovery of such costs through regulated revenues of the completed project is probable. Any inception-to-date costs that were initially expensed are reversed and capitalized as Property, Plant and Equipment.
Long-Lived Asset Impairments. We evaluate whether long-lived assets, excluding goodwill, have been impaired when circumstances indicate the carrying value of those assets may not be recoverable. For such long-lived assets, an impairment exists when its carrying value exceeds the sum of estimates of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. When alternative courses of action to recover the carrying amount of a long-lived asset are under consideration, a probability-weighted approach is used in developing estimates of future undiscounted cash flows. If the carrying value of the long-lived asset is not recoverable based on these estimated future undiscounted cash flows, an impairment loss is measured as the excess of the asset’s carrying value over its fair value, such that the asset’s carrying value is adjusted to its estimated fair value.
We assess the fair value of long-lived assets using commonly accepted techniques, and may use more than one source. Sources to determine fair value include, but are not limited to, recent third-party comparable sales, internally developed discounted cash flow analyses and analyses from outside advisors. Significant changes in market conditions resulting from events such as changes in natural gas available to our systems, the condition of an asset, a change in our intent to utilize the asset or a significant change in contracted revenues or regulatory recoveries would generally require us to reassess the cash flows related to the long-lived assets.
Asset Retirement Obligations. We recognize asset retirement obligations (AROs) for legal commitments associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset and conditional AROs in which the timing or method of settlement are conditional on a future event that may or may not be within our control. The fair value of a liability for an ARO is recognized in the period in which it is incurred if a reasonable estimate of fair value can be made and is added to the carrying amount of the associated asset. This additional carrying amount is depreciated over the estimated useful life of the asset.
Unamortized Debt Premium, Discount and Expense. Premiums, discounts, and expenses incurred with the issuance of outstanding long-term debt are amortized over the terms of the debt issues. Any call premiums or unamortized expenses associated with refinancing higher-cost debt obligations to finance regulated assets and operations are amortized consistent with regulatory treatment of those items, where appropriate.
Environmental Expenditures. We expense environmental expenditures related to conditions caused by past operations that do not generate current or future revenues. Environmental expenditures related to operations that generate current or future revenues are expensed or capitalized, as appropriate. Undiscounted liabilities are recorded when the necessity for environmental remediation becomes probable and the costs can be reasonably estimated, or when other potential environmental liabilities are reasonably estimable and probable.
71
Segment Reporting. Operating segments are components of an enterprise about which separate financial information is available and evaluated regularly by the chief operating decision maker in deciding how to allocate resources and evaluate performance. Two or more operating segments may be aggregated into a single reportable segment provided certain criteria are met. There is no such aggregation within our defined business segment. A description of our reportable segments consistent with how business results are reported internally to management, and the disclosure of segment information is presented in Note 4.
Consolidated Statements of Cash Flows. Cash received from insurance proceeds are classified depending on the activity that resulted in the insurance proceeds. For example, business interruption insurance proceeds are included as a component of operating activities while insurance proceeds from damaged property are included as a component of investing activities. With respect to cash overdrafts, book overdrafts are included within operating cash flows while bank overdrafts, if any, are included within financing cash flows. Cash flows from borrowings and repayments under revolving credit facilities that had documented original maturities of 90 days or less are reported on a net basis as a Net Decrease in Revolving Credit Facilities Borrowings within Cash Flows From Financing Activities.
Distributions from Unconsolidated Affiliates. We consider distributions received from unconsolidated affiliates which do not exceed cumulative equity in earnings subsequent to the date of investment to be a return on investment and classify these amounts as Cash Flows From Operating Activities within the accompanying Consolidated Statements of Cash Flows. Cumulative distributions received in excess of cumulative equity in earnings subsequent to the date of investment are considered to be a return of investment and are classified as Cash Flows From Investing Activities.
New Accounting Pronouncements. There were no significant accounting pronouncements 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.
2. Acquisitions
U.S. Assets Dropdown. On November 1, 2013, we completed the closing of substantially all of the U.S. Assets Dropdown, excluding a 25.05% ownership interest in Southeast Supply Header, LLC (SESH) and a 1% ownership interest in Steckman Ridge, LP (Steckman Ridge). Consideration to Spectra Energy for the November 1, 2013 closing included $2.3 billion in cash, assumption (indirectly by acquisition of the contributed entities) of approximately $2.4 billion of third-party indebtedness of the contributed entities, 167.6 million newly issued limited partner units and 3.4 million newly issued general partner units. The first of the remaining two closings of the U.S. Assets Dropdown is expected to occur at least 12 months following the November 1, 2013 closing, consisting of the transfer of a 24.95% ownership interest in SESH and the remaining 1% ownership interest in Steckman Ridge, with the final closing expected to occur at least 12 months thereafter, consisting of the transfer of the remaining 0.1% ownership interest in SESH.
The contributed assets provide transportation and storage of natural gas, crude oil and NGLs for customers in various regions of the U.S. and in Alberta, Canada. The contributed assets included in the U.S. Assets Dropdown, once the final closing is completed, will consist of:
•a 100% ownership interest in Texas Eastern Transmission, LP (Texas Eastern)
•a 100% ownership interest in Algonquin Gas Transmission, LLC (Algonquin)
•Spectra Energy’s remaining 60% ownership interest in Express US
•Spectra Energy’s remaining 38.77% ownership interest in Maritimes & Northeast Pipeline, L.L.C. (M&N US)
•a 33.3% ownership interest in DCP Sand Hills Pipeline, LLC (Sand Hills)
•a 33.3% ownership interest in DCP Southern Hills Pipeline, LLC (Southern Hills)
•Spectra Energy’s remaining 1% ownership interest in Gulfstream Natural Gas System, LLC (Gulfstream)
•a 50% ownership interest in SESH
•a 100% ownership interest in Bobcat Gas Storage (Bobcat)
•Spectra Energy’s remaining 50% of Market Hub
•a 50% ownership interest in Steckman Ridge
•Texas Eastern’s and Express-Platte’s storage facilities
As the U.S. Assets Dropdown represented a transfer of entities under common control, the Consolidated Financial Statements and related information presented herein have been recast to include the historical results of the U.S. Assets Dropdown for all periods presented. As such, summarized financial information has not been presented.
Express-Platte. 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
72
general partner units. The Express-Platte pipeline 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. 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.
The following table summarizes the preliminary fair values of the assets and liabilities as of March 14, 2013, the acquisition date of Express-Platte from third-parties by Spectra Energy. Subsequent adjustments may be recorded upon the completion of the valuation and the final determination of the purchase price allocation.
Purchase Price Allocation | |||
(in millions) | |||
Cash | $ | 67 | |
Receivables | 25 | ||
Other current assets | 10 | ||
Goodwill | 486 | ||
Property, plant and equipment | 1,311 | ||
Accounts payable | (18 | ) | |
Other current liabilities | (17 | ) | |
Deferred credits and other liabilities | (283 | ) | |
Long-term debt, including current portion | (260 | ) | |
Total assets acquired/liabilities assumed | $ | 1,321 | |
The following tables present summarized financial information for Express-Platte since March 14, 2013, the acquisition date of Express-Platte from third-parties by Spectra Energy.
March 14, 2013 to December 31, 2013 | |||
Operating revenues | $ | 238 | |
Earnings before interest and taxes | 109 | ||
Net income | 89 | ||
December 31, 2013 | |||
(in millions) | |||
Total current assets | $ | 88 | |
Investments and other assets | 483 | ||
Net property, plant and equipment | 1,307 | ||
Total Assets | $ | 1,878 | |
Total current liabilities | $ | 85 | |
Note payable—affiliate | 176 | ||
Long-term debt | 196 | ||
Deferred credits and other liabilities | 16 | ||
Equity | 1,405 | ||
Total Liabilities and Equity | $ | 1,878 | |
73
The following table presents unaudited pro forma results of operations information that reflect the acquisition of Express-Platte as if the acquisition had occurred as of January 1, 2012, adjusted for items that are directly attributable to the acquisition. This information has been compiled from current and historical financial statements, and is not necessarily indicative of the results that actually would have been achieved had the transaction occurred at the beginning of the periods presented or that may be achieved in the future.
2013 | 2012 | ||||||
(in millions, except per-unit amounts) | |||||||
Operating revenues | $ | 2,024 | $ | 2,022 | |||
Earnings before income taxes | 751 | 707 | |||||
Net income | 1,099 | 697 | |||||
Net income-controlling interests | 1,083 | 682 | |||||
Net income per limited partner unit—basic and diluted | 7.01 | 6.15 | |||||
M&N US. On October 31, 2012, we acquired a 38.76% 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. M&N US’ pipeline location and key interconnects with our transmission system link regional natural gas supplies primarily to the northeast U.S. market. M&N US is a part of the U.S. Transmission segment. We acquired Spectra Energy’s remaining 38.77% ownership interest in M&N US in connection with the U.S. Assets Dropdown.
The initial 38.76% interest in M&N US was recorded at the historical book value of Spectra Energy of $199 million. The $176 million excess purchase price over the book value of net assets acquired was recorded as a reduction to Partners’ Capital, and the $56 million of common and general partner units issued to Spectra Energy were recorded as increases to Partners’ Capital.
Sand Hills and 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. Asset 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.
Big Sandy Pipeline, L.L.C. (Big Sandy). In July 2011, we acquired Big Sandy from EQT Corporation for approximately $390 million in cash.
The assets and liabilities of Big Sandy were recorded at their respective fair values as of the purchase date and the results of operations were included in the Consolidated Financial Statements beginning as of the effective date of the acquisition. Since Big Sandy records assets and liabilities resulting from the rate making process, the fair values of the individual assets and liabilities are considered to approximate their carrying values. Big Sandy is part of the U.S. Transmission segment.
The following table summarizes the fair values of the assets and liabilities acquired as of the date of acquisition.
Purchase Price Allocation | |||
(in millions) | |||
Purchase price | $ | 390 | |
Property, plant and equipment acquired | 196 | ||
Goodwill | $ | 194 | |
The purchase price is greater than the sum of fair values of the net assets acquired, resulting in goodwill as noted above. The goodwill reflects the value of the strategic location of the pipeline and the opportunity to expand and grow the business. Pro forma results of operations reflecting the acquisition of Big Sandy as if the acquisition had occurred as of the beginning of the periods presented in this report do not materially differ from actual reported results.
74
3. Transactions with Affiliates
In the normal course of business, we provide natural gas transmission, storage and other services to Spectra Energy and its affiliates.
In addition, pursuant to an agreement with Spectra Energy, Spectra Energy and its affiliates perform centralized corporate functions for us, including legal, accounting, compliance, treasury and other areas. We reimburse Spectra Energy for the expenses to provide these services as well as other expenses it incurs on our behalf, such as salaries of personnel performing services for our benefit and the cost of employee benefits and general and administrative expenses associated with such personnel, capital expenditures, maintenance and repair costs, taxes and direct expenses, including operating expenses and certain allocated operating expenses associated with the ownership and operation of the contributed assets. Spectra Energy and its affiliates charge such expenses based on the cost of actual services provided or using various allocation methodologies based on our percentage of assets, employees, earnings or other measures, as compared to Spectra Energy’s other affiliates.
Transactions with affiliates are summarized in the tables below:
Consolidated Statements of Operations
2013 | 2012 | 2011 | |||||||||
(in millions) | |||||||||||
Revenues | $ | 58 | $ | 65 | $ | 86 | |||||
Operating, maintenance and other expenses | 252 | 218 | 190 | ||||||||
Interest expense | 222 | 260 | 261 | ||||||||
We are party to an agreement with DCP Midstream, LLC (DCP Midstream), an equity investment of Spectra Energy, in which DCP Midstream processes certain of our customers' gas to meet quality specifications in order to be transported on our system. DCP Midstream processes the gas and sells the NGLs that are extracted from the gas. A portion of the proceeds from those sales are retained by DCP Midstream and the balance is remitted to us. We recognized revenues of $48 million, $53 million and $70 million in 2013, 2012 and 2011, respectively, related to those services, classified as Storage of Natural Gas and Other in our Consolidated Statements of Operations.
We recorded natural gas transmission revenues from DCP Midstream and its affiliates totaling $7 million in 2013, $8 million in 2012 and $10 million in 2011, classified as Transportation of Natural Gas in our Consolidated Statements of Operations.
In addition to the above, we recorded other revenues from DCP Midstream and its affiliates totaling $3 million in 2013, $4 million in 2012 and $6 million in 2011, classified as Storage of Natural Gas and Other in our Consolidated Statements of Operations.
Consolidated Balance Sheets
December 31, | |||||||
2013 | 2012 | ||||||
(in millions) | |||||||
Receivables | $ | 17 | $ | 17 | |||
Current assets — other | 3 | 4 | |||||
Accounts payable | 60 | 12 | |||||
Interest accrued | — | 4 | |||||
Notes payable — affiliates | — | 4,202 | |||||
See also Notes 1, 8, 13 and 14 for discussion of specific related party transactions.
75
4. Business Segments
As a result of the Express-Platte acquisition and the U.S. Assets Dropdown, which represented transfers of entities under common control, 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.
We manage our business in two reportable segments: U.S. Transmission and Liquids. The remainder of our business operations is presented as “Other,” and consists of certain corporate costs.
Our chief operating decision maker regularly reviews financial information about both segments in deciding how to allocate resources and evaluate performance. There is no aggregation of segments within our reportable business segments.
The U.S. Transmission segment provides interstate transmission and storage of natural gas. Substantially all of our operations are subject to the Federal Energy Regulatory Commission (FERC) and the Department of Transportation’s (DOT’s) rules and regulations. Our investments in Gulfstream, SESH and Steckman Ridge are included in U.S. Transmission.
Liquids provides transportation of crude oil and NGLs. The Express-Platte pipeline system is a crude oil pipeline system that connects Canadian and U.S. producers to refineries in the U.S. Rocky Mountain and Midwest regions. These operations are primarily subject to the rules and regulations of the FERC and the National Energy Board (NEB). The Sand Hills and Southern Hills pipelines, which were acquired in the fourth quarter of 2013 in the U.S. Assets Dropdown, provide transportation of NGLs from the Permian Basin and Eagle Ford region to the premium NGL markets on the Gulf Coast, and from the Mid-Continent to Mont Belvieu, Texas, respectively. We have direct one-third ownership interests in Sand Hills and Southern Hills. DCP Midstream and Phillips 66 also each own direct one-third ownership interests in the two pipelines. Sand Hills and Southern Hills are subject to the rules and regulations of the FERC.
Our reportable segments offer different products and services and are managed separately as business units. Management evaluates segment performance based on earnings from continuing operations before interest, taxes, and depreciation and amortization (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. 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.
76
Business Segment Data
Total Revenues | Segment EBITDA/ Consolidated Earnings from Continuing Operations Before Income Taxes | Depreciation and Amortization | Capital and Investment Expenditures (a) | Assets | |||||||||||||||
(in millions) | |||||||||||||||||||
2013 | |||||||||||||||||||
U.S. Transmission | $ | 1,727 | $ | 1,279 | $ | 241 | $ | 1,000 | $ | 14,174 | |||||||||
Liquids | 238 | 132 | 21 | 299 | 2,604 | ||||||||||||||
Total | 1,965 | 1,411 | 262 | 1,299 | 16,778 | ||||||||||||||
Other | — | (27 | ) | — | — | 16 | |||||||||||||
Depreciation and amortization | — | 262 | — | — | — | ||||||||||||||
Interest expense | — | 383 | — | — | — | ||||||||||||||
Interest income and other | — | (1 | ) | — | — | — | |||||||||||||
Total consolidated | $ | 1,965 | $ | 738 | $ | 262 | $ | 1,299 | $ | 16,794 | |||||||||
2012 | |||||||||||||||||||
U.S. Transmission | $ | 1,754 | $ | 1,251 | $ | 231 | $ | 930 | $ | 13,199 | |||||||||
Liquids | — | — | — | 513 | 517 | ||||||||||||||
Total | 1,754 | 1,251 | 231 | 1,443 | 13,716 | ||||||||||||||
Other | — | (9 | ) | — | — | 169 | |||||||||||||
Depreciation and amortization | — | 231 | — | — | — | ||||||||||||||
Interest expense | — | 407 | — | — | — | ||||||||||||||
Interest income and other | — | 1 | — | — | — | ||||||||||||||
Total consolidated | $ | 1,754 | $ | 605 | $ | 231 | $ | 1,443 | $ | 13,885 | |||||||||
2011 | |||||||||||||||||||
U.S. Transmission | $ | 1,746 | $ | 1,223 | $ | 221 | $ | 746 | $ | 12,438 | |||||||||
Liquids | — | — | — | — | — | ||||||||||||||
Total | 1,746 | 1,223 | 221 | 746 | 12,438 | ||||||||||||||
Other | — | (9 | ) | — | — | 7 | |||||||||||||
Depreciation and amortization | — | 221 | — | — | — | ||||||||||||||
Interest expense | — | 408 | — | — | — | ||||||||||||||
Interest income and other | — | 1 | — | — | — | ||||||||||||||
Total consolidated | $ | 1,746 | $ | 586 | $ | 221 | $ | 746 | $ | 12,445 | |||||||||
________
(a) | Excludes the $2,210 million net cash outlay for the U.S. Assets Dropdown in 2013, $343 million cash outlay for the acquisition of Express-Platte in 2013, and the $390 million acquisition of Big Sandy in 2011. |
Geographic Data (a)
U.S. | Canada | Consolidated | ||||||||||
(in millions) | ||||||||||||
2013 | ||||||||||||
Consolidated revenues | $ | 1,919 | $ | 46 | $ | 1,965 | ||||||
Consolidated long-lived assets | 15,975 | 254 | 16,229 | |||||||||
________
(a) | We did not own any Canadian assets prior to 2013. |
77
5. Regulatory Matters
Regulatory Assets and Liabilities.
We record assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for non-regulated entities. See Note 1 for further discussion.
December 31, | Recovery/Refund Period Ends | ||||||||
2013 | 2012 | ||||||||
(in millions) | |||||||||
Regulatory Assets (a,b) | |||||||||
Regulatory asset related to income taxes (c) | $ | 156 | $ | 124 | (d) | ||||
Vacation accrual | 17 | 16 | (f) | ||||||
Deferred debt expense/premium (g) | 32 | 38 | (e) | ||||||
Asset retirement obligations | 2 | 2 | |||||||
Under-recovery of fuel costs(h,i) | 28 | 13 | 2014 | ||||||
Project development costs | 2 | 2 | |||||||
Cost of service | 10 | 10 | 2036 | ||||||
Other | 7 | 7 | 2017 | ||||||
Total Regulatory Assets | $ | 254 | $ | 212 | |||||
Regulatory Liabilities (b) | |||||||||
Removal costs (g,l) | 5 | 5 | (k) | ||||||
Over-recovery of fuel costs (i,j) | 35 | 29 | 2014 | ||||||
Pipeline rate credit (l) | 26 | 28 | (e) | ||||||
Total Regulatory Liabilities | $ | 66 | $ | 62 | |||||
(a)Included in Regulatory Assets and Deferred Debits, unless otherwise noted.
(b)All regulatory assets and liabilities are excluded from rate base unless otherwise noted.
(c)Relates to tax gross-up of the AFUDC equity portion. All amounts are expected to be included in future rate filings.
(d) | Amortized over the life of the related property, plant and equipment. |
(e) | Recovery/refund is over the life of the associated asset or liability. |
(f)Recoverable in future periods.
(g) Included in rate base.
(h) Included in Other Current Assets.
(i) | Included in certain costs which are settled in cash annually through transportation rates in accordance with FERC gas tariffs. |
(j) Included in Other Current Liabilities.
(k) Liability is extinguished as the associated assets are retired.
(l) Included in Deferred Credits and Other Liabilities.
6. Income Taxes
In connection with the U.S. Assets Dropdown and resulting changes in tax status of certain entities, $354 million of deferred income tax liabilities were eliminated and recorded as a benefit to Income Tax Expense (Benefit) on the Consolidated Statement of Operations in 2013.
We are not subject to federal income tax. Our federal taxable income or loss is reported on the respective income tax returns of our partners. However, we are subject to Canadian foreign income tax and Tennessee and New Hampshire income tax. Market Hub is liable to Spectra Energy for Texas income (margin) tax under a tax sharing agreement.
78
7. Net Income Per Limited Partner Unit and Cash Distributions
The following table presents our net income per limited partner unit calculations:
2013 | 2012 | 2011 | |||||||||
(in millions, except per-unit amounts) | |||||||||||
Net income—controlling interests (a,b) | $ | 1,070 | $ | 580 | $ | 570 | |||||
Less: | |||||||||||
General partner’s interest in net income — 2% | 21 | 12 | 12 | ||||||||
General partner’s interest in net income attributable to incentive distribution rights | 62 | 25 | 17 | ||||||||
Limited partners’ interest in net income | $ | 987 | $ | 543 | $ | 541 | |||||
Weighted average limited partner units outstanding — basic and diluted (a) | 138 | 97 | 93 | ||||||||
Net income per limited partner unit — basic and diluted | $ | 7.15 | $ | 5.60 | $ | 5.82 | |||||
________
(a) | As discussed in Note 1, the Consolidated Financial Statements for periods prior to the November 1, 2013 U.S. Assets Dropdown, including Net Income—Controlling Interests as presented on our Consolidated Statements of Operations, have been recast. Weighted average limited partners units outstanding used in the calculation of net income per limited partner unit for periods prior to the U.S. Assets Dropdown has not been recast. |
(b) Includes a $354 million benefit related to the elimination of accumulated deferred income tax liabilities. See Note 6 for further discussion.
Our 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.
Available Cash. Available Cash, for any quarter, consists of all cash and cash equivalents on hand at the end of that quarter:
• | less the amount of cash reserves established by the general partner to: |
• | provide for the proper conduct of business, |
• | comply with applicable law, any debt instrument or other agreement, or |
• | provide funds for minimum quarterly distributions to the unitholders and to the general partner for any one or more of the next four quarters, |
• | plus, if the general partner so determines, all or a portion of cash and cash equivalents on hand on the date of determination of Available Cash for the quarter. |
Incentive Distribution Rights. The general partner holds incentive distribution rights beyond the first target distribution in accordance with the partnership agreement as follows:
Total Quarterly Distribution | Marginal Percentage Interest in Distributions | ||||||
Target Per-Unit Amount | Common Unitholders | General Partner | |||||
Minimum Quarterly Distribution | $0.30 | 98 | % | 2 | % | ||
First Target Distribution | up to $0.345 | 98 | % | 2 | % | ||
Second Target Distribution | above $0.345 up to $0.375 | 85 | % | 15 | % | ||
Third Target Distribution | above $0.375 up to $0.45 | 75 | % | 25 | % | ||
Thereafter | above $0.45 | 50 | % | 50 | % | ||
To the extent these incentive distributions are made to the general partner, there will be more Available Cash proportionately allocated to the general partner than to holders of common units. A cash distribution of $0.54625 per limited
79
partner unit was declared on February 4, 2014 and is payable on February 28, 2014 to unit holders of record at the close of business on February 14, 2014.
8. Investments in and Loans to Unconsolidated Affiliates
Investments in affiliates for which we are not the primary beneficiary, but over which we have significant influence, are
accounted for using the equity method. As of December 31, 2013 and 2012, the carrying amounts of investments in affiliates
approximated the amounts of underlying equity in net assets. We received distributions from our equity investments of $180 million in 2013, $106 million in 2012 and $107 million in 2011. There were no cumulative undistributed earnings of unconsolidated affiliates at December 31, 2013 or 2012.
U.S. Transmission. Investments are comprised of a 50% interest in Gulfstream, a 24.95% interest in SESH and a 49% interest in Steckman Ridge. Gulfstream is an interstate natural gas pipeline that extends from Mississippi and Alabama across the Gulf of Mexico to Florida. SESH is an interstate natural gas pipeline that extends from northeast Louisiana to Mobile County, Alabama where it connects to the Gulfstream system. Steckman Ridge is a storage project located in Bedford County, Pennsylvania.
We have a loan outstanding to Steckman Ridge in connection with the construction of its storage facilities. The loan carries market-based interest rates and is due the earlier of October 1, 2023 or coincident with the closing of any long-term
financings by Steckman Ridge. The loan receivable from Steckman Ridge, including accrued interest, totaled $71 million at December 31, 2013.
Liquids. Investments are comprised of 33.3% interests in Sand Hills and Southern Hills. The Sand Hills pipeline 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 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.
Investments in and Loans to Unconsolidated Affiliates
December 31, | |||||||
2013 | 2012 | ||||||
(in millions) | |||||||
U.S. Transmission | $ | 670 | $ | 619 | |||
Liquids | 726 | 517 | |||||
Total | $ | 1,396 | $ | 1,136 | |||
Equity in Earnings of Unconsolidated Affiliates
2013 | 2012 | 2011 | |||||||||
(in millions) | |||||||||||
U.S. Transmission | $ | 87 | $ | 86 | $ | 86 | |||||
Liquids | 2 | — | — | ||||||||
Total | $ | 89 | $ | 86 | $ | 86 | |||||
80
Summarized Combined Financial Information of Unconsolidated Affiliates (Presented at 100%)
Statements of Operations
2013 | 2012 | 2011 | |||||||||||||||||||||||||||||||||
Gulfstream | Other | Total | Gulfstream | Other | Total | Gulfstream | Other | Total | |||||||||||||||||||||||||||
(in millions) | |||||||||||||||||||||||||||||||||||
Operating revenues | $ | 274 | $ | 210 | $ | 484 | $ | 275 | $ | 157 | $ | 432 | $ | 273 | $ | 129 | $ | 402 | |||||||||||||||||
Operating expenses | 69 | 118 | 187 | 76 | 67 | 143 | 71 | 48 | 119 | ||||||||||||||||||||||||||
Operating income | 205 | 92 | 297 | 199 | 90 | 289 | 202 | 81 | 283 | ||||||||||||||||||||||||||
Net income | 135 | 70 | 205 | 129 | 69 | 198 | 132 | 61 | 193 | ||||||||||||||||||||||||||
Balance Sheets
December 31, 2013 | December 31, 2012 | ||||||||||||||||||||||
Gulfstream | Other | Total | Gulfstream | Other | Total | ||||||||||||||||||
(in millions) | |||||||||||||||||||||||
Current assets | $ | 92 | $ | 124 | $ | 216 | $ | 91 | $ | 92 | $ | 183 | |||||||||||
Non-current assets | 1,751 | 3,536 | 5,287 | 1,782 | 2,968 | 4,750 | |||||||||||||||||
Current liabilities | 18 | 118 | 136 | 19 | 89 | 108 | |||||||||||||||||
Non-current liabilities | 1,150 | 518 | 1,668 | 1,149 | 518 | 1,667 | |||||||||||||||||
Equity | $ | 675 | $ | 3,024 | $ | 3,699 | $ | 705 | $ | 2,453 | $ | 3,158 | |||||||||||
9. Goodwill
The following table presents activity within goodwill based on the reporting unit determination:
U.S. Transmission | Liquids | Total Goodwill | |||||||||||||||||
Enterprise Goodwill | Other Goodwill | Total | |||||||||||||||||
(in millions) | |||||||||||||||||||
December 31, 2011 | $ | 1,779 | $ | 987 | $ | 2,766 | $ | — | $ | 2,766 | |||||||||
Foreign currency translation | 48 | — | 48 | — | 48 | ||||||||||||||
December 31, 2012 | 1,827 | 987 | 2,814 | — | 2,814 | ||||||||||||||
Acquisition of Express-Platte | — | — | — | 486 | 486 | ||||||||||||||
Foreign currency translation | (82 | ) | — | (82 | ) | (3 | ) | (85 | ) | ||||||||||
December 31, 2013 | $ | 1,745 | $ | 987 | $ | 2,732 | $ | 483 | $ | 3,215 | |||||||||
A significant portion of goodwill originated from Spectra Energy’s acquisition of Westcoast Energy, Inc., a Canadian entity, in 2002. Following Spectra Energy’s separation from Duke Energy Corporation (Duke Energy) in 2007, a portion of the enterprise goodwill was assigned to the entities that were contributed in the U.S. Assets Dropdown. Since this goodwill originated from the acquisition of a Canadian entity, it was subject to foreign currency translation at the parent level. Effective with the closing of the U.S. Assets Dropdown, the associated portion of goodwill was included with the contributed entities we acquired. As a result, the associated portion of goodwill is no longer considered to be Spectra Energy's enterprise goodwill and, therefore, is deemed to be U.S. dollar-denominated and not subject to foreign currency translation.
10. Marketable Securities and Restricted Funds
We routinely invest excess cash and various restricted balances in securities such as commercial paper, bankers acceptances, corporate debt securities, treasury bill and money market funds in the United States. We do not purchase marketable securities for speculative purposes; therefore, we do not have any securities classified as trading securities. While
81
we do not routinely sell marketable securities prior to their scheduled maturity dates, some of our investments may be held and restricted for the purposes of funding future capital expenditures and acquisitions, so these investments are classified as AFS marketable securities as they may occasionally be sold prior to their scheduled maturity dates due to the unexpected timing of cash needs. Initial investments in securities are classified as purchases of the respective types of securities (AFS marketable securities or HTM marketable securities). Maturities of securities are classified within proceeds from sales and maturities of securities in the Consolidated Statements of Cash Flows.
AFS Securities. We had no AFS securities outstanding as of December 31, 2013. During the fourth quarter of 2012, we invested the proceeds from our issuance of common units in AFS marketable securities. These investments were restricted for the purpose of funding capital expenditures and acquisitions. We had $141 million in commercial paper classified as Investments and Other Assets - Other Investments-Restricted Funds on the Consolidated Balance Sheet as of December 31, 2012.
During the second quarter of 2013, we invested the proceeds from our issuance of common units in AFS marketable securities. These securities were restricted for the purpose of funding future capital expenditures and acquisitions. In September 2013, we issued $1.9 billion of long-term debt for which the net proceeds were restricted for the purpose of paying a portion of the cash consideration to Spectra Energy for the acquisition of its remaining U.S. transmission, storage, and liquids assets. All of our remaining AFS restricted funds held for the purpose of funding capital expenditure and acquisitions were used to pay Spectra Energy for the U.S. Assets Dropdown on November 1, 2013.
There were no material gross unrealized holding gains or losses associated with investments in AFS securities at December 31, 2012.
HTM Securities. All of our HTM securities held at December 31, 2013 are restricted funds. We had $3 million of money market securities classified as Current Assets - Other on the Consolidated Balance Sheet as of December 31, 2013. These securities are restricted pursuant to certain Express-Platte debt agreements. We had no HTM securities outstanding as of December 31, 2012.
At December 31, 2013, the weighted-average contractual maturity of outstanding HTM securities was less than one year.
There were no material gross unrealized holding gains or losses associated with investments in HTM securities at December 31, 2013.
Interest income. Interest income totaled $1 million in 2013, 2012, and 2011, and is included in Interest Income on the Consolidated Statements of Operations.
82
11. Property, Plant and Equipment
Estimated Useful Life | December 31, | |||||||||
2013 | 2012 | |||||||||
(years) | (in millions) | |||||||||
Plant | ||||||||||
Natural gas transmission | 15-100 | $ | 10,872 | $ | 9,629 | |||||
Natural gas storage | 10-122 | 1,454 | 1,251 | |||||||
Gathering and processing facilities | 25-40 | 12 | 12 | |||||||
Crude oil transportation and storage | 60-75 | 1,243 | — | |||||||
Land rights and rights of way | 20-122 | 421 | 319 | |||||||
Other buildings and improvements | 10-50 | 33 | 13 | |||||||
Equipment | 3-40 | 58 | 57 | |||||||
Vehicles | 5-15 | 9 | 8 | |||||||
Land | — | 70 | 62 | |||||||
Construction in process | — | 375 | 824 | |||||||
Software | 5-15 | 4 | 3 | |||||||
Other | 5-82 | 41 | 42 | |||||||
Total property, plant and equipment | 14,592 | 12,220 | ||||||||
Total accumulated depreciation | (3,125 | ) | (2,929 | ) | ||||||
Total accumulated amortization | (104 | ) | (97 | ) | ||||||
Total net property, plant and equipment | $ | 11,363 | $ | 9,194 | ||||||
We had no material capital leases at December 31, 2013 or December 31, 2012.
Almost 80% of our property, plant and equipment is regulated with estimated useful lives based on rates approved by the FERC. Composite weighted-average depreciation rates were 2.0% for 2013, 2.1% for 2012 and 2.1% for 2011.
Amortization expense of intangible assets totaled $7 million in both 2013 and 2012, and $8 million in 2011. Estimated amortization expense for the next five years follows:
Estimated Amortization Expense | |||
(in millions) | |||
2014 | $ | 7 | |
2015 | 7 | ||
2016 | 7 | ||
2017 | 7 | ||
2018 | 7 | ||
12. Asset Retirement Obligations
Our asset retirement obligations relate mostly to the retirement of offshore pipelines and certain onshore assets, obligations related to right-of-way agreements and contractual leases for land use. However, we have determined that a significant portion of our assets have an indeterminate life, and as such, the fair values of those associated retirement obligations are not reasonably estimable. These assets include onshore and some offshore pipelines, and certain storage facilities, whose retirement dates will depend mostly on the various natural gas supply sources that connect to our systems and the ongoing demand for natural gas usage in the markets we serve. We expect these supply sources and market demands to continue for the foreseeable future, therefore we are unable to estimate retirement dates that would result in asset retirement obligations.
83
Asset retirement obligations are adjusted each period for liabilities incurred or settled during the period, accretion expense and any revisions made to the estimated cash flows.
Reconciliation of Changes in Asset Retirement Obligation Liabilities
2013 | 2012 | ||||||
(in millions) | |||||||
Balance at Beginning of year | $ | 17 | $ | 16 | |||
Accretion expense | 1 | 1 | |||||
Revisions in estimated cash flows | (1 | ) | — | ||||
Balance at the end of the year (a) | $ | 17 | $ | 17 | |||
_________
(a)Amounts included in Deferred Credits and Other Liabilities in the Consolidated Balance Sheets.
13. Debt and Credit Facility
Summary of Debt and Related Terms
December 31, | |||||||
2013 | 2012 | ||||||
(in millions) | |||||||
Spectra Energy Partners, LP 2.95% senior unsecured notes due June 2016 | $ | 250 | $ | 250 | |||
Spectra Energy Partners, LP 2.95% senior unsecured notes due September 2018 | 500 | — | |||||
Spectra Energy Partners, LP variable-rate senior unsecured term loan due November 2018 | 400 | — | |||||
Spectra Energy Partners, LP 4.60% senior unsecured notes due June 2021 | 250 | 250 | |||||
Spectra Energy Partners, LP 4.75% senior unsecured noted due March 2024 | 1,000 | — | |||||
Spectra Energy Partners, LP 5.95% senior unsecured notes due September 2043 | 400 | — | |||||
Texas Eastern 6.00% senior unsecured notes due September 2017 | 400 | 400 | |||||
Texas Eastern 4.13% senior unsecured notes due December 2020 | 300 | 300 | |||||
Texas Eastern 2.80% senior unsecured notes due October 2022 | 500 | 500 | |||||
Texas Eastern 7.00% senior unsecured notes due July 2032 | 450 | 450 | |||||
Algonquin 3.51% senior unsecured notes due July 2024 | 350 | 350 | |||||
East Tennessee Natural Gas, LLC 3.10% senior unsecured notes due December 2024 | 200 | 200 | |||||
M&N US 7.50% senior unsecured notes due May 2014 | 411 | 429 | |||||
Express-Platte 6.09% senior secured notes due January 2020 | 110 | — | |||||
Express-Platte 7.39% subordinated secured notes due 2014 to 2019 | 104 | — | |||||
Long-term debt principal (including current maturities) | 5,625 | 3,129 | |||||
Notes payable—affiliates (including current maturities) | — | 4,202 | |||||
Unamortized debt discount, net | (2 | ) | (6 | ) | |||
Commercial paper (a) | 338 | 336 | |||||
Total debt | 5,961 | 7,661 | |||||
Current maturities of long-term debt | (445 | ) | (18 | ) | |||
Current maturities of note payable—affiliate | — | (17 | ) | ||||
Commercial paper (b) | (338 | ) | (336 | ) | |||
Total long-term debt | $ | 5,178 | $ | 7,290 | |||
_________
(a)The weighted-average days to maturity were 10 days as of December 31, 2013 and 17 days as of December 31, 2012.
(b) | Weighted-average rates outstanding on commercial paper were 0.33% as of December 31, 2013 and 0.75% as of December 31, 2012. |
84
Unsecured Debt. On September 25, 2013, we issued $1.9 billion aggregate principal amount of senior unsecured notes, comprised of $500 million of 2.95% senior notes due in 2018, $1 billion of 4.75% senior notes due in 2024 and $400 million of 5.95% senior notes due in 2043. Net proceeds from the offering were used in connection with the U.S. Assets Dropdown from Spectra Energy which closed on November 1, 2013.
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 was used in connection with the U.S. Assets Dropdown.
Secured Debt. Secured debt, totaling $214 million as of December 31, 2013, includes project financings for Express-Platte. The notes are secured by the assignment of the Express-Platte transportation receivables and by the Canadian portion of the Express-Platte pipeline system assets.
Floating Rate Debt. Debt included approximately $738 million of floating-rate debt as of December 31, 2013 and $988 million as of December 31, 2012. The weighted average interest rate of borrowings outstanding that contained floating rates was 0.85% at December 31, 2013 and 0.43% at December 31, 2012.
Notes Payable—Affiliates. Notes payable—affiliates, including current maturities, totaled $4,202 million as of December 31, 2012, comprised of $151 million to Southern Hills, $157 million to Sand Hills, $326 million to Bobcat and$3,551 million to Spectra Energy Transmission Resources, LLC, and a current maturity of $17 million to M&N US. The notes payable had variable interest rates with the exception of the note payable to Spectra Energy Transmission Resources, LLC, which had a fixed rate.
Annual Maturities
December 31, 2013 | |||
(in millions) | |||
2014 | $ | 445 | |
2015 | 32 | ||
2016 | 280 | ||
2017 | 412 | ||
2018 | 900 | ||
Thereafter | 3,554 | ||
Total long-term debt, including current maturities (a) | $ | 5,623 | |
_________
(a)Excludes commercial paper of $338 million.
We have the ability under certain debt facilities to repay the obligations prior to scheduled maturities. Therefore, the actual timing of future cash repayments could be materially different than presented above.
Credit Facility
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 billion and expires in 2018.
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 financial and other covenants, including the maintenance of a consolidated leverage ratio, as defined in the agreement. Failure to meet those covenants beyond applicable grace periods could result in
85
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 or other significant indebtedness of some of our subsidiaries. The credit agreement does not contain provisions that trigger an acceleration of indebtedness based solely on the occurrence of an adverse change in our financial condition or results of operations.
As noted above, the terms of the credit agreement requires us to maintain a consolidated leverage ratio of consolidated indebtedness to consolidated EBITDA, 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.
14. Fair Value Measurements
The following presents, for each of the fair value hierarchy levels, assets that are measured at fair value on a recurring basis as of December 31, 2012. Assets at December 31, 2012 consisted of commercial paper. There were no assets or liabilities measured at fair value on a recurring basis at December 31, 2013.
Consolidated Balance Sheet Caption | December 31, 2012 | ||||||||||||||
Total | Level 1 | Level 2 | Level 3 | ||||||||||||
(in millions) | |||||||||||||||
Cash and cash equivalents | $ | 15 | $ | — | $ | 15 | $ | — | |||||||
Investments and other assets — other investments-restricted funds | 141 | — | 141 | — | |||||||||||
Total Assets | $ | 156 | $ | — | $ | 156 | $ | — | |||||||
Level 1
Level 1 valuations represent quoted unadjusted prices for identical instruments in active markets.
Level 2 Valuation Techniques
Fair values of our financial instruments that are actively traded in the secondary market, including our long-term debt, are determined based on market-based prices. These valuations may include inputs such as quoted market prices of the exact or similar instruments, broker or dealer quotations, or alternative pricing sources that may include models or matrix pricing tools, with reasonable levels of price transparency.
Level 3 Valuation Techniques
Level 3 valuation techniques include the use of pricing models, discounted cash flow methodologies or similar techniques where at least one significant model assumption or input is unobservable. Level 3 financial instruments also include those for which the determination of fair value requires significant management judgment or estimation.
Financial Instruments. The fair values of financial instruments that are recorded and carried at book value are summarized in the following table. Judgment is required in interpreting market data to develop the estimates of fair value. These estimates are not necessarily indicative of the amounts we could have realized in current markets.
December 31, 2013 | December 31, 2012 | ||||||||||||||
Consolidated Balance Sheet Caption | Book Value | Approximate Fair Value | Book Value | Approximate Fair Value | |||||||||||
(in millions) | |||||||||||||||
Note receivable, noncurrent (a) | $ | 71 | $ | 71 | $ | — | $ | — | |||||||
Long-term debt, including current maturities (b) | 5,625 | 5,813 | 3,129 | 3,464 | |||||||||||
________
(a)Included within Investments in and Loans to Unconsolidated Affiliates.
(b)Excludes unamortized items.
The fair values of long-term debt are determined based on market-based prices as described in the Level 2 valuation technique above and are classified as Level 2.
86
The fair values of cash and cash equivalents, restricted cash, short-term investments, accounts receivable, notes receivable-noncurrent, accounts payable and commercial paper are not materially different from their carrying amounts because of the short-term nature of these instruments or because the stated rates approximate market rates. It is not practical to measure the fair value of notes payable - affiliates due to its related party nature.
During 2013 and 2012, there were no material adjustments to assets and liabilities measured at fair value on a nonrecurring basis.
15. Risk Management and Hedging Activities
Our floating-to-fixed interest rate swaps expired or were terminated in 2011 in conjunction with the pay down of our credit facility. Through December 31, 2013, unrealized net losses on the agreements have been deferred in AOCI in the Consolidated Balance Sheets. As of December 31, 2013, we did not have any derivatives outstanding.
Credit Risk Our principal customers for natural gas transmission and storage services are local distribution companies, industrial end-users, and natural gas marketers located throughout the United States and Canada. 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, including gas imbalance receivables, from these sectors throughout these regions. These concentrations of customers may affect our overall credit risk in that risk factors can negatively affect the credit quality of the entire sector. Where exposed to credit risk, we analyze the customers’ financial condition prior to entering into an agreement, establish credit limits and monitor the appropriateness of those limits on an ongoing basis. We also obtain parental guarantees, cash deposits, or letters of credit from customers to provide credit support, where appropriate, based on our financial analysis of the customer and the regulatory or contractual terms and conditions applicable to each contract.
Included in Current Liabilities - Other are collateral liabilities of $27 million at December 31, 2013 and $9 million at December 31, 2012, which represent cash collateral posted by third parties with us.
Interest Rate Risk. We are exposed to the impact of changes in interest rates as a result of our issuance of variable and fixed-rate debt and commercial paper. We manage our interest rate exposure by limiting our variable-rate exposure and by monitoring the effects of market changes in interest rates. The reclassifications from Other Comprehensive Income into income on derivatives follow:
Cash Flow Hedging Derivatives | Consolidated Statements of Operations Caption | 2013 | 2012 | 2011 | ||||||||||
(in millions) | ||||||||||||||
Interest rate swaps | Interest expense | $ | (1 | ) | $ | (1 | ) | $ | 2 | |||||
16. Commitments and Contingencies
General Insurance. We are insured through Spectra Energy’s master insurance program for insurance coverages consistent with companies engaged in similar commercial operations with similar type properties. Our insurance program includes (1) commercial general and excess liability insurance for liabilities to third parties for bodily injury and property damage resulting from our operations; (2) workers’ compensation liability coverage to required statutory limits; (3) automobile liability insurance for all owned, non-owned and hired vehicles covering liabilities to third parties for bodily injury and property damage; (4) insurance policies in support of the indemnification provisions of Spectra Energy’s by-laws and (5) property insurance, including machinery breakdown, on an all risk-replacement valued basis, onshore business interruption and extra expense. All coverages are subject to certain deductibles, terms and conditions common for companies with similar types of operations.
Environmental. We are subject to various federal, state and local laws and regulations regarding air and water quality, hazardous and solid waste disposal and other environmental matters. These laws and regulations can change from time to time, imposing new obligations on us.
Like others in the energy industry, we and our affiliates are responsible for environmental remediation at various contaminated sites. These include some properties that are part of our ongoing operations, sites formerly owned or used by us, and sites owned by third parties. Remediation typically involves management of contaminated soils and may involve groundwater remediation. Managed in conjunction with relevant federal, state/provincial and local agencies, activities vary with
87
site conditions and locations, remedial requirements, complexity and sharing of responsibility. If remediation activities involve statutory joint and several liability provisions, strict liability, or cost recovery or contribution actions, we or our affiliates could potentially be held responsible for contamination caused by other parties. In some instances, we may share liability associated with contamination with other potentially responsible parties, and may also benefit from insurance policies or contractual indemnities that cover some or all cleanup costs. All of these sites generally are managed in the normal course of business or affiliated operations.
Litigation. We are involved in legal, tax and regulatory proceedings in various forums arising in the ordinary course of business, including matters regarding contracts and payment claims, some of which may involve substantial monetary amounts. We have insurance coverage for certain of these losses should they be incurred. We believe that the final disposition of these proceedings will not have a material effect on our consolidated results of operations, financial position or cash flows.
Legal costs related to the defense of loss contingencies are expensed as incurred. We had no material reserves recorded as of December 31, 2013 or 2012 related to litigation.
Leases. We lease assets in various areas of our operations. Consolidated rental expense for operating leases was $21 million in 2013, $22 million in 2012 and $23 million in 2011. The following is a summary of future minimum lease payments under operating leases which at inception had noncancelable terms of more than one year. We had no material capital lease commitments at December 31, 2013.
Long-term Operating Leases | |||
(in millions) | |||
2014 | $ | 15 | |
2015 | 15 | ||
2016 | 15 | ||
2017 | 13 | ||
2018 | 11 | ||
Thereafter | 92 | ||
Total future minimum lease payments | $ | 161 | |
17. Issuances of Common Units
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 (NYSE), 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 November 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 for further discussion of the U.S. Assets Dropdown.
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 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 used to fund capital expenditures and acquisitions. Pending such use, the net proceeds of this offering were held as cash or invested in short-term securities, or a combination of both.
In 2012, we issued 5.5 million common units to the public representing limited partner interests. The net proceeds from this offering were $148 million, including our general partner’s proportionate unit purchase of 0.1 million general partner units.
88
The net proceeds from this issuance were held to fund capital expenditures and acquisitions, including the U.S. Assets Dropdown.
In 2011, we issued 7.2 million common units to the public representing limited partner interests. The net proceeds from this offering were $218 million, including our general partner’s proportionate unit purchase of 0.1 million general partner units. The net proceeds from this issuance were used to fund a portion of the purchase price of the Big Sandy acquisition. See Note 2 for additional information.
18. Equity-Based Compensation
Phantom units are granted under a Long-Term Incentive Plan to certain employees of Spectra Energy and vest over three years. We did not award phantom units in 2013 or 2011. We awarded 7,500 phantom units in 2012. There were no units vested in 2013. The total fair value of units vested in 2012 and 2011 was not significant.
Phantom Unit Awards | ||
Outstanding at December 31, 2012 | 7,500 | |
Granted | — | |
Vested | — | |
Forfeited | — | |
Outstanding at December 31, 2013 | 7,500 | |
Awards expected to vest | 7,060 | |
We account for the phantom units as liability awards. Compensation expense for these awards was not significant in 2013, 2012 or 2011. As of December 31, 2013 and assuming no change in fair value, we expect to recognize an insignificant amount of future compensation cost related to phantom awards in 2014.
19. Quarterly Financial Data (Unaudited)
First Quarter | Second Quarter | Third Quarter | Fourth Quarter | Total | |||||||||||||||
(in millions, except per-unit amounts) | |||||||||||||||||||
2013 | |||||||||||||||||||
Operating revenues | $ | 459 | $ | 492 | $ | 494 | $ | 520 | $ | 1,965 | |||||||||
Operating income | 249 | 243 | 234 | 247 | 973 | ||||||||||||||
Net income | 185 | 181 | 176 | 544 | 1,086 | ||||||||||||||
Net income — controlling interests | 181 | 177 | 172 | 540 | 1,070 | ||||||||||||||
Net income per limited partner unit (a,b) | 1.63 | 1.52 | 1.40 | 2.18 | 7.15 | ||||||||||||||
2012 | |||||||||||||||||||
Operating revenues | $ | 459 | $ | 429 | $ | 425 | $ | 441 | $ | 1,754 | |||||||||
Operating income | 253 | 216 | 208 | 220 | 897 | ||||||||||||||
Net income | 175 | 140 | 135 | 145 | 595 | ||||||||||||||
Net income — controlling interests | 171 | 136 | 132 | 141 | 580 | ||||||||||||||
Net income per limited partner unit (a) | 1.70 | 1.32 | 1.28 | 1.30 | 5.60 | ||||||||||||||
(a) | Quarterly net income per limited partner unit amounts are stand-alone calculations and may not be additive to full-year amounts due to rounding and changes in outstanding units. |
(b) | During the fourth quarter of 2013, we recorded a $354 million benefit related to the elimination of accumulated deferred income tax liabilities, which impacted net income and net income-controlling interests. See Note 6 for further discussion. This benefit impacted net income per limited partners unit by $1.56 for the quarter and $2.57 year-to-date. |
As discussed in Note 1, the Consolidated Financial Statements for periods prior to the November 1, 2013 U.S. Assets Dropdown have been recast. The quarterly information presented above has also been recast accordingly.
89
SPECTRA ENERGY PARTNERS, LP
SCHEDULE II — CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS AND
RESERVES
Balance at Beginning of Period | Additions: | Deductions(a) | Balance at End of Period | ||||||||||||||||
Charged to Expense | Charged to Other Accounts | ||||||||||||||||||
(in millions) | |||||||||||||||||||
December 31, 2013 | |||||||||||||||||||
Allowance for doubtful accounts | $ | — | $ | 1 | $ | — | $ | — | $ | 1 | |||||||||
$ | — | $ | 1 | $ | — | $ | — | $ | 1 | ||||||||||
December 31, 2012 | |||||||||||||||||||
Allowance for doubtful accounts | $ | 4 | $ | — | $ | — | $ | 4 | $ | — | |||||||||
$ | 4 | $ | — | $ | — | $ | 4 | $ | — | ||||||||||
December 31, 2011 | |||||||||||||||||||
Allowance for doubtful accounts | $ | 2 | $ | 4 | $ | — | $ | 2 | $ | 4 | |||||||||
$ | 2 | $ | 4 | $ | — | $ | 2 | $ | 4 | ||||||||||
_________
(a)Principally cash payments and reserve reversals.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
Item 9A. Controls and Procedures.
Disclosure controls and procedures are controls and other procedures that are designed to ensure that information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act of 1934 (Exchange Act) is recorded, processed, summarized, and reported within the time periods specified by the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to provide reasonable assurance that information required to be disclosed by us in the reports we file or submit under the Exchange Act is accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
Under the supervision and with the participation of the management of Spectra Energy Partners (DE) GP, LP (our General Partner), including the Chief Executive Officer and Chief Financial Officer, we have evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act) as of December 31, 2013, and, based upon this evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that these controls and procedures are effective at the reasonable assurance level.
Changes in Internal Control over Financial Reporting
Under the supervision and with the participation of the management of our General Partner, including the Chief Executive Officer and Chief Financial Officer, we have evaluated changes in internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the fiscal quarter ended December 31, 2013 and found no change that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.
Management’s Annual Report on Internal Control over Financial Reporting
The report of management required under this Item 9A is contained in Item 8. Financial Statements and Supplementary Data, Management’s Annual Report on Internal Control over Financial Reporting.
90
Attestation Report of Independent Registered Public Accounting Firm
The attestation report required under this Item 9A is contained in Item 8. Financial Statements and Supplementary Data, Report of Independent Registered Public Accounting Firm.
Item 9B. Other Information.
None.
91
PART III
Item 10. Directors, Executive Officers and Corporate Governance.
Management of Spectra Energy Partners, LP
We do not have directors or officers, which is commonly the case with publicly traded partnerships. Our operations and activities are managed by our general partner, Spectra Energy Partners (DE) GP, LP, which in turn is managed by its general partner, Spectra Energy Partners GP, LLC, (the General Partner). The General Partner is wholly owned by a subsidiary of Spectra Energy. The officers and directors of the General Partner are responsible for managing us. All of the directors of the General Partner are elected annually by Spectra Energy and all of the officers of the General Partner serve at the discretion of the directors. Unitholders are not entitled to participate, directly or indirectly, in management or operations.
Board of Directors and Officers
The Board of Directors of the General Partner currently has seven members, three of whom are independent as defined under the independence standards established by the New York Stock Exchange (NYSE). The NYSE does not require a listed limited partnership to have a majority of independent directors on its general partner’s Board of Directors or to establish a compensation committee or a nominating committee. However, the Board of Directors of the General Partner has established an audit committee (the Audit Committee) and a conflicts committee (the Conflicts Committee) to address conflict situations, each consisting of Nora Mead Brownell, Fred J. Fowler and J.D. Woodward, III.
The Board of Directors of the General Partner annually reviews the independence of directors and affirmatively makes a determination that each director expected to be independent has no material relationship with the General Partner, either directly or indirectly as a partner, unitholder or officer of an organization that has a relationship with the General Partner. The members of the Audit Committee each meet the independence and experience standards established by the NYSE and the Securities Exchange Act of 1934 (Exchange Act) as amended, to serve on an audit committee of a board of directors.
The officers of the General Partner manage the day-to-day affairs of our business. All of our executive management personnel are employees of Spectra Energy and devote a portion of their time to our business and affairs. We also utilize a significant number of employees of Spectra Energy to operate our business and provide general and administrative services. We reimburse Spectra Energy for allocated expenses of operational personnel who perform services for our benefit and for allocated general and administrative expenses.
The General Partner does not receive any management fee or other compensation for its management of our partnership under the amended and restated omnibus agreement with Spectra Energy (Omnibus Agreement) or otherwise. Under the terms of the Omnibus Agreement, we reimburse Spectra Energy for the provision of various general and administrative services for our benefit. We also reimburse Spectra Energy for direct expenses incurred on our behalf. The partnership agreement provides that the General Partner will determine the expenses that are allocable to us.
Meeting Attendance and Preparation
Members of the General Partner’s Board of Directors attended at least 90% of regular board meetings and meetings of the committees on which they serve, either in person or telephonically. In addition, directors are expected to be prepared for each meeting of the board by reviewing materials distributed in advance.
92
Directors and Executive Officers
The following table shows information regarding the current directors and executive officers of the General Partner. Directors are elected for one-year terms.
Name | Age | Position with Spectra Energy Partners GP, LLC | |||
Gregory L. Ebel | 49 | President, Chief Executive Officer and Chairman | |||
J. Patrick Reddy | 61 | Vice President and Chief Financial Officer | |||
Reginald D. Hedgebeth | 46 | General Counsel | |||
Fred J. Fowler | 68 | Director | |||
Dorothy M. Ables | 56 | Director | |||
Nora Mead Brownell | 67 | Director | |||
Julie A. Dill | 54 | Director | |||
J.D. Woodward, III | 64 | Director | |||
William T. Yardley | 49 | Director | |||
Directors of Spectra Energy Partners GP, LLC hold office until the earlier of their death, resignation, removal or disqualification or until their successors have been elected and qualified. Officers serve at the discretion of the Board of Directors. There are no family relationships among any of our directors or executive officers.
Gregory L. Ebel was appointed President, Chief Executive Officer and Chairman of the Board of Spectra Energy Partners GP, LLC on November 1, 2013. He is also President and Chief Executive Officer of Spectra Energy and a member of the company’s board of directors. Mr. Ebel served as Group Executive and Chief Financial Officer of Spectra Energy from January 2007 until assuming his current position at Spectra Energy in January 2009. Prior to that time, Mr. Ebel served as President of Union Gas Limited from January 2005 until January 2007, and Vice President, Investor & Shareholder Relations of Duke Energy from November 2002 until January 2005. Mr. Ebel joined Duke Energy in March 2002 as Managing Director of Mergers and Acquisitions in connection with Duke Energy’s acquisition of Westcoast Energy Inc. Mr. Ebel also serves on the board of directors for DCP Midstream, a joint venture between Spectra Energy and Phillips 66. Mr. Ebel is also a director of The Mosaic Company. He is a member of the National Petroleum Council, an oil and natural gas advisory committee to the U.S. Secretary of Energy, and former chair of the Interstate Natural Gas Association of America. Mr. Ebel was selected to serve as Chairman of Spectra Energy Partners GP, LLC because he serves as President and Chief Executive Officer and has served in a variety of senior management positions at Spectra Energy.
J. Patrick Reddy was appointed Vice President and Chief Financial Officer of Spectra Energy Partners GP, LLC effective March 2013. He is also Spectra Energy’s Chief Financial Officer, a position he assumed in January 2009. As Spectra Energy's Chief Financial Officer, he leads the financial function, which includes the controller’s office, financial planning and analysis, treasury, tax, risk management and insurance. He also serves on the board of directors for DCP Midstream, a joint venture between Spectra Energy and Phillips 66. Mr. Reddy is a member of the American Gas Association’s Leadership Council and serves on the Corporate Advisory Board of USC’s Marshall School of Business. He previously served on the board of directors for the Dallas Symphony.
Reginald D. Hedgebeth was appointed General Counsel of Spectra Energy GP, LLC in December 2013. He is also Spectra Energy's General Counsel and Chief Ethics and Compliance Officer. Mr. Hedgebeth joined Spectra Energy in March 2009. Prior to joining Spectra Energy, he served as Senior Vice President, General Counsel and Secretary with Circuit City Stores, Inc., a role he assumed in 2005. Mr. Hedgebeth currently serves on the board of directors of The Brink’s Company and previously served on the boards of the William Byrd Community House in Richmond, Va. and the Urban League of Greater Atlanta.
Fred J. Fowler was appointed to the Board of Directors of Spectra Energy Partners GP, LLC as its Chairman in December 2008, a position he held until November 1, 2013. He retired as President and Chief Executive Officer of Spectra Energy in December 2008, a position he held since its inception in January 2007. Mr. Fowler previously served as Group Executive and President of Duke Energy Gas Transmission from April 2006. He was President and Chief Operating Officer from November 2002 to April 2006. Mr. Fowler was elected to the board of EnCana Corp effective February 1, 2010. Mr. Fowler was elected to serve on the Pacific Gas and Electric Company board effective March 1, 2012. Mr. Fowler was elected to serve as a director because of his extensive knowledge and experience of the energy industry and its participants, as well as a deep understanding of our assets, customers and regulatory environments.
93
Dorothy M. Ables was appointed to the Board of Directors of Spectra Energy Partners GP, LLC in December 2013. She was named Chief Administrative Officer for Spectra Energy in November 2008, responsible for the company's information technology, audit services, human resources, supports services and community relations functions. Prior to then, she served as Spectra Energy's Vice President of Audit Services and Chief Ethics and Compliance Officer from 2007. Ms. Ables was appointed to the board because of her broad leadership experience with the company's natural gas transmission business, primarily in the strategic planning and financial areas and the areas of information technology, human resources, community relations and public affairs.
Nora Mead Brownell was appointed to the Board of Directors of Spectra Energy Partners GP, LLC in May 2007 and serves on our Audit Committee and the Conflicts Committee. In May 2001, Ms. Brownell was confirmed as Commissioner of the Federal Energy Regulatory Commission (FERC) where she served until the expiration of her term in June 2006. Prior to the FERC, Ms. Brownell served as a member of the Pennsylvania Public Utility Commission from 1997 to 2001. Ms. Brownell also currently serves on the Board of Directors of National Grid plc, ONCOR, Inc., a regulated electric distribution and transmission company and Tangent Energy Solutions, a private next generation energy services resource. Ms. Brownell is co-founder and principal of ESPY Energy Solutions, LLC, a woman-owned independent energy consulting company. Ms. Brownell was elected to serve as a director because she brings a diverse background that includes experience in business, finance and the regulatory arenas.
Julie A. Dill was appointed to the Board of Directors of Spectra Energy Partners GP, LLC effective January 1, 2012. Ms. Dill has served on the Board of QEP Resources since 2013. Ms. Dill is Chief Communications Officer of Spectra Energy. Prior to assuming her current role in January 2014, Ms. Dill served as President and Chief Executive Officer of Spectra Energy Partners GP, LLC and Group Vice President of Strategy for Spectra Energy. Ms. Dill served as Chair and President of Union Gas Limited from December 2006 through December 2011. Ms. Dill was Vice President of Investor Relations from 2004 and 2006 for Duke Energy. She served as Group Executive - Investor Relations and Chief Communications Officer from April 2006 until assuming her position with Union Gas in December 2006. Ms. Dill was appointed to the board because of her over 32 years of energy experience.
William T. Yardley was appointed to the board of directors of Spectra Energy Partners GP, LLC in August 2012. Mr. Yardley is President of Spectra Energy’s U.S. Transmission and Storage business, responsible for the company’s extensive network of natural gas infrastructure across the company. Mr. Yardley joined the company in 2000 as General Manager of Marketing for Spectra Energy’s predecessor company, Duke Energy Gas Transmission. He later served as Vice President of Marketing and Business Development and as Group Vice President of the company’s northeastern U.S. assets and operations. He was named to his current position in January 2013. Mr. Yardley currently serves on the board of the Northeast Gas Association and is a member of the Leadership Council of the American Gas Association. Mr. Yardley brings his business and industry expertise to the Board as well as his knowledge of our assets.
J.D. Woodward, III was appointed to the board in September 2009 and serves on the Conflicts Committee as Chairman and on the Audit Committee as Chairman. Mr. Woodward is a managing member of Woodward-Apple Springs, LLC, an owner and operator of natural gas midstream assets in East Texas, and a managing member of OGP Trinity, LLC, an owner of gas production properties and various leasehold interests in East Texas. He retired in 2006 from Atmos Energy as Senior Vice President of Non-Utility Operations. Mr. Woodward was selected to serve as a director because he understands the operations of a large corporation, with a particular focus on customer issues. Mr. Woodward is an experienced senior executive in the energy industry.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Exchange Act requires the General Partner’s directors and executive officers, and persons who own more than 10% of any class of our equity securities to file with the Securities and Exchange Commission (SEC) and the NYSE initial reports of ownership and reports of changes in ownership of our common units and other equity securities. Spectra Energy prepares and files these reports on behalf of the General Partner’s directors and executive officers. To our knowledge, all Section 16(a) reporting requirements applicable to the General Partner’s directors and executive officers were complied with during 2013.
Audit Committee
The Board of Directors of the General Partner has a standing audit committee composed of Nora Mead Brownell, Fred J. Fowler and J.D. Woodward, III, each of whom is able to understand fundamental financial statements and at least one of whom has past experience in accounting or related financial management experience. The Board has determined that each member of the Audit Committee is independent under Section 303A.02 of the NYSE listing standards and Section 10A(m)(3) of the Exchange Act, as amended. In making the independence determination, the Board considered the requirements of the NYSE.
94
The Audit Committee has adopted a charter, which has been ratified and approved by the Board of Directors. Mr. Woodward has been designated by the Board of Directors as the Audit Committee’s financial expert meeting the requirements promulgated by the SEC based upon his education and employment experience.
The Audit Committee assists the Board of Directors in its oversight of the integrity of our financial statements and compliance with legal and regulatory requirements and corporate policies and controls. The Audit Committee has the sole authority to retain and terminate our independent registered public accounting firm, approve all auditing services and related fees and terms thereof, and pre-approve any non-audit services to be rendered by our independent registered public accounting firm. The Audit Committee is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm has unrestricted access to the Audit Committee.
Conflicts Committee
The Board of Directors has a standing Conflicts Committee, which is comprised of Nora Mead Brownell, Fred J. Fowler and J.D. Woodward, III. The Conflicts Committee reviews specific matters that the Board of Directors believes may involve conflicts of interest. The Conflicts Committee will determine if the resolution of the conflict of interest is in the best interest of our partnership. The members of the Conflicts Committee may not be officers, employees or security holders of the General Partner, or directors, officers or employees of its affiliates. Any matters approved by the Conflicts Committee in good faith will be conclusively deemed to be fair and reasonable to us, approved by all of our partners, and not a breach by the General Partner of any duties it may owe us or our unitholders.
Principles for Corporate Governance and Code of Business Ethics
We have adopted Corporate Governance Guidelines that outline the important policies and practices regarding our governance. We have also adopted the Spectra Energy Code of Business Ethics applicable to persons serving as the General Partner’s officers and directors.
Copies of the Corporate Governance Guidelines, the Code of Business Ethics and the Audit Committee Charter are available online at www.spectraenergypartners.com. Copies of these items are also available free of charge in print to any unitholder who sends a request to the office of Investor Relations of our partnership at 5400 Westheimer Court, Houston, Texas 77056, (713) 627-4963.
Executive Sessions of the Board of Directors
As set forth in our Corporate Governance Guidelines and in accordance with NYSE listing standards, the Board of Directors of the General Partner holds executive sessions on a regular basis without the presence of management. Mr. Woodward, a non-management director, presides over all executive sessions.
Communications by Unitholders
Unitholders and other interested parties may communicate with any and all members of the Board of Directors, including non-management directors, by transmitting correspondence by mail or facsimile addressed to one or more directors by name or to the chairman of the Board of Directors or any committee of the Board of Directors at the following address and fax number; Name of the Director(s), c/o President, Spectra Energy Partners, LP, 5400 Westheimer Court, Houston, Texas 77056 fax: (713) 989-1818.
Report of the Audit Committee
The Audit Committee oversees our financial reporting process on behalf of the Board of Directors. Management has the primary responsibility for the financial statements and the reporting process including the systems of internal controls. The Audit Committee operates under a written charter approved by the Board of Directors. The charter, among other things, provides that the Audit Committee has authority to appoint, retain and oversee the independent auditor and is available on the corporate governance section on our website at www.spectraenergypartners.com.
In this context, the Audit Committee:
• | reviewed and discussed the audited financial statements in this annual report on Form 10-K with management, including a discussion of the quality, not just the acceptability, of the accounting principles, the reasonableness of significant judgments and the clarity of disclosures in the financial statements; |
• | reviewed with Deloitte & Touche, LLP, our independent auditors, who are responsible for expressing an opinion on the conformity of the audited financial statements with generally accepted accounting principles, their judgments as to the |
95
quality and acceptability of our accounting principles and such other matters as are required to be discussed with the Audit Committee under generally accepted auditing standards;
• | received the written disclosures and the letter required by applicable requirements of the Public Company Accounting Oversight Board regarding Deloitte & Touche, LLP’s communications with the audit committee concerning independence from Spectra Energy Partners and its subsidiaries, and has discussed with Deloitte & Touche, LLP the firm’s independence; |
• | discussed with Deloitte & Touche, LLP the matters required to be discussed by Statements on Auditing Standards No. 16; |
• | discussed with Spectra Energy’s internal auditors and Deloitte & Touche, LLP the overall scope and plans for their respective audits. The Audit Committee meets with the internal auditors and Deloitte & Touche, LLP, with and without management present, to discuss the results of their examinations, their evaluations of our internal controls and the overall quality of our financial reporting; |
• | based on the foregoing reviews and discussions, recommended to the Board of Directors that the audited financial statements be included in the annual report on Form 10-K for the year ended December 31, 2013, for filing with the SEC; and |
• | approved the selection and appointment of Deloitte & Touche, LLP to serve as our independent auditors. |
This report has been furnished by the members of the Audit Committee of the Board of Directors:
Audit Committee
Nora Mead Brownell
Fred J. Fowler
J.D. Woodward, III
February 17, 2014
The report of the Audit Committee in this report shall not be deemed incorporated by reference into any other filing by Spectra Energy Partners, LP under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, except to the extent that we specifically incorporate this information by reference, and shall not otherwise be deemed filed under such acts.
96
Item 11. Executive Compensation.
COMPENSATION DISCUSSION AND ANALYSIS
References below to “Spectra Energy Partners,” “we,” “our,” “us,” or similar terms refer to Spectra Energy Partners, LP.
This compensation discussion and analysis is intended to provide general information about the design and purpose of compensation programs applicable to the officers of the general partner of our partnership listed in the Summary Compensation Table. We do not directly employ any of the persons responsible for managing our business and we do not have a compensation committee. We are managed by our general partner, the executive officers of which are employees of Spectra Energy. Our reimbursement for the compensation of executive officers is governed by the Omnibus Agreement and is generally based on time allocated to us during a period.
Our principal executive officer, together with our principal financial officer are our "named executive officers." Ms. Julie Dill was Chief Executive Officer from January through October 2013 and effective November 1, 2013, Mr. Gregory L. Ebel was named Chief Executive Officer. Ms. Laura Sayavedra was Chief Financial Officer January and February 2013 and effective March 1, 2013, Mr. J. Patrick Reddy was named Chief Financial Officer. This compensation discussion and analysis provides information on both current and former named executive officers. Compensation paid or awarded by us in 2013 to our named executive officers reflects the total compensation paid by Spectra Energy, which includes compensation that is allocated to us pursuant to Spectra Energy’s allocation methodology and subject to the terms of the Omnibus Agreement. The Board of Directors of Spectra Energy, upon recommendation of the Compensation Committee of the Board of Directors of Spectra Energy (Compensation Committee), approves targeted compensation levels for the current Chief Executive Officer. The Compensation Committee has ultimate decision making authority with respect to the compensation of all remaining named executive officers other than with respect to awards of equity in our partnership, for which our Board retains control. Any awards under our long-term incentive plan are recommended by the Compensation Committee and approved by the Board of Directors of Spectra Energy Partners GP, LLC. The elements of compensation discussed below, and Spectra Energy’s decisions with respect to determinations on payments was approved by the Compensation Committee, and was not subject to approvals by the Board of Directors of our general partner.
With respect to compensation objectives and decisions regarding our named executive officers for 2013, the Compensation Committee approved the cash compensation and equity based compensation of our named executive officers based on its compensation philosophy, which includes rewarding both continued employment and performance through a combination of short-term cash incentives and long-term equity compensation. Senior management of Spectra Energy typically utilizes compensation consultants and reviews market data to determine relevant compensation levels and compensation program elements through the review of and, in certain cases, participation in, various relevant compensation surveys. Senior management then submits a proposal to the Compensation Committee for the compensation to be paid or awarded to executives and employees for consideration. Spectra Energy consulted with compensation consultants with respect to determining 2013 compensation for the named executive officers in a manner consistent with its current compensation philosophy. All compensation determinations are discretionary and are, as noted above, subject to Spectra Energy’s decision-making authority. A full discussion of the compensation policies and programs will be included in the Executive Compensation Discussion and Analysis section of Spectra Energy Corp's 2014 Proxy Statement which will be available upon its filing on the SEC's website at www.sec.gov and on Spectra Energy's website at www.spectraenergy.com at the "Investors - Publications and SEC Filings" tab.
The elements of Spectra Energy’s compensation program discussed below are intended to provide a compensation package designed to drive performance and reward contributions in support of the business strategies of Spectra Energy and its affiliates at the corporate, partnership and individual levels. Accordingly, a significant portion of the compensation provided to our executive officers has been in the form of short-term and long-term incentives.
Committee Advisors
Since 2007, the Compensation Committee has retained ExeQuity, LLP, as its independent compensation consultant. ExeQuity reports directly to the Compensation Committee on matters related to executive compensation, advises it on best practices and analyzes meeting materials prepared by management. It confers, independently of management, with the Compensation Committee and its Chair, although it may discuss compensation matters with management on a limited basis at the direction of the Compensation Committee. As needed, ExeQuity meets with the Compensation Committee in executive sessions without the presence of management. ExeQuity performs no other services for Spectra Energy other than its services as independent consultant to the Compensation Committee. In 2013, ExeQuity reviewed materials provided to the Compensation Committee by management, consulted with the Chair prior to meetings regarding agenda items and attended meetings of the Compensation Committee.
97
Elements of the Compensation Program
The objective of Spectra Energy’s compensation program is to link total compensation to both individual and company performance, on both a short and long-term basis, with significant percentages of potential earning opportunities based on the achievement of predetermined performance targets. As such, the compensation program is a valuable tool that assists us in attracting, retaining and incenting well qualified executives.
The following table sets forth the principal components of compensation for our named executive officers:
Component | Description | Rationale | ||
Salary | Paid in cash at regular intervals throughout the year. | Provides compensation for performing day-to-day responsibilities and creates a framework for incentive awards, which are structured as a percentage of base salary. | ||
Short-Term Incentive | Annual cash payment based on the achievement of defined financial and operational performance goals. | Makes significant percentage of cash compensation contingent on specific financial targets and operational performance objectives. These objectives are considered to be appropriate measures of the business imperatives that are necessary to build a solid record of financial success and operational excellence. | ||
Long-Term Incentive | Performance share units and phantom awards. | Rewards long-term company stock performance, aligns the interests of executives with unitholders and shareholders of Spectra Energy, creates equity ownership and provides retention incentive. | ||
Retirement | Spectra Energy sponsored retirement and savings plans. | Provides retention incentives and rewards service through retirement-related payments and provides savings opportunities. | ||
Factors Considered When Determining Total Compensation
Group Comparison. The Compensation Committee sets salaries and short-term and long-term incentive target levels based in part on what it believes to be the market median of compensation available to our executives in the market. The market for highly talented executives is competitive, and we believe our success depends on our ability to attract and retain executives who are qualified to successfully execute our long term objectives. We believe that hiring objectives cannot be achieved unless we offer compensation opportunities that are competitive in the marketplace. In setting compensation targets, the Compensation Committee considers data from both published compensation surveys as well as information from the public filings of companies in the markets where Spectra Energy competes for talent. Specifically, the Compensation Committee has used the Aon Hewitt Total Compensation Management Database as a source of market information because the Compensation Committee believes that the survey provides a reliable indication of compensation practices in companies that are comparable in size as measured by revenues.
External Market Conditions and Individual Factors. In addition to using benchmark survey data, the Compensation Committee takes into account external market conditions and individual factors when establishing the total compensation of the named executive officers. Some of these factors include the executive’s performance, level of experience, position, tenure and responsibilities, competitive pressures for that position within the industry, economic developments, the condition of labor markets and the financial and market performance of Spectra Energy.
Risk Assessment of Total Compensation. The overall compensation mix of short-term and long-term compensation opportunities for our executives, as well as the components of these incentive opportunities are balanced to mitigate undue risk. No single measure of the short-term compensation program is greater than 30% of a named executive officer's targeted award. Sixty percent of the executives’ long-term opportunity is contingent on the performance of Spectra Energy’s stock relative to its peers and stock ownership levels are required of the executives.
98
2013 Compensation Opportunities
The following table shows the 2013 target direct pay opportunities for our named executive officers.
2013 Target Pay Opportunity
Name | Salary | Short-Term Incentive Target Opportunity | Long-Term Incentive Target Opportunity | Total Target Pay Opportunity | ||||||||||
Gregory L. Ebel | $ | 1,100,000 | 100 | % | 325 | % | $ | 5,775,000 | ||||||
J. Patrick Reddy | $ | 591,660 | 75 | % | 170 | % | $ | 2,041,227 | ||||||
Julie Dill | $ | 384,312 | 50 | % | 135 | % | $ | 1,095,288 | ||||||
Laura Buss Sayavedra | $ | 236,323 | 40 | % | 50 | % | $ | 449,014 | ||||||
Salary. In February 2013, the Compensation Committee considered whether adjustments to salaries were appropriate and adjusted 2013 salaries of the named executive officers at that time, based upon job responsibilities, level of experience, company and individual performance, comparisons to the salaries of executives in similar positions obtained from peer data, market surveys and internal comparisons.
Short-Term Incentives. Short-term incentive opportunities, awarded under the Spectra Energy Executive Short-Term Incentive (STI) Plan for 2013, were designed to compensate executives for financial and operational performance during the year based on goals set at the beginning of the year and for overall individual performance during the year. The threshold, target and maximum incentive opportunities for each participant in the STI Plan during 2013 were established as a percentage of base salary. Cash incentives were earned based on the achievement of corporate and business unit financial and operational goals as determined by the Compensation Committee, with the Compensation Committee having discretion to adjust payments based on assessments of individual performance. Target STI awards expressed as a percentage of base annual salary for our named executive officers in 2013 are reflected in the “2013 Target Pay Opportunity” table above.
Under guidelines adopted for the 2013 STI program, participants were eligible to receive up to 200% of the amount of their STI target. The maximum that could be earned for performance on financial or operational measures was 200% of target. The amount that could be paid for performance at a specified minimum level for any measure was 50% of the target amount. 100% of the target amount would be paid for performance at the target level. No compensation was to be earned if performance fell below a specified minimum level.
As shown in the following table, STI payments for our named executive officers were based on the achievement of financial and operational objectives related to management responsibilities for Spectra Energy and Spectra Energy Partners, with an additional review based on an overall assessment of individual performance during the year.
2013 Target Incentive Payment Opportunity
Messrs. Ebel and Reddy | Mses. Dill and Sayavedra* | |||
Measures | Percentage | |||
Spectra Energy Ongoing EPS | 30 | % | 20 | % |
Spectra Energy Transmission EBIT | 25 | % | — | |
Spectra Energy Transmission Return on Capital Employed (ROCE) | 20 | % | 20 | % |
Spectra Energy Partners Distributable Cash | — | 25 | % | |
Environmental, Health and Safety Scorecards | 10 | % | 10 | % |
Operational and Capital Project Scorecards | 15 | % | 25 | % |
*Only reflects measures applicable while an officer of Spectra Energy Partners | ||||
99
Determination of 2013 Short-Term Incentive Payments
At the end of the 2013 cycle, management prepared a report on the achievement of financial and operational goals. These results were reviewed and approved by the Compensation Committee in February 2014 along with any proposed adjustments based on individual performance for our named executive officers. Any adjustments based on individual performance were reviewed by the Compensation Committee, which then approved the final performance results and payment of incentives for our named executive officers.
The amounts set forth below show target amounts for achieving the threshold, target and maximum levels established for each financial goal as well as the actual result. The percentage of the target opportunity achieved is shown in parentheses. For each category, achievement of the Threshold, Target and Maximum amounts would result in the payment of 50%, 100% and 200%, respectively, of the target level. For instance, the short-term incentive payment for an executive associated with Spectra Energy Transmission’s ROCE results was calculated as 20% of such executive’s target cash incentive opportunity multiplied by the actual percentage achieved, which was 155.71%.
Measures | Threshold | Target | Maximum | Actual | ||||||||||
Spectra Energy Ongoing EPS | $ | 1.25 | $ | 1.50 | $ | 1.85 | $1.64 (140.00%) | |||||||
Spectra Energy Transmission EBIT (in millions) | $ | 1,788 | $ | 1,863 | $ | 2,012 | $1,907.7 (130.00%) | |||||||
Spectra Energy Transmission Return on Capital Employed | 8.3 | % | 8.6 | % | 9.3 | % | 8.99% (155.71%) | |||||||
Spectra Energy Partners Distributable Cash (in millions) | $ | 247 | $ | 256 | $ | 274 | $269.0 (172.22%) | |||||||
The Environmental, Health and Safety Scorecard achieved a payout percentage of 92.65%. The weighting of elements on the Operational and Capital Project Scorecard differ for various levels of management in the Spectra Energy organization. The Operational and Capital Project Scorecard achieved a payout percentage of 107.41% for Messrs. Ebel and Reddy and for Mses. Dill and Sayavedra, it achieved a payout percentage of 126.51%. In determining final award amounts for Messrs. Ebel and Reddy, the Compensation Committee also considered other factors driving Spectra Energy's strong performance in 2013, such as the successful delivery of new projects placed into service, including the New Jersey-New York pipeline, the recent dropdown of assets into Spectra Energy Partners, creating one of the largest fee-based master limited partnerships in North America, the successful acquisition of the Express-Platte Pipeline System and a total shareholder return of 35% for Spectra Energy in 2013.
The following table is a summary of the payments made to our named executive officers.
2013 STI Awards
Name | Short-Term Incentive Award | Actual Payout as a Percent of Target Short-Term Incentive Award | |||||
Gregory L. Ebel | $ | 1,941,204 | 176 | % | |||
J. Patrick Reddy | $ | 681,388 | 154 | % | |||
Julie Dill | $ | 274,955 | 143 | % | |||
Laura Buss Sayavedra | $ | 128,508 | 134 | % | |||
Long-Term Incentives. Spectra Energy provides long-term incentive opportunities to our executive officers to achieve an alignment of executive and shareholder interests and motivate executives to achieve strategic goals that will maximize shareholder value.
The Compensation Committee decided that its long term incentive program would consist of awards that result in share ownership when certain specific performance goals are achieved in combination with phantom units that vest over a three-year period. We believe that the combination of these two forms of awards are an effective means of creating a focus on returns to shareholders and retaining our executive talent in a competitive market.
For 2013, the performance share unit awards continued to make up 60% of the target value of annual long-term compensation and are earned based on how Spectra Energy performs relative to a group of energy companies over a three-year period. The companies in Spectra Energy’s long-term incentive (LTI) peer group are:
100
Ameren Corporation | CenterPoint Energy, Inc. | Consolidated Edison, Inc. | ||
Dominion Resources, Inc. | DTE Energy Company | Enbridge Inc. | ||
EQT Corporation | Kinder Morgan, Inc. | NiSource Inc. | ||
National Fuel Gas Company | ONEOK, Inc. | PG&E Corporation | ||
Public Service Enterprise Group | Questar Corp. | Sempra Energy | ||
TransCanada Corporation | The Williams Companies, Inc. | Xcel Energy Inc. | ||
The Performance share unit awards generally vest only to the extent Spectra Energy’s Total Shareholder Return (TSR) is achieved over a three-year measurement period, as compared to the peer group, in accordance with the percentages outlined in the following table:
Relative TSR Performance Results | Percent Payout of Target Performance Share Units | |
80th Percentile or Higher | 200 | % |
50th Percentile (Target) | 100 | % |
30th Percentile | 50 | % |
Below 30th Percentile | — | % |
The Compensation Committee approved the percentages after reviewing similar plans adopted by many of the companies in the peer group, reviewing the historical returns of the peer group as well as indices that track energy company performance, and after consultations with Spectra Energy’s outside compensation advisors. Once earned, half of the performance share units will be converted to shares of Spectra Energy common stock and half will be paid in cash, based on the fair market value of Spectra Energy common stock at the time of vesting. The payout design is intended to provide for stock accumulation while also allowing for investment diversification.
Phantom units comprised the remaining 40% of annual long-term compensation grant value. These units will vest at the end of three years at which time they will be converted to shares of Spectra Energy common stock. Dividend equivalents accumulated from the date of grant will be paid in cash on the number of performance share units and phantom units at the time which these units vest.
The table below shows long-term incentive awards granted to our named executive officers in 2013:
Name | Expected Value of Long-Term Incentive/Equity Grants as a Percentage of Base Salary | Number of Performance Share Units Granted | Number of Phantom Units Granted | ||||||
Gregory L. Ebel | 325 | % | 88,000 | 55,400 | |||||
J. Patrick Reddy | 170 | % | 24,800 | 15,600 | |||||
Julie Dill | 135 | % | 12,800 | 8,000 | |||||
Laura Buss Sayavedra | 50 | % | 2,900 | 1,900 | |||||
Determination of 2011-2013 Performance Share Unit Awards. The 2011 performance share unit cycle commenced on January 1, 2011 and ended on December 31, 2013. The performance share units vest based on Spectra Energy’s total shareholder return for the three year period as compared to the total shareholder return for companies in Spectra Energy’s customized long-term incentive peer group, which is the same long-term incentive peer group used for the 2013 awards listed above, with the exception of Kinder Morgan. Spectra Energy’s total shareholder return for the three year period is 53.88% which is at the 46.5 percentile of the peer group. This results in a payout percentage of 91.25%. The following table lists the resulting number of 2011-2013 performance share units that vested and the amount of associated dividend equivalents:
101
Name | Vested Performance Share Units | Dividend Equivalent Payment | |||||
Gregory L. Ebel | 78,932 | $ | 276,262 | ||||
J. Patrick Reddy | 22,266 | $ | 77,931 | ||||
Julie Dill | 12,594 | $ | 44,079 | ||||
Laura Buss Sayavedra | 2,830 | $ | 9,905 | ||||
Retirement and Other Benefits. Spectra Energy provides our executives with retirement benefits under the Spectra Energy Retirement Savings Plan, the Spectra Energy Executive Savings Plan, the Spectra Energy Retirement Cash Balance Plan and the Spectra Energy Executive Cash Balance Plan. The Compensation Committee has determined that, based on market surveys, these plans are comparable to the benefits provided by our peers and provide an important tool for attracting and retaining our executives. Refer to “Executive Compensation” for disclosure of the amounts paid to our named executive officers under these plans.
The Spectra Energy Retirement Savings Plan, a “401(k) plan,” is generally available to all employees in the United States. The plan is a tax-qualified retirement plan that provides a means for employees to save for retirement on a tax-deferred basis and to receive an employer matching contribution. Earnings on amounts credited to the Spectra Energy Retirement Savings Plan are determined by reference to investment choices (including a Spectra Energy Common Stock Fund) selected by each participant.
The Spectra Energy Executive Savings Plan enables executives to defer compensation, and receive employer matching contributions, in excess of the limits of the Internal Revenue Code, that apply to qualified retirement plans such as the Spectra Energy Retirement Savings Plan. Earnings on amounts credited to the Spectra Energy Executive Savings Plan are determined by reference to investment choices similar to those offered under the Spectra Energy Retirement Savings Plan.
The Spectra Energy Retirement Cash Balance Plan provides a defined benefit for retirement, the amount of which is based on a participant’s cash balance account balance, which grows with monthly pay and interest credits.
The Spectra Energy Executive Cash Balance Plan provides executives with the retirement benefits to which they would be entitled under the Spectra Energy Retirement Cash Balance Plan if the limits contained in the Internal Revenue Code, did not exist.
Perquisites and Personal Benefits. At the direction of Spectra Energy's Board of Directors, Mr. Ebel uses the Spectra Energy aircraft for personal travel in limited circumstances, primarily for business efficiency. Mr. Ebel's family and guests may accompany him on business and personal trips. Other executive officers are not allowed to initiate personal trips on corporate or chartered aircraft. However, executive officers are permitted to bring their spouses or personal guests on business-related flights when space is available. When the executive officer’s use of aircraft or a guest’s travel does not meet the Internal Revenue Service’s (IRS) standard for business use, the cost of that travel is imputed as income to the officer.
Audit Committee Report
The Audit Committee of the Board reviewed and discussed with management the Compensation Discussion and Analysis contained in this Annual Report on Form 10-K and, based on these reviews and discussions, recommended that the Compensation Discussion and Analysis be included in this Annual Report on Form 10-K.
Nora Mead Brownell
Fred J. Fowler
J.D. Woodward, III
102
EXECUTIVE COMPENSATION
The table below sets forth compensation of Spectra Energy Partners’ named executive officers for 2011 through 2013, and reflects the total compensation paid by Spectra Energy, which includes compensation that is allocated to us pursuant to Spectra Energy’s allocation methodology and subject to the terms of the Omnibus Agreement.
SUMMARY COMPENSATION TABLE
Name and Principal Position | Year | Salary ($) | Bonus ($) | Stock Awards ($)(1) | Option Awards ($) | Non-Equity Incentive Plan Compensation ($)(2) | Change in Pension Value and Nonqualified Deferred Compensation Earnings ($)(3) | All Other Compensation ($)(4) | Total ($) | ||||||||||||||||
Gregory L. Ebel (8) (9) | 2013 | 1,094,167 | — | 4,841,116 | — | 1,941,204 | 249,233 | 175,023 | 8,300,743 | ||||||||||||||||
President and Chief Executive Officer | |||||||||||||||||||||||||
J. Patrick Reddy (7) | 2013 | 588,788 | — | 1,363,936 | — | 681,388 | 99,231 | 67,069 | 2,800,412 | ||||||||||||||||
Vice President and Chief Financial Officer | |||||||||||||||||||||||||
Julie Dill (5) | 2013 | 382,446 | — | 702,432 | — | 274,955 | 69,189 | 549,243 | 1,978,265 | ||||||||||||||||
Former President and Chief Executive Officer | 2012 | 371,015 | — | 964,339 | — | 212,271 | 136,445 | 1,423,007 | 3,107,077 | ||||||||||||||||
Laura Buss Sayavedra (6) | 2013 | 238,176 | — | 161,747 | — | 128,508 | 35,534 | 32,509 | 596,474 | ||||||||||||||||
Former Vice President and Chief Financial Officer | 2012 | 227,773 | — | 163,645 | — | 183,552 | 79,507 | 25,652 | 680,130 | ||||||||||||||||
2011 | 219,440 | — | 149,471 | — | 118,470 | 68,361 | 27,798 | 583,540 | |||||||||||||||||
________
(1) | This column reflects the aggregate grant date fair value computed in accordance with the provisions of FASB ASC Topic 718 with respect to performance share units and phantom unit awards granted each year. The aggregate dollar amount was determined without regard to any estimate of forfeitures related to service-based vesting conditions. If the performance share units vested at the maximum level, the following represents the maximum value that would be payable on the performance share units based on the closing stock price of our common stock on the grant date of these awards for Messrs. Ebel and Reddy and Mses. Dill and Sayavedra in the amount of $5,234,240, $1,475,104, $761,344, and $172,492, respectively. |
(2) | This column includes amounts payable under the Spectra Energy STI Plan with respect to the 2013, 2012 and 2011 performance periods. Unless deferred, these amounts were paid in February 2014, March 2013 and March 2012, respectively. |
(3) | This column includes the amounts listed below. These figures represent the change in value during the twelve month period ending December 31. |
103
Gregory L. Ebel | J. Patrick Reddy | Julie Dill | Laura Buss Sayavedra | |||||||||||||
Change in actuarial present value of accumulated benefit under the Spectra Energy Retirement Cash Balance Plan for the period beginning on January 1, 2013 and ending on December 31, 2013 | $ | 21,537 | $ | 24,060 | $ | 27,286 | $ | 18,717 | ||||||||
Change in actuarial present value of accumulated benefit under the Spectra Energy Executive Cash Balance Plan for the period beginning on January 1, 2013 and ending on December 31, 2013 | 169,778 | 75,171 | 41,903 | 16,817 | ||||||||||||
Change in actuarial present value of accumulated benefit under the Pension Choices Plan for Employees of Westcoast Energy Inc. and Affiliated Companies for the period beginning on January 1, 2013 and ending on December 31, 2013 | (8,083 | ) | — | — | — | |||||||||||
Change in actuarial present value of accumulated benefit under the Spectra Energy Supplemental Pension Plan for the period beginning on January 1, 2013 and ending on December 31, 2013 | 66,001 | — | — | — | ||||||||||||
Total | $ | 249,233 | $ | 99,231 | $ | 69,189 | $ | 35,534 | ||||||||
________
(4)All Other Compensation column includes the compensation set forth in the following table for 2013:
Gregory L. Ebel | J. Patrick Reddy | Julie Dill | Laura Buss Sayavedra | |||||||||||||
Matching contributions under the Spectra Energy Retirement Savings Plan | $ | 15,300 | $ | 15,300 | $ | 15,300 | $ | 15,055 | ||||||||
Premiums for life insurance coverage provided under Life Insurance Plans | 1,710 | 7,524 | 1,969 | 755 | ||||||||||||
Make-whole matching contribution credits under the Spectra Energy Executive Savings Plan | 98,275 | 39,364 | 20,383 | 10,249 | ||||||||||||
Charitable contributions made in the name of the Executive under Spectra Energy’s matching gift policy | 7,000 | — | 4,550 | 6,450 | ||||||||||||
Tax return preparation services | 3,450 | 3,000 | — | |||||||||||||
Personal use of Company aircraft | 49,288 | 4,881 | — | — | ||||||||||||
Foreign taxes paid related to former expatriate assignment in Canada* | — | — | 504,041 | — | ||||||||||||
Total | $ | 175,023 | $ | 67,069 | $ | 549,243 | $ | 32,509 | ||||||||
________
*The amount was $1,363,924 for 2012.
(5) | Ms. Dill was President and Chief Executive Officer from January 1, 2012 through October 31, 2013. Compensation for the entire fiscal year 2013 and 2012 is disclosed for Ms. Dill. |
(6) | Ms. Sayavedra was Chief Financial Officer from July 1, 2008 through February 28, 2013. Compensation for the entire fiscal years 2013, 2012 and 2011 is disclosed for Ms. Sayavedra. |
(7) | Mr. Reddy became Chief Financial Officer effective March 1, 2013. Compensation for the entire fiscal year 2013 is disclosed for Mr. Reddy. |
(8) | Mr. Ebel became President and Chief Executive Officer effective November 1, 2013. Compensation for the entire fiscal year 2013 is disclosed for Mr. Ebel. |
(9) | A portion of Mr. Ebel's pension value for 2013 was provided in Canadian dollars and has been converted to U.S. dollars using the Bloomberg spot rate of $0.9414 on December 31, 2013. |
104
2013 GRANTS OF PLAN-BASED AWARDS
Name | Grant Date | Committee Approval Date | Estimated Possible Payouts Under Non-Equity Incentive Plan Awards(1) | Estimated Future Payouts Under Equity Incentive Plan Awards(2) | All Other Stock Awards: Number of Shares of Stock or Units (#)(2) | Grant Date Fair Value of Stock and Option Awards ($)(3) | ||||||||||||||||||||||
Threshold ($) | Target ($) | Maximum ($) | Threshold (#) | Target (#) | Maximum (#) | |||||||||||||||||||||||
Gregory L. Ebel | 550,000 | 1,100,000 | 2,200,000 | |||||||||||||||||||||||||
Gregory L. Ebel | 2/19/2013 | 2/18/2013 | 44,000 | 88,000 | 176,000 | 3,193,520 | ||||||||||||||||||||||
Gregory L. Ebel | 2/19/2013 | 2/18/2013 | 55,400 | 1,647,596 | ||||||||||||||||||||||||
J. Patrick Reddy | 221,873 | 443,745 | 887,490 | |||||||||||||||||||||||||
J. Patrick Reddy | 2/19/2013 | 2/18/2013 | 12,400 | 24,800 | 49,600 | 899,992 | ||||||||||||||||||||||
J. Patrick Reddy | 2/19/2013 | 2/18/2013 | 15,600 | 463,944 | ||||||||||||||||||||||||
Julie Dill | 96,078 | 192,156 | 384,312 | |||||||||||||||||||||||||
Julie Dill | 2/19/2013 | 2/18/2013 | 6,400 | 12,800 | 25,600 | 464,512 | ||||||||||||||||||||||
Julie Dill | 2/19/2013 | 2/18/2013 | 8,000 | 237,920 | ||||||||||||||||||||||||
Laura Buss Sayavedra | 47,265 | 94,529 | 189,058 | |||||||||||||||||||||||||
Laura Buss Sayavedra | 2/19/2013 | 2/18/2013 | 1,450 | 2,900 | 5,800 | 105,241 | ||||||||||||||||||||||
Laura Buss Sayavedra | 2/19/2013 | 2/18/2013 | 1,900 | 56,506 | ||||||||||||||||||||||||
_______
(1) | The awards reflected in the Estimated Possible Payouts Under Non-Equity Incentive Plan Awards column were granted for the 2013 performance period under the terms of the Spectra Energy Corp Executive STI Plan. The actual amounts payable to each executive under the terms of such plan are disclosed in the Summary Compensation Table. |
(2) | Awards reflected in these columns with a grant date of February 19, 2013 were made in units of Spectra Energy common stock and were granted under the terms of the Spectra Energy Corp 2007 Long-Term Incentive Plan, as amended and restated. |
(3) | All awards reflected in this column were computed in accordance with FASB ASC Topic 718. The per share full grant date fair value of the phantom units and performance share units granted on February 19, 2013 is $29.74 and $36.29, respectively. |
105
OUTSTANDING EQUITY AWARDS AT 2013 FISCAL YEAR-END
Option Awards | Stock Awards | |||||||||||||||||||||||||
Name | Number of Securities Underlying Unexercised Options (#) Exercisable | Number of Securities Underlying Unexercised Options (#) Unexercisable | Option Exercise Price ($)(1) | Option Expiration Date | Number of Shares or Units of Stock That Have Not Vested (#)(2) | Market Value of Shares or Units of Stock That Have Not Vested ($) | Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested (#)(3) | Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested ($) | ||||||||||||||||||
Gregory L. Ebel | SE | 76,700 | 25.64 | 2/27/2017 | SE | 160,500 | 5,717,010 | 170,200 | 6,062,524 | |||||||||||||||||
J. Patrick Reddy | SE | 47,620 | 1,696,224 | 45,900 | 1,634,958 | |||||||||||||||||||||
Julie Dill (4) | SE | 38,300 | 25.64 | 2/27/2017 | SE | 24,000 | 854,880 | 24,800 | 883,376 | |||||||||||||||||
SEP | 7,500 | 340,125 | ||||||||||||||||||||||||
Total | 1,195,005 | |||||||||||||||||||||||||
Laura Buss Sayavedra | SE | 10,100 | 25.64 | 2/27/2017 | SE | 5,500 | 195,910 | 5,600 | 199,472 | |||||||||||||||||
______
(1) | For options granted February 27, 2007, the exercise price is equal to the closing price of Spectra Energy common stock on the date of grant. |
(2) | Messrs. Ebel and Reddy and Mses. Dill and Sayavedra received Spectra Energy phantom units on February 19, 2013, February 21, 2012 and February 22, 2011, which, subject to certain exceptions, vest on the third anniversary of the date of grant. |
(3) | Messrs. Ebel and Reddy and Mses. Dill and Sayavedra received Spectra Energy performance share units on February 19, 2013 and February 21, 2012 that, subject to certain exceptions, are eligible for vesting on December 31, 2014 and December 31, 2013, respectively. Pursuant to Instruction 3 to Item 402(f)(2) of Regulation S-K, performance share units are listed at the targeted number of units. |
(4) | On January 3, 2012, Ms. Dill received a grant in the amount of 7,500 units, which, subject to certain exceptions, vest on the third anniversary of the date of grant. |
106
2013 OPTION EXERCISES AND STOCK VESTED
Option Awards | Stock Awards | |||||||||||
Name | Number of Shares Acquired on Exercise(#) | Value Realized on Exercise($)(1) | Number of Shares Acquired on Vesting(#)(2) | Value Realized on Vesting($)(3) | ||||||||
Gregory L. Ebel | ||||||||||||
Spectra Energy | 4,300 | 73,573 | 144,532 | 5,351,061 | ||||||||
J. Patrick Reddy | ||||||||||||
Spectra Energy | — | — | 47,386 | 1,724,456 | ||||||||
Julie Dill | ||||||||||||
Spectra Energy | 12,850 | 227,702 | 25,294 | 944,202 | ||||||||
Laura Buss Sayavedra | ||||||||||||
Spectra Energy | 825 | 14,520 | 5,630 | 206,541 | ||||||||
________
(1) | The value realized upon exercise was calculated based on the closing price of a share of Spectra Energy common stock on the date of option exercise. |
(2) | Time-vested shares included in this column are 65,500 to Mr. Ebel, 25,120 to Mr. Reddy, 12,700 to Ms. Dill and 2,800 to Ms. Sayavedra, and the remainder are fifty percent settled in stock and in cash. |
(3) | The value realized upon vesting of stock awards was calculated based on the closing price of a share of common stock on the respective vesting date and includes cash payments are $490,118 to Mr. Ebel, $163,243 to Mr. Reddy, $85,663 to Ms. Dill and $19,033 to Ms. Sayavedra for dividend equivalents paid at the time of vesting on earned phantom and performance share units. |
Spectra Energy Retirement Cash Balance Plan and Executive Cash Balance Plan
Spectra Energy provides pension benefits that are intended to assist its retirees with their retirement income needs. A more detailed description of the plans that comprise Spectra Energy’s pension program follows.
Spectra Energy Partners executive officers actively participated in pension plans sponsored by Spectra Energy or an affiliate in 2013. Officers participated in the Spectra Energy Retirement Cash Balance Plan (RCBP), which is a noncontributory, defined benefit retirement plan that is intended to satisfy the requirements for qualification under Section 401(a) of the Internal Revenue Code. The RCBP generally covers non-bargaining employees of Spectra Energy and affiliates. The RCBP provides benefits under a “cash balance account” formula.
Spectra Energy Partners executive officers participate in the RCBP and have satisfied the eligibility requirements to receive her account benefit upon termination of employment. The RCBP benefit is payable in the form of a lump sum in the amount credited to the hypothetical account at the time of benefit commencement. Payment is also available in the form of an annuity based on the actuarial equivalent of the account balance.
The amount credited to the hypothetical account is increased with monthly pay credits equal to (a) for participants with combined age and service of less than 35 points, 4% of eligible monthly compensation, (b) for participants with combined age and service of 35 to 49 points, 5% of eligible monthly compensation, (c) for participants with combined age and service of 50 to 64 points, 6% of eligible monthly compensation, and (d) for participants with combined age and service of 65 or more points, 7% of eligible monthly compensation. If the participant earns more than the Social Security wage base, the account is credited with additional pay credits equal to 4% of eligible compensation above the Social Security wage base. Interest credits are credited monthly, with the interest rate determined quarterly based on the 30-year Treasury rate.
For the RCBP, eligible monthly compensation is equal to Form W-2 wages, plus elective deferrals under a 401(k) or cafeteria plan. Compensation does not include severance pay (including payment for unused vacation), expense reimbursements, allowances, cash or noncash fringe benefits, moving expenses, bonuses for performance periods in excess of one year, transition pay, long-term incentive compensation (including income resulting from any stock-based awards such as stock options, stock appreciation rights, phantom stock or restricted stock) and other compensation items to the extent described as not included for purposes of benefit plans or the RCBP.
The benefit of participants in the RCBP may not be less than determined under certain prior benefit formulas (including optional forms). In addition, the benefit under the RCBP is limited by maximum benefits and compensation limits under the Internal Revenue Code.
107
Spectra Energy Partners executive officers were eligible to participate in the Spectra Energy Executive Cash Balance Plan (ECBP), which is a noncontributory, defined benefit retirement plan that is not intended to satisfy the requirements for qualification under Section 401(a) of the Internal Revenue Code. Benefits earned under the ECBP are attributable to (a) compensation in excess of the annual compensation limit ($255,000 for 2013) under the Internal Revenue Code that applies to the determination of pay credits under the RCBP, (b) restoration of benefits in excess of a defined benefit plan maximum annual benefit limit ($205,000 for 2013) under the Internal Revenue Code that applies to the RCBP, and (c) supplemental benefits granted to a particular participant. Generally, benefits earned under the RCBP and the ECBP vest upon completion of three years of service, and, with certain exceptions, vested benefits generally become payable upon termination of employment with Spectra Energy.
Spectra Energy has established a grantor trust that is subject to the claims of our creditors into which funds related to the ECBP are deposited. Funds deposited into the trust are managed by an independent trustee subject to guidelines provided by us.
Pension Choices Plan for Employees of Westcoast Energy Inc. and Spectra Energy Supplemental Pension Plan
Mr. Ebel has a benefit under the Pension Choices Plan for Employees of Westcoast Energy Inc. and Affiliated Companies (Pension Plan) (registered under the Income Tax Act and the Pension Benefits Act (Ontario)) and the Spectra Energy Supplemental Executive Retirement Plan (SERP) since he was an active participant in the plans while he resided in Canada prior to 2007. Mr. Ebel's active participation in the plans was suspended upon his transfer to the U.S. The executive component of the Pension Plan is a non-contributory defined benefit plan that provides a pension benefit. The benefit under the SERP (which is paid from the general revenues of Spectra Energy) is primarily intended to restore benefits under the Pension Plan to the level that would be available in accordance with the benefit formulas under the Pension Plan if certain restrictions imposed by the Income Tax Act were not applicable.
The following table provides information related to each plan that provides for payments or other benefits at, following or in connection with retirement, determined as of December 31, 2013.
PENSION BENEFITS
Name | Plan Name | Number of Years Credited Service (#) | Present Value of Accumulated Benefit ($) | Payments During Last Fiscal Year ($) | |||||||
Gregory L. Ebel | Spectra Energy Retirement Cash Balance Plan | 16.00 | 221,202 | — | |||||||
Gregory L. Ebel | Spectra Energy Executive Cash Balance Plan | 16.00 | 812,173 | — | |||||||
Gregory L. Ebel | Pension Choices Plan for Employees of Westcoast Energy Inc. | 6.48 | 184,603 | — | |||||||
Gregory L. Ebel | Spectra Energy Supplemental Pension Plan | 6.48 | 2,389,212 | — | |||||||
J. Patrick Reddy | Spectra Energy Retirement Cash Balance Plan | 5.00 | 115,152 | — | |||||||
J. Patrick Reddy | Spectra Energy Executive Cash Balance Plan | 5.00 | 382,836 | — | |||||||
Julie Dill | Spectra Energy Retirement Cash Balance Plan | 15.34 | 363,323 | — | |||||||
Julie Dill | Spectra Energy Executive Cash Balance Plan | 15.34 | 435,974 | — | |||||||
Laura Buss Sayavedra | Spectra Energy Retirement Cash Balance Plan | 18.15 | 312,047 | — | |||||||
Laura Buss Sayavedra | Spectra Energy Executive Cash Balance Plan | 18.15 | 69,545 | — | |||||||
Spectra Energy Executive Savings Plan
Under the Spectra Energy Executive Savings Plan, participants can elect to defer a portion of their base salary, short-term incentive compensation and long-term incentive compensation (other than stock options). Participants also receive a company matching contribution in excess of the contribution limits prescribed by the IRS under the Spectra Energy Retirement Savings Plan. In general, payments are made following termination of employment or death in the form of a lump sum or installments, as selected by the participant. Participants may request an accelerated distribution upon an “unforeseeable emergency.” In general, participants may direct the deemed investment of base salary deferrals, short-term incentive deferrals and matching contributions among investments options available under the Spectra Energy Retirement Savings Plan, including in a Spectra Energy Common Stock Fund. Deferrals of equity awards are credited with earnings and losses based on the performance of the Spectra Energy Common Stock Fund. Spectra Energy has established a grantor trust that is subject to the claims of our creditors
108
into which funds related to the Spectra Energy Executive Savings Plan are deposited. Funds deposited into the trust are managed by an independent trustee subject to guidelines provided by us.
NONQUALIFIED DEFERRED COMPENSATION
Name | Executive Contributions in Last FY ($)(1) | Registrant Contributions in Last FY($)(2) | Aggregate Earnings in Last FY ($) | Aggregate Withdrawals/ Distributions ($) | Aggregate Balance at Last FYE ($) | ||||||||||
Gregory L. Ebel Spectra Energy Executive Savings Plan | 164,455 | 98,275 | 198,956 | — | 1,685,075 | ||||||||||
J. Patrick Reddy Spectra Energy Executive Savings Plan | 1,564,300 | 39,364 | 514,451 | — | 2,471,021 | ||||||||||
Julie Dill Spectra Energy Executive Savings Plan | 690,276 | 20,383 | 1,441,501 | — | 6,454,674 | ||||||||||
Laura Buss Sayavedra Spectra Energy Executive Savings Plan | 7,804 | 10,249 | 7,852 | — | 58,791 | ||||||||||
________
(1) | The table reflects contributions made to the Spectra Energy Executive Savings Plan. Executive contributions credited to the plan in 2013 include amounts reported as “Salary” in the Summary Compensation Table as well as “Non-Equity Incentive Plan Compensation” paid in 2013 but reported in the table as compensation earned in 2012. Amounts may also include elective deferrals of awards earned under our Long-Term Incentive Plan and payable in 2013. |
(2) | Reflects make-whole matching contribution credits made in 2013 under the plan with respect to elective salary deferrals made by executives during 2013. |
Potential Payments Upon Termination of Employment or Change in Control
Under certain circumstances, each named executive officer would be entitled to compensation if his or her employment were to terminate. The amount of the compensation is contingent upon a variety of factors, including the circumstances under which employment is terminated. The agreements and terms of awards affecting this type of compensation are described below, followed by a table that estimates the amount that would become payable to each named executive officer as a result of a change in control or a termination of employment, assuming a termination was effective as of December 31, 2013. The actual amounts that would be paid can only be determined at the time of the named executive officer’s termination of employment.
The following table summarizes the consequences under Spectra Energy and Spectra Energy Partners’ long-term incentive award agreements that would occur in the event of a change in control or the termination of employment of a named executive officer, without giving effect to the change in control agreements described below.
Event | Consequences | |
Change in Control | Phantom Units — continue to vest Performance Share Units — award vests based on target performance | |
Termination with cause | Phantom and Performance Share Units — executive’s right to unvested portion of award terminates immediately | |
Voluntary termination (not retirement eligible) | Phantom and Performance Share Units — executive’s right to unvested portion of award terminates immediately | |
Involuntary termination without cause (not retirement eligible) | Phantom Units — prorated portion of award vests Performance Share Units — prorated portion of award vests based on actual performance after performance period ends | |
Voluntary termination or involuntary termination without cause (retirement eligible) | Phantom Units — prorated portion of award continues to vest Performance Share Units — prorated portion of award vests based on actual performance after performance period ends | |
Involuntary termination after a Change in Control | Phantom Units — award vests Performance Share Units — award vests based on target performance | |
Death or Disability | Phantom Units — award vests Performance Share Units — award vests based on target performance | |
109
Messrs. Ebel and Reddy and Ms. Dill have entered into a Change in Control Agreement with Spectra Energy and it has an initial term of two years, after which the agreement automatically extends annually, unless six months prior written notice is provided.
The Change in Control Agreement provides for payments and benefits to the executive in the event of termination of employment within two years after a “change in control” of Spectra Energy, other than termination: 1) by Spectra Energy for “cause”; 2) by reason of death or disability; or 3) of the executive for other than “good reason” (each such term as defined in the agreements). Payments and benefits include: (1) a lump-sum cash payment equal to a pro-rata amount of the executive’s target cash incentive for the year in which the termination occurs; (2) a lump-sum cash payment equal to two times the sum of the executive’s annual base salary and target annual incentive opportunity in effect immediately prior to termination or, if higher, in effect immediately prior to the first occurrence of an event or circumstance constituting “good reason”; (3) continued medical, dental and basic life insurance coverage for a two-year period (or a lump sum cash payment of equivalent value); and (4) a lump-sum cash payment representing the amount Spectra Energy would have allocated or contributed to the executive’s qualified and nonqualified defined benefit pension plan and defined contribution savings plan accounts during the two years following the termination date, plus the unvested portion, if any, of the executive’s accounts as of the date of termination that would have vested during such two year period. In addition, under certain circumstances the agreement may provide for continued vesting of certain long-term incentive awards for two additional years.
Under the Change in Control Agreement, the covered executive is also entitled to reimbursement of up to $50,000 for the cost of certain legal fees incurred in connection with claims under the agreements. In the event that any of the payments or benefits provided for in the Change in Control Agreement otherwise would constitute an “excess parachute payment” (as defined in Section 280G of the Internal Revenue Code), the amount of payments or benefits would be reduced to the maximum level that would not result in excise tax under Section 4999 of the Internal Revenue Code if such reduction would cause the executive to retain an after-tax amount in excess of what would be retained if no reduction were made. In the event a named executive officer becomes entitled to payments and benefits under a change in control agreement, he or she would be subject to a one-year noncompetition and nonsolicitation provision from the date of termination, in addition to certain confidentiality and cooperation provisions.
110
POTENTIAL PAYMENTS UPON TERMINATION OF
EMPLOYMENT OR A CHANGE IN CONTROL (CIC)
Name and Triggering Event(1) | Cash Severance Payment ($)(2) | Incremental Retirement Plan Benefit ($)(3) | Welfare and Similar Benefits ($)(4) | Stock Awards ($)(5) | Option Awards ($) | Total Payments ($) | ||||||||||||
Gregory L. Ebel | ||||||||||||||||||
Change in Control | — | — | — | 6,314,431 | — | 6,314,431 | ||||||||||||
Voluntary termination or termination with cause | — | — | 42,308 | — | — | 42,308 | ||||||||||||
Involuntary termination without cause | — | — | 42,308 | 3,884,271 | — | 3,926,579 | ||||||||||||
Involuntary or good reason termination after a CIC | 4,400,000 | 760,119 | 77,719 | 12,359,478 | — | 17,597,316 | ||||||||||||
Death or Disability | — | — | 42,308 | 12,359,478 | — | 12,401,786 | ||||||||||||
J. Patrick Reddy | ||||||||||||||||||
Change in Control | — | — | — | 1,701,644 | — | 1,701,644 | ||||||||||||
Termination with cause | — | — | 79,647 | — | — | 79,647 | ||||||||||||
Voluntary or involuntary termination without cause | — | — | 79,647 | 1,244,321 | — | 1,323,968 | ||||||||||||
Involuntary or good reason termination after a CIC | 2,070,810 | 352,563 | 111,728 | 3,507,410 | — | 6,042,511 | ||||||||||||
Death or Disability | — | — | 79,647 | 3,507,410 | — | 3,587,057 | ||||||||||||
Julie Dill | ||||||||||||||||||
Change in Control | — | — | — | 920,108 | — | 920,108 | ||||||||||||
Voluntary termination or termination with cause | — | — | 14,781 | — | — | 14,781 | ||||||||||||
Involuntary termination without cause | — | — | 14,781 | 838,361 | — | 853,142 | ||||||||||||
Involuntary or good reason termination after a CIC | 1,152,936 | 191,955 | 28,715 | 2,194,715 | — | 3,568,321 | ||||||||||||
Death or Disability | — | — | 14,781 | 2,194,715 | — | 2,209,496 | ||||||||||||
Laura Buss Sayavedra | ||||||||||||||||||
Change in Control | — | — | — | 207,755 | — | 207,755 | ||||||||||||
Voluntary termination or termination with cause | — | — | 9,089 | — | — | 9,089 | ||||||||||||
Involuntary termination without cause | — | — | 9,089 | 133,807 | — | 142,896 | ||||||||||||
Involuntary or good reason termination after a CIC | — | — | 9,089 | 414,962 | — | 424,051 | ||||||||||||
Death or Disability | — | — | 9,089 | 414,962 | — | 424,051 | ||||||||||||
________
(1) | Amounts in the above table represent obligations of Spectra Energy under agreements currently in place at Spectra Energy, and valued as of December 31, 2013. |
(2) | Amounts listed under “Cash Severance Payment” are payable under the terms of Messrs. Ebel and Reddy and Ms. Dill’s change in control agreements. The severance benefits set forth above do not include accrued salary and cash incentive payments earned through December 31, 2013; however, such amounts are reflected in the Summary Compensation Table above. |
(3) | Pursuant to change in control agreements of Messrs. Ebel and Reddy and Ms. Dill, amounts listed under “Incremental Retirement Plan Benefit” represent the additional amounts that would be credited and vested in respect of the Spectra Energy Retirement Cash Balance Plan, Spectra Energy Executive Cash Balance Plan, Spectra Energy Retirement Savings Plan and the Spectra Energy Executive Savings Plan in the event he or she continued to be employed by Spectra Energy for two additional years, at his or her rate of base salary plus target bonus percentage in effect on December 31, 2013. |
(4) | Amounts listed under “Welfare and Other Benefits” include the maximum accrued vacation allowed under Company policy for Messrs. Ebel and Reddy and Mses. Dill and Sayavedra and the amount that would be paid to Messrs. Ebel and Reddy and Ms. Dill who have entered into a Change in Control Agreement in lieu of providing continued welfare benefits for 24 months. |
111
(5) | The amounts listed under “Stock Awards” would be the result of the acceleration of the vesting of previously awarded stock as a result of each event listed and any associated dividend or distribution equivalent payments due upon vesting. |
The amounts listed in the preceding table have been determined based on a variety of assumptions, and the actual amounts to be paid out can only be determined at the time of the named executive officer’s termination of employment. The amounts described in the table do not include compensation to which the named executive officers would be entitled without regard to his or her termination of employment, including (a) base salary and short-term incentives that have been earned but not yet paid, and (b) amounts that have been earned, but not yet paid, under the terms of the plans listed under the “Pension Benefits” and “Nonqualified Deferred Compensation” tables.
With respect to Messrs. Ebel and Reddy and Ms. Dill, the amounts shown above do not reflect the fact that if, in the event that payments to the executive in connection with a change in control otherwise would result in an excise tax under Section 4999 of the Internal Revenue Code, such payments may be reduced to the extent necessary so that the excise tax does not apply.
The amounts shown above with respect to outstanding Spectra Energy and Spectra Energy Partners stock awards were calculated based on a variety of assumptions, including the following: (a) the Spectra Energy Partners executive officer terminated employment on the last day of 2013; (b) the price for Spectra Energy common stock of $35.62 and for Spectra Energy Partners units of $45.35, which were the closing prices on the last trading day of 2013; (c) the continuation of Spectra Energy’s dividend and Spectra Energy Partners’ distribution at the rate in effect on December 31, 2013; and (d) performance at the target level with respect to performance share units.
112
DIRECTORS’ COMPENSATION
The following section provides information regarding payments to members of the board of directors of our general partner. Members of the board who are also employees of affiliates of our general partner do not receive additional compensation for serving on the board. The following is a description of the compensation program for non-employee directors of our general partner for 2013.
Director Compensation Program. Under the director compensation program approved by our general partner, each director receives an annual cash retainer of $70,000 and a grant of a number of common units equal to $55,000 divided by the closing price of our common units on the NYSE on the date of grant. Each Committee Chair also receives an annual cash retainer of $20,000.
Charitable Giving Program. Members of the board of our general partner are eligible to participate in the Spectra Energy Foundation Matching Gifts Program under which Spectra Energy will match contributions to qualifying institutions of up to $7,500 per director per calendar year. In 2013, the Spectra Energy Foundation made matching charitable contributions on behalf of Mr. Woodward of up to $7,500.
Expense Reimbursement. Non-employee directors are reimbursed for expenses reasonably incurred in connection with attendance and participation at Board and Committee meetings.
The following table describes the compensation earned during 2013 by each individual who served as an outside director during 2013.
DIRECTOR COMPENSATION
Name | Fees Earned or Paid in Cash ($) | Stock Awards ($)(1) | All Other Compensation ($) | Total ($) | ||||||||
Nora Mead Brownell | 70,000 | 54,990 | — | 124,990 | ||||||||
Fred J. Fowler (2) | 100,000 | 84,981 | — | 184,981 | ||||||||
J.D. Woodward, III | 90,500 | 54,990 | 7,500 | 152,990 | ||||||||
(1) | This column reflects the aggregate grant date fair value of the equity awarded computed in accordance with FASB ASC Topic 718. |
(2)Mr. Fowler resigned as Chairman, effective November 1, 2013, and he remains as a director.
The value of all perquisites and other personal benefits or property received by each director in 2013 was less than $1,000 and are not included in the above table.
113
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.
The following table sets forth the beneficial ownership of Spectra Energy Partners’ units as of February 17, 2014 held by:
• | all of the directors of the General Partner; |
• | each named executive officer of the General Partner; and |
• | all directors and officers of the General Partner as a group. |
Name of Beneficial Owner (1) | Common Units Beneficially Owned | Percentage of Common Units Beneficially Owned | ||||
Spectra Energy Corp (2) | 237,416,307 | 83.5 | % | |||
Spectra Energy Transmission, LLC | 158,962,739 | 55.9 | % | |||
Spectra Energy Southeast Pipeline Corp. | 43,956,556 | 15.5 | % | |||
Spectra Energy Sabal Trail Transmission | 2,175,649 | * | ||||
Spectra Energy Southeast Supply Header | 4,414,018 | 1.6 | % | |||
Spectra Energy Partners (DE) GP, LP | 27,907,345 | 9.8 | % | |||
Dorothy M. Ables | 4,353 | * | ||||
Julie A. Dill | 250 | * | ||||
Gregory L. Ebel | 5,766 | * | ||||
J. Patrick Reddy | — | * | ||||
Fred J. Fowler | 32,575 | * | ||||
Reginald D. Hedgebeth | — | * | ||||
William T. Yardley | 500 | * | ||||
Nora Mead Brownell | 20,458 | * | ||||
J.D. Woodward, III | 34,681 | * | ||||
All directors and executive officers as a group (nine persons) | 98,583 | * | ||||
________
(*) | Less than 1% of units outstanding. |
(1) | Unless otherwise indicated, the address for all beneficial owners in this table is 5400 Westheimer Court, Houston, TX 77056. |
(2) | Spectra Energy is the ultimate parent company of each of Spectra Energy Transmission, LLC, Spectra Energy Southeast Pipeline Corp., Spectra Energy Sabal Trail Transmission, Spectra Energy Southeast Supply Header and Spectra Energy Partners (DE) GP, LP and may, therefore, be deemed to beneficially own the units held by each of these entities. |
114
Equity Compensation Plan Information
The following table summarizes information about Spectra Energy Partners’ equity compensation plan as of December 31, 2013.
Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights(1) (a) | Weighted -Average Exercise Price of Outstanding Options, Warrants and Rights (b) | Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column(a)) (c) | ||||||
Equity compensation plans approved by unitholders | — | n/a | — | |||||
Equity compensation plans not approved by unitholders | — | n/a | 766,979 | |||||
Total | — | n/a | 766,979 | |||||
________
(1)The long-term incentive plan currently permits the grant of awards covering an aggregate of 900,000 units.
Item 13. Certain Relationships and Related Transactions, and Director Independence.
Spectra Energy and its affiliates own 237,416,307 common units as of December 31, 2013, representing an aggregate 84% limited partner interest in Spectra Energy Partners. In addition, the General Partner owns a 2% general partner interest in Spectra Energy Partners and all of the incentive distribution rights.
Distributions and Payments to The General Partner and its Affiliates
The following table summarizes the distributions and payments made or to be made by Spectra Energy Partners to the General Partner and its affiliates in connection with the ongoing operation and any liquidation of Spectra Energy Partners. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm’s-length negotiations.
Operational Stage
Distributions of Available Cash to the General Partner and its affiliates | Spectra Energy Partners generally makes cash distributions 98% to its unitholders pro rata, including the General Partner and its affiliates, as the holders of an aggregate 237,416,307 common units, and 2% to the General Partner. In addition, if distributions exceed the minimum quarterly distribution and other higher target distribution levels, the General Partner will be entitled to increasing percentages of the distributions, up to 50% of the distributions above the highest target distribution level. |
Payments to the General Partner and its affiliates | Spectra Energy Partners reimburses Spectra Energy and its affiliates for the payment of certain operating expenses and for the provision of various general and administrative services for the benefit of Spectra Energy Partners. |
Withdrawal or removal the General Partner | If the General Partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests. |
Liquidation Stage
Liquidation | Upon Spectra Energy Partners’ liquidation, the partners, including the General Partner, will be entitled to receive liquidating distributions according to their respective capital account balances. |
115
Omnibus Agreement
Spectra Energy Partners has entered into the Omnibus Agreement with Spectra Energy, its general partner and the general partner of its general partner. The Omnibus Agreement, addresses the following matters:
• | Spectra Energy Partners’ obligation to reimburse Spectra Energy for the payment of direct operating expenses it incurs on Spectra Energy Partners’ behalf in connection with Spectra Energy Partners’ business and operations; |
• | Spectra Energy Partners’ obligation to reimburse Spectra Energy for providing it allocated corporate, general and administrative services; and |
• | Spectra Energy’s obligation to indemnify Spectra Energy Partners’ for certain liabilities and Spectra Energy Partners’ obligation to indemnify Spectra Energy for certain liabilities. |
The General Partner and its affiliates also receive payments from Spectra Energy Partners pursuant to the contractual arrangements described below under the caption “Contracts with Affiliates.”
Any or all of the provisions of the Omnibus Agreement, other than the indemnification provisions described below, is terminable by Spectra Energy at its option if the General Partner is removed without cause and units held by the General Partner and its affiliates are not voted in favor of that removal. The Omnibus Agreement (other than the indemnification provisions) will also terminate in the event of a change of control of Spectra Energy Partners, its general partner or the general partner of its general partner.
Reimbursement of Operating and General and Administrative Expense
Under the Omnibus Agreement, Spectra Energy Partners reimburses Spectra Energy for the payment of certain operating expenses and for the provision of various corporate, general and administrative services for Spectra Energy Partners’ benefit.
Pursuant to these arrangements, Spectra Energy performs centralized corporate functions for Spectra Energy Partners, including legal, accounting, compliance, treasury, insurance, risk management, health, safety and environmental, human resources, credit, payroll, internal audit and tax. Spectra Energy Partners reimburses Spectra Energy for the expenses to provide these services as well as other expenses it incurs on Spectra Energy Partners’ behalf, such as salaries of personnel performing services for Spectra Energy Partners’ benefit and the cost of Spectra Energy employee benefits and general and administrative expenses associated with such personnel; capital expenditures; maintenance and repair costs; taxes; and direct expenses, including operating expenses and certain allocated operating expenses, associated with the ownership and operation of the contributed assets.
Competition
Neither Spectra Energy or any of its affiliates is restricted, under either Spectra Energy Partners’ partnership agreement or the Omnibus Agreement, from competing with Spectra Energy Partners. Spectra Energy and any of its affiliates may acquire, construct or dispose of additional transportation and storage or other assets in the future without any obligation to offer Spectra Energy Partners the opportunity to purchase or construct those assets.
Indemnification
Under the Omnibus Agreement, Spectra Energy Partners agreed to indemnify Spectra Energy against certain potential environmental and toxic tort claims, and certain losses and expenses associated with certain Spectra Energy Partners assets. Additionally, Spectra Energy Partners will indemnify Spectra Energy for all federal, state and local income tax liabilities attributable to the ownership or operations of certain assets, and losses associated with the operations of certain assets.
Contracts with Affiliates
Gulfstream Limited Liability Company Agreement
In connection with the closing of the IPO, Spectra Energy contributed to Spectra Energy Partners 24.5% of its 50.0% interest in Gulfstream. In connection with the Gulfstream acquisition in the fourth quarter of 2010, Spectra Energy contributed an additional 24.5% of its interest in Gulfstream to Spectra Energy Partners. In connection with the U.S. Assets Dropdown in fourth quarter of 2013, Spectra Energy Partners acquired Spectra Energy's remaining 1% interest in Gulfstream. Currently, Spectra Energy Partners owns a 50% interest in Gulfstream and affiliates of The Williams Companies, Inc. (Williams) own a collective 50% interest. Gulfstream’s second amended and restated limited liability company agreement governs the ownership and management of Gulfstream and provides for quarterly distributions equal to 100% of its available cash, which is defined to include Gulfstream’s cash and cash equivalents on hand at the end of the quarter less any reserves that may be deemed
116
appropriate by the Gulfstream management committee for the operation of its business (including reserves for its future maintenance capital expenditures and for its anticipated future credit needs) or for its compliance with laws or other agreements.
The management committee of Gulfstream makes the determinations related to Gulfstream’s available cash. The management committee is comprised of one representative from each of Spectra Energy Partners and Spectra Energy and two representatives from Williams. Each representative’s vote is equal to its members’ ownership interest in Gulfstream. In addition, following the acquisition, under the terms of the limited liability company agreement, Spectra Energy Partner’s affirmative vote is required for all decision that require more than a majority vote of the ownership interests in Gulfstream.
Under the Gulfstream limited liability company agreement, each member’s interest is subject to transfer restrictions, including a right of first offer in favor of the other members except in the case of certain transfers to affiliates. Accordingly, if a member identifies a potential third-party purchaser for all or a portion of its interest, that member must first offer the other members the opportunity to acquire the interest that it proposes to sell on the same terms and conditions as proposed by such potential purchaser.
Market Hub General Partnership Agreement
In connection with the closing of the IPO, Spectra Energy contributed to Spectra Energy Partners 50% of its interest in Market Hub. In connection with the U.S. Assets Dropdown in fourth quarter 2013, we acquired Spectra Energy’s remaining 50% interest in Market Hub. Currently, Spectra Energy Partners owns 100% interest in Market Hub. A partnership agreement governs the ownership and management of Market Hub and provides for quarterly distributions equal to 100% of its available cash, which is defined to include Market Hub’s cash and cash equivalents on hand at the end of the quarter less any reserves that may be deemed appropriate by the Market Hub management committee for the operation of its business (including reserves for its future maintenance capital expenditures and for its anticipated future credit needs) or for its compliance with law or other agreements.
Maritimes & Northeast Pipeline, L.L.C. Limited Liability Agreement
On October 31, 2012, Spectra Energy Partners acquired an 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. As a result of this acquisition, Spectra Energy Partners owned 39% interest in M&N US, Spectra Energy owned 39% interest, and affiliates of Emera, Inc. and Exxon Mobil Corporation owned the remaining 13% and 9% interests, respectively. In connection with the U.S. Assets Dropdown in fourth quarter 2013, we acquired Spectra Energy's remaining 39% interest in M&N US, resulting in our currently owning 78% of M&N US. An amended and restated limited liability company agreement governs the ownership and management of M&N US, and distributions of available cash are made to the owners in accordance with their ownership interests. The timing and amount of distributions is determined by the management committee of M&N US which is comprised of one member from each of Spectra Energy Partners, Spectra Energy, Emera, Inc. and Exxon Mobil Corporation. Each member’s vote is equal to its ownership share in M&N US. Currently, distributions are made on a monthly basis.
M&N US makes distributions equal to 100% of its available cash, which is defined to include M&N US’ cash and cash equivalents on hand at the end of the month less any reserves that may be deemed appropriate by the M&N US management committee for the operation of its business (including reserves for its future maintenance capital expenditures and for its anticipated future credit needs) or for its compliance with laws or other agreements.
Under the M&N US limited liability company agreement, each member’s interest is subject to transfer restrictions, including a preferential right in favor of other members, except in the case of certain transfers to affiliates. Accordingly, if a member identifies a potential third-party purchaser for all or a portion of its interest, that member must first offer the other members the opportunity to acquire the interest that it proposes to sell on the same terms and conditions as proposed by such potential purchaser.
Storage and Transportation Related Arrangements
Spectra Energy Partners charges transportation and storage fees to Spectra Energy and its respective affiliates. Management anticipates continuing to provide these services to Spectra Energy and its respective affiliates in the ordinary course of business.
Board Leadership and Risk Oversight
The board of our General Partner is currently led by our Chairman, Mr. Ebel. In exercising its duties to our unitholders, our board members should not be conflicted in any way and we have procedures that are specified in our partnership agreement
117
to address potential conflicts, which include referring transactions that present a conflict to our Conflicts Committee. We believe that this board leadership structure is appropriate in maximizing the effectiveness of our board oversight and in providing perspective to our business.
The board has responsibility for oversight of our risk management process and receives regular reports from our executives and from Spectra Energy regarding the risks faced in our business. The board exercises its risk oversight responsibilities through the Audit Committee, with respect to financial reporting and compliance risks. In addition, the Compensation Committee of Spectra Energy provides oversight with respect to risks that may be created by our compensation programs. Spectra Energy’s management has undertaken, and the Compensation Committee has reviewed, an evaluation of the incentives to its employees to take risk that are created by its compensation programs. Based upon that evaluation, Spectra Energy has concluded that its compensation programs do not create risks that are reasonably likely to result in a material adverse affect on the Company.
Director Independence
See Item 10. Directors, Executive Officers and Corporate Governance for information about the independence of the General Partner’s board of directors and its committees.
118
Item 14. Principal Accounting Fees and Services.
The following table presents fees for professional services rendered by Deloitte & Touche LLP, and the member firms of Deloitte Touche Tohmatsu and their respective affiliates (collectively, Deloitte) for us for 2013 and 2012:
Type of Fees | 2013 | 2012 | ||||||
(in millions) | ||||||||
Audit Fees(a) | $ | 2 | $ | 1 | ||||
Audit-Related Fees(b) | 2 | — | ||||||
Total Fees: | $ | 4 | $ | 1 | ||||
________
(a) | Audit Fees are fees billed or expected to be billed by Deloitte for professional services for the audit of our Consolidated Financial Statements included in our annual report on Form 10-K and review of financial statements included in our quarterly reports on Form 10-Q, services that are normally provided by Deloitte in connection with statutory, regulatory or other filings or engagements or any other service performed by Deloitte to comply with generally accepted auditing standards. Audit Fees also includes fees billed or expected to be billed by Deloitte for professional services for the audit of our internal controls under the requirements of Section 404 of the Sarbanes-Oxley Act of 2002 and related regulations. |
(b) | Audit-Related Fees are fees billed by Deloitte for assurance and related services that are reasonably related to the performance of an audit or review of our financial statements, including assistance with acquisitions and divestitures and internal control reviews. Audit-Related Fees also include comfort and consent letters in connection with SEC filings and financing transactions. |
To safeguard the continued independence of the independent auditor, the Audit Committee adopted a policy that prevents our independent auditor from providing services to us that are prohibited under Section 10A(g) of the Exchange Act, as amended. This policy also provides that independent auditors are only permitted to provide services to us and our subsidiaries that have been pre-approved by the Audit Committee. Pursuant to the policy, all audit services require advance approval by the Audit Committee. All other services by the independent auditor that fall within certain designated dollar thresholds, both per engagement as well as annual aggregate, have been pre-approved under the policy. Different dollar thresholds apply to the three categories of pre-approved services specified in the policy (Audit-Related services, Tax services and Other services). All services that exceed the dollar thresholds must be approved in advance by the Audit Committee. Pursuant to applicable provisions of the Exchange Act, as amended, the Audit Committee has delegated approval authority to the Chairman of the Audit Committee. The Chairman has presented all approval decisions to the full Audit Committee. All engagements performed by the independent auditor since July 2, 2007 were approved by the Audit Committee pursuant to its pre-approval policy.
119
PART IV
Item 15. Exhibits, Financial Statement Schedules.
(a) Consolidated Financial Statements, Supplemental Financial Data and Supplemental Schedules included in Part II of this annual report are as follows:
Spectra Energy Partners, LP:
Report of Independent Registered Public Accounting Firm
Consolidated Statements of Operations
Consolidated Statements of Comprehensive Income
Consolidated Balance Sheets
Consolidated Statements of Cash Flows
Consolidated Statements of Equity
Notes to Consolidated Financial Statements
Schedule II — Consolidated Valuation and Qualifying Accounts and Reserves
All other schedules are omitted because they are not required or because the required information is included in the Consolidated Financial Statements or Notes.
(b) Exhibits — See Exhibit Index at the end of this Annual Report on Form 10-K.
120
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
SPECTRA ENERGY PARTNERS, LP | ||||
By: | Spectra Energy Partners (DE) GP, LP, its general partner | |||
By: | Spectra Energy Partners GP, LLC, its general partner | |||
Date: February 28, 2014 | /s/ GREGORY L. EBEL | |||
Gregory L. Ebel President and Chief Executive Officer Spectra Energy Partners GP, LLC | ||||
Date: February 28, 2014 | /s/ J. PATRICK REDDY | |||
J. Patrick Reddy Vice President and Chief Financial Officer Spectra Energy Partners GP, LLC | ||||
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.
* | President and Chief Executive Officer | |
(i) Gregory L. Ebel | (Principal Executive Officer and Chairman of the Board) | |
* | Vice President and Chief Financial Officer | |
(ii) J. Patrick Reddy | (Principal Financial Officer and Principal Accounting Officer) | |
* | Chairman of the Board of Directors | |
(iii) Gregory L. Ebel | ||
* | Director | |
Dorothy M. Ables | ||
* | Director | |
Fred J. Fowler | ||
* | Director | |
Nora Mead Brownell | ||
* | Director | |
William T. Yardley | ||
* | Director | |
Julie Dill | ||
* | Director | |
J.D. Woodward, III | ||
121
Date: February 28, 2014
J. Patrick Reddy, by signing his name hereto, does hereby sign this document on behalf of the registrant and on behalf of each of the above-named persons previously indicated by asterisk pursuant to a power of attorney duly executed by the registrant and such persons, filed with the Securities and Exchange Commission as an exhibit hereto.
By: | /s/ J. PATRICK REDDY | |
J. Patrick Reddy | ||
Attorney-In-Fact | ||
Exhibit Index
Exhibit No. | Exhibit Description | |
2.1 | Asset Purchase Agreement, dated December 13, 2007, between Spectra Energy Virginia Pipeline Company and East Tennessee Natural Gas, LLC (filed as Exhibit 10.2 to Spectra Energy Partners, LP’s Form 8-K dated December 14, 2007). | |
2.2 | Securities Purchase Agreement, dated as of April 7, 2009, among Spectra Energy Partners OLP, LP, Atlas Pipeline Mid-Continent LLC, Atlas Pipeline Partners, L.P, solely as guarantor of Atlas Pipeline Mid-Continent LLC, and Spectra Energy Partners, L.P., solely as guarantor of Spectra Energy Partners OLP, LP (filed as Exhibit 10.1 to Spectra Energy Partners, LP’s Form 8-K dated April 8, 2009). | |
2.3 | Contribution Agreement, dated November 30, 2010, by and among Spectra Energy Partners, LP, Spectra Energy Partners (DE) GP, LP and Spectra Energy Southeast Pipeline Corporation (filed as Exhibit No. 2.1 to Spectra Energy Partners, LP’s Form 8-K dated November 30, 2010). | |
2.4 | Purchase and Sale Agreement dated as of May 11, 2011, by and among Equitrans, L.P. and, solely for the purpose of Sections 1.8, 1.9, 4.17 and 9.15, EQT Corporation, Spectra Energy Partners, LP and, solely for the purpose of Section 9.16, Spectra Energy Capital, LLC (Filed as Exhibit No. 2.1 to Spectra Energy Partners, LP’s Form 8-K dated May 11, 2011). | |
2.5 | First Amendment to Purchase and Sale Agreement, dated as of June 30, 2011, by and among Equitrans, L.P. and, solely for the purpose of Sections 1.8, 1.9, 4.17 and 9.15, EQT Corporation, Spectra Energy Partners, LP and, solely for the purpose of Section 9.16, Spectra Energy Capital, LLC (Filed as Exhibit No. 2.1 to Spectra Energy Partners, LP’s Form 8-K dated July 1, 2011). | |
2.6 | Contribution Agreement, dated October 23, 2012, by and between Spectra Energy Partners, LP and Spectra Energy Partners (DE) GP, LP. (filed as Exhibit 2.1 to Spectra Energy Partners, LP’s Form 8-K dated October 23, 2012). | |
2.7 | Contribution Agreement, dated as of May 2, 2013, by and between Spectra Energy Partners, LP and Spectra Energy Partners (DE) GP, LP (filed as Exhibit 2.1 to Spectra Energy Partners, LP’s Form 8-K dated May 3, 2013). | |
2.8 | First Amendment to Contribution Agreement, dated August 1, 2013, by and between Spectra Energy Partners, LP and Spectra Energy Partners (DE) GP, LP (filed as Exhibit 2.1 to Spectra Energy Partners, LP’s Form 8-K dated August 2, 2013). | |
2.9 | Securities Purchase Agreement, dated May 2, 2013, by and among Spectra Energy Partners, LP, Spectra Energy Express Pipeline (Canada), Inc. and Spectra Energy Capital Funding, Inc. (filed as Exhibit 2.2 to Spectra Energy Partners, LP’s Form 8-K dated May 3, 2013). | |
2.10 | First Amendment to Securities Purchase Agreement, dated as of August 1, 2013, by and among Spectra Energy Partners, LP, Spectra Energy Express Pipeline (Canada), Inc. and Spectra Energy Capital Funding, Inc. (filed as Exhibit 2.4 to Spectra Energy Partners, LP’s Form 10-Q dated August 7, 2013). | |
2.11 | Contribution Agreement by and between Spectra Energy Corp and Spectra Energy Partners, LP, dated as of August 5, 2013 (filed as Exhibit 2.1 to Spectra Energy Partners, LP’s Form 8-K dated August 6, 2013). | |
2.12 | First Amendment to Contribution Agreement by and between Spectra Energy Corp and Spectra Energy Partners, LP, dated as of October 31, 2013 (filed as Exhibit 2.1 to Spectra Energy Partners, LP’s Form 8-K dated November 1, 2013). | |
3.1 | First Amended and Restated Agreement of Limited Partnership of Spectra Energy Partners, LP (filed as Exhibit 3.1 to Spectra Energy Partners, LP’s Form 8-K dated July 9, 2007). | |
3.2 | Amendment No. 1 to First Amended and Restated Agreement of Limited Partnership of Spectra Energy Partners, LP, dated April 11, 2008 (filed as Exhibit 10.1 to Spectra Energy Partners, LP’s Form 10-Q on May 14, 2008). | |
3.3 | Certificate of Limited Partnership of Spectra Energy Partners, LP (filed as Exhibit 3.1 to Spectra Energy Partner, LP’s Form S-1 on March 30, 2007, file no. 333-141687). | |
3.4 | First Amended and Restated Agreement of Limited Partnership Agreement of Spectra Energy Partners (DE) GP, LP (filed as Exhibit 3.2 to Spectra Energy Partners, LP’s Form 8-K dated July 9, 2007). | |
3.5 | Certificate of Limited Partnership of Spectra Energy Partners (DE) GP, LP (filed as Exhibit 3.3 to Spectra Energy Partner, LP’s Form S-1 on March 30, 2007, file no. 333-141687). | |
Exhibit No. | Exhibit Description | |
122
3.6 | First Amended and Restated Limited Liability Agreement of Spectra Energy Partners GP, LLC (filed as Exhibit 3.3 to Spectra Energy Partners, LP’s Form 8-K dated July 9, 2007). | |
3.7 | Certificate of Formation of Spectra Energy Partners GP, LLC (filed as Exhibit 3.5 to Spectra Energy Partner, LP’s Form S-1 on March 30, 2007, file no. 333-141687). | |
3.8 | Second Amended and Restated Limited Liability Company Agreement of Spectra Energy Partners GP, LLC (filed as Exhibit 3.1 to Spectra Energy Partners, LP’s Form 10-Q dated May 8, 2013). | |
3.9 | First Amended and Restated Limited Liability Company Agreement of Express Holdings (USA), LLC, dated August 2, 2013, by and between Spectra Energy Express Holding II, LLC and Spectra Energy Partners, LP (filed as Exhibit 2.2 to Spectra Energy Partners, LP’s Form 8-K dated August 2, 2013). | |
3.10 | Second Supplemental Indenture, dated September 25, 2013, between Spectra Energy Partners, LP, as Issuer, and Wells Fargo Bank, National Association, as Trustee (filed as Exhibit 4.2 to Spectra Energy Partners, LP’s Form 8-K dated September 25, 2013 ). | |
3.11 | Second Amended and Restated Agreement of Limited Partnership of Spectra Energy Partners, LP, dated as of November 1, 2013 (filed as Exhibit 3.1 to Spectra Energy Partners, LP’s Form 8-K dated November 1, 2013). | |
3.12 | Third Amended and Restated Limited Liability Company Agreement of Spectra Energy Partners GP, LLC, dated as of November 1, 2013 (filed as Exhibit 3.2 to Spectra Energy Partners, LP’s Form 8-K dated November 1, 2013). | |
4.1 | Indenture, dated as of June 9, 2011, between Spectra Energy Partners, LP, as Issuer and Wells Fargo Bank, National Association, as Trustee (Filed as Exhibit No. 4.1 to Spectra Energy Partners, LP’s Form 8-K dated June 9, 2011). | |
4.2 | First Supplemental Indenture, dated as of June 9, 2011, between Spectra Energy Partners, LP, as Issuer and Wells Fargo Bank, National Association, as Trustee (Filed as Exhibit No. 4.2 to Spectra Energy Partners, LP’s Form 8-K dated June 9, 2011). | |
4.3 | Second Supplemental Indenture, dated September 25, 2013, between Spectra Energy Partners, LP, as Issuer and Wells Fargo Bank, National Association, as Trustee (filed as Exhibit 4.2 to Spectra Energy Partners, LP’s Form 8-K dated September 25, 2013. | |
4.4 | Form of 2.95% Senior Notes due 2016 (Included in Exhibit 4.2 to Spectra Energy Partners, LP’s Form 8-K dated June 9, 2011). | |
4.5 | Form of 4.60% Senior Notes due 2021 (Included in Exhibit 4.2 to Spectra Energy Partners, LP’s Form 8-K dated June 9, 2011). | |
4.6 | Form of 2.950% Senior Notes due 2018 (filed in Exhibit 4.3 to Spectra Energy Partners, LP’s Form 8-K dated September 25, 2013). | |
4.7 | Form of 4.750% Senior Notes due 2024 (filed in Exhibit 4.4 to Spectra Energy Partners, LP’s Form 8-K dated September 25, 2013). | |
4.8 | Form of 5.950% Senior Notes due 2043 (filed in Exhibit 4.5 to Spectra Energy Partners, LP’s Form 8-K dated September 25, 2013). | |
10.1 | Contribution, Conveyance and Assumption Agreement, dated July 2, 2007, by and among Spectra Energy Partners, LP, Spectra Energy Partners OLP, LP, Spectra Energy Partners GP, LLC, Spectra Energy Partners OLP GP, LLC, Spectra Energy Partners (DE) GP, LP, Spectra Energy Transmission, LLC, Spectra Energy Southeast Pipeline Corporation, East Tennessee Natural Gas, LLC, Egan Hub Storage, LLC, Moss Bluff Hub, LLC and Market Hub Partners Holding, LLC (filed as Exhibit 10.1 to Spectra Energy Partners, LP’s Form 8-K dated July 9, 2007). | |
10.2 | Omnibus Agreement, dated July 2, 2007, by and among Spectra Energy Partners, LP, Spectra Energy Partners (DE) GP, LP, Spectra Energy Partners GP, LLC and Spectra Energy Corp (filed as Exhibit 10.2 to Spectra Energy Partners, LP’s Form 8-K dated July 9, 2007). | |
+10.3 | Long Term Incentive Plan of Spectra Energy Partners, LP (filed as Exhibit 10.3 to Spectra Energy Partners, LP’s Form 8-K dated July 9, 2007). | |
+10.4 | Form of Phantom Unit Award Agreement under the Spectra Energy Partners, LP Long-Term Incentive Plan (filed as Exhibit 4.3 to Spectra Energy Partners, LP’s Form S-8 on July 2, 2007). | |
123
Exhibit No. | Exhibit Description | |
10.5 | General Partnership Agreement of Market Hub Partners Holding (filed as Exhibit 10.4 to Spectra Energy Partners, LP’s Form 8-K dated July 9, 2007). | |
10.6 | Contribution Agreement, dated December 13, 2007, by and among Spectra Energy Transmission, LLC, Spectra Energy Partners (DE) GP, LP and Spectra Energy Partners, LP (filed as Exhibit 10.8 to Spectra Energy Partners, LP’s 10-K/A on May 14, 2009). | |
10.7 | Gulfstream Natural Gas System, L.L.C. Indenture dated October 26, 2005 relating to $500,000,000 of its 5.56% Senior Notes due 2015 and $350,000,000 of its 6.19% Senior Notes due 2025 (filed as Exhibit 10.4 to Spectra Energy Partners, LP’s Form S-1/A on June 13, 2007, file no. 333-141687). | |
10.8 | Second Amended and Restated Limited Liability Company Agreement of Gulfstream Natural Gas System, L.L.C. (filed as Exhibit 10.6 to Spectra Energy Partners, LP’s Form S-1/A on June 4, 2007, file no. 333-141687). | |
10.9 | East Tennessee Natural Gas, LLC Note Purchase Agreement dated December 15, 2002 relating to $150,000,000 of its 5.71% Senior Notes due 2012 (filed as Exhibit 10.11 to Spectra Energy Partners, LP’s Form 10-K/A on May 14, 2009). | |
10.10 | Amendment No. 1, dated as of April 4, 2008, to the Omnibus Agreement entered into and effective as of July 2, 2007 (filed as Exhibit 10.12 to Spectra Energy Partners, LP’s Form 10-K on February 28, 2011). | |
10.11 | Amendment No. 1, dated as of June 1, 2010, to the Omnibus Agreement entered into and effective as of July 2, 2007 (filed as Exhibit No. 10.1 to Spectra Energy Partners, LP’s Form 8-K dated June 4, 2010). | |
10.12 | Amendment to Limited Liability Company Agreement of Gulfstream Natural Gas System, L.L.C., dated as of March 22, 2010 (filed as Exhibit No. 10.14 to Spectra Energy Partners, LP’s Form 10-K on February 28, 2011). | |
10.13 | Credit Agreement, dated as of October 18, 2011, among Spectra Energy Partners, LP, the Initial Lenders and Issuing Banks named therein, and Citibank, N.A., as Administrative Agent (filed as Exhibit No. 10.1 to Form 8-K of Spectra Energy Partners, LP on October 20, 2011). | |
10.14 | Second Amendment to Limited Liability Company Agreement of Gulfstream Natural Gas System, L.L.C., dated as of September 9, 2011 (filed as Exhibit No. 10.2 to Spectra Energy Partners, LP’s Form 10-Q on November 8, 2011). | |
10.15 | Amended and Restated Omnibus Agreement, dated November 1, 2013, by and among Spectra Energy Partners, LP, Spectra Energy Partners (DE) GP, LP, Spectra Energy Partners GP, LLC and Spectra Energy Corp (filed as Exhibit 10.1 to Spectra Energy Partners, LP’s Form 8-K dated November 1, 2013). | |
10.16 | Amended and Restated Credit Agreement, dated as of November 1, 2013, by and among Spectra Energy Partners, LP, as Borrower, Citibank, N.A., as Administrative Agent, and the lenders party thereto (filed as Exhibit 10.2 to Spectra Energy Partners, LP’s Form 8-K dated November 1, 2013). | |
10.17 | Credit Agreement, dated as of November 1, 2013, by and among Spectra Energy Partners, LP, as Borrower, The Bank of Tokyo-Mitsubishi UFJ, LTD, as Administrative Agent, and the lenders party thereto (filed as Exhibit 10.3 to Spectra Energy Partners, LP’s Form 8-K dated November 1, 2013). | |
10.18 | Equity Distribution Agreement dated as of November 19, 2013, among Spectra Energy Partners, LP, Spectra Energy Partners (DE) GP, LP, Spectra Energy Partners GP, LLC, Citigroup Global Markets Inc., Credit Suisse Securities (USA) LLC and Wells Fargo Securities, LLC (filed as Exhibit 1.1 to Spectra Energy Partners, LP's Form 8-K dated November 19, 2013). | |
*12.1 | Computation of Ratio of Earnings to Fixed Charges. | |
*21.1 | Subsidiaries of the Registrant. | |
*23.1 | Consent of Deloitte & Touche LLP related to Spectra Energy Partners, LP | |
*24.1 | Power of Attorney. | |
*31.1 | Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |
*31.2 | Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |
*32.1 | Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | |
*32.2 | Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | |
124
Exhibit No. | Exhibit Description | |
*101.INS | XBRL Instance Document. | |
*101.SCH | XBRL Taxonomy Extension Schema. | |
*101.CAL | XBRL Taxonomy Extension Calculation Linkbase. | |
*101.DEF | XBRL Taxonomy Extension Definition Linkbase. | |
*101.LAB | XBRL Taxonomy Extension Label Linkbase. | |
*101.PRE | XBRL Taxonomy Extension Presentation Linkbase. | |
* | Filed herewith. |
+ | Denotes management contract or compensatory plan or arrangement. |
125