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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, 2009
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 ¨ No x
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 ¨ 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 ¨ | Accelerated filer x | 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, 2009: $459,000,000.
At February 26, 2010, there were 58,705,791 Common Units, 21,638,730 Subordinated Units and 1,639,117 General Partner Units outstanding.
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SPECTRA ENERGY PARTNERS, LP
FORM 10-K FOR THE YEAR ENDED
DECEMBER 31, 2009
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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
This document includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements are based on management’s beliefs and assumptions. These forward-looking statements are identified by terms and phrases such as: anticipate, believe, intend, estimate, expect, continue, should, could, may, plan, project, predict, will, potential, forecast, and similar expressions. Forward-looking statements involve risks and uncertainties that may cause actual results to be materially different from the results predicted. Factors that could cause actual results to differ materially from those indicated in any forward-looking statement include, but are not limited to:
| • | state and federal legislative and regulatory initiatives that affect cost and investment recovery, have an effect on rate structure, and affect the speed at and degree to which competition enters the natural gas industries; |
| • | outcomes of litigation and regulatory investigations, proceedings or inquiries; |
| • | weather and other natural phenomena, including the economic, operational and other effects of hurricanes and storms; |
| • | the timing and extent of changes in interest rates; |
| • | general economic conditions, which can affect the long-term demand for natural gas and related services; |
| • | potential effects arising from terrorist attacks and any consequential or other hostilities; |
| • | changes in environmental, safety and other laws and regulations; |
| • | results of financing efforts, including the ability to obtain financing on favorable terms, which can be affected by various factors, including credit ratings and general market and economic conditions; |
| • | increases in the cost of goods and services required to complete capital projects; |
| • | growth in opportunities, including the timing and success of efforts to develop domestic pipeline, storage, gathering and other infrastructure projects and the effects of competition; |
| • | the performance of natural gas transmission, storage and gathering facilities; |
| • | the extent of success in connecting natural gas supplies to transmission and gathering systems and in connecting to expanding gas markets; |
| • | the effect of accounting pronouncements issued periodically by accounting standard-setting bodies; |
| • | conditions of the capital markets during the periods covered by the forward-looking statements; and |
| • | the ability to successfully complete merger, acquisition or divestiture plans; regulatory or other limitations imposed as a result of a merger, acquisition or divestiture; and the success of the business following a merger, acquisition or divestiture. |
In light of these risks, uncertainties and assumptions, the events described in the forward-looking statements might not occur or might occur to a different extent or at a different time than Spectra Energy Partners, LP has described. Spectra Energy Partners, LP undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.
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PART I
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.
Spectra Energy Partners, LP, through its subsidiaries and equity affiliates, is engaged in the transportation and gathering of natural gas through interstate pipeline systems with over 3,100 miles of pipelines that serve the southeastern United States, Oklahoma, Arkansas and Missouri, and the storage of natural gas in underground facilities with aggregate working gas storage capacity of approximately 49 billion cubic feet (Bcf) that are located in southeast Texas, south central Louisiana and southwest Virginia. We are a Delaware master limited partnership (MLP) formed on March 19, 2007. Our common units are listed on the New York Stock Exchange (NYSE) under the symbol “SEP.” Our internet website is http://www.spectraenergypartners.com.
We transport, gather and store natural gas for a broad mix of customers, including local gas distribution companies (LDCs, companies that obtain a major portion of their revenues from retail distribution systems for the delivery of natural gas for ultimate consumption), municipal utilities, interstate and intrastate pipelines, direct industrial users, electric power generators, marketers and producers, and exploration and production companies. In addition to serving the directly connected southeastern United States, Oklahoma, Arkansas and Missouri markets, our pipeline, storage and gathering systems have access to customers in the mid-Atlantic, northeastern and midwestern regions of the United States through numerous interconnections with major pipelines. Our rates are regulated under the Federal Energy Regulatory Commission’s (FERC’s) rate-making policies with the exception of Market Hub Partners Holding’s (Market Hub’s) intrastate storage operations and our gathering facilities. The FERC is the U.S. agency that regulates the transportation of natural gas in interstate commerce.
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, 2009, Spectra Energy and its subsidiaries collectively owned 74% of us and the remaining 26% was publicly owned.
On July 2, 2007, immediately prior to the closing of our initial public offering (IPO), Spectra Energy contributed to us 100% of the ownership of East Tennessee Natural Gas, LLC (East Tennessee), 50% of the ownership of Market Hub and a 24.5% interest in Gulfstream Natural Gas System, L.L.C. (Gulfstream). Spectra Energy indirectly owned 100% of us prior to the closing of the IPO. On July 2, 2007, we issued 11.5 million common units to the public, representing 17% of our outstanding equity. As a result, Spectra Energy retained an 83% equity interest in us, including common units, subordinated units and a 2% general partner interest.
In 2008, we completed the acquisition of the equity interests of Saltville Gas Storage Company L.L.C. (Saltville) and the P-25 pipeline from a wholly owned subsidiary of Spectra Energy at a purchase price of $107.0 million, which included the issuance of 4.2 million common units and 0.1 million general partner units, and a cash payment of $4.7 million to Spectra Energy. Spectra Energy’s ownership of our partnership increased from 83% to 84% as a result of receipt of the new common and general partner units.
In the second quarter of 2009, we acquired all of the ownership interests of NOARK Pipeline System, Limited Partnership (NOARK) from Atlas Pipeline Partners, L.P. (Atlas) for approximately $294.5 million in cash. NOARK’s
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assets consist of 100% ownership interests of Ozark Gas Transmission, L.L.C. (Ozark Gas Transmission) and Ozark Gas Gathering, L.L.C. (Ozark Gas Gathering) (collectively referred to as “Ozark”). This transaction was partially refinanced in the second quarter of 2009 through our sale of common units, resulting in a reduction of Spectra Energy’s ownership interest in us from 84% to 74%.
For financial information on our acquisitions, see Item 8. Financial Statements and Supplementary Data, Note 2 of Notes to Consolidated Financial Statements.
Gas Transportation and Storage
Our sole segment, Gas Transportation and Storage, includes East Tennessee, Saltville and Ozark. Gas Transportation and Storage provides interstate transportation, storage, fee-based gathering of natural gas, and storage and redelivery of liquefied natural gas (LNG, natural gas that has been converted to liquid form) for customers in the southeastern United States, Oklahoma, Arkansas and Missouri. These operations are primarily subject to the FERC’s and the Department of Transportation’s (DOT’s) rules and regulations.
General
We own and operate 100% of the 1,510-mile East Tennessee interstate natural gas transportation system, which extends from central Tennessee eastward into southwest Virginia and northern North Carolina, and southward into northern Georgia. East Tennessee supports the energy demands of the southeast and mid-Atlantic regions of the United States through connections to 31 receipt points and 179 delivery points and has market delivery capability of approximately 1.5 billion cubic feet per day (Bcf/d) of natural gas. East Tennessee also owns and operates an LNG storage facility in Kingsport, Tennessee with a working gas storage capacity of 1.1 Bcf and regasification capability of 150 million cubic feet per day (MMcf/d).
We own and operate 100% of the Saltville natural gas storage facilities which consist of 5.5 Bcf of total storage capacity. The storage facilities interconnect with the East Tennessee system in southwest Virginia and offer high deliverability salt cavern and reservoir storage capabilities that are strategically located near markets in Tennessee, Virginia and North Carolina.
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We own and operate 100% of the 565-mile Ozark Gas Transmission interstate natural gas transportation system, which extends from southeastern Oklahoma through Arkansas to southeastern Missouri. This system has connections to 52 receipt points and 26 delivery points and market delivery capability of approximately 0.5 Bcf/d of natural gas. We also own and operate 100% of the 365-mile Ozark Gas Gathering system that accesses Fayetteville Shale and Arkoma natural gas production that feeds into Ozark Gas Transmission.
Customers and Contracts
Gas Transportation and Storage’s customers include LDCs, utilities, interstate and intrastate pipelines, industrial companies, natural gas marketers and producers, electric power generators, and exploration and production companies. Gas Transportation and Storage’s largest customer in 2009 was Atmos Energy Corporation, which accounted for approximately 10% of Gas Transportation and Storage’s revenues.
Gas Transportation and Storage has contracts with its customers to provide firm transportation and storage services as well as fee-based gathering services. Payments under firm transportation and storage services are primarily based on the volume of capacity reserved on the system regardless of the capacity actually used, plus a variable charge based on the volume of natural gas actually transported. As a result, firm transportation revenues typically remain relatively constant over the term of the contracts. Gathering service contracts, which represent less than 3% of Gas Transportation and Storage 2009 operating revenues, include variable charges based on volume of natural gas actually gathered and the number of compression stages needed to deliver the gathered gas. Maximum and minimum rates for transportation and storage services are governed by the applicable FERC-approved natural gas tariff while fee-based gathering services are governed by the applicable state oil and gas commissions.
In 2005, East Tennessee entered into a rate settlement with its customers which established new base rates under the tariff and provided rate certainty through the settlement’s expiration on October 31, 2010. Following
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expiration of the settlement agreement, East Tennessee’s rates will remain the same, subject to further negotiation or a future rate proceeding.
On September 1, 2008, Saltville placed into effect new rates approved by the FERC as a result of a settlement with customers associated with a rate proceeding. This settlement includes a rate moratorium until October 1, 2011. Following expiration of the moratorium, Saltville’s rates will remain the same, subject to further negotiation or a future rate proceeding. Also pursuant to the settlement, Saltville is required to file a rate case by October 1, 2013.
Gas Transportation and Storage also provides interruptible transportation and storage services under which gas is transported or stored for customers when operationally feasible and customers pay only for the actual volume of gas transported or stored. Under all contracts, Gas Transportation and Storage retains, at no cost, a fixed percentage of the natural gas it transports in order to supply the fuel needed for natural gas compression on the system.
As of December 31, 2009, East Tennessee and Saltville firm transportation and storage contracts had a weighted average remaining life of approximately eight years and Ozark, excluding gathering contracts, had a weighted average remaining life of approximately two years. In 2009, 97% of East Tennessee and Saltville and 67% of Ozark Gas Transmission’s revenues were derived from capacity reservation charges under firm contracts (including LNG storage services), with the remainder representing variable usage fees under firm and interruptible transportation contracts.
Source of Supply
Gas supply attachments are a critical factor for Gas Transportation and Storage customers. Its customers benefit from gas supply from the Gulf Coast region through Tennessee Gas Pipeline Company, and to a lesser degree Texas Eastern Transmission, L.P. (Texas Eastern, a subsidiary of Spectra Energy), Southern Natural Gas Company, Columbia Gulf Transmission Company and Midwestern Gas Pipeline System. Its customers also receive natural gas supply from conventional and non-conventional sources such as Appalachian Shale and coal-bed methane, as well as from Fayetteville Shale and Arkoma supply basins. Natural gas withdrawn from East Tennessee’s LNG storage facility and other on-system storage fields, including Saltville’s natural gas storage facilities, provide customers with additional supply sources used to supplement supplies during periods of peak demand.
Competition
The mountainous geography of the regions served by East Tennessee creates natural barriers to entry that make competition from new pipeline entrants difficult and expensive. As a result, East Tennessee is the sole source of interstate natural gas transportation for many of the firm capacity customers that transport natural gas on this system. At both ends of this system, East Tennessee is subject to competition from other pipelines.
Natural gas is in direct competition with electricity for residential and commercial heating demand in East Tennessee’s and Saltville’s market areas. While this competition does not directly affect firm sales, LDC customers’ growth is partially dependent upon the installation of natural gas furnaces in new home construction. Although substitution of electric heat for natural gas heat could have a long-term effect on customers’ demand requirements, East Tennessee and Saltville have already benefited from the addition of natural gas fired electric generation supplied by the pipeline.
An increase in competition in the region served by East Tennessee and Saltville could arise from new ventures or expanded operations from existing competitors. Other competitive factors include the quantity, location and physical flow characteristics of interconnected pipelines, the ability to offer service from multiple storage or production locations, and the cost-of-service and rates offered by East Tennessee’s and Saltville’s competitors.
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The Ozark assets compete with CenterPoint Energy Gas Transmission Company, Texas Gas Transmission, LLC’s Fayetteville Lateral, which went into service in 2009, and the Fayetteville Express Pipeline LLC, which is scheduled to be in-service in the fourth quarter 2010.
General
We own a 24.5% interest in the 745-mile Gulfstream interstate natural gas transportation system which extends from Pascagoula, Mississippi and Mobile, Alabama across the Gulf of Mexico and into Florida. The Gulfstream pipeline currently includes approximately 295 miles of onshore pipeline in Florida, 15 miles of onshore pipeline in Alabama and Mississippi, and 435 miles of offshore pipeline in the Gulf of Mexico. Facilities also include gas treatment facilities and a compressor station in Coden, Alabama. Gulfstream supports the south and central Florida markets through its connection to eight receipt points and 23 delivery points and has market delivery capability of 1.26 Bcf/d of natural gas. Spectra Energy and affiliates of The Williams Companies, Inc. (Williams) own the remaining 25.5% and 50% interests in Gulfstream, respectively, and jointly operate the system.
Customers, Contracts and Supply
In 2009, Florida Power & Light Company and Florida Power Corporation d/b/a Progress Energy Florida, Inc. accounted for approximately 52% and 27%, respectively, of Gulfstream’s revenues.
Gulfstream provides firm and interruptible transportation services, interruptible park and loan services, and operational balancing agreements to resolve any differences between scheduled and actual receipts and deliveries. All of Gulfstream’s firm transportation contracts include negotiated rates through the life of the contract. These negotiated rates are currently less than the maximum applicable recourse rate allowed by the FERC.
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As of December 31, 2009, Gulfstream’s firm transportation and storage contracts had a weighted average remaining life of 19 years. In 2009, 97% of Gulfstream’s revenues were derived from capacity reservation charges under firm contracts, 2% of revenues were derived from variable usage fees under firm contracts and 1% of revenues were derived from interruptible transportation contracts.
Gulfstream shippers increasingly have the option of buying natural gas supplies from a wide range of producers in the eastern Gulf of Mexico and from onshore sites along the entire Gulf Coast. Gulfstream is connected to processing plants and supply pipelines in the Mobile Bay area. Currently, shippers have the ability to source supply at eight access points, including access to supplies delivered by the Southeast Header Supply, LLC (SESH) joint venture. SESH originates in Perryville, LA and interconnects with Gulfstream near Coden, Alabama. In addition, anticipated increasing LNG imports along the Gulf Coast should further diversify the gas supplies available to Gulfstream’s customers, potentially offsetting some of the risks associated with offshore Gulf of Mexico natural gas production.
Competition
Within the Florida market for natural gas, Gulfstream competes with other pipelines that transport and supply natural gas to end-users. Gulfstream’s competitors attempt to either attract new supply or attach new load to their pipelines, including those that are currently connected to markets served by Gulfstream. Gulfstream’s most direct competitor is Florida Gas Transmission Company, LLC, owned by subsidiaries of El Paso Corporation and Southern Union Company.
An increase in competition in the market could arise from new ventures or expanded operations from existing competitors. Other competitive factors include the quantity, location and physical flow characteristics of interconnected pipelines, access to natural gas storage, the cost-of-service and rates, and the terms of service offered.
General
We own a 50% interest in Market Hub, which owns and operates two high-deliverability salt cavern natural gas storage facilities — the Egan facility and the Moss Bluff facility. These storage facilities are capable of being fully or partially filled and depleted, or “cycled,” multiple times per year. Market Hub’s storage facilities offer access to traditional Gulf of Mexico natural gas supplies, onshore Texas and Louisiana supplies, mid-continent production, non-conventional (shale and tight-sands) onshore production, and growing imports of LNG to the Gulf Coast. Spectra Energy owns the remaining 50% interest in Market Hub and operates the system.
The Egan storage facility, located in Acadia Parish, Louisiana, has four storage caverns with a working gas capacity of approximately 28 Bcf, and includes a 47-mile pipeline system that interconnects with seven interstate pipeline systems, including Texas Eastern Transmission, and one intrastate pipeline system. Egan offers access to Gulf Coast, midwest, southeast and northeast markets. Egan is undergoing a multi-year expansion program to add approximately 8 Bcf of storage capacity and 16 miles of pipeline extensions. The initial phase-in of storage expansion of 6 Bcf occurred in mid-2009, and the project is scheduled to be completed in the second half of 2012.
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The Moss Bluff storage facility, located in Liberty County, Texas, has three storage caverns with a working gas capacity of approximately 15 Bcf, and includes a 20-mile pipeline system that interconnects with two interstate pipeline systems, including Texas Eastern Transmission, and three intrastate pipeline systems. Moss Bluff offers access to Texas, northeast and midwest markets. The construction on Cavern 4 will continue during 2010. This multi-year project is expected to increase working capacity by 6.5 Bcf as well as upgrade top-side facilities and expand pipeline interconnects. The cavern is expected to be placed in service in 2011.
Customer, Contracts and Supply
Market Hub provides storage services to a broad mix of customers including marketers, electric power generators, gas producers, pipelines and LDCs. In 2009, there were no customers that accounted for more than 10% of Market Hub’s revenues.
Market Hub provides firm storage, park and loan, and wheeling services. Under firm storage contracts, customers pay a reservation rate for the right to inject, withdraw and store a specified volume of natural gas. Under park and loan contracts, customers pay for the interruptible right to park (store) or loan (borrow) gas for a specific period of time. Customers who desire to wheel gas through a Market Hub facility pay for the interruptible right to receive natural gas at one interconnecting pipeline on the storage facility header system and have it simultaneously delivered to a different interconnecting pipeline on the storage facility header system.
As of December 31, 2009, Market Hub’s firm storage contracts had a weighted average remaining life of approximately three years, which is typical of the shorter contract life of market-based storage facilities as compared to transportation systems. Approximately 87% of Market Hub’s revenues in 2009 were derived from capacity reservation fees under firm storage contracts and 13% from interruptible storage contracts including park and loan services.
Egan has aggregate receipt capacity from major interconnecting pipelines of approximately 3.8 Bcf/d compared to an injection capability of 1.3 Bcf/d. Moss Bluff has aggregate receipt capacity from major
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interconnecting pipelines of approximately 2.3 Bcf/d compared to an injection capability of 0.6 Bcf/d. Egan has access to major interstate pipelines, while Moss Bluff has access to major interstate and intrastate pipelines. This level of supply connectivity gives customers access to a broad range of natural gas supply sources from existing onshore and offshore Gulf Coast and mid-Continent production areas as well as LNG supplies.
Competition
Market Hub competes with several regional storage facilities along the Gulf Coast as well as the storage services offered by interstate and intrastate pipelines that serve the same markets as Market Hub. The principal elements of competition among storage facilities are rates, terms of service, types of service, deliverability, supply and market access, and flexibility and reliability of service. An increase in competition in the market could arise from new ventures or expanded operations from existing competitors.
We compete for transportation, gathering and storage customers based on the specific type of service a customer needs, operating flexibility, available capacity and price. As noted previously, we provide a significant portion of our transportation and storage services through firm contracts and derive a smaller portion of our revenue through interruptible contracts, seeking to maximize the portion of physical capacity sold under firm contracts. To the extent physical capacity that is contracted for firm service is not being fully utilized, we can contract such capacity for interruptible service. Our gathering services, representing less than 3% of Gas Transmission and Storage operating revenues, are fee-based and dependent upon the volume of natural gas gathered. The table below summarizes certain information regarding our contracts and revenues as of and for the year ended December 31, 2009:
| Revenue Composition % | % of Physical Capacity Subscribed Under Firm Contracts |
Weighted Average Remaining Firm Contract Life (in years)(a) | |||||||||||||||
| Firm Contracts | Interruptible Contracts |
Volume-based Fees |
|||||||||||||||
| Asset |
Capacity Reservation Fees |
Variable Fees |
|||||||||||||||
| East Tennessee |
99 | % | 1 | % | — | % | — | % | 95 | % | 9 | ||||||
| Ozark |
|||||||||||||||||
| Transmission |
67 | 26 | 7 | — | 100 | 2 | |||||||||||
| Gathering |
— | — | — | 100 | n/a | n/a | |||||||||||
| Saltville |
87 | 6 | 7 | — | 99 | 8 | |||||||||||
| Gulfstream |
97 | 2 | 1 | — | 99 | 19 | |||||||||||
| Market Hub |
87 | — | 13 | — | 100 | 3 | |||||||||||
| (a) | The average life of each contract is calculated based on contract revenues. |
| n/a | Indicates not applicable. |
We purchase a variety of manufactured equipment and materials for use in operations and expansion projects. The primary equipment and materials utilized in operations and project execution processes are steel pipe, compression engines, valves, fittings, polyethylene plastic pipe, gas meters and other consumables.
We utilize Spectra Energy’s supply chain management function which operates a North American supply chain management network with employees dedicated to this function in the United States and Canada. The supply chain management group uses the economies-of-scale of Spectra Energy to maximize the efficiency of supply networks where applicable.
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There can be no assurance that the ability to obtain sufficient equipment and materials will not be adversely affected by unforeseen developments. In addition, the price of equipment and materials may vary, perhaps substantially, from year to year.
Our interstate gas transmission pipeline and storage operations are regulated by the FERC with the exception of Moss Bluff intrastate storage operations and the Ozark gathering facilities. The FERC regulates natural gas transportation in U.S. interstate commerce including the establishment of recourse rates for services. The FERC also regulates the construction of U.S. interstate pipelines and storage facilities including extension, enlargement and abandonment of facilities. Our Ozark gathering operations are subject to oversight by the Arkansas Public Service Commission and Oklahoma Corporation Commission. The Moss Bluff intrastate storage operations are subject to oversight by the Texas Railroad Commission (TRC).
The FERC may propose and implement new rules and regulations affecting interstate natural gas transmission and storage companies, which remain subject to the FERC’s jurisdiction. These initiatives may also affect certain transportation of gas by intrastate pipelines.
Our gas transmission and storage operations are subject to the jurisdiction of the Environmental Protection Agency (EPA) and various other federal, state and local environmental agencies. See “Environmental Matters” for a discussion of environmental regulation. Our interstate natural gas pipelines are also subject to the regulations of the DOT concerning pipeline safety.
Under current policy, the FERC permits pipelines and storage companies to include a tax allowance in the cost-of-service used as the basis for calculating their regulated rates. For pipelines and storage companies owned by partnerships or limited liability company interests, the tax allowance will reflect the actual or potential income tax liability on the FERC jurisdictional income attributable to all partnership or limited liability company interests if the ultimate owner of the interest has an actual or potential income tax liability on such income. This policy was upheld on May 29, 2007 by the Court of Appeals for the District of Columbia Circuit. Whether the owners of a pipeline or storage company have such actual or potential income tax liability will be reviewed by the FERC on a case-by-case basis. In a future rate case, the pipelines and storage companies in which we own an interest may be required to demonstrate the extent to which inclusion of an income tax allowance in the applicable cost-of-service is permitted under the current income tax allowance policy. Egan and Moss Bluff have authority to charge market-based rates and therefore this tax allowance issue does not affect the rates that they charge their customers.
We are subject to federal, state and local laws and regulations with regard to air and water quality, hazardous and solid waste disposal and other environmental matters. These regulations often impose substantial testing and certification requirements.
Environmental laws and regulations affecting us include, but are not limited to:
| • | The Clean Air Act (CAA) and the 1990 amendments to the CAA, as well as state laws and regulations affecting air emissions (including State Implementation Plans related to existing and new national ambient air quality standards), which may limit new sources of air emissions. Our natural gas transmission, storage and gathering assets are considered sources of air emissions and are thereby subject to the CAA. Owners and/or operators of air emission sources, such as us, are responsible for obtaining permits for existing and new sources of air emissions and for annual compliance and reporting. |
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| • | The Federal Water Pollution Control Act (Clean Water Act), which requires permits for facilities that discharge wastewaters into the environment. The Oil Pollution Act (OPA), was enacted in 1990 and amends parts of the Clean Water Act and other statutes as they pertain to the prevention of and response to oil spills. OPA imposes certain spill prevention, control and countermeasure requirements. Although we are primarily a natural gas business, OPA affects our business because of the presence of liquid hydrocarbons (condensate) in our offshore pipeline. |
| • | The Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act, which requires certain solid wastes, including hazardous wastes, to be managed pursuant to a comprehensive regulatory regime. As part of our business, we generate solid waste within the scope of these regulations and therefore must comply with such regulations. |
| • | The National Environmental Policy Act, which requires federal agencies to consider potential environmental effects in their decisions, including site approvals. Many of our capital projects require federal agency review, and therefore the environmental effect of proposed projects is a factor in determining whether we will be permitted to complete proposed projects. |
For more information on environmental matters, including possible liability and capital costs, see Item 8. Financial Statements and Supplementary Data, Note 15 of Notes to Consolidated Financial Statements.
Except to the extent discussed in Note 15, compliance with federal, state and local provisions regulating the discharge of materials into the environment, or otherwise protecting the environment, is incorporated into the routine cost structure of our partnership and is not expected to have a material adverse effect on our competitive position or consolidated results of operations, financial position or cash flows.
We do not have any employees. We are managed by the directors and officers of our general partner. Our general partner or its affiliates currently employ 110 people who spend a majority of their time operating the East Tennessee, Ozark and Saltville facilities, and 5 people who are primarily dedicated to us. Market Hub is operated by Spectra Energy pursuant to an operating and maintenance agreement and the employees who operate the Market Hub assets are therefore not included in the above numbers. Gulfstream is operated by Spectra Energy (with respect to business functions) and Williams (with respect to technical functions) pursuant to an operating and maintenance agreement, and therefore, the employees who operate the Gulfstream assets are also not included in the above numbers.
Terms used to describe our business are defined below.
Available Cash. For any quarter ending prior to liquidation:
(a) the sum of:
(1) all cash and cash equivalents of the partnership and our subsidiaries on hand at the end of that quarter; and
(2) if our general partner so determines all or a portion of any additional cash or cash equivalents of our partnership and our subsidiaries on hand on the date of determination of Available Cash for that quarter;
(b) less the amount of cash reserves established by our general partner to:
(1) provide for the proper conduct of the business of the partnership and our subsidiaries (including reserves for future capital expenditures and for future credit needs of the partnership and our subsidiaries) after that quarter;
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(2) comply with applicable law or any debt instrument or other agreement or obligation to which we or any of our subsidiaries are a part or our assets are subject; and
(3) provide funds for minimum quarterly distributions and cumulative common unit arrearages for any one or more of the next four quarters;
provided, however, that our general partner may not establish cash reserves pursuant to clause (b)(3) immediately above unless our general partner has determined that the establishment of reserves will not prevent us from distributing the minimum quarterly distribution on all common units and any cumulative common unit arrearages thereon for that quarter; and provided, further, that disbursements made by us or any of our subsidiaries or cash reserves established, increased or reduced after the end of that quarter but on or before the date of determination of Available Cash for that quarter shall be deemed to have been made, established, increased or reduced, for purposes of determining Available Cash, within that quarter if our general partner so determines.
Cumulative Common Unit Arrearage. The amount by which the minimum quarterly distribution for a quarter during the subordination period exceeds the distribution of Available Cash from operating surplus actually made for that quarter on a common unit, cumulative for that quarter and all prior quarters during the subordination period.
Operating Surplus. For any period prior to liquidation, on a cumulative basis and without duplication:
(a) the sum of:
(1) all cash receipts of our partnership and our subsidiaries for the period beginning on the closing date of our initial public offering and ending with the last day of the period, other than cash receipts from interim capital transactions; and
(2) an amount equal to the sum of (A) two times the amount needed for any one quarter for us to pay the minimum quarterly distribution on all units (including the general partner units) and (B) two times the amount in excess of the minimum quarterly distribution for any quarter to pay a distribution on all Common Units at the same per unit amount as was distributed on the Common Units in excess of the minimum quarterly distribution in the immediately preceding quarter, provided the amount in (B) will be deemed to be Operating Surplus only to the extent that the distribution paid in respect of such amounts is paid on Common Units, less
(b) the sum of:
(1) operating expenditures for the period beginning on the closing date of our initial public offering and ending with the last day of that period; and
(2) the amount of cash reserves (or our proportionate share of cash reserves in the case of subsidiaries that are not wholly owned) established by our general partner to provide funds for future operating expenditures; provided however, that disbursements made (including contributions to us or our subsidiaries or disbursements on behalf of us or our subsidiaries) or cash reserves established, increased or reduced after the end of that period but on or before the date of determination of Available Cash for that period shall be deemed to have been made, established, increased or reduced for purposes of determining operating surplus, within that period if our general partner so determines.
Subordination Period. The subordination period began with the closing of the initial public offering on July 2, 2007, and will last until the first to occur of the following dates:
(a) The first day of any quarter beginning after June 30, 2010 in respect of which each of the following tests are met:
(1) distribution of Available Cash from operating surplus on each of the outstanding common units and subordinated units equaled or exceeded the sum of the minimum quarterly distributions on all
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of the outstanding common units and subordinated units for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;
(2) the adjusted operating surplus generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of the minimum quarterly distributions on all of the outstanding common units, subordinated units and general partner units during those periods on a fully diluted basis; and
(3) there are no outstanding cumulative common units arrearages.
(b) The first date after we have earned and paid at least $0.45 per quarter (150% of the minimum quarterly distribution of $0.30 per quarter, which is $1.80 on an annualized basis) on each outstanding limited partner unit and general partner unit for any four consecutive quarters ending on or after June 30, 2008; and
(c) The date on which the general partner is removed as our general partner upon the requisite vote by the limited partners under circumstances where cause does not exist and units held by our general partner and its affiliates are not voted in favor of the removal.
When the subordination period ends, all remaining subordinated units will convert into common units on a one-for-one basis, and the common units will no longer be entitled to arrearages.
We were formed on March 19, 2007 as a Delaware master limited partnership. Our principal executive offices are located at 5400 Westheimer Court, Houston, Texas 77056 and our telephone number is 713-627-5400. We electronically file various reports with the Securities and Exchange Commission (SEC), including annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to such reports. The public may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains an internet site that contains reports and information statements, and other information regarding issuers that file electronically with the SEC at http://www.sec.gov. Additionally, information about us, including our reports filed with the SEC, is available through our web site at http://www.spectraenergypartners.com. Such reports are accessible at no charge through our web site and are made available as soon as reasonably practicable after such material is filed with or furnished to the SEC. Our website and the information contained on that site, or connected to that site, is not incorporated by reference into this report.
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Discussed below are the more significant risk factors relating to us.
Risks Related to our Business
We may not have sufficient cash from operations to enable us to make cash distributions to holders of common and subordinated units.
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 $24.1 million per quarter, or $96.4 million per year, depending on the actual number of common units and subordinated units outstanding. We may not have sufficient Available Cash from operating surplus each quarter to enable us to make cash distributions at the minimum distribution rate. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from operations, which will fluctuate based on, among other things:
| • | the rates charged for transportation, storage and gathering services, and the volumes of natural gas contracted by customers for transportation, storage and gathering services; |
| • | the overall demand for natural gas in the southeastern, mid-Continent and mid-Atlantic regions of the United States and the quantities of natural gas available for transport, especially from the Gulf of Mexico, Appalachian and mid-Continent areas; |
| • | regulatory action affecting the demand for natural gas, the supply of natural gas, the rates we can charge, contracts for services, existing contracts, operating costs and operating flexibility; |
| • | 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 cash available for distribution will depend on other factors, some of which are beyond our control, including:
| • | the level of capital expenditures to complete construction projects; |
| • | the cost and form of payment of acquisitions; |
| • | debt service requirements and other liabilities; |
| • | fluctuations in working capital needs; |
| • | the ability to borrow funds and access capital markets; |
| • | restrictions on distributions contained in debt agreements; and |
| • | the amount of cash reserves established by our general partner. |
Our subsidiaries and equity affiliates conduct operations and own our operating assets, which may affect our ability to make distributions to our unitholders. In addition, we cannot control the amount of cash that will be received from Gulfstream and Market Hub, and we may be required to contribute significant cash to fund their operations.
We are a partnership holding company and our operating subsidiaries conduct all of our operations and own all of our operating assets. We have no significant assets other than the ownership interests in our subsidiaries and our equity investments, including Gulfstream and Market Hub. As a result, our ability to make distributions to our unitholders depends on the performance of these subsidiaries and equity investments and their ability to distribute funds to us. The ability of our subsidiaries and equity investments to make distributions to us may be restricted by, among other things, the provisions of existing and future indebtedness, applicable state partnership and limited liability company laws and other laws and regulations, including FERC policies.
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Market Hub and Gulfstream are expected to generate approximately one-half of the cash we distribute. Spectra Energy operates Market Hub and the operation of Gulfstream is shared between Spectra Energy and Williams. Accordingly, we do not control the amount of cash distributed to us nor do we control ongoing operational decisions, including the incurrence of capital expenditures that we may be required to fund.
Our lack of control over the operations of Gulfstream and Market Hub may mean that we do not receive the amount of cash we expect to be distributed to us. In addition, we may be required to provide additional capital, and these contributions may be material. Neither Gulfstream nor Market Hub is prohibited from incurring indebtedness by the terms of their respective limited liability company agreement and general partnership agreements. If Gulfstream or Market Hub were to incur significant additional indebtedness, it could inhibit their respective abilities to make distributions to us. This lack of control may significantly and adversely affect our ability to distribute cash.
Natural gas transportation, storage and gathering operations are subject to regulation by federal, state and local authorities, which could have an adverse effect on our ability to establish transportation, storage and gathering rates that would allow us to recover the full cost of operating our pipelines, including a reasonable return, and our ability to make distributions.
Our interstate natural gas transportation, storage and gathering operations are subject to federal, state and local regulatory authorities. Specifically, our natural gas pipeline systems and certain of our storage facilities and related assets are subject to regulation by the FERC. Its authority to regulate natural gas pipeline transportation services includes the rates charged for the services, terms and conditions of service, certification and construction of new facilities, the extension or abandonment of services and facilities, the maintenance of accounts and records, the acquisition and disposition of facilities, the initiation and discontinuation of services, and various other matters.
In addition, we cannot give any assurance regarding the likely future regulations under which we will operate our natural gas transportation, storage and gathering businesses or the effect such regulation could have on our business, financial condition, results of operations and our ability to make distributions.
Certain transportation services are subject to long-term, fixed-price “negotiated rate” contracts that are not subject to adjustment, even if our cost to perform services exceeds the revenues received from such contracts, and, as a result, our costs could exceed our revenues received under such contracts.
Under the FERC policy, a regulated service provider and a customer may mutually agree to sign a contract for service at a “negotiated rate” which may be above or below the FERC-regulated “recourse rate” for that service. For 2009, 99% of Gulfstream’s firm revenues were derived from such negotiated rate contracts and approximately 44% of Gas Transportation and Storage’s firm revenues were derived from capacity reservation charges under negotiated rate contracts. These negotiated rate contracts are not subject to adjustment for increased costs which could be produced by inflation or other factors relating to the specific facilities being used to perform the services. It is possible that Gulfstream’s, East Tennessee’s, Ozark’s and Saltville’s costs to perform services under these negotiated rate contracts will exceed the negotiated rates. If this occurs, it could decrease cash flows from Gulfstream, East Tennessee, Ozark and Saltville.
Market Hub’s right to charge “market-based rates” at its Egan storage facility is subject to the continued existence of certain conditions related to the competitive position of Market Hub and, if those conditions change, the right to charge market-based rates could be terminated.
Certain of the rates charged by Market Hub are regulated by the FERC pursuant to its market-based rate policy, which allows regulated storage companies to charge rates above those which would be permitted under traditional cost-of-service regulation. The right of Market Hub to charge market-based rates is based upon determinations by the FERC that it does not have market power in the relevant market areas it serves. This determination of a lack of market power is subject to review and revision by the FERC if circumstances change. In the event of an adverse determination concerning market power with respect to Market Hub, its rates could become subject to cost-of-service regulation which could have adverse consequences for the cash flows of Market Hub.
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Increased competition from alternative natural gas transportation, storage and gathering options and alternative fuel sources could have a significant financial effect on us.
We compete primarily with other interstate and intrastate pipelines, storage and gathering facilities in the transportation, storage and gathering of natural gas. Some of our competitors have greater financial resources and access to greater supplies of natural gas than we do. Some of these competitors may expand or construct transportation, storage and gathering systems that would create additional competition for the services we provide to our customers. Moreover, Spectra Energy and its affiliates are not limited in their ability to compete with us. Further, natural gas also competes with other forms of energy available to our customers, including electricity, coal and fuel oils.
The principal elements of competition among natural gas transportation, storage and gathering assets are rates, terms of service, access to natural gas supplies, flexibility and reliability. The FERC’s policies promoting competition in natural gas markets are having the effect of increasing the natural gas transportation, storage and gathering options for our traditional customer base. As a result, we could experience some “turnback” of firm capacity as existing agreements expire. If East Tennessee, Ozark, Saltville, Gulfstream or Market Hub are unable to remarket this capacity or can remarket it only at substantially discounted rates compared to previous contracts, they may have to bear the costs associated with the turned back capacity. Increased competition could reduce the volumes of natural gas transported, stored or gathered by our systems or, in cases where we do not have long-term fixed rate contracts, could force us to lower our transportation, storage or gathering rates. Competition could intensify the negative effect of factors that significantly decrease demand for natural gas in the markets served by our pipeline systems, such as competing or alternative forms of energy, a recession or other adverse economic conditions, weather, higher fuel costs and taxes or other governmental or regulatory actions that directly or indirectly increase the cost or limit the use of natural gas. Our ability to renew or replace existing contracts at rates sufficient to maintain current revenues and cash flows could be adversely affected by the activities of our competitors. All of these competitive pressures could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions.
Any significant decrease in supplies of natural gas connected to our areas of operation could adversely affect business and operating results, and reduce cash available for distribution.
All of our businesses are dependent on the continued availability of natural gas production and reserves. Low prices for natural gas or regulatory limitations could adversely affect development of additional reserves and production that is accessible by our pipeline and storage assets. Production from existing wells and natural gas supply basins with access to our pipelines will naturally decline over time. Additionally, the amount of natural gas reserves underlying these wells may also be less than anticipated, and the rate at which production from these reserves declines may be greater than anticipated. Accordingly, to maintain or increase throughput on our pipelines and cash flows associated with the transportation of gas, our customers must continually obtain new supplies of natural gas.
If new supplies of natural gas are not obtained to replace the natural decline in volumes from existing supply basins, the overall volume of natural gas transported, stored and gathered on our systems would decline, which could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions.
We may not be able to maintain or replace expiring natural gas transportation, storage and gathering contracts at favorable rates.
Our primary exposure to market risk occurs at the time existing transportation, storage and gathering contracts expire and are subject to renegotiation and renewal. A portion of the revenue generated by our systems in 2009 is attributable to firm capacity reservation fees that are set to expire on or prior to December 31, 2012. For Gas Transportation and Storage, Gulfstream and Market Hub, those portions were 18%, 1% and 51%,
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respectively. Upon expiration, we may not be able to extend contracts with existing customers or obtain replacement contracts at favorable rates or on a long-term basis. The extension or replacement of existing contracts depends on a number of factors beyond our control, including:
| • | the level of existing and new competition to deliver natural gas to our markets; |
| • | the growth in demand for natural gas in our markets; |
| • | whether the market will continue to support long-term contracts; |
| • | whether our business strategy continues to be successful; and |
| • | the effects of state regulation on customer contracting practices. |
Our key markets are projected to continue to exhibit higher than average annual growth in natural gas demand of approximately 3.0% through 2019 as compared with the U.S. lower 48 average growth rate of approximately 2% for the same period. This demand growth is primarily driven by the natural gas-fired electric generation sector.
Any failure to extend or replace a significant portion of our existing contracts may have a material adverse effect on our business, financial condition, results of operations and ability to make distributions.
We depend on certain key customers for a significant portion of our revenues. The loss of any of these key customers could result in a decline in our revenues and cash available to make distributions.
We rely on a limited number of customers for a significant portion of revenues. For the year ended December 31, 2009, the three largest customers for Gas Transportation and Storage were Atmos Energy Corporation, CNX Gas Corporation and Southwestern Energy Services, Co.; for Gulfstream were Florida Power & Light Company, Florida Power Corporation d/b/a Progress Energy Florida, Inc. and TECO Energy and its affiliates; and for Market Hub were J.P. Morgan Ventures Energy Corporation, NiSource and AGL Resources. In 2009, these customers accounted for approximately 26%, 87% and 25% of the operating revenues for Gas Transportation and Storage, Gulfstream and Market Hub, respectively. While most of these customers are subject to long-term contracts, the loss of all or even a portion of the contracted volumes of these customers as a result of competition, creditworthiness, inability to negotiate extensions or replacements of contracts or otherwise, could have a material adverse effect on our financial condition, results of operations and ability to make distributions, unless we are able to contract for comparable volumes from other customers at favorable rates.
If third-party pipelines and other facilities interconnected to our pipelines become unavailable to transport natural gas, our revenues and cash available to make distributions 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 a material adverse effect on our business, results of operations, financial condition and 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; |
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| • | an inability to obtain necessary rights-of-way or government approvals, including regulatory agencies; |
| • | an inability to successfully integrate the businesses we build or acquire; |
| • | we are unable to raise financing for such expansion projects or acquisitions on economically acceptable terms; |
| • | incorrect assumptions about volumes, reserves, revenues and costs, including synergies and potential growth; or |
| • | we are unable to secure adequate customer commitments to use the newly expanded or acquired facilities. |
Expansion projects or future acquisitions that appear to be accretive may nevertheless reduce our cash from operations on a per unit basis.
Even if we complete expansion projects or make acquisitions that we believe will be accretive, these expansion projects or acquisitions may nevertheless reduce our cash from operations on a per-unit basis. Any expansion project or acquisition involves potential risks, including, among other things:
| • | an inability to complete expansion projects on schedule or within the budgeted cost due to the unavailability of required construction personnel, equipment or materials, and the risk of cost overruns resulting from inflation or increased costs of materials, labor and equipment; |
| • | a decrease in our liquidity as a result of us using a significant portion of our Available Cash or borrowing capacity to finance the project or acquisition; |
| • | an inability to complete expansion projects on schedule due to accidents, weather conditions or an inability to obtain necessary permits; |
| • | an inability to receive cash flows from a newly built or acquired asset until it is operational; |
| • | unforeseen difficulties operating in new product areas or new geographic areas; and |
| • | customer losses at the acquired business. |
Any of these risks could prevent a project from proceeding, delay its completion or increase our anticipated costs. As a result, our new facilities may not achieve expected investment returns, which could adversely affect our results of operations, financial position or cash flows. If any expansion projects or acquisitions that we ultimately complete are not accretive to cash available for distribution, our ability to make distributions may be reduced.
The amount of our cash available for distribution depends primarily on our cash flows and not solely on profitability, which may prevent us from making cash distributions during periods when we record net income.
Our amount of cash available for distribution 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.
Significant prolonged changes in natural gas prices could affect supply and demand, reducing contracted volumes on our systems and adversely affecting revenues and cash available to make distributions over the long-term.
Higher natural gas prices over the long term could result in a decline in the demand for natural gas and, therefore, in the throughput on our systems. Also, lower natural gas prices over the long term could result in a
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decline in the production of natural gas resulting in reduced contracted volumes on our systems. In addition, prolonged reduced price volatility could reduce the revenues generated by our parking-and-lending and interruptible storage services. As a result, significant prolonged changes in natural gas prices could have a material adverse effect on our financial condition, results of operations and ability to make distributions.
Our operations are subject to environmental laws and regulations that may expose us to significant costs and liabilities.
Our natural gas transportation, storage and gathering activities are subject to stringent and complex federal, state and local environmental laws and regulations. We may incur substantial costs in order to conduct our operations in compliance with these laws and regulations. Moreover, new and stricter environmental laws, regulations or enforcement policies could be implemented that significantly increase our compliance costs or the cost of any remediation of environmental contamination that may become necessary, and these costs could be material.
Failure to comply with environmental laws and regulations, or the permits issued under them, may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations and the issuance of injunctions limiting or preventing some or all of our operations. In addition, strict joint and several liability may be imposed under certain environmental laws, which could cause us to become liable for the conduct of others or for consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. Private parties may also have the right to pursue legal actions against us to enforce compliance, as well as to seek damages for noncompliance, with environmental laws and regulations or for personal injury or property damage that may result from environmental and other effects of operations. We may not be able to recover some or any of these costs through insurance or increased revenues, which may have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions.
The enactment of future climate change legislation could result in increased operating costs and delays in obtaining necessary permits for our capital projects.
The current international climate framework, the United Nations-sponsored Kyoto Protocol, prescribes specific targets to reduce greenhouse gas (GHG) emissions for developed countries for the 2008-2012 period. The Kyoto Protocol expires in 2012 and has not been signed by the United States. United Nations-sponsored international negotiations were held in Copenhagen, Denmark in December 2009 with the intent of defining a future agreement for 2012 and beyond. While the talks resulted in a non-binding political agreement, to date, a binding successor accord to the Kyoto Protocol has not been realized.
In the United States, climate change action is evolving at state, regional and federal levels. We expect that a number of our assets and operations could be affected by eventual mandatory GHG programs; however, the timing and specific policy objectives in many jurisdictions, including at the federal level, remain uncertain. In addition, a number of states in the United States are establishing or considering state or regional programs that would mandate reductions in GHG emissions. We expect a number 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.
The EPA has proposed the Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule in 2009 to address how GHG emissions would be regulated under the existing Clean Air Act. This proposed rulemaking has not yet been finalized. Regulation of GHG emissions under the Clean Air Act would subject our new capital projects to additional permitting requirements which may result in delays in completing such projects. In addition, several legislative proposals have been introduced and discussed in the U.S. Congress that would impose GHG emissions constraints, including H.R. 2454 – the American Clean Energy and Security Act, which passed the House of Representatives in June 2009. To date, similar legislation has not been considered by the full U.S. Senate. Due to the speculative outlook regarding any U.S. federal and state policies, we cannot
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estimate the potential effect of proposed GHG policies on our future consolidated results of operations, financial position or cash flows. However such legislation could materially increase our operating costs, require material capital expenditures or create additional permitting, which could delay proposed construction projects.
We may incur significant costs and liabilities as a result of pipeline integrity management program testing and any necessary pipeline repair or preventative or remedial measures.
The DOT has adopted regulations requiring pipeline operators to develop integrity management programs for transportation pipelines located where a leak or rupture could do the most harm in “high consequence areas.” The regulations require operators to:
| • | perform ongoing assessments of pipeline integrity; |
| • | identify and characterize applicable threats to pipeline segments that could affect a high consequence area; |
| • | improve data collection, integration and analysis; |
| • | repair and remediate the pipeline as necessary; and |
| • | implement preventive and mitigating actions. |
Our actual implementation costs may be affected by industry-wide demand for the associated contractors and service providers. Additionally, should we fail to comply with DOT regulations, we could be subject to penalties and fines.
Our operations are subject to operational hazards and unforeseen interruptions.
Our operations are subject to many hazards inherent in the transportation, storage and gathering of natural gas, including:
| • | damage to pipelines, facilities and related equipment caused by hurricanes, tornadoes, floods, fires and other natural disasters, explosions and acts of terrorism; |
| • | inadvertent damage from third parties, including from construction, farm and utility equipment; |
| • | leaks of natural gas and other hydrocarbons or losses of natural gas as a result of the malfunction of equipment or facilities; |
| • | collapse of storage caverns; |
| • | operator error; |
| • | environmental pollution; |
| • | explosions and blowouts; |
| • | risks related to underwater pipelines in the Gulf of Mexico, which are susceptible to damage from shifting as a result of water currents (as seen in the Gulf of Mexico following Hurricanes Katrina, Rita, Gustav and Ike), as well as damage from vessels; |
| • | risks related to pipeline that traverses areas in Florida where karst conditions exist. Karst conditions refers to terrain, usually found where limestone or other carbonate rock is present, that may subside or result in a sinkhole collapse when the underlying water table changes; and |
| • | risks related to operating in a marine environment. |
These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment, and pollution or other environmental damage which may result in curtailment or suspension of our related operations. A natural disaster or other hazard affecting the areas in which we operate could have a material adverse effect on our operations.
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We do not insure against all potential losses and could be seriously harmed by unexpected liabilities.
We are not fully insured against all risks inherent to our business. We are not insured against all environmental accidents that might occur. If a significant accident or event occurs that is not fully insured, it could adversely affect our operations and financial condition. In addition, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. Changes in the insurance markets subsequent to the September 11, 2001 terrorist attacks, and Hurricanes Katrina, Rita, Gustav and Ike have made it more difficult for us to obtain certain types of coverage, and we may elect to self insure a portion of our asset portfolio. In addition, we do not maintain offshore business interruption insurance. There can be no assurance that we will be able to obtain the levels or types of insurance we would otherwise have obtained prior to these market changes or that the insurance coverage we do obtain will not contain large deductibles or fail to cover certain hazards or cover all potential losses. The occurrence of any operating risks not fully covered by insurance could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions.
Our debt levels may limit our flexibility in obtaining additional financing and in pursuing other business opportunities.
At December 31, 2009, we had $240 million in revolving debt under our $500 million credit facility. We continue to have the ability to incur additional debt, subject to limitations in our credit facility. Our level of debt could have important consequences, including the following:
| • | our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms; |
| • | we will need a substantial portion of our cash flow to make principal and interest payments on our indebtedness, reducing the funds that would otherwise be available for operations, future business opportunities and distributions to unitholders; and |
| • | our debt level could make us more vulnerable than our competitors with less debt to competitive pressures or a downturn in our business or the economy in general. |
Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. In addition, our ability to service debt under our revolving credit facility will depend on market interest rates, since we anticipate that the interest rates applicable to our borrowings will fluctuate with movements in interest rate markets. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets, restructuring or refinancing debt, or seeking additional equity capital. We may not be able to affect any of these actions on satisfactory terms, or at all.
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.
We are a holding company with no business operations. As such, we depend upon the earnings and cash flow of our subsidiaries and equity investments and the distribution of that cash to us in order to meet our obligations and to allow us to make distributions to our unitholders. Any interruption of distributions to us from our subsidiaries and equity investments may limit our ability to satisfy our obligations and to make distributions. 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; |
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| • | 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.
If we were to have an independent credit rating in the future, our credit rating could be adversely affected by the leverage of our general partner or Spectra Energy, as credit rating agencies may consider the leverage and credit profile of Spectra Energy and its affiliates because of their ownership interest in and control of us, and the strong operational links between Spectra Energy and us. Any adverse effect on our credit rating would increase our cost of borrowing or hinder our ability to raise financing in the capital markets, which would impair our ability to grow our business and make distributions.
Terrorist attacks, and the threat of terrorist attacks, have resulted in increased costs to our business. Continued global hostilities or other sustained military campaigns may adversely affect our results of operations.
Acts of terrorism and any possible reprisals as a consequence of any action by the United States and its allies could be directed against companies operating in the United States. This risk is particularly great for companies, like ours, operating in any energy infrastructure industry that handles volatile gaseous and liquid hydrocarbons. The potential for terrorism has subjected our operations to increased risks that could have a material adverse effect on our business. In particular, we may experience increased capital and operating costs to implement increased security for our facilities and pipelines, such as additional physical facility and pipeline security, and additional security personnel. Moreover, any physical damage to high profile facilities resulting from acts of terrorism may not be covered, or covered fully, by insurance. We may be required to expend material amounts of capital to repair any facilities, the expenditure of which could adversely affect our cash flows and business.
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Changes in the insurance markets attributable to terrorist attacks may make certain types of insurance more difficult for us to obtain. Moreover, the insurance that may be available to us may be significantly more expensive than our existing insurance coverage. Instability in the financial markets as a result of terrorism or war could also affect our ability to raise capital.
Risks Inherent in an Investment in Us
Spectra Energy controls our general partner, which has sole responsibility for conducting our business and managing our operations. Our general partner and its affiliates, including Spectra Energy, have conflicts of interest with us and limited fiduciary duties, and may favor their own interests to the detriment of us.
Spectra Energy owns and controls our general partner. Some of our general partner’s directors, and some of its executive officers, are directors or officers of Spectra Energy or its affiliates. Although our general partner has a fiduciary duty to manage us in a manner beneficial to Spectra Energy and our unitholders, the directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to Spectra Energy. Therefore, conflicts of interest may arise between Spectra Energy and its affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. These conflicts include, among others, the following situations:
| • | neither our partnership agreement nor any other agreement requires Spectra Energy to pursue a business strategy that favors us. Spectra Energy’s directors and officers have a fiduciary duty to make these decisions in the best interests of the owners of Spectra Energy, which may be contrary to our interests; |
| • | our general partner is allowed to take into account the interests of parties other than us, such as Spectra Energy and its affiliates, in resolving conflicts of interest; |
| • | Spectra Energy and its affiliates are not limited in their ability to compete with us; |
| • | our general partner may make a determination to receive a quantity of our Class B units in exchange for resetting the target distribution levels related to its incentive distribution rights without the approval of the Conflicts Committee of our general partner or our unitholders; |
| • | some officers of Spectra Energy who provide services to us also will devote significant time to the business of Spectra Energy and will be compensated by Spectra Energy for the services rendered to it; |
| • | our general partner has limited its liability and reduced its fiduciary duties, and has also restricted the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty. By purchasing common units, unitholders will be deemed to have consented to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable law; |
| • | our general partner determines the amount and timing of asset purchases and sales, borrowings, 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 and the ability of the subordinated units to convert to common units; |
| • | our general partner determines which costs incurred by it and its affiliates are reimbursable by us; |
| • | in some instances, our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination period; |
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| • | our partnership agreement does not restrict our general partner from causing us to pay it or our affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf; |
| • | our general partner intends to limit its liability regarding our contractual and other obligations and, in some circumstances, is entitled to be indemnified by us; |
| • | our general partner may exercise its limited right to call and purchase common units if it and its affiliates own more than 80% of the common units; |
| • | our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates; and |
| • | our general partner decides whether to retain separate counsel, accountants or others to perform services for us. |
Affiliates of our general partner, including Spectra Energy, DCP Midstream, LLC and DCP Midstream Partners, LP, are not limited in their ability to compete with us, which could limit commercial activities or our ability to acquire additional assets or businesses.
Neither our partnership agreement nor the omnibus agreement among us, Spectra Energy and others prohibits affiliates of our general partner, including Spectra Energy, DCP Midstream, LLC and DCP Midstream Partners, LP, from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, Spectra Energy and its affiliates may acquire, construct or dispose of additional transportation, storage and gathering or other assets in the future, without any obligation to offer us the opportunity to purchase or construct any of those assets. Each of these entities is a large, established participant in the midstream energy business and each has significantly greater resources and experience than we have, which factors may make it more difficult for us to compete with these entities with respect to commercial activities as well as for acquisition candidates. As a result, competition from these entities could adversely affect our results of operations and cash available for distribution.
If a unitholder is not an Eligible Holder, such unitholder will not be entitled to receive distributions or allocations of income or loss on common units and those common units will be subject to redemption at a price that may be below the current market price.
In order to comply with certain FERC rate-making policies applicable to entities that pass through taxable income to their owners, we have adopted certain requirements regarding those investors who may own our common and subordinated units. Eligible Holders are individuals or entities subject to United States federal income taxation on the income generated by us or entities not subject to United States federal income taxation on the income generated by us, so long as all of the entity’s owners are subject to such taxation. If a unitholder is not a person who fits the requirements to be an Eligible Holder, such unitholder will not receive distributions or allocations of income and loss on the unitholder’s units and the unitholder runs the risk of having the units redeemed by us at the lower of the unitholder’s purchase price cost or the then-current market price. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner.
Cost reimbursements to our general partner and its affiliates for services provided, which will be determined by our general partner, will be substantial and will reduce our cash available for distribution.
Pursuant to an omnibus agreement we entered into with Spectra Energy, our general partner and certain of their affiliates, Spectra Energy will receive reimbursement for the payment of operating expenses related to our operations and for the provision of various general and administrative services for our benefit, including costs for rendering administrative staff and support services, and overhead allocated to us, which amounts will be determined by our general partner in its sole discretion. Payments for these services will be substantial and will reduce the amount of cash available for distribution. In addition, under Delaware partnership law, our general partner has unlimited liability for our obligations, such as our debts and environmental liabilities, except for
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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 and subordinated units, and restricts the remedies available to holders of our common and subordinated units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
Our partnership agreement contains provisions that reduce the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty laws. For example, our partnership agreement:
| • | permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting us, our affiliates or any limited partner; |
| • | 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. |
By purchasing a common unit, a common unitholder will agree to become bound by the provisions in the partnership agreement, including the provisions discussed above.
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
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minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per common unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as the “reset minimum quarterly distribution”) and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution amount.
In connection with resetting these target distribution levels, our general partner will be entitled to receive a number of Class B units. The Class B units will be entitled to the same cash distributions per unit as our common units and will be convertible into an equal number of common units. The number of Class B units to be issued will be equal to that number of common units whose aggregate quarterly cash distributions equaled the average of the distributions to our general partner on the incentive distribution rights in the prior two quarters. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion; however, it is possible that our general partner could exercise this reset election at a time when it is experiencing, or may be expected to experience, declines in the cash distributions it receives related to its incentive distribution rights and may therefore desire to be issued our Class B units, which are entitled to receive cash distributions from us on the same priority as our common units, rather than retain the right to receive incentive distributions based on the initial target distribution levels. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued new Class B units to our general partner in connection with resetting the target distribution levels related to our general partner incentive distribution rights.
Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors, which could reduce the price at which the common units will trade.
Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will not elect our general partner or its board of directors, and will have no right to elect our general partner or board of directors on an annual or other continuing basis. The board of directors of our general partner, including the independent directors, will be chosen entirely by its owners and not by the unitholders. Furthermore, if the unitholders were dissatisfied with the performance of the general partner, they will have little ability to remove the general partner. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.
Even if holders of our common units are dissatisfied, they cannot initially remove our general partner without its consent.
The unitholders will be unable initially to remove our general partner without its consent because the general partner and its affiliates own sufficient units to be able to prevent its removal. The vote of the holders of at least 66 2/3% of all outstanding units voting together as a single class is required to remove our general partner. Our general partner and its affiliates own 73% of our aggregate outstanding common and subordinated units. Also, if our general partner is removed without cause during the subordination period and units held by our general partner and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically convert into common units and any existing arrearages on our common units will be extinguished. A removal of our general partner under these circumstances would adversely affect our common units by prematurely eliminating their distribution and liquidation preference over the subordinated units, which would otherwise have continued until we had met certain distribution and performance tests. “Cause” is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding the general partner liable for actual fraud or willful or wanton misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business, so the removal of the general partner because of the unitholders’ dissatisfaction with the general partner’s performance in managing us will most likely result in the termination of the subordination period and conversion of all subordinated units to common units.
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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 a material adverse effect on our business.
Our assets include a 100% ownership interest in East Tennessee, Ozark and Saltville, a 24.5% limited liability company interest in Gulfstream and a 50% general partner interest in Market Hub. If a sufficient amount of our assets, such as our ownership interests in Gulfstream and Market Hub or other assets acquired in the future, are deemed to be “investment securities” within the meaning of the Investment Company Act of 1940, we would either have to register as an investment company under the Investment Company Act, obtain exemptive relief from the SEC or modify the organizational structure or contract rights to fall outside the definition of an investment company. Although general partner interests are typically not considered “securities” or “investment securities,” there is a risk that our 50% general partner interest in Market Hub could be deemed to be an investment security. In that event, it is possible that our ownership of this interest, combined with our 24.5% interest in Gulfstream or assets acquired in the future, could result in us being required to register under the Investment Company Act if we were not successful in obtaining exemptive relief or otherwise modifying the organizational structure or applicable contract rights. Registering as an investment company could, among other things, materially limit our ability to engage in transactions with affiliates, including the purchase and sale of certain securities or other property to or from its 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 a material adverse effect on our business.
Control of our general partner may be transferred to a third party without unitholder consent.
Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of the owners of our general partner or its parent from transferring all or a portion of their respective ownership interest in the general partner or its parent to a third party. The new owners of our general partner or its parent would then be in a position to replace the board of directors and officers of its parent with its own choices and thereby influence the decisions taken by the board of directors and officers.
Increases in interest rates could adversely affect our unit price and our ability to issue additional equity to make acquisitions, incur debt or for other purposes.
In recent years, the U.S. credit markets have experienced 50-year record lows in interest rates. Interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our unit price is affected by the level of our cash distributions and implied distribution yield. Therefore, changes in interest rates may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse effect on our unit price and the ability to issue additional equity to make acquisitions, to incur debt or for other purposes.
We may issue additional units without our common unitholders’ approval, which would dilute our existing common unitholders’ ownership interests.
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Our partnership agreement does not limit the number of additional limited partner interests that we may issue at any time without the approval of our unitholders. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:
| • | each unitholder’s proportionate ownership interest in us will decrease; |
| • | the amount of cash available for distribution on each unit may decrease; |
| • | because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase; |
| • | the ratio of taxable income to distributions may increase; |
| • | the relative voting strength of each previously outstanding unit may be diminished; and |
| • | the market price of the common units may decline. |
Spectra Energy and its affiliates may sell units in the public or private markets, which sales could have an adverse effect on the trading price of the common units.
As of February 26, 2010, Spectra Energy and its affiliates hold an aggregate of 37,337,521 common units and 21,638,730 subordinated units. All of the subordinated units will convert into common units at the end of the subordination period, which could occur on the first business day after June 30, 2010, and all of the subordinated units may convert into common units if additional tests are satisfied. 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 February 26, 2010, our general partner and its affiliates own approximately 64% of our outstanding common units. At the end of the subordination period, assuming no additional issuances of common units (other than for the conversion of the subordinated units into common units), our general partner and its affiliates will own approximately 73% of our aggregate outstanding common units.
Our common unitholder’s 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 unitholder’s right to act with other unitholders to remove or replace the general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitutes “control” of our business. |
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Unitholders may have liability to repay distributions that were wrongfully distributed to them.
Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to the unitholder if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable for the obligations of the assignor to make contributions to the partnership that are known to the substituted limited partner at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the partnership agreement.
Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.
Tax Risks to Common Unitholders
Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service (IRS) treats us as a corporation or we become subject to a material amount of entity-level taxation for state tax purposes, it would substantially reduce the amount of cash available for distribution.
The anticipated after-tax economic benefit of an investment in our common units depends largely on us being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter affecting us.
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35% and would likely pay state income tax at varying rates. Distributions would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to the common unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to a common unitholder, likely causing a substantial reduction in the value of our common units.
Current law may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. In addition, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation.
Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution levels may be adjusted to reflect the effect of that law.
An IRS contest of the federal income tax positions we take may adversely affect the market for our common units, and the cost of any IRS contest will reduce our cash available for distribution.
We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter. The IRS may adopt positions that differ from the conclusions of us. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take. A court may not agree with all of our conclusions or positions we take. Any contest with the IRS may materially and adversely affect the market for our common units and the price at which they trade. In addition, the costs of any contest with the IRS will be borne indirectly by the unitholders and our general partner because the costs will reduce our cash available for distribution.
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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 will be treated as partners to whom we will allocate taxable income which could be different in amount than the cash distributed, common unitholders will be required to pay any federal income taxes and, in some cases, state and local income taxes on the common unitholder’s share of taxable income even if the common unitholders receive no cash distributions from us. The common unitholder may not receive cash distributions from us equal to the unitholder’s share of taxable income or even equal to the actual tax liability that results from that income.
Tax gain or loss on disposition of our common units could be more or less than expected.
If the common unitholder sells its common units, the unitholder will recognize a gain or loss equal to the difference between the amount realized and the common unitholder’s tax basis in those common units. Because distributions in excess of the common unitholder’s allocable share of our net taxable income decrease the common unitholder’s tax basis in the common units, the amount, if any, of such prior excess distributions with respect to the units the unitholder sells will, in effect, become taxable income to the unitholder if the unitholder sells such units at a price greater than the tax basis, even if the price the unitholder receives is less than the original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes the share of our nonrecourse liabilities, if the common unitholder sells the units, the common unitholder may incur a tax liability in excess of the amount of cash the unitholder receives from the sale.
Tax-exempt entities and foreign persons face unique tax issues from owning common units that may result in adverse tax consequences to them.
Investment in common units by tax-exempt entities, such as individual retirement accounts (IRAs), other retirement plans and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file United States federal tax returns and pay tax on their share of our taxable income. If the unitholder is a tax-exempt entity or a foreign person, the unitholder should consult a tax advisor before investing in our common units.
We will treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.
Because we cannot match transferors and transferees of common units and because of other reasons, we will adopt depreciation and amortization positions that may not conform to all aspects of existing U.S. Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to 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
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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.
A common unitholder will likely be subject to state and local taxes and return filing requirements in states where the common unitholder does not live as a result of investing in our common units.
In addition to federal income taxes, a common unitholder will likely be subject to other taxes, including foreign, state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property, even if the common unitholder does not live in any of those jurisdictions. The common unitholder will likely be required to file foreign, state and local income tax returns and pay state and local income taxes in some or all of these jurisdictions. Further, the common unitholder may be subject to penalties for failure to comply with those requirements. We will initially own assets and do business in Alabama, Arkansas, Florida, Georgia, Louisiana, Mississippi, Missouri, North Carolina, Oklahoma, Tennessee, Texas and Virginia. Each of these states, other than Texas and Florida, currently imposes a personal income tax on individuals. A majority of these states impose an income tax on corporations and other entities. As we make acquisitions or expand our business, we may own assets or conduct business in additional states that impose an income tax. It is the common unitholder’s responsibility to file all United States federal, foreign, state and local tax returns. Our counsel has not rendered an opinion on the foreign, state or local tax consequences of an investment in the common units.
Item 1B. Unresolved Staff Comments.
None.
Our principal executive offices are located at 5400 Westheimer Court, Houston, Texas 77056, which is a facility leased by Spectra Energy. Our telephone number is 713-627-5400.
For a description of material properties, see Item 1. Business.
For information regarding legal proceedings, including regulatory and environmental matters, see Item 8. Financial Statements and Supplementary Data, Notes 5 and 15 of Notes to Consolidated Financial Statements.
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PART II
Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities.
Our common units are listed on the NYSE under the symbol “SEP.” The following table sets forth the high and low closing sales prices for our common units during the periods indicated, as reported by the NYSE, and the amount of the quarterly cash distributions we paid on each of our common units.
Common Unit Data by Quarter
| Distributions Paid in the Quarter | Unit Price Range(a) | |||||||||||
| Per Common Unit | Per Subordinated Unit | High | Low | |||||||||
| 2009 |
||||||||||||
| First Quarter |
$ | 0.36 | $ | 0.36 | $ | 22.78 | $ | 18.77 | ||||
| Second Quarter |
0.37 | 0.37 | 23.55 | 19.85 | ||||||||
| Third Quarter |
0.38 | 0.38 | 24.75 | 21.15 | ||||||||
| Fourth Quarter |
0.40 | 0.40 | 29.93 | 23.84 | ||||||||
| 2008 |
||||||||||||
| First Quarter |
0.32 | 0.32 | 25.97 | 21.17 | ||||||||
| Second Quarter |
0.33 | 0.33 | 26.15 | 22.84 | ||||||||
| Third Quarter |
0.34 | 0.34 | 25.00 | 17.06 | ||||||||
| Fourth Quarter |
0.35 | 0.35 | 30.00 | 12.10 | ||||||||
| (a) | Unit prices represent the intra-day high and low unit price. |
As of February 26, 2010, there were approximately 27 holders of record of our common units. A cash distribution to unitholders of $0.41 per limited partner unit was declared on January 21, 2010 and was paid on February 12, 2010, which is a $0.01 per limited partner unit increase over the cash distribution of $0.40 per limited partner unit paid on November 13, 2009.
34
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Index to Financial Statements
Unit Performance Graph
The following graph reflects the comparative changes in the value from June 27, 2007, the first trading day of our common units on the NYSE, through December 31, 2009 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.
| June 27, 2007 |
December 31, | |||||||||||
| 2007 | 2008 | 2009 | ||||||||||
| Spectra Energy Partners |
$ | 100.00 | $ | 84.61 | $ | 74.07 | $ | 118.32 | ||||
| S&P 500 |
100.00 | 98.44 | 62.02 | 78.43 | ||||||||
| Alerian MLP Index |
100.00 | 93.90 | 59.23 | 104.50 | ||||||||
Market Repurchases
We have not made any repurchases of common, subordinated or general partner units.
Distributions of Available Cash
General. Our partnership agreement requires that, within 45 days after the end of each quarter, beginning with the quarter ending September 30, 2007, we distribute all of our Available Cash, as defined, to unitholders of record on the applicable record date.
See the Glossary contained in Item 1. for the definition of Available Cash.
Minimum Quarterly Distribution. The Minimum Quarterly Distribution, as set forth in the partnership agreement, is $0.30 per limited partner unit per quarter, or $1.20 per limited partner unit per year. The quarterly distribution as of January 21, 2010 is $0.41 per limited partner unit, or $1.64 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. We will be prohibited from making any distributions to unitholders if it would cause an event of default, or an event of default is existing, under our credit agreement.
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Index to Financial Statements
General Partner Interest and Incentive Distribution Rights. Our general partner is entitled to 2% of all quarterly distributions since inception. This general partner interest is represented by 1,639,117 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. During 2009, the general partner contributed $4.4 million to maintain its 2% interest as a result of the additional limited partner units issued in the second quarter 2009 associated with the financing of the Ozark acquisition.
The general partner also currently holds incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 50%, of the cash we distribute from operating surplus in excess of $0.345 per unit per quarter. The maximum distribution of 50% includes distributions paid to the general partner on its 2% general partner interest and assumes that the general partner maintains its general partner interest at 2%. The maximum distribution of 50% does not include any distributions that the general partner may receive on 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.
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Index to Financial Statements
Item 6. Selected Financial Data.
The following selected financial data should be read in conjunction with Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Item 8. Financial Statements and Supplementary Data.
Basis of Presentation. For periods prior to the closing of our IPO on July 2, 2007, the selected financial data presented was prepared from the separate records maintained by Spectra Energy Capital, LLC for the entities that were originally contributed to us and for the operations included in the Saltville acquisition, and are based on Spectra Energy Capital, LLC’s historical ownership percentages of these operations. The combined financial results of these entities are treated as the historical results of our partnership for financial statement reporting purposes. The selected financial data covering periods prior to the closing of the IPO may not necessarily be indicative of the actual results of operations had those contributed entities been operated separately during those periods.
| 2009 | 2008 | 2007 | 2006 | 2005 | ||||||||||||
| (in millions, except per-unit amounts) | ||||||||||||||||
| Statements of Operations |
||||||||||||||||
| Operating revenues |
$ | 178.9 | $ | 124.9 | $ | 121.1 | $ | 101.5 | $ | 84.6 | ||||||
| Operating income |
82.8 | 51.9 | 60.6 | 47.9 | 28.1 | |||||||||||
| Equity in earnings of unconsolidated affiliates |
70.7 | 61.4 | 55.6 | 41.1 | 46.3 | |||||||||||
| Net income |
135.9 | 101.3 | 202.9 | (a) | 68.1 | 59.0 | ||||||||||
| Net Income per Limited Partner Unit(b) |
||||||||||||||||
| Net income per limited partner unit — basic and diluted |
$ | 1.71 | $ | 1.40 | $ | 0.68 | n/a | n/a | ||||||||
| Distributions paid per limited partner unit |
1.51 | 1.34 | 0.30 | n/a | n/a | |||||||||||
| December 31, | |||||||||||||||
| 2009 | 2008 | 2007 | 2006 | 2005 | |||||||||||
| (in millions) | |||||||||||||||
| Balance Sheet |
|||||||||||||||
| Total assets |
$ | 1,812.5 | $ | 1,601.5 | $ | 1,611.3 | $ | 1,399.5 | $ | 1,336.7 | |||||
| Long-term debt |
390.0 | 390.0 | 400.0 | 150.0 | 150.0 | ||||||||||
| (a) | Includes a benefit of $110.5 million from the reversal of deferred income tax liabilities in 2007. See Item 8. Financial Statements and Supplementary Data, Note 6 of Notes to Consolidated Financial Statements for further discussion. |
| (b) | Reflective of general and limited partners’ interests in Net Income since the closing of our IPO on July 2, 2007. |
| n/a | Indicates not applicable. |
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Index to Financial Statements
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
INTRODUCTION
Management’s Discussion and Analysis should be read in conjunction with Item 8. Financial Statements and Supplementary Data.
EXECUTIVE OVERVIEW
In 2009, our focus was to continue consistent delivery on the strategies we had communicated in conjunction with our IPO in 2007. This included a significant focus on growth opportunities to support our cash distribution objectives. During 2009, we completed the $294.5 million acquisition of NOARK and continued the execution and pursuit of organic growth projects. In addition, we increased the quarterly cash distributions each quarter in 2009 from $0.36 per limited partner unit for the fourth quarter of 2008, paid in February 2009, to $0.41 per limited partner unit for the fourth quarter of 2009, paid in February 2010, or a 14% increase.
We reported net income of $135.9 million in 2009 compared with $101.3 million in 2008. The increase resulted from higher earnings from the acquisition of the Ozark assets in the second quarter of 2009, a full year from the Greenway Nora and Glade Spring expansion projects at East Tennessee placed in service in late 2008, as well as increased equity earnings from Market Hub due to increased revenues from ongoing expansion projects.
Consistent with our strategy to opportunistically pursue acquisitions, on May 4, 2009, we acquired all of the ownership interests of NOARK from Atlas for approximately $294.5 million. NOARK’s assets consist of 100% ownership interests in Ozark Gas Transmission, a 565-mile FERC-regulated interstate natural gas transmission system and Ozark Gas Gathering, a 365-mile, fee-based, natural gas gathering system whose operations are regulated by the applicable state commissions.
In the second quarter of 2009, we issued 9.8 million common units to the public, representing limited partner interests, and 0.2 million general partner units to Spectra Energy, in connection with the refinancing of the purchase of NOARK, resulting in net proceeds of $212.2 million and a reduction of Spectra Energy’s ownership interest in us from 84% to 74%. See Note 2 of Notes to Consolidated Financial Statements for further discussion.
In 2010 and 2011, we expect to invest approximately $200 million in expansion capital, with $60 million in 2010. We will continue investing in our ongoing projects including the Gulfstream Phase V expansion project, a multi-year expansion program at Market Hub and the development of East Tennessee’s Northeastern Tennessee expansion project. See further discussion under “Liquidity and Capital Resources — Investing Cash Flows.”
Business Strategies
Our primary business objective is to grow unitholder value over time by executing the following strategies:
| • | Optimize existing assets and achieve additional operating efficiencies. We intend to enhance the profitability of our existing assets by undertaking additional initiatives to enhance utilization, improve operating efficiencies and develop rate and contract structures that create value for our customers. |
| • | Deliver on organic growth opportunities. We continually evaluate organic expansion opportunities in existing and new markets that could allow us to increase value and cash distributions to our investors. |
| • | Opportunistically pursue acquisitions. We may expand our existing natural gas transportation and storage businesses by pursuing acquisitions that add value and fit our fee-based business model. We would pursue acquisitions in areas where our assets currently operate that provide the opportunity for operational efficiencies or higher capacity utilization of existing assets, as well as acquisitions in complementary fee-based operations or new geographic areas of operation in order to grow the scale of our business. |
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Index to Financial Statements
Significant Economic Factors for Our Business
The high percentage of our business derived from capacity reservation fees mitigates the risk of revenue fluctuations due to near-term changes in natural gas supply and demand conditions. However, all of our businesses can be negatively affected in the long term by sustained downturns in the economy in general, and are impacted by shifts in supply and demand dynamics, the mix of services requested by our customer, and changes in regulatory requirements affecting our operations. Short-term contracts and interruptible service arrangements are not a significant component of our revenue; however, these services can be impacted positively or negatively to varying degrees by natural gas price volatility and other factors beyond our control. We mitigate our exposure to natural gas prices by maximizing the contracting of our available transportation capacity with long-term, fixed-rate arrangements.
We believe the key factors that impact our business are the supply of and demand for natural gas in the markets in which we operate, our customers and their requirements, competition and government regulation of natural gas pipelines and storage systems. These key factors play an important role in how we evaluate our operations and implement our long-term strategies.
Supply and Demand Dynamics
Changes in natural gas supply such as new discoveries of natural gas reserves, declining production in older fields and the introduction of new sources of natural gas supply, such as non-conventional and natural gas shale plays, affect the demand for our services from both producers and consumers. As these supply dynamics shift, we anticipate that we will actively pursue projects that link these new sources of supply to producers and consumers willing to contract for transportation or storage on a long-term firm basis. Changes in demographics, the amount of natural gas fired power generation and shifts in residential usage affect the overall demand for natural gas. In turn, our customers, which include LDCs, utilities, marketers and producers and power generators, increase or decrease their demand for our services as a result of these changes.
Growing Markets
Our key markets are projected to continue to exhibit higher than average annual growth in natural gas demand of approximately 3.0% through 2019 compared with the U.S. lower 48 average growth rate of approximately 2% for the same period. This demand growth is primarily driven by the natural gas-fired electric generation sector.
Growth of Natural Gas Transportation Capacity
As natural gas supplies and demand continue to shift, our customers have additional options in meeting their needs for natural gas pipeline capacity. A number of new natural gas transmission projects have been announced in recent years, and are in various stages of development, especially in the Arkansas, Oklahoma, and Fayetteville supply regions. The increased supply of transmission capacity from these areas could result in some “turnback” of Ozark firm capacity over the next several years. We are actively engaged with customers to address their capacity needs on Ozark over the next several years.
Growth of Natural Gas Storage Facilities
Natural gas storage plays an important role in the natural gas transportation industry, due to the need to balance seasonal pricing, provide gas for power generation and to balance the difference in timing of natural gas supplies and natural gas demand. A substantial number of natural gas storage projects have been announced in recent years and are in various stages of development, especially in Mississippi, Texas and Louisiana. In 2009, 60.7 Bcf of natural gas storage came into service in this region, while another 32.8 Bcf was delayed or cancelled. The southeastern region of the United States has a large number of high-deliverability, salt-cavern storage facilities and the demand for this type of storage is expected to continue to grow. An increased supply of storage capacity competing with Market Hub’s storage facilities could negatively impact our operations.
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Index to Financial Statements
Regulation
Government regulation of natural gas transportation, storage and gathering has a significant impact on our business. The natural gas transportation rates are regulated under the FERC rate-making policies. Our storage facility in Texas is subject to oversight by the TRC. Our gathering operations are subject to oversight by the Arkansas Public Service Commission and Oklahoma Corporation Commission. The FERC regulatory policies govern the rates that each pipeline is permitted to charge customers for interstate transportation and storage of natural gas. Under certain circumstances, we are permitted to enter into contracts with customers under “negotiated rates” and “market-based” rates that differ from the rates imposed by the FERC.
RESULTS OF OPERATIONS
| 2009 | 2008 | 2007 | |||||||||
| (in millions) | |||||||||||
| Operating revenues |
$ | 178.9 | $ | 124.9 | $ | 121.1 | |||||
| Operating, maintenance and other expenses |
67.6 | 46.7 | 34.1 | ||||||||
| Depreciation and amortization |
28.5 | 26.3 | 26.4 | ||||||||
| Operating income |
82.8 | 51.9 | 60.6 | ||||||||
| Equity in earnings of unconsolidated affiliates |
70.7 | 61.4 | 55.6 | ||||||||
| Other income and expenses, net |
0.1 | 0.9 | 0.4 | ||||||||
| Interest income |
0.2 | 3.5 | 5.5 | ||||||||
| Interest expense |
16.7 | 17.8 | 17.1 | ||||||||
| Earnings before income taxes |
137.1 | 99.9 | 105.0 | ||||||||
| Income tax expense (benefit) |
1.2 | (1.4 | ) | (97.9 | ) | ||||||
| Net income |
$ | 135.9 | $ | 101.3 | $ | 202.9 | |||||
| Net cash provided by operating activities |
$ | 159.7 | $ | 139.2 | $ | 84.9 | |||||
| Adjusted EBITDA(a) |
111.3 | 78.2 | 87.0 | ||||||||
| Cash Available for Distribution(a) |
158.1 | 120.6 | 119.2 | ||||||||
| (a) | See “Reconciliation of Non-GAAP Measures” for a reconciliation of this measure to its most directly comparable financial measures calculated and presented in accordance with generally accepted accounting principles (GAAP). |
2009 Compared to 2008
Operating Revenues. The $54.0 million increase in 2009 was driven primarily by $43.5 million from the acquisition of the Ozark assets effective May 4, 2009 and $10.2 million from East Tennessee’s Greenway Nora and Glade Spring expansion projects that were placed in service in the fourth quarter of 2008.
Operating, Maintenance and Other. The $20.9 million increase in 2009 was driven primarily by:
| • | a $16.2 million increase from the acquisition of the Ozark assets, including approximately $2.9 million of transaction costs, and |
| • | a $2.5 million increase due to a favorable ad valorem tax adjustment recorded in 2008, partially offset by |
| • | a $0.5 million increase in net fuel recoveries. |
Equity in Earnings of Unconsolidated Affiliates. The $9.3 million increase in 2009 consisted of a $2.9 million increase in earnings from our 24.5% interest in Gulfstream and a $6.4 million increase in earnings from our 50% interest in Market Hub.
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Index to Financial Statements
The following discussion explains the factors affecting the equity earnings of Gulfstream and Market Hub, each representing 100% of the earnings drivers of those entities.
| 2009 | 2008 | Increase (Decrease) |
2007 | Increase (Decrease) |
||||||||||||||
| (in millions) | ||||||||||||||||||
| Gulfstream |
||||||||||||||||||
| Operating revenues |
$ | 251.5 | $ | 206.7 | $ | 44.8 | $ | 185.3 | $ | 21.4 | ||||||||
| Operating, maintenance and other expenses |
33.1 | 31.1 | 2.0 | 15.9 | 15.2 | |||||||||||||
| Depreciation and amortization |
34.5 | 30.3 | 4.2 | 30.0 | 0.3 | |||||||||||||
| Loss on sale of assets |
— | (0.6 | ) | 0.6 | — | (0.6 | ) | |||||||||||
| Other income and expenses, net |
1.4 | 11.1 | (9.7 | ) | 3.9 | 7.2 | ||||||||||||
| Interest expense |
61.3 | 45.0 | 16.3 | 47.9 | (2.9 | ) | ||||||||||||
| Net income |
$ | 124.0 | $ | 110.8 | $ | 13.2 | $ | 95.4 | $ | 15.4 | ||||||||
| Spectra Energy Partners’ share |
$ | 30.4 | $ | 27.5 | $ | 2.9 | $ | 23.5 | $ | 4.0 | ||||||||
Gulfstream’s net income increased $13.2 million to $124.0 million in 2009 compared to $110.8 million in 2008. The increase was primarily due to the final phase-in, which started in late 2008, of the Phase III and Phase IV expansion projects. With 2009 as the first full year of operations, these projects were the main driver for increased operating revenues, operating expenses (including ad valorem tax expense) and depreciation expense. In addition, other income and expenses were lower in 2009 due to a decrease in the equity portion of AFUDC as there were higher capital expenditures on these expansion projects in 2008. Interest expense increased related to a $300.0 million debt offering in May 2009.
| 2009 | 2008 | Increase (Decrease) |
2007 | Increase (Decrease) |
|||||||||||||
| (in millions) | |||||||||||||||||
| Market Hub |
|||||||||||||||||
| Operating revenues |
$ | 115.5 | $ | 98.0 | $ | 17.5 | $ | 91.3 | $ | 6.7 | |||||||
| Operating, maintenance and other expenses |
22.6 | 20.0 | 2.6 | 23.6 | (3.6 | ) | |||||||||||
| Depreciation and amortization |
12.1 | 10.6 | 1.5 | 9.1 | 1.5 | ||||||||||||
| Gains on sale of other assets and other income and expenses |
— | 0.2 | (0.2 | ) | 7.0 | (6.8 | ) | ||||||||||
| Interest income |
0.3 | 3.1 | (2.8 | ) | 2.3 | 0.8 | |||||||||||
| Interest expense |
0.1 | 1.0 | (0.9 | ) | 3.6 | (2.6 | ) | ||||||||||
| Income tax expense |
0.2 | 0.4 | (0.2 | ) | 0.1 | 0.3 | |||||||||||
| Net income |
$ | 80.8 | $ | 69.3 | $ | 11.5 | $ | 64.2 | $ | 5.1 | |||||||
| Spectra Energy Partners’ share |
$ | 40.3 | $ | 33.9 | $ | 6.4 | $ | 32.1 | $ | 1.8 | |||||||
Market Hub’s net income increased $11.5 million to $80.8 million in 2009 compared to $69.3 million in 2008. The increase was primarily due to the expansion projects at both Moss Bluff and Egan as well as lower interest rates.
The initial phase-in of the Egan Cavern 3 storage facilities expansion beginning in 2009 and the phase-in of the Egan Cavern 4 in August 2008 increased operating revenues when compared to 2008. Additional operating expenses and depreciation expense were attributable to these projects.
Lower interest rates caused both a decrease to interest income and interest expense. Interest income was also impacted by a lower balance of notes receivable from affiliates while interest expense was impacted by a reduction of collateral held from counterparties.
Interest Income. The $3.3 million decrease in 2009 was due to the sale of marketable securities held by us that were originally purchased with a portion of the IPO proceeds in July 2007.
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Index to Financial Statements
Interest Expense. The $1.1 million decrease was due to lower interest rates on credit facility borrowings, partially offset by interest on borrowings associated with the acquisition of NOARK.
Income Tax Expense (Benefit). Income tax expense was $1.2 million in 2009 compared to an income tax benefit of $1.4 million in 2008. The benefit in 2008 was due to a change in the tax status of certain businesses related to the Saltville acquisition.
2008 Compared to 2007
Operating Revenues. The $3.8 million increase in 2008 was driven by a $6.4 million increase from new and replacement firm transportation contracts on East Tennessee’s Jewell Ridge lateral and Patriot systems, partially offset by the absence of $2.5 million of salt sales during 2008 due to the sale of the salt plant in the second quarter of 2007.
Operating, Maintenance and Other. The $12.6 million increase in 2008 was driven by:
| • | a $6.2 million increase from lower net pipeline fuel recoveries recognized by East Tennessee in the 2008 period compared to the 2007 period, |
| • | a $4.0 million increase in public company costs and governance expenses from a full year’s activity in 2008 compared to only six months of activity in 2007 subsequent to the formation of Spectra Energy Partners, |
| • | a $2.2 million increase from higher project costs at East Tennessee related to activities around the proposed Greenway expansions, and |
| • | a $1.5 million increase in general and administrative expenses as a result of increased outside services and labor costs, partially offset by |
| • | a $1.3 million decrease in ad valorem tax expense primarily related to lower tax rates and lower franchise taxes. |
Equity in Earnings of Unconsolidated Affiliates. The $5.8 million increase in 2008 consisted of a $4.0 million increase in earnings from Gulfstream and a $1.8 million increase in earnings from Market Hub.
The following discussion explains the factors affecting the equity earnings of Gulfstream (owned 24.5%) and Market Hub (owned 50%), each representing 100% of the earnings drivers of those entities.
Gulfstream’s net income increased $15.4 million to $110.8 million in 2008 compared to $95.4 million in 2007. The increase was primarily driven by:
| • | a $21.4 million increase in revenues driven primarily by the Phase III and Phase IV expansion contracts, |
| • | a $7.2 million increase in other income and expenses driven primarily by AFUDC as a result of capital expenditures for Gulfstream’s Phase III and Phase IV expansion projects, |
| • | a $2.9 million decrease in interest expense resulting from higher interest costs capitalized as a result of capital expenditures for Gulfstream’s Phase III and Phase IV expansion projects, partially offset by |
| • | a $15.2 million increase in operating, maintenance and other expenses primarily resulting from a $7.0 million increase in ad valorem tax expense due to the impact of a favorable valuation in 2007, a $3.6 million increase in project costs due to the 2007 capitalization of previously expensed costs related to the Phase IV expansion, and a $4.6 million increase due to higher pipeline operations costs and a favorable adjustment to administrative and general expenses in 2007. |
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Index to Financial Statements
Market Hub’s net income increased $5.1 million to $69.3 million in 2008 compared to $64.2 million in 2007. The increase was primarily due to:
| • | a $6.7 million increase in revenues driven by an increase of $11.6 million in firm storage revenues as a result of the completion of the Egan Cavern 4 expansion, partially offset by a decrease in interruptible services of $4.9 million driven by a change in market demand, |
| • | a $0.8 million increase in interest income due to notes receivable with affiliates issued in the third quarter of 2007, |
| • | a $2.6 million decrease in interest expense primarily due to lower interest rates associated with collateral held from counterparties and affiliates, and |
| • | a $3.6 million decrease in operating, maintenance and other expenses resulting primarily from a $5.1 million write-down of inventory at Egan in 2007, partially offset by a $0.8 million increase in ad valorem tax expense primarily due to a favorable valuation in the first quarter of 2007 and a $0.6 increase in operating expenses due to the Egan expansion in 2007, partially offset by |
| • | a $7.0 million gain on sales of other assets in 2007 relating to the receipt of an insurance settlement associated with an incident at Moss Bluff in 2005, and |
| • | a $1.5 million increase in depreciation expense primarily due to the Egan horsepower expansion placed in service in July 2007. |
Interest Income. The $2.0 million decrease in 2008 was caused by lower interest earned due to the sale of marketable securities purchased with a portion of the IPO proceeds in July 2007.
Interest Expense. The $0.7 million increase in 2008 was due to a full year’s expense in 2008 as compared to six months in 2007 from term and revolver borrowings entered into on July 2, 2007, mostly offset by lower interest rates in 2008.
Income Tax Expense (Benefit). Our income tax benefit in 2008 was $1.4 million compared to an income tax benefit of $97.9 million in the same period in 2007. We recorded a one-time benefit of $110.5 million in the third quarter of 2007 from the reversal of deferred income tax liabilities. Effective July 2, 2007, as a result of our MLP structure, we are no longer subject to federal income taxes. In addition, a tax benefit of $2.5 million was recognized in the second quarter of 2008 due to a change in tax status of certain businesses related to the Saltville acquisition.
Matters Affecting Future Results
We plan to continue earnings growth through a consistent focus on executing our strategy of optimization, organic growth and opportunistic acquisitions that fit our business model.
Future earnings growth will be dependent on the success of our expansion plans in both the market and supply areas of the pipeline network, the ability to continue renewing service contracts and continued regulatory stability.
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Index to Financial Statements
Adjusted EBITDA and Cash Available for Distribution
Adjusted EBITDA
We define our Adjusted Earnings Before Interest, Taxes, Depreciation and Amortization (EBITDA) as Net Income plus Interest Expense, Income Taxes and Depreciation and Amortization less our Equity in Earnings of Gulfstream and Market Hub, Interest Income, and Other Income and Expenses, Net, which primarily consists of non-cash AFUDC. Our Adjusted EBITDA is not a presentation made in accordance with GAAP. Because Adjusted EBITDA excludes some, but not all, items that affect net income and is defined differently by companies in our industry, our definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies.
Adjusted EBITDA is used as a supplemental financial measure by our management and by external users of our financial statements to assess:
| • | the financial performance of assets without regard to financing methods, capital structure or historical cost basis; |
| • | the ability to generate cash sufficient to pay interest on indebtedness and to make distributions to partners; and |
| • | operating performance and return on invested capital as compared to those of other publicly traded limited partnerships that own energy infrastructure assets, without regard to financing methods and capital structure. |
Significant drivers of variances in Adjusted EBITDA between the periods presented are substantially the same as those previously discussed under Results of Operations.
Cash Available for Distribution
We define Cash Available for Distribution as our Adjusted EBITDA plus Cash Available for Distribution from Gulfstream and Market Hub and net preliminary project costs, less net cash paid for interest expense, net cash paid for income tax expense, and maintenance capital expenditures. Cash Available for Distribution does not reflect changes in working capital balances. Cash Available for Distribution for Gulfstream and Market Hub is defined on a basis consistent with us. Cash Available for Distribution should not be viewed as indicative of the actual amount of cash that we plan to distribute for a given period.
Cash Available for Distribution should not be considered an alternative to Net Income, Operating Income, cash from operations or any other measure of financial performance or liquidity presented in accordance with GAAP. Cash Available for Distribution excludes some, but not all, items that affect Net Income and Operating Income and these measures may vary among other companies. Therefore, Cash Available for Distribution as presented may not be comparable to similarly titled measures of other companies.
Significant drivers of variances in Cash Available for Distribution between the periods presented are substantially the same as those previously discussed under Results of Operations. Other drivers include the timing of certain cash outflows, such as capital expenditures for maintenance and the scheduled payments of interest.
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Spectra Energy Partners
Reconciliation of Non-GAAP “Adjusted EBITDA” and “Cash Available for Distribution”
| 2009 | 2008 | 2007 | |||||||||
| (in millions) | |||||||||||
| Net income |
$ | 135.9 | $ | 101.3 | $ | 202.9 | |||||
| Add: |
|||||||||||
| Interest expense |
16.7 | 17.8 | 17.1 | ||||||||
| Income tax expense (benefit) |
1.2 | (1.4 | ) | (97.9 | ) | ||||||
| Depreciation and amortization |
28.5 | 26.3 | 26.4 | ||||||||
| Less: |
|||||||||||
| Equity in earnings of Gulfstream |
30.4 | 27.5 | 23.5 | ||||||||
| Equity in earnings of Market Hub |
40.3 | 33.9 | 32.1 | ||||||||
| Interest income |
0.2 | 3.5 | 5.5 | ||||||||
| Other income and expenses, net |
0.1 | 0.9 | 0.4 | ||||||||
| Adjusted EBITDA |
111.3 | 78.2 | 87.0 | ||||||||
| Add: |
|||||||||||
| Cash Available for Distribution from Gulfstream |
38.2 | 30.7 | 28.3 | ||||||||
| Cash Available for Distribution from Market Hub |
40.8 | 36.0 | 31.9 | ||||||||
| Preliminary project costs, net |
0.4 | 2.2 | — | ||||||||
| Less: |
|||||||||||
| Cash paid for interest expense, net |
16.2 | 14.3 | 10.3 | ||||||||
| Cash paid for income tax expense, net |
0.1 | 0.9 | 6.5 | ||||||||
| Maintenance capital expenditures |
16.3 | 11.3 | 11.2 | ||||||||
| Cash Available for Distribution |
$ | 158.1 | $ | 120.6 | $ | 119.2 | |||||
Spectra Energy Partners
Reconciliation of Non-GAAP “Adjusted EBITDA” and “Cash Available for Distribution”
| 2009 | 2008 | 2007 | ||||||||||
| (in millions) | ||||||||||||
| Net cash provided by operating activities |
$ | 159.7 | $ | 139.2 | $ | 84.9 | ||||||
| Interest income |
(0.2 | ) | (3.5 | ) | (5.5 | ) | ||||||
| Interest expense |
16.7 | 17.8 | 17.1 | |||||||||
| Income tax expense — current |
— | 0.6 | 5.7 | |||||||||
| Distributions received from Gulfstream |
(38.6 | ) | (28.5 | ) | (16.8 | ) | ||||||
| Distributions received from Market Hub |
(35.7 | ) | (43.2 | ) | (5.9 | ) | ||||||
| Changes in working capital and other |
9.4 | (4.2 | ) | 7.5 | ||||||||
| Adjusted EBITDA |
111.3 | 78.2 | 87.0 | |||||||||
| Add: |
||||||||||||
| Cash Available for Distribution from Gulfstream |
38.2 | 30.7 | 28.3 | |||||||||
| Cash Available for Distribution from Market Hub |
40.8 | 36.0 | 31.9 | |||||||||
| Preliminary project costs, net |
0.4 | 2.2 | — | |||||||||
| Less: |
||||||||||||
| Cash paid for interest expense, net |
16.2 | 14.3 | 10.3 | |||||||||
| Cash paid for income tax expense, net |
0.1 | 0.9 | 6.5 | |||||||||
| Maintenance capital expenditures |
16.3 | 11.3 | 11.2 | |||||||||
| Cash Available for Distribution |
$ | 158.1 | $ | 120.6 | $ | 119.2 | ||||||
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Gulfstream
Reconciliation of Non-GAAP “Adjusted EBITDA” and “Cash Available for Distribution”
| 2009 | 2008 | 2007 | |||||||||
| (in millions) | |||||||||||
| Net income |
$ | 124.0 | $ | 110.8 | $ | 95.4 | |||||
| Add: |
|||||||||||
| Interest expense |
61.3 | 45.0 | 47.9 | ||||||||
| Depreciation and amortization |
34.5 | 30.3 | 30.0 | ||||||||
| Less: |
|||||||||||
| Other income and expenses, net |
1.4 | 11.1 | 3.9 | ||||||||
| Adjusted EBITDA — 100% |
218.4 | 175.0 | 169.4 | ||||||||
| Add: |
|||||||||||
| Preliminary project costs, net |
(1.3 | ) | 1.1 | (2.5 | ) | ||||||
| Less: |
|||||||||||
| Cash paid for interest expense, net |
60.1 | 49.5 | 49.9 | ||||||||
| Maintenance capital expenditures |
0.9 | 1.3 | 1.4 | ||||||||
| Cash Available for Distribution — 100% |
$ | 156.1 | $ | 125.3 | $ | 115.6 | |||||
| Adjusted EBITDA — 24.5% |
$ | 53.5 | $ | 42.9 | $ | 41.5 | |||||
| Cash Available for Distribution — 24.5% |
$ | 38.2 | $ | 30.7 | $ | 28.3 | |||||
Market Hub
Reconciliation of Non-GAAP “Adjusted EBITDA” and “Cash Available for Distribution”
| 2009 | 2008 | 2007 | |||||||
| (in millions) | |||||||||
| Net income |
$ | 80.8 | $ | 69.3 | $ | 64.2 | |||
| Add: |
|||||||||
| Interest expense |
0.1 | 1.0 | 3.6 | ||||||
| Income tax expense |
0.2 | 0.4 | 0.1 | ||||||
| Depreciation and amortization |
12.1 | 10.6 | 9.1 | ||||||
| Less: |
|||||||||
| Interest income |
0.3 | 3.1 | 2.2 | ||||||
| Other income and expenses, net |
— | 0.2 | 7.1 | ||||||
| Adjusted EBITDA — 100% |
92.9 | 78.0 | 67.7 | ||||||
| Less: |
|||||||||
| Cash paid for interest expense, net |
7.1 | — | — | ||||||
| Cash paid for income tax expense, net |
0.5 | — | — | ||||||
| Maintenance capital expenditures |
3.8 | 5.9 | 4.0 | ||||||
| Cash Available for Distribution — 100% |
$ | 81.5 | $ | 72.1 | $ | 63.7 | |||
| Adjusted EBITDA — 50% |
$ | 46.5 | $ | 39.0 | $ | 33.9 | |||
| Cash Available for Distribution — 50% |
$ | 40.8 | $ | 36.0 | $ | 31.9 | |||
Effective January 1, 2009, we revised the calculation of Cash Available for Distribution, within the definition contained in the partnership agreement. As discussed in Item 8. Financial Statements and Supplementary Data, Note 1 of Notes to Consolidated Financial Statements, for our regulated entities that follow current regulatory accounting standards, we expense preliminary project costs until such time that management determines that recovery of these costs is probable. At that time, we capitalize those costs, which reduces
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operating expenses in that period. The revised calculation for Cash Available for Distribution adds back preliminary project costs to EBITDA as those costs are initially incurred and deducts the expense reductions in the period the costs are capitalized. These project costs do not represent operating cash flow activity. In addition, we also revised the calculation of Cash Available for Distribution to exclude net cash paid for income tax expense.
The effects of these changes on Spectra Energy Partners and Gulfstream for 2008 and 2007 were as follows:
Spectra Energy Partners
| 2008 | 2007 | ||||||
| (in millions) | |||||||
| Cash Available for Distribution, as previously reported |
$ | 119.0 | $ | 126.3 | |||
| Add: |
|||||||
| Change in Cash Available for Distribution from Gulfstream (see below)(a) |
0.3 | (0.6 | ) | ||||
| Preliminary project costs, net |
2.2 | — | |||||
| Less: |
|||||||
| Cash paid for income tax expense, net |
0.9 | 6.5 | |||||
| Cash Available for Distribution, as revised |
$ | 120.6 | $ | 119.2 | |||
| (a) | Amount represents 24.5% of Gulfstream’s preliminary project costs, net. |
Gulfstream
| 2008 | 2007 | ||||||
| (in millions) | |||||||
| Cash Available for Distribution, as previously reported |
$ | 124.2 | $ | 118.1 | |||
| Add: |
|||||||
| Preliminary project costs, net |
1.1 | (2.5 | ) | ||||
| Cash Available for Distribution, as revised — 100% |
$ | 125.3 | $ | 115.6 | |||
| Cash Available for Distribution, as revised — 24.5% |
$ | 30.7 | $ | 28.3 | |||
These changes did not have an effect on the Cash Available for Distribution calculation for Market Hub.
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. The estimates and judgments may change as time passes and more information becomes available. If estimates and judgments are different than the actual amounts recorded, adjustments are made in subsequent periods to take into consideration the new information. We discuss our critical accounting policies and estimates and other significant accounting policies with our Audit Committee.
Regulatory Accounting
We account for our regulated operations at East Tennessee, Ozark Gas Transmission and Saltville under accounting for regulated entities. As a result, we record assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for non-regulated entities. Regulatory assets generally represent incurred costs that have been deferred because such costs are probable of future recovery in
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customer rates. Regulatory liabilities generally represent obligations to make refunds to customers for previous collections for costs that either are not likely to or have yet to be incurred. We continually assess whether the regulatory assets are probable of future recovery by considering factors such as applicable regulatory changes and recent rate orders to other regulated entities. Based on this continual assessment, we believe our existing regulatory assets are probable of recovery. This assessment reflects the current political and regulatory climate at the state and federal levels, and is subject to change in the future. If future recovery of costs ceases to be probable, asset write-offs would be required to be recognized. Additionally, regulatory agencies can provide flexibility in the manner and timing of the depreciation of property, plant and equipment and amortization of regulatory assets. Total regulatory assets were $15.4 million as of December 31, 2009 and $10.0 million as of December 31, 2008. We had no regulatory liabilities included in our financial statements.
Impairment of 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. Prior to 2009, we performed the annual impairment testing of goodwill using August 31 as the measurement date. Our financial and strategic planning process, including the preparation of long-term cash flow projections, commences in October and typically concludes in January of the following year. These long-term cash flow projections are a key component in performing our annual impairment test of goodwill. This planning cycle historically created significant constraints in the availability of both information and human resources needed to provide the appropriate projections to be used in the goodwill impairment test using the August 31 test date. Accordingly, effective with our 2009 annual impairment test, we changed our goodwill impairment test date from August 31 to April 1. We believe that using the April 1 date will alleviate the information and resource constraints that historically existed during the third quarter and will better coincide with the completion of our long-term financial projections. We believe that this accounting change is to an alternative accounting principle that is preferable under the circumstances and did not result in the delay, acceleration or avoidance of an impairment charge. We have determined that this change in accounting principle does not result in adjustments to our 2008 or 2007 Consolidated Financial Statements when applied retrospectively as our base assumptions used in the August 31 measurement date would not have changed significantly had we used April 1 as the measurement date.
We had goodwill balances of $267.9 million at December 31, 2009 and $118.3 million at December 31, 2008. The increase in goodwill in 2009 was the result of $149.6 million of goodwill associated with the acquisition of NOARK in May 2009. There was no impairment of goodwill recorded during 2009, 2008 or 2007.
We perform an annual goodwill impairment test and update the test if events or circumstances occur that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Key assumptions used in the determination of fair value include the use of an appropriate discount rate and estimated future cash flows. In estimating cash flows, we incorporate expected long-term growth rates in key markets served by our operations, regulatory stability and the ability to renew contracts, as well as other factors that affect our revenue, expense and capital expenditure projections.
The long-term growth rates used for our reporting unit reflect continued expansion of our assets, driven by new natural gas supplies such as shale gas and, notwithstanding the current economic downturn, increasing demand for capacity on our pipeline systems. For our 2009 goodwill impairment analysis, we assumed a weighted-average long-term growth rate of 3%. If we had assumed a zero growth rate for our reporting unit, there would have been no impairment of goodwill in 2009.
We continue to monitor the effects of the economic downturn that global economies are currently facing on the long-term cost of capital utilized to calculate our reporting unit fair value. For our 2009 goodwill impairment analysis, we estimated a weighted-average cost of capital that market participants would use in evaluating our business of 7.7%. If we had assumed a 100 basis point increase in cost of capital for our reporting unit, there would have been no impairment of goodwill in 2009.
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Based on the results of our annual impairment testing, the fair value of our reporting unit at April 1, 2009 significantly exceeded its carrying value. No triggering events or changes in circumstances occurred during the period April 1, 2009 (our testing date) through December 31, 2009 that would warrant re-testing for goodwill impairment.
Equity Method Investments
We account for investments in 20% to 50% owned affiliates, and investments in less than 20% owned affiliates where we have the ability to exercise significant influence, under the equity method. Accordingly, our 24.5% interest in Gulfstream and 50.0% interest in Market Hub are accounted for under the equity method.
Revenue Recognition
Revenues from the transportation, storage and gathering of natural gas and storage of LNG are recognized when the service is provided. Revenues related to these services provided but not yet billed are estimated each month. These estimates are generally based on contract data, regulatory information and preliminary throughput and allocation measurements. Final bills for the current month are billed and collected in the following month. Differences between actual and estimated unbilled revenues are immaterial.
LIQUIDITY AND CAPITAL RESOURCES
Known Trends and Uncertainties
We will rely primarily upon cash flows from operations, including cash distributions received from Gulfstream and Market Hub, an available credit facility and potential additional financing transactions to fund our liquidity and capital requirements for 2010. As of December 31, 2009, we had negative net working capital of $8.4 million compared to negative $23.6 million as of December 31, 2008, of which the December 31, 2009 balance included $27.5 million and the December 31, 2008 balance included $50.0 million for the note payable on demand to Market Hub.
Cash flows from operations are fairly stable given that most of our revenues and those of our equity affiliates are derived from operations under firm contracts. However, total operating cash flows are subject to a number of factors, including, but not limited to, contract renewal rates and cash distributions from our equity affiliates, Gulfstream and Market Hub. The amount of cash distributed to us, and the amount of cash we may be required to fund is determined by our equity affiliates based on operating cash flows and other factors as determined by the management of our equity affiliates. While we participate on the management committees of these equity affiliates, determination of the amount of distributions and contributions, if any, are not within our control. We received total distributions from equity affiliates of $144.8 million in 2009, $71.7 million in 2008 and $22.7 million in 2007. The increased distributions in 2009 were primarily from net proceeds received by Gulfstream as a result of their $300.0 million debt issuance in May 2009. As discussed in Item 8. Financial Statements and Supplementary Data, Note 1 of Notes to the Consolidated Financial Statements, a portion of these distributions are classified within Operating Cash Flows and the remainder is classified as Investing Cash Flows. See Item 1A. Risk Factors for discussion of other factors that could affect our cash flows.
As we execute on our strategic objectives around organic expansion opportunities, capital expansion expenditures could be significant, and are currently estimated at $60 million in 2010 and $140 million in 2011. The timing and extent of these expenditures are likely to vary significantly from year to year, depending primarily on general economic conditions and market requirements. Given that we expect to continue to pursue expansion opportunities over the next several years, capital resources will continue to include long-term borrowings on our current credit facility and possibly securing additional sources of capital including debt and/or equity. However, as a result of our ongoing strong earnings performance expected in existing operations, we expect to maintain a capital structure and liquidity profile that supports our strategic objectives and therefore will continue to monitor market requirements and our liquidity and make adjustments to these plans as needed.
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Operating Cash Flows
Net cash provided by operating activities increased $20.5 million to $159.7 million in 2009 compared to 2008. Higher earnings from the Ozark acquisition and our equity affiliates, primarily Market Hub, were partially offset by the timing of payments for services provided by our general partner when compared to 2008.
Net cash provided by operating activities increased $54.3 million to $139.2 million in 2008 compared to 2007. This change was driven primarily by a $49.0 million increase in distributions received from equity affiliates, primarily Market Hub. Effective with our 2007 IPO, Market Hub is required to make distributions of its Available Cash to its partners, including us.
Investing Cash Flows
Net cash flows used in investing activities totaled $249.4 million in 2009 compared to $17.3 million in 2008. The $232.1 million change was driven primarily by:
| • | the $294.5 million acquisition of NOARK in 2009, and |
| • | $31.6 million of proceeds in 2009 from the liquidation of available-for-sale securities that were held as collateral for the term loan as compared to $123.0 million of net proceeds from the liquidation of such securities in 2008, partially offset by |
| • | a $70.5 million increase in distributions received from Gulfstream as a result of their $300.0 million debt issuance in 2009, |
| • | a $51.9 million decrease in investment expenditures in 2009 as a result of completions on Gulfstream’s Phase III and Phase IV and Market Hub’s Egan Cavern 4 expansion projects in 2008, as well as reduced spending on Market Hub’s multi-year expansion projects in 2009, |
| • | a $26.7 million decrease in capital expenditures primarily due to lower growth projects in 2009 at East Tennessee, and |
| • | the $4.7 million cash portion of the Saltville acquisition in 2008. |
Net cash flows used in investing activities totaled $17.3 million in 2008 compared to $205.0 million in 2007. This $187.7 million change was driven primarily by:
| • | $154.6 million of net purchases in 2007 of available-for-sale securities that were held as collateral for a term loan as compared to $123.0 million of net proceeds in 2008 from the liquidation of such securities. As permitted by the terms of that credit facility, proceeds were used for capital and investment expenditures. This $277.6 million decrease in cash used was partially offset by |
| • | a $60.3 million increase in investment expenditures representing capital contributions to Gulfstream and Market Hub in 2008 used to fund their expansion projects, |
| • | a $4.7 million cash portion of the Saltville acquisition in 2008, and |
| • | proceeds from sales of assets in 2007 of $8.3 million. |
Capital and Investment Expenditures
| 2009 | 2008 | 2007 | |||||||
| (in millions) | |||||||||
| Capital Expenditures |
|||||||||
| Gas Transportation and Storage(a) |
$ | 20.3 | $ | 47.0 | $ | 30.4 | |||
| Investment Expenditures |
|||||||||
| Gulfstream |
9.8 | 44.0 | 18.7 | ||||||
| Market Hub |
26.9 | 44.6 | 9.6 | ||||||
| Total capital and investment expenditures |
$ | 57.0 | $ | 135.6 | $ | 58.7 | |||
| (a) | Excludes the acquisitions of NOARK in 2009 and Saltville in 2008. |
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Capital and investment expenditures for 2009 totaled $57.0 million and included $40.7 million for expansion projects and $16.3 million for maintenance and other projects. Expansion capital and investment expenditures in 2009 included the completion of Gulfstream’s Phase III and Phase IV expansion projects and the continued expansion on Market Hub’s Egan Cavern 3 and Moss Bluff Cavern 4 projects.
We project 2010 capital and investment expenditures of approximately $75 million, of which $60 million is expected to be used for expansion projects and $15 million for maintenance and other projects. Given our objective of growth through acquisitions and expansions of existing assets, we anticipate that we will continue to invest significant amounts of capital to grow and acquire assets. Expansion capital expenditures may vary significantly based on investment opportunities.
We continue to evaluate customers’ needs for incremental expansion opportunities at East Tennessee, Gulfstream and Market Hub. In addition, we are assessing the needs of our Ozark customers for additional transportation services. We expect that significant natural gas infrastructure, including both natural gas transportation and storage with links to growing gas supplies and markets, will be needed over time to serve growth in gas-fired power generation, oil-to-gas conversions, industrial development and attachments to new gas supply.
Our primary business objective is to grow our cash distributions over time. We intend to accomplish this objective through expansions of our existing asset base. In addition, we will continue to pursue strategic acquisitions of transportation and storage assets. Significant 2010 expansion projects, including those of Gulfstream and Market Hub, are expected to include:
| • | Moss Bluff — Cavern 4 construction continues, ultimately expected to increase storage working capacity by 6.5 Bcf to 22.0 Bcf, as well as upgrade top-side facilities and expand pipeline interconnects. The cavern is expected to be placed into service in 2011. |
| • | Egan — Cavern 3 was placed into initial gas service in the second half of 2009. The expected final working capacity of Egan Cavern 3 is 8.2 Bcf. The project, which also includes infrastructure improvements, is projected to be completed in 2012. |
| • | Gulfstream — The Phase V compression project is expected to be completed in mid-2011. |
| • | East Tennessee — Preliminary development efforts will begin on the Northeastern Tennessee expansion project, consisting of pipeline extension, pickup and relays and compression station modifications. The initial gas service date is expected to be in the second half of 2011. |
Financing Cash Flows
Net cash provided by financing activities totaled $71.0 million in 2009 compared to $105.9 million cash used in 2008. The $176.9 million change was driven primarily by:
| • | $212.2 million of net proceeds received from the issuance of units associated with the NOARK acquisition in 2009, and |
| • | $10.0 million of net payments on long-term debt in 2008, partially offset by |
| • | a $22.5 million net payment on note payable to affiliates in 2009, and |
| • | $23.3 million of increased distributions to partners in 2009 compared to 2008, as a result of increasing distribution rates and an increase in the number of units outstanding due to the issuance in the second quarter of 2009. |
Net cash flows used in financing activities in 2008 totaled $105.9 million compared to $135.0 million cash provided in 2007. This $240.9 million change was driven primarily by:
| • | $300.0 million net issuances of long-term debt and note payable to affiliates in 2007 as compared to a net reduction of $10.0 million in 2008, |
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| • | $230.2 million of net cash received in 2007 from the issuance of common units to the public in the IPO, and |
| • | $74.8 million of distributions to partners in 2008, partially offset by |
| • | $362.4 million of net transfers to parent in 2007, which included an initial cash distribution of $345.0 million to Spectra Energy on July 2, 2007, and |
| • | $12.5 million of dividends in 2007 by East Tennessee to its parent prior to the IPO. |
Prior to the completion of the IPO, all of our excess cash flow was distributed as dividends and net transfers to Spectra Energy. As a result, our changes in cash provided by operating activities and cash used in investing activities were offset by cash flows for financing activities.
Funding of NOARK Acquisition. On May 4, 2009, we acquired all of the ownership interests of NOARK from Atlas for approximately $294.5 million. The transaction was initially funded by $218.0 million drawn on our available bank credit facility, $70.0 million borrowed under a credit facility with a subsidiary of Spectra Energy and $6.5 million from cash on hand. This transaction was partially refinanced in the second quarter of 2009 through the issuance of 9.8 million common units to the public, representing limited partner interests, and 0.2 million general partner units to Spectra Energy, resulting in net proceeds of $212.2 million that was used to repay $142.2 million drawn on our bank credit facility and $70.0 million drawn on the credit facility with a subsidiary of Spectra Energy. Effective with the $70.0 million repayment, the credit facility with the subsidiary of Spectra Energy was terminated. The bank credit facility was further paid down with the proceeds from the special distribution of $72.7 million received from Gulfstream in the second quarter of 2009.
Available Credit Facility and Restrictive Debt Covenants. Effective as of July 2, 2007, we entered into a five-year $500.0 million credit agreement that included both term and revolving borrowing capacity, of which we borrowed $194.0 million of term borrowings and $125.0 million of revolving borrowings upon the closing of the IPO. The term loans were repaid in 2008 and 2009 and that feature of the credit facility is no longer available. The revolving credit facility bears interest based on the London InterBank Offering Rate (LIBOR) and $260.0 million is available under this facility.
The credit facility prohibits us from making distributions of Available Cash to unitholders if any default or event of default, as defined, exists. In addition, the credit facility contains covenants, among others, limiting our ability to make other restricted distributions or dividends on account of the purchase, redemption, retirement, acquisition, cancellation or termination of partnership interests, and is also subject to certain financial covenants. These financial covenants include financial leverage and interest coverage ratios. The terms of the credit agreement require us to maintain a ratio of total debt to Adjusted Earnings Before Interest, Taxes, Depreciation and Amortization (EBITDA), as defined in the credit agreement, of 5.0 or less. As of December 31, 2009, the ratio was 1.5. The terms of the credit agreement also require us to maintain a ratio of Adjusted EBITDA to interest expense of 2.5 or greater. As of December 31, 2009, the ratio was 16.5. Adjusted EBITDA, and therefore these ratios, are affected by substantially the same economic and other drivers as those previously discussed under Results of Operations. We are not aware of any events that would cause us to not comply with such covenants in the near future. The credit facility 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.
Cash Distributions. The partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our Available Cash, as defined, to unitholders of record on the applicable record date. We have increased the quarterly cash distributions each quarter of 2009 from $0.36 per limited partner unit for the fourth quarter of 2008 to $0.41 per limited partner unit for the fourth quarter of 2009, or 14%. A cash distribution to our unitholders of $0.41 per limited partner unit was declared on January 21, 2010 and was paid on February 12, 2010, which is a $0.01 per limited partner unit increase over the cash distribution paid on November 13, 2009.
Other Financing Matters. As of the date of this filing, we have $1.3 billion available in the aggregate under an effective shelf registration statement on file with the SEC to register the issuance of limited partner common units and various debt securities.
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Off Balance Sheet Arrangements
We do not have any off-balance sheet financing entities or structures with third parties other than our equity investments in Gulfstream and Market Hub, and maintain no debt obligations that contain provisions requiring accelerated payment of the related obligation in the event of specified declines in credit ratings.
Gulfstream has $1,150.0 million aggregate principal amount of senior notes outstanding, none of which is included on our consolidated balance sheets.
Contractual Obligations
We enter into contracts that require payment of cash at certain specified periods, based on certain specified minimum quantities and prices. The following table summarizes our contractual cash obligations for each of the periods presented. The table below excludes all amounts classified as Current Liabilities on the Consolidated Balance Sheets. It is expected that the majority of these current liabilities will be paid in cash in 2010, with the exception of the note payable to affiliate. The note payable to affiliate has a maturity date of 2012, however is payable on demand thus classified as a current liability.
Contractual Obligations as of December 31, 2009
| Payments Due by Period | |||||||||||||||
| Total | 2010 | 2011 & 2012 |
2013 & 2014 |
2015 & Beyond | |||||||||||
| (in millions) | |||||||||||||||
| Long-term debt(a) |
$ | 418.8 | $ | 10.0 | $ | 408.8 | $ | — | $ | — | |||||
| Operating leases |
0.5 | 0.1 | 0.2 | 0.2 | — | ||||||||||
| Purchase obligations |
0.6 | 0.6 | — | — | — | ||||||||||
| Total contractual cash obligations |
$ | 419.9 | $ | 10.7 | $ | 409.0 | $ | 0.2 | $ | — | |||||
| (a) | See Note 12 of Notes to Consolidated Financial Statements. Amounts include estimated scheduled interest payments over the life of the associated debt. |
Quantitative and Qualitative Disclosures About Market Risk
We are exposed to market risks associated with interest rate and credit exposure. We have established comprehensive risk management policies to monitor and manage these market risks. Spectra Energy is responsible for the overall governance of managing our interest rate risk and credit risk, including monitoring exposure limits.
Interest Rate Risk
We are exposed to risk resulting from changes in interest rates as a result of our issuance of variable and fixed-rate debt and investments in short-term securities. We manage our interest rate exposure by limiting our variable-rate exposures to percentages of total debt and by monitoring the effects of market changes in interest rates. We also enter into financial derivative instruments, including, but not limited to, interest rate swaps to manage and mitigate interest rate risk exposure. See Item 8. Financial Statements and Supplementary Data, Notes 1, 12 and 16 of Notes to Consolidated Financial Statements.
Based on a sensitivity analysis as of December 31, 2009, it was estimated that if market interest rates average 100 basis points higher (lower) in 2010 than in 2009, interest expense, net of offsetting impacts in interest income, would increase (decrease) by $0.8 million. Comparatively, based on a sensitivity analysis as of December 31, 2008, had interest rates averaged 100 basis points higher (lower) in 2009 than in 2008, it was estimated that interest expense, net of offsetting interest income, would have fluctuated by $1.2 million. These amounts were estimated by considering the effect of the hypothetical interest rates on variable-rate debt outstanding, adjusted for interest rate hedges, investments, and cash and cash equivalents outstanding as of December 31, 2009 and 2008. If interest rates changed significantly, we would
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likely take action to manage our exposure to the change. However, due to the uncertainty of the specific actions that would be taken and their possible effects, the sensitivity analysis assumes no changes in our financial structure.
In 2008, we entered into a series of two and three-year “pay fixed — receive floating” interest rate swap agreements with Spectra Energy to mitigate our exposure to variable interest rates on $140.0 million of loans outstanding under the revolving credit facility. In 2009, we entered into a series of three-year “pay fixed — receive floating” interest rate swap agreements with third parties to mitigate our exposure to variable interest rates on $40.0 million of loans outstanding under the revolving credit facility. As of December 31, 2009, the total notional amount of our interest rate swaps was $180.0 million.
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 transportation, storage and gathering services are industrial end-users, marketers, exploration and production companies, LDCs and utilities located in the southeastern United States, Oklahoma, Arkansas and Missouri. We have concentrations of receivables from these industry sectors. These concentrations of customers may affect our overall credit risk in that risk factors can negatively affect the credit quality of the entire sector.
We had one customer that represented approximately 11% of the gross fair value of trade accounts receivable at December 31, 2009.
Where exposed to credit risk, we analyze the counterparties’ financial condition prior to entering into an agreement, establish credit limits and monitor the appropriateness of these limits on an ongoing basis. We also obtain parental guarantees, cash 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 transaction. Over 90% of our credit exposures for transportation, storage and gathering services are either with customers who have an investment-grade rating (or the equivalent based on an evaluation by Spectra Energy), or are secured by collateral. 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.
We manage cash to maximize value while assuring appropriate amounts of cash are available, as required. We typically invest our available cash in high-quality money market securities. Such money market securities are designed for safety of principal and liquidity, and accordingly, do not include equity-based securities.
Market Hub, our 50% equity investment, also has gas imbalances created primarily by park-and-loan services. Increases in gas prices and gas price volatility can materially increase Market Hub’s credit risk related to gas loaned to customers. The highest amount of gas loaned out by Market Hub during 2009 was approximately 4.0 Bcf. The market value of that volume, assuming an average market price of $6.00 per MMBtu, would be $24 million. Market Hub’s credit exposure from gas loans is managed consistent with the program described above, and Market Hub obtains security deposits as necessary from third parties and affiliates to cover any excess exposure.
Based on our policies for managing credit risk, our exposures and our credit and other reserves, we do not anticipate a materially adverse effect on our consolidated results of operations or financial position as a result of non-performance by any counterparty.
OTHER ISSUES
Global Climate Change. Policymakers at regional, federal and international levels continue to evaluate potential legislative and regulatory compliance mechanisms to achieve reductions in global GHG emissions in an effort to
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address the challenge of climate change. It is likely that our assets and operations are or will become subject to direct and indirect effects of current and possible future global climate change regulatory actions in the jurisdictions in which those assets and operations are located.
The current international climate framework, the United Nations-sponsored Kyoto Protocol, prescribes specific targets to reduce GHG emissions for developed countries for the 2008-2012 period. The Kyoto Protocol expires in 2012 and has not been signed by the United States. United Nations-sponsored international negotiations were held in Copenhagen, Denmark in December 2009 with the intent of defining a future agreement for 2012 and beyond. While the talks resulted in a non-binding political agreement, to date, a binding successor agreement to the Kyoto Protocol has not been reached.
In the United States, climate change action is evolving at state, regional and federal levels. We expect that a number of our assets and operations could be affected by eventual mandatory GHG programs; however, the timing and specific policy objectives in many jurisdictions, including at the federal level, remain uncertain.
The United States is not a signatory to the Kyoto Protocol, nor has the federal government adopted a mandatory GHG emissions reduction requirement. However, the EPA issued the final Mandatory Greenhouse Gas Reporting rule in 2009 that will require annual reporting of GHG emissions data from certain of our U.S. operations beginning in 2010. This reporting requirement is not anticipated to have a material impact on our consolidated results of operations, financial position or cash flows. The EPA also proposed the Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule in 2009 to address how GHG emissions would be regulated under the existing Clean Air Act. This proposed rulemaking has not yet been finalized. In addition, several legislative proposals have been introduced and discussed in the U.S. Congress that would impose GHG emissions constraints, including H.R. 2454—the American Clean Energy and Security Act, which passed the House of Representatives in June 2009. To date, similar legislation has not been considered by the full U.S. Senate.
A number of states in the United States are establishing or considering state or regional programs that would mandate reductions in GHG emissions. These regional programs include the Regional Greenhouse Gas Initiative which applies only to power producers in select northeastern states, the Western Climate Initiative which includes a number of western states and Canadian provinces, and the Midwestern Greenhouse Gas Reduction Accord which includes six midwestern states and one Canadian province. We expect a number of our assets and operations could be affected either directly or indirectly by state or regional programs. However, as the key details of future GHG restrictions and compliance mechanisms remain undefined, the likely future effects on our business are highly uncertain.
Due to the speculative outlook regarding any U.S. federal and state policies, we cannot estimate the potential effect of proposed GHG policies on our future consolidated results of operations, financial position or cash flows. However, such legislation 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 in the jurisdictions in which we operate.
Other. For additional information on other issues, see Item 8. Financial Statements and Supplementary Data, Notes 5 and 15 of Notes to Consolidated Financial Statements.
New Accounting Pronouncements
See Note 1 of Notes to Consolidated Financial Statements for discussion.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Quantitative and Qualitative Disclosures About Market Risk for discussion.
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Item 8. Financial Statements and Supplementary Data.
Management’s Annual Report on Internal Control over Financial Reporting
The management of our General Partner is responsible for establishing and maintaining an adequate system of internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Our internal control system was designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes, in accordance with generally accepted accounting principles. Because of inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies and procedures may deteriorate.
The management of our General Partner, including our Chief Executive Officer and Chief Financial Officer, has conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2009 based on the framework in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2009.
Our independent registered public accounting firm has audited and issued a report on the effectiveness of our internal control over financial reporting, which is included in its Report of Independent Registered Public Accounting Firm.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Unitholders of
Spectra Energy Partners, LP:
We have audited the accompanying consolidated balance sheets of Spectra Energy Partners, LP and subsidiaries as of December 31, 2009 and 2008, and the related consolidated statements of operations, partners’ capital/predecessor equity and comprehensive income, and cash flows of Spectra Energy Partners, LP and subsidiaries and Spectra Energy Partners’ Predecessor for each of the three years in the period ended December 31, 2009 (collectively, Spectra Energy Partners, LP and subsidiaries and Spectra Energy Partners’ Predecessor are the “Company”). Our audits also included the financial statement schedule listed in the Index at Item 15. We also have audited the Company’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the financial statements and financial statement schedule based on our audits. The consolidated financial statements give retroactive effect to the acquisition of 100% of the equity interests of Saltville Gas Storage Company L.L.C. (“Saltville”) and the P-25 pipeline from Spectra Energy Corp by the Company on April 4, 2008, which has been accounted for in a manner similar to a pooling of interests as described in Notes 1 and 2 to the consolidated financial statements.
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.
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In our opinion, such consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2009 and 2008, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2009, after giving retroactive effect to the acquisition of Saltville and the P-25 pipeline described in Notes 1 and 2 to the consolidated financial statements, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects the information set forth therein. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
As discussed in Note 1 to the consolidated financial statements, on July 2, 2007 the Company completed its initial public offering. For periods prior to the closing of the initial public offering, the financial statements were prepared from the separate records maintained by Spectra Energy Capital, LLC for East Tennessee Natural Gas LLC, Market Hub Partners Holding and Gulfstream Natural Gas System, L.L.C., the entities that were contributed to the Company by Spectra Energy Corp, and are based on the historical ownership percentages of the entities’ operations that were contributed. The financial results of the entities are treated as the historical results of the Company for financial statement purposes and may not necessarily be indicative of the conditions that would have existed or the results of operations if the Company had been operated as an unaffiliated entity. Portions of certain expenses represent allocations made from and are applicable to Spectra Energy Capital, LLC as a whole.
Also as described in Note 1 to the consolidated financial statements, the portion of the accompanying consolidated financial statements attributable to Saltville and the P-25 pipeline have been prepared from the separate records maintained by Spectra Energy Capital, LLC and may not necessarily be indicative of the conditions that would have existed or the results of operations if Saltville and the P-25 pipeline had been operated as unaffiliated entities. Portions of certain expenses represent allocations made from, and are applicable to Spectra Energy Capital, LLC as a whole.
/S/ Deloitte & Touche LLP
Houston, Texas
March 11, 2010
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SPECTRA ENERGY PARTNERS, LP
CONSOLIDATED STATEMENTS OF OPERATIONS
(In millions, except per-unit amounts)
| Years Ended December 31, | |||||||||||
| 2009 | 2008 | 2007 | |||||||||
| Operating Revenues |
|||||||||||
| Transportation of natural gas |
$ | 150.7 | $ | 107.0 | $ | 100.6 | |||||
| Storage of natural gas and other |
28.2 | 17.9 | 20.5 | ||||||||
| Total operating revenues |
178.9 | 124.9 | 121.1 | ||||||||
| Operating Expenses |
|||||||||||
| Operating, maintenance and other |
24.7 | 20.2 | 26.4 | ||||||||
| Operating, maintenance and other — affiliates |
35.6 | 23.4 | 3.3 | ||||||||
| Depreciation and amortization |
28.5 | 26.3 | 26.4 | ||||||||
| Property and other taxes |
7.3 | 3.1 | 4.4 | ||||||||
| Total operating expenses |
96.1 | 73.0 | 60.5 | ||||||||
| Operating Income |
82.8 | 51.9 | 60.6 | ||||||||
| Other Income and Expenses |
|||||||||||
| Equity in earnings of unconsolidated affiliates |
70.7 | 61.4 | 55.6 | ||||||||
| Other income and expenses, net |
0.1 | 0.9 | 0.4 | ||||||||
| Total other income and expenses |
70.8 | 62.3 | 56.0 | ||||||||
| Interest Income |
0.2 | 3.5 | 5.5 | ||||||||
| Interest Expense |
11.5 | 16.3 | 16.5 | ||||||||
| Interest Expense — Affiliates |
5.2 | 1.5 | 0.6 | ||||||||
| Earnings Before Income Taxes |
137.1 | 99.9 | 105.0 | ||||||||
| Income Tax Expense (Benefit)(a) |
1.2 | (1.4 | ) | (97.9 | ) | ||||||
| Net Income |
$ | 135.9 | $ | 101.3 | $ | 202.9 | |||||
| Calculation of Limited Partners’ Interest in Net Income: |
|||||||||||
| Net income |
$ | 135.9 | $ | 101.3 | $ | 202.9 | |||||
| Less: |
|||||||||||
| Net income attributable to predecessor operations |
— | 1.6 | 156.7 | ||||||||
| General partner’s interest in net income |
5.7 | 2.5 | 0.9 | ||||||||
| Limited partners’ interest in net income |
$ | 130.2 | $ | 97.2 | $ | 45.3 | |||||
| Weighted average limited partners units outstanding — basic and diluted |
76.4 | 69.4 | 66.2 | ||||||||
| Net income per limited partner unit — basic and diluted |
$ | 1.71 | $ | 1.40 | $ | 0.68 | |||||
| Distributions paid per limited partner unit |
$ | 1.51 | $ | 1.34 | $ | 0.30 | |||||
| (a) | Includes a $2.5 million benefit in 2008 and a $110.5 million benefit in 2007 related to the elimination of accumulated deferred income tax liabilities. See Note 6 for further discussion. |
See Notes to Consolidated Financial Statements.
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SPECTRA ENERGY PARTNERS, LP
CONSOLIDATED BALANCE SHEETS
(In millions)
| December 31, | ||||||
| 2009 | 2008 | |||||
| ASSETS | ||||||
| Current Assets |
||||||
| Cash and cash equivalents |
$ | 12.2 | $ | 30.9 | ||
| Receivables, trade (net of allowance for doubtful accounts of $0.1 and $0.5 at December 31, 2009 and 2008, respectively) |
21.5 | 11.4 | ||||
| Receivables — affiliates |
0.6 | 0.8 | ||||
| Natural gas imbalance receivables |
3.5 | 2.2 | ||||
| Natural gas imbalance receivables — affiliates |
1.7 | 2.5 | ||||
| Inventory |
5.2 | 3.0 | ||||
| Fuel tracker |
0.6 | — | ||||
| Other |
2.2 | 1.5 | ||||
| Total current assets |
47.5 | 52.3 | ||||
| Investments and Other Assets |
||||||
| Investments in unconsolidated affiliates |
536.3 | 573.3 | ||||
| Goodwill |
267.9 | 118.3 | ||||
| Other investments |
— | 31.6 | ||||
| Total investments and other assets |
804.2 | 723.2 | ||||
| Property, Plant and Equipment |
||||||
| Cost |
1,124.3 | 969.6 | ||||
| Less accumulated depreciation and amortization |
179.0 | 154.4 | ||||
| Net property, plant and equipment |
945.3 | 815.2 | ||||
| Regulatory Assets and Deferred Debits |
15.5 | 10.8 | ||||
| Total Assets |
$ | 1,812.5 | $ | 1,601.5 | ||
See Notes to Consolidated Financial Statements.
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SPECTRA ENERGY PARTNERS, LP
CONSOLIDATED BALANCE SHEETS
(In millions)
| December 31, | ||||||||
| 2009 | 2008 | |||||||
| LIABILITIES AND PARTNERS’ CAPITAL | ||||||||
| Current Liabilities |
||||||||
| Accounts payable |
$ | 3.4 | $ | 4.4 | ||||
| Accounts payable — affiliates |
11.4 | 7.6 | ||||||
| Taxes accrued |
4.1 | 2.4 | ||||||
| Interest accrued |
0.5 | 0.8 | ||||||
| Natural gas imbalance payables |
3.6 | 3.2 | ||||||
| Note payable — affiliates |
27.5 | 50.0 | ||||||
| Fuel tracker |
— | 2.8 | ||||||
| Other |
5.4 | 4.7 | ||||||
| Total current liabilities |
55.9 | 75.9 | ||||||
| Long-term Debt |
390.0 | 390.0 | ||||||
| Deferred Credits and Other Liabilities |
||||||||
| Deferred income taxes |
10.0 | 8.8 | ||||||
| Other — affiliates |
4.8 | 5.6 | ||||||
| Other |
3.3 | 2.8 | ||||||
| Total deferred credits and other liabilities |
18.1 | 17.2 | ||||||
| Commitments and Contingencies |
||||||||
| Partners’ Capital |
||||||||
| Common units (58.7 million and 48.9 million units issued and outstanding at December 31, 2009 and 2008, respectively) |
1,015.0 | 794.5 | ||||||
| Subordinated units (21.6 million units issued and outstanding) |
308.5 | 304.7 | ||||||
| General partner units (1.6 million and 1.4 million units outstanding at December 31, 2009 and December 31, 2008, respectively) |
27.2 | 21.4 | ||||||
| Accumulated other comprehensive loss |
(2.2 | ) | (2.2 | ) | ||||
| Total partners’ capital |
1,348.5 | 1,118.4 | ||||||
| Total Liabilities and Partners’ Capital |
$ | 1,812.5 | $ | 1,601.5 | ||||
See Notes to Consolidated Financial Statements.
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SPECTRA ENERGY PARTNERS, LP
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
| Years Ended December 31, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
| CASH FLOWS FROM OPERATING ACTIVITIES |
||||||||||||
| Net income |
$ | 135.9 | $ | 101.3 | $ | 202.9 | ||||||
| Adjustments to reconcile net income to net cash provided by operating activities: |
||||||||||||
| Depreciation and amortization |
28.5 | 26.3 | 26.4 | |||||||||
| Deferred income tax expense (benefit) |
1.2 | (2.0 | ) | (103.6 | ) | |||||||
| Equity in earnings of unconsolidated affiliates |
(70.7 | ) | (61.4 | ) | (55.6 | ) | ||||||
| Distributions received from unconsolidated affiliates |
74.3 | 71.7 | 22.7 | |||||||||
| Decrease (increase) in: |
||||||||||||
| Receivables |
(4.8 | ) | 3.7 | (14.8 | ) | |||||||
| Taxes receivable — affiliates |
(0.2 | ) | (0.2 | ) | 1.5 | |||||||
| Other current assets |
(0.7 | ) | (1.2 | ) | 1.6 | |||||||
| Increase (decrease) in: |
||||||||||||
| Accounts payable |
(1.0 | ) | 2.5 | 8.4 | ||||||||
| Taxes accrued |
(0.2 | ) | (1.1 | ) | 3.8 | |||||||
| Other current liabilities |
(4.5 | ) | (1.4 | ) | (4.5 | ) | ||||||
| Other, assets |
1.3 | 1.2 | 1.6 | |||||||||
| Other, liabilities |
0.6 | (0.2 | ) | (5.5 | ) | |||||||
| Net cash provided by operating activities |
159.7 | 139.2 | 84.9 | |||||||||
| CASH FLOWS FROM INVESTING ACTIVITIES |
||||||||||||
| Capital expenditures |
(20.3 | ) | (47.0 | ) | (30.4 | ) | ||||||
| Investment expenditures |
(36.7 | ) | (88.6 | ) | (28.3 | ) | ||||||
| Acquisitions, net of cash acquired |
(294.5 | ) | (4.7 | ) | — | |||||||
| Distributions received from unconsolidated affiliates |
70.5 | — | — | |||||||||
| Proceeds from sales of assets |
— | — | 8.3 | |||||||||
| Purchases of available-for-sale securities |
— | (1,132.0 | ) | (1,439.0 | ) | |||||||
| Proceeds from sales and maturities of available-for-sale securities |
31.6 | 1,255.0 | 1,284.4 | |||||||||
| Net cash used in investing activities |
(249.4 | ) | (17.3 | ) | (205.0 | ) | ||||||
| CASH FLOWS FROM FINANCING ACTIVITIES |
||||||||||||
| Proceeds from issuance of debt under credit facilities |
3,159.0 | 1,785.0 | 380.0 | |||||||||
| Payments for the redemption of debt under credit facilities |
(3,159.0 | ) | (1,795.0 | ) | (130.0 | ) | ||||||
| Proceeds from issuance of units |
212.2 | — | 230.2 | |||||||||
| Proceeds from notes payable — affiliates |
77.0 | — | 50.0 | |||||||||
| Payments on notes payable — affiliates |
(99.5 | ) | — | — | ||||||||
| Dividends to parent |
— | — | (12.5 | ) | ||||||||
| Distributions to partners |
(118.4 | ) | (95.1 | ) | (20.3 | ) | ||||||
| Transfers to parent, net |
— | (0.8 | ) | (362.4 | ) | |||||||
| Other |
(0.3 | ) | — | — | ||||||||
| Net cash provided by (used in) financing activities |
71.0 | (105.9 | ) | 135.0 | ||||||||
| Net increase (decrease) in cash and cash equivalents |
(18.7 | ) | 16.0 | 14.9 | ||||||||
| Cash and cash equivalents at beginning of the period |
30.9 | 14.9 | — | |||||||||
| Cash and cash equivalents at end of the period |
$ | 12.2 | $ | 30.9 | $ | 14.9 | ||||||
| Supplemental Disclosures |
||||||||||||
| Cash paid for interest, net of amount capitalized |
$ | 16.2 | $ | 14.3 | $ | 10.3 | ||||||
| Cash paid for income taxes |
0.1 | 0.9 | 6.5 | |||||||||
| Property, plant and equipment noncash accruals |
0.7 | 1.3 | 1.9 | |||||||||
See Notes to Consolidated Financial Statements.
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SPECTRA ENERGY PARTNERS, LP
CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL/PREDECESSOR
EQUITY AND COMPREHENSIVE INCOME
(In millions)
| Predecessor Equity |
Partners’ Capital | Accumulated Other Comprehensive Income (Loss) |
Total | |||||||||||||||||||||
| Limited Partners | General Partner |
|||||||||||||||||||||||
| Common | Subordinated | |||||||||||||||||||||||
| December 31, 2006 |
$ | 1,093.3 | $ | — | $ | — | $ | — | $ | 3.8 | $ | 1,097.1 | ||||||||||||
| Net income attributable to the period January 1, 2007 through July 2, 2007 |
156.7 | — | — | — | — | 156.7 | ||||||||||||||||||
| Net income attributable to the period July 3, 2007 through December 31, 2007 |
— | 30.5 | 14.8 | 0.9 | — | 46.2 | ||||||||||||||||||
| Reclassification of cash flow hedges into earnings |
— | — | — | — | (0.3 | ) | (0.3 | ) | ||||||||||||||||
| Total comprehensive income |
202.6 | |||||||||||||||||||||||
| Dividends to parent |
(12.5 | ) | — | — | — | — | (12.5 | ) | ||||||||||||||||
| Distributions to partners |
— | (13.4 | ) | (6.5 | ) | (0.4 | ) | — | (20.3 | ) | ||||||||||||||
| Net change in parent advances |
(373.4 | ) | — | — | — | — | (373.4 | ) | ||||||||||||||||
| Conversion to Spectra Energy Partners, LP |
(765.7 | ) | 452.0 | 295.2 | 18.5 | — | — | |||||||||||||||||
| Issuance of common units |
— | 230.2 | — | — | — | 230.2 | ||||||||||||||||||
| December 31, 2007 |
98.4 | 699.3 | 303.5 | 19.0 | 3.5 | 1,123.7 | ||||||||||||||||||
| Net income |
1.6 | 66.9 | 30.3 | 2.5 | — | 101.3 | ||||||||||||||||||
| Unrealized mark-to-market net loss on hedges |
— | — | — | — | (6.2 | ) | (6.2 | ) | ||||||||||||||||
| Reclassification of cash flow hedges into earnings |
— | — | — | — | 0.5 | 0.5 | ||||||||||||||||||
| Total comprehensive income |
95.6 | |||||||||||||||||||||||
| Net change in parent advances |
(0.8 | ) | — | — | — | — | (0.8 | ) | ||||||||||||||||
| Acquisition of Saltville and P-25 pipeline |
(99.2 | ) | — | — | — | — | (99.2 | ) | ||||||||||||||||
| Excess purchase price over net acquired assets |
— | (7.6 | ) | — | (0.2 | ) | — | (7.8 | ) | |||||||||||||||
| Issuance of units |
— | 100.2 | — | 2.1 | — | 102.3 | ||||||||||||||||||
| Attributed deferred tax expense |
— | (0.2 | ) | (0.1 | ) | — | — | (0.3 | ) | |||||||||||||||
| Distributions to partners |
— | (64.1 | ) | (29.0 | ) | (2.0 | ) | — | (95.1 | ) | ||||||||||||||
| December 31, 2008 |
— | 794.5 | 304.7 | 21.4 | (2.2 | ) | 1,118.4 | |||||||||||||||||
| Net income |
— | 93.9 | 36.3 | 5.7 | — | 135.9 | ||||||||||||||||||
| Unrealized mark-to-market net loss on hedges |
— | — | — | — | (4.9 | ) | (4.9 | ) | ||||||||||||||||
| Reclassification of cash flow hedges into earnings |
— | — | — | — | 4.9 | 4.9 | ||||||||||||||||||
| Total comprehensive income |
135.9 | |||||||||||||||||||||||
| Issuance of units |
— | 207.8 | — | 4.4 | — | 212.2 | ||||||||||||||||||
| Attributed deferred tax expense |
— | (0.1 | ) | — | — | — | (0.1 | ) | ||||||||||||||||
| Distributions to partners |
— | (81.4 | ) | (32.7 | ) | (4.3 | ) | — | (118.4 | ) | ||||||||||||||
| Other, net |
— | 0.3 | 0.2 | — | — | 0.5 | ||||||||||||||||||
| December 31, 2009 |
$ | — | $ | 1,015.0 | $ | 308.5 | $ | 27.2 | $ | (2.2 | ) | $ | 1,348.5 | |||||||||||
See Notes to Consolidated Financial Statements.
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SPECTRA ENERGY PARTNERS, LP
Notes to Consolidated Financial Statements
INDEX
| Page | ||||
| 1. | 64 | |||
| 2. | 70 | |||
| 3. | 72 | |||
| 4. | 73 | |||
| 5. | 74 | |||
| 6. | 75 | |||
| 7. | 76 | |||
| 8. | 78 | |||
| 9. | 78 | |||
| 10. | 79 | |||
| 11. | 80 | |||
| 12. | 80 | |||
| 13. | 81 | |||
| 14. | 82 | |||
| 15. | 82 | |||
| 16. | 83 | |||
| 17. | 84 | |||
| 18. | 84 | |||
| 19. | 85 |
1. Summary of Operations and Significant Accounting Policies
The terms “we,” “our,” “us,” and “Spectra Energy Partners” as used in this report refer collectively to Spectra Energy Partners, LP and its subsidiaries unless the context suggests otherwise. These terms are used for convenience only and are not intended as a precise description of any separate legal entity within Spectra Energy Partners.
Nature of Operations. Spectra Energy Partners, LP, through its subsidiaries and equity affiliates, is engaged in the transportation and gathering of natural gas through interstate pipeline systems that are located in the southeastern United States, Oklahoma, Arkansas and Missouri, and the storage of natural gas in underground facilities that are located in southeast Texas, south central Louisiana and southwest Virginia. We are a Delaware master limited partnership (MLP) formed on March 19, 2007. As of December 31, 2009, Spectra Energy and its subsidiaries collectively owned 74% of us and the remaining 26% was publicly owned.
Initial Public Offering. On July 2, 2007, immediately prior to the closing of our initial public offering (IPO), Spectra Energy Corp (Spectra Energy) contributed to us 100% of the ownership of East Tennessee Natural Gas LLC (East Tennessee) less certain working capital balances retained as per the partnership agreements, 50% of the ownership of Market Hub Partners Holding (Market Hub) and a 24.5% interest in Gulfstream Natural Gas System, L.L.C. (Gulfstream). See Note 3 for further information regarding the working capital transfers. Spectra Energy indirectly owned 100% of us prior to the closing of the IPO.
On July 2, 2007, we completed our IPO. We issued 11.5 million common units to the public, representing 17% of our outstanding equity. Net cash of $230.2 million was received by us upon closing of the IPO. Spectra Energy retained an 83% equity interest in our partnership, including common units, subordinated units and a 2% general partner interest. Approximately $26.0 million of these proceeds were distributed to Spectra Energy, $194.0 million was used to purchase qualifying investment-grade securities and $10.0 million was retained by us
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to meet working capital requirements. Also on July 2, 2007, we borrowed $194.0 million in term debt using the investment-grade securities as collateral and borrowed an additional $125.0 million of revolving debt. Proceeds from these borrowings, totaling $319.0 million, were distributed to Spectra Energy.
See Note 2 for a discussion of acquisitions that have diluted Spectra Energy’s ownership percentage from 83% at inception to the current 74%.
Basis of Presentation. For periods prior to the closing of the IPO, the combined financial statements were prepared from the separate records maintained by Spectra Energy Capital, LLC for the entities that were originally contributed to us and are based on Spectra Energy Capital, LLC’s historical ownership percentages of those operations, and for the operations included in the Saltville Gas Storage L.L.C (Saltville) and P-25 pipeline acquisition (collectively, hereafter referred to as the “Saltville acquisition”). The combined financial results of these entities are treated as the historical results of our partnership for financial statement reporting purposes. Both the combined financial statements of East Tennessee, Saltville, Market Hub and Gulfstream, as well as the consolidated financial statements of our partnership for the periods post-IPO, are hereafter referred to as the Consolidated Financial Statements. The historical data for periods prior to the closing of the IPO and for periods prior to the Saltville acquisition may not necessarily be indicative of the actual results of operations had those entities been operated separately during those periods. Because a direct ownership relationship did not exist among entities comprising our partnership prior to July 2, 2007 and prior to the Saltville acquisition on April 4, 2008, the net investment in our partnership is shown as Predecessor Equity in the applicable Consolidated Financial Statements.
We generally account for investments in 20% to 50%-owned affiliates, and investments in less than 20%-owned affiliates where we have the ability to exercise significant influence, under the equity method. Accordingly, the consolidated historical financial statements for our partnership reflect the consolidation of East Tennessee, Ozark Gas Transmission, L.L.C. (Ozark Gas Transmission) and Ozark Gas Gathering, L.L.C. (Ozark Gas Gathering) (collectively, hereafter referred to as “Ozark”) and Saltville, of which we own 100% of each, and our 50% investment in Market Hub and 24.5% investment in Gulfstream that are accounted for under the equity method. Intercompany balances and transactions have been eliminated in consolidation.
Spectra Energy managed its cash on a centralized basis for the entire Spectra Energy consolidated group, which in the periods up to the completion of our IPO, included the various assets and operations of the companies that were contributed to us in connection with our IPO, with the exception of Gulfstream which did not participate in the centralized cash management activity of Spectra Energy. The individual cash accounts maintained at the business unit levels (i.e. within our entities) were swept to a Spectra Energy corporate account on a daily basis, creating an Advance Receivable between Spectra Energy (or other affiliates/corporate entities) and the individual entities that now comprise our partnership. Therefore, our financials do not reflect any cash balances prior to the IPO. These net advances did not bear interest and were carried as unsecured, intercompany balances. Spectra Energy and our entities settled the cumulative advance balances through equity distributions or contributions prior to our IPO. Therefore, the consolidated net advances have been classified as Predecessor Equity in the Consolidated Statement of Partners’ Capital/Predecessor Equity and Comprehensive Income.
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.
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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 in the rate-setting process in a period different from the period in which the amounts would be recorded by an unregulated enterprise. Accordingly, we record assets and liabilities that result from the regulated ratemaking process that 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 applicable to other regulated entities. Based on this continual assessment, we believe our existing regulatory assets are probable of recovery. These regulatory assets are classified in the Consolidated Balance Sheets as Current Assets — Fuel Tracker, and Regulatory Assets and Deferred Debits. We periodically evaluate our regulated assets, and consider factors such as regulatory changes and the effect of competition. If cost-based regulation ends or competition increases, we may have to reduce our asset balances to reflect a market basis less than cost and write-off the associated regulatory assets. See Note 5 for further discussion.
Revenue Recognition. Revenues from the transportation, gathering and storage of natural gas and the storage of liquefied natural gas (LNG) are recognized when the service is provided. Revenues related to these services provided but not yet billed are estimated each month. These estimates are generally based on contract data, regulatory information and preliminary throughput and allocation measurements. Final bills for the current month are billed and collected in the following month. Differences between actual and estimated unbilled revenues are immaterial.
Customers accounting for 10% or more of consolidated revenues during 2009, 2008 or 2007 are as follows:
| % of Revenues | |||||||||
| Customer |
2009 | 2008 | 2007 | ||||||
| Atmos Energy Corporation |
10 | % | 14 | % | 15 | % | |||
Allowance for Funds Used During Construction (AFUDC). AFUDC, which represents the estimated debt and equity costs of capital funds necessary to finance the construction and expansion of certain new regulated facilities, consists of two components, an equity component and an interest expense component. The equity component is a non-cash item. AFUDC is capitalized as a component of Property, Plant and Equipment cost, with offsetting credits to the Consolidated Statements of Operations through Other Income and Expenses, Net for the equity component and Interest Expense for the interest expense component. After construction is completed, we are permitted to recover these costs through inclusion in the rate base and in the depreciation provision. The total amount of AFUDC included in the Consolidated Statements of Operations was $0.1 million in 2009 (an equity component of $0.1 million), $1.1 million in 2008 (an equity component of $0.9 million and an interest expense component of $0.2 million) and $0.3 million in 2007 (an equity component of $0.2 million and an interest expense component of $0.1 million).
Income Taxes. Our Gas Transportation and Storage operations that were contributed to us in connection with our IPO were subject to corporate income tax under tax sharing agreements with Spectra Energy in 2007. During those periods, income taxes were calculated by us on the basis of our separate company income and deductions related to Gas Transportation and Storage in accordance with respective established practices of Spectra Energy. Deferred income taxes have been provided for temporary differences between the GAAP and tax carrying amounts of assets and liabilities. These differences create taxable or tax deductible amounts for future periods. Effective July 2, 2007, as a result of our MLP structure, we are no longer subject to federal income tax, but are still subject to Tennessee income tax.
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Market Hub is liable for Texas income (margin) tax under a tax sharing agreement with Spectra Energy.
Cash and Cash Equivalents. Highly liquid investments with original maturities of three months or less at the date of acquisition, except for the investments that were previously pledged as collateral against long-term debt as discussed in Note 12, are considered cash equivalents.
Inventory. Inventory consists primarily 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 average cost.
Natural Gas Imbalances. The Consolidated Balance Sheets include in-kind balances as a result of differences in gas volumes received and delivered for customers. Since settlement of imbalances is in-kind, changes in the balances do not have an effect on our Consolidated Statements of Cash Flows. Natural gas volumes owed to or by us are valued at natural gas market index prices as of the balance sheet dates.
Cash Flow Hedges. We have entered into interest rate swaps which were designated as effective cash flow hedges. Changes in the fair value of a derivative designated and qualified as a cash flow hedge, to the extent effective, are reported as Accumulated Other Comprehensive Income (Loss) (AOCI) until earnings are affected by the hedged transaction.
Investments. We may actively invest a portion of our cash 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 were restricted due to debt collateral requirements. We have classified all investments that are debt securities with maturity dates over one year as available-for-sale. These available-for-sale securities are carried at fair value. Investments in money market securities are 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 cost of securities sold is determined using the specific identification method. Purchases and sales of available-for-sale securities are presented on a gross basis within Investing Cash Flows in the accompanying Consolidated Statements of Cash Flows. We had no investments in marketable securities pledged as collateral at December 31, 2009, and $31.6 million at December 31, 2008. These investments are classified within Investments and Other Assets — Other Investments on the Consolidated Balance Sheet.
Goodwill. We perform our goodwill impairment test annually and evaluate goodwill when events or changes in circumstances indicate that its carrying value may not be recoverable. Prior to 2009, we performed the annual impairment testing of goodwill using August 31 as the measurement date. Our financial and strategic planning process, including the preparation of long-term cash flow projections, commences in October and typically concludes in January of the following year. These long-term cash flow projections are a key component in performing our annual impairment test of goodwill. This planning cycle historically created significant constraints in the availability of both information and human resources needed to provide the appropriate projections to be used in the goodwill impairment test using the August 31 test date. Accordingly, effective with our 2009 annual impairment test, we changed our goodwill impairment test date from August 31 to April 1. We believe that using the April 1 date will alleviate the information and resource constraints that historically existed during the third quarter and will better coincide with the completion of our long-term financial projections. We believe that this accounting change is to an alternative accounting principle that is preferable under the circumstances and did not result in the delay, acceleration or avoidance of an impairment charge. We have determined that this change in accounting principle does not result in adjustments to our 2008 or 2007 Consolidated Financial Statements when applied retrospectively as our base assumptions used in the August 31 measurement date would not have changed significantly had we used April 1 as the measurement date. We completed our goodwill impairment test as of April 1, 2009 and no impairments were identified. See Note 10 for further discussion.
We perform the annual review for goodwill impairment at the reporting unit level, which we have determined to be an operating segment or one level below.
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Impairment testing of goodwill consists of a two-step process. The first step involves a comparison of the implied fair value of a reporting unit with its carrying amount. If the carrying amount of the reporting unit exceeds its fair value, the second step of the process involves a comparison of the fair value and carrying value of the goodwill of that reporting unit. If the carrying value of the goodwill of a reporting unit exceeds the implied fair value of that goodwill, an impairment loss is recognized in an amount equal to the excess. Additional impairment tests are performed between the annual reviews if events or changes in circumstances make it more likely than not that the fair value of a reporting unit is below its carrying amount.
We primarily use a discounted cash flow analysis to determine fair value for each reporting unit. Key assumptions in the determination of fair value include the use of an appropriate discount rate and estimated future cash flows. In estimating cash flows, we incorporate expected long-term growth rates in key markets served by our operations, regulatory stability and the ability to renew contracts, as well as other factors that affect our revenue, expense and capital expenditure projections.
Property, Plant and Equipment. Property, plant and equipment are 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 cost of renewals and betterments that extend the useful life or increase the expected output of property, plant and equipment is also capitalized. The cost of repairs, replacements and major maintenance projects that do not extend the useful life or increase the expected output of property, plant and equipment is expensed as incurred. Depreciation is generally computed over the asset’s estimated useful life using the straight-line method.
When we retire regulated property, plant and equipment, we charge the original cost plus the cost of retirement, less salvage value, to accumulated depreciation and amortization. When we sell entire regulated operating units, or retire or sell non-regulated properties, the cost is removed from the property account and the related accumulated depreciation and amortization accounts are reduced. Any gain or loss is recorded in earnings, unless otherwise required by the applicable regulatory body.
Preliminary Project Costs. Project development costs, including expenditures for preliminary surveys, plans, investigations, environmental studies, regulatory applications and other costs incurred for the purpose of determining the feasibility of capital expansion projects, are initially expensed for rate-regulated enterprises. If and when it is determined that recovery of such costs through regulated revenues of the completed project is probable, the inception-to-date costs of the project are recognized 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 analysis and analysis from outside advisors. Significant changes in market conditions resulting from events such as changes in natural gas available to our systems, the condition of an asset, a change in our intent to utilize the asset or a significant change in contracted revenues or regulatory recoveries would generally require us to reassess the cash flows related to the long-lived assets.
Unamortized Debt Expense. Debt expenses incurred with the issuance of outstanding long-term debt are amortized over the terms of the debt issues. Any call premiums or unamortized expenses associated with refinancing higher-cost debt obligations to finance regulated assets and operations are amortized consistent with regulatory treatment of those items, where appropriate.
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Environmental Expenditures. We expense environmental expenditures related to conditions caused by past operations that do not generate current or future revenues. Environmental expenditures related to operations that generate current or future revenues are expensed or capitalized, as appropriate. Undiscounted liabilities are recorded when the necessity for environmental remediation becomes probable and the costs can be reasonably estimated, or when other potential environmental liabilities are reasonably estimable and probable.
Segment Reporting. Operating segments are components of an enterprise about which separate financial information is available and evaluated regularly by the chief operating decision maker in deciding how to allocate resources and evaluate performance. Two or more operating segments may be aggregated into a single reportable segment provided certain criteria are met. There is no aggregation within our defined business segment. A description of our reportable segment, Gas Transportation and Storage, consistent with how business results are reported internally to management and the disclosure of segment information is presented in Note 4.
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 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 investing activities.
New Accounting Pronouncements — 2009. The following new accounting pronouncements were adopted during 2009 and the effect of such adoption, if applicable, has been presented in the accompanying Consolidated Financial Statements:
Accounting Standards Codification (ASC) 105, “Generally Accepted Accounting Principles” (previously Statement of Financial Accounting Standards (SFAS) No. 168, “The FASB Accounting Standards CodificationTM and the Hierarchy of Generally Accepted Accounting Principles — A Replacement of FASB Statement No. 162”). This accounting standard results in the Financial Accounting Standards Board (FASB) Accounting Standards Codification (the Codification) becoming the source of authoritative U.S. GAAP recognized by the FASB to be applied by nongovernmental entities. Rules and interpretive releases of the Securities and Exchange Commission (SEC) are also considered sources of authoritative GAAP for SEC registrants. The Codification supersedes all then-existing non-SEC accounting and reporting standards. All other nongrandfathered, non-SEC accounting literature not included in the Codification is nonauthoritative. The adoption of the provisions of this accounting standard did not change the application of existing GAAP for us, and as a result, did not have any impact on our consolidated results of operations, financial position or cash flows.
ASC 820, “Fair Value Measurement and Disclosures” (previously SFAS No. 157, “Fair Value Measurements”). This accounting standard defines fair value, establishes a framework for measuring fair value in GAAP and expands disclosures about fair value measurements. The FASB issued an amendment to this standard which delayed its effective date for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). The adoption of the provisions of this amended standard on January 1, 2009 for the measurement of our asset retirement obligation and for our goodwill impairment test did not have any impact on our consolidated results of operations, financial position or cash flows.
ASC 805, “Business Combinations” (previously SFAS 141R, “Business Combinations”). This accounting standard requires an acquiring entity in a business combination to recognize all and only the assets acquired and liabilities assumed in the transaction, establishes the acquisition-date fair value as the measurement objective for all assets acquired and liabilities assumed, and requires the acquirer to disclose to investors and other users all of the information they need to evaluate and understand the nature and financial effect of the business combination. This standard applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. We adopted the provisions of this standard effective January 1, 2009 as required.
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ASC 815-10, “Derivatives and Hedging–Overall” (previously SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133”). This accounting standard expands the disclosure requirements related to derivative instruments and hedging activities with the intent to provide users of financial statements an enhanced understanding of how and why derivative instruments are used, how derivative instruments and related hedged items are accounted for and how they affect an entity’s financial position, financial performance and cash flows. We adopted the provisions of this standard effective January 1, 2009 as required.
ASC 275-10, “Risks and Uncertainties–Overall” and ASC 350-30, “Intangibles–Goodwill and Other–General Intangible Other than Goodwill” (previously FASB Staff Position (FSP) No. FAS 142-3, “Determination of the Useful Life of Intangible Assets”). These accounting standards amend the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset. The adoption of the provisions of these standards on January 1, 2009 had no impact on our consolidated results of operations, financial position or cash flows.
ASC 260-10, “Earnings Per Share — Overall” (previously Emerging Issues Task Force (EITF) 07-4, “Application of the Two — Class Method under FASB Statement No. 128 to Master Limited Partnerships”). This accounting standard addresses the application of the two-class method for MLPs when incentive distribution rights (IDR) are present and entitle the IDR holder to a portion of distributions. The final consensus states that when earnings exceed distributions, the computation of net income per unit should be based on the terms of the partnership agreement. Accordingly, any contractual limitations on the distributions to IDR holders (e.g., limitations that only entitle IDR holders to “available cash”) would need to be determined for each reporting period. The adoption of the provisions of this standard on January 1, 2009 did not have a material impact on our computation of net income per limited partner unit.
ASC 855-10, “Subsequent Events — Overall” (previously SFAS No. 165, “Subsequent Events”). This accounting standard establishes general standards for the accounting for and disclosure of events that occur subsequent to the balance sheet date but before the financial statements of an entity are issued or are available to be issued. The adoption of the provisions of this standard effective June 30, 2009 did not have any impact on our consolidated results of operations, financial position or cash flows.
2008 and 2007. There were no significant accounting pronouncements adopted during 2008 and 2007 that had a material impact on our consolidated results of operations, financial position or cash flows.
Pending. The following new accounting pronouncement has been issued but not adopted as of December 31, 2009:
ASC 810-10, “Consolidations-Overall” (previously SFAS No. 167, “Amendments to FASB Interpretation No. 46(R)”). In June 2009, the FASB issued this accounting standard which is intended to address (1) the effects on certain consolidation provisions as a result of the elimination of the concept of qualifying special-purpose entities and (2) constituent concerns about the application of certain consolidation provisions including those in which the accounting and disclosures do not always provide timely and useful information about an enterprise’s involvement in a variable interest entity. For us, this accounting standard must be applied as of January 1, 2010. The adoption of the provisions of this standard did not have any impact on our consolidated results of operations, financial position or cash flows.
Saltville. In 2008, we completed the Saltville acquisition from Spectra Energy at a purchase price of $107.0 million, which included the issuance of 4.2 million common units and 0.1 million general partner units, and a cash payment of $4.7 million to Spectra Energy. Saltville assets include three separate natural gas storage facilities adjacent to the East Tennessee system in southwest Virginia with approximately 5.5 billion cubic feet of
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working capacity. The P-25 pipeline, now part of the operations of East Tennessee, is a 72-mile, eight-inch natural gas pipeline with a capacity of 40 million cubic feet per day that runs parallel to the East Tennessee system in Virginia. The Saltville storage assets and the P-25 pipeline are strategically integrated with our East Tennessee system. The completion of the Saltville acquisition allows for a streamlined regulatory structure under the Federal Energy Regulatory Commission (FERC) jurisdiction, an enhanced operational flexibility that will benefit both East Tennessee and Saltville customers and a broader array of organic expansion opportunities for our pipeline and storage assets.
Spectra Energy’s ownership of us increased from 83% to 84% as a result of receipt of the new common and general partner units. The $7.8 million excess purchase price over the book value of net assets acquired was recorded as a reduction to Partners’ Capital, and the $102.3 million of common and general partner units issued were recorded as increases to Partners’ Capital.
The Saltville acquisition represented a transfer of entities under common control. Accordingly, the Consolidated Financial Statements and related information presented herein include the historical results of Saltville and the P-25 pipeline for all periods presented.
NOARK. On May 4, 2009, we acquired all of the ownership interests of NOARK Pipeline System, Limited Partnership (NOARK) from Atlas Pipeline Partners, L.P. (Atlas) for approximately $294.5 million. NOARK’s assets consist of 100% ownership interests in Ozark Gas Transmission, a 565-mile FERC regulated interstate natural gas transmission system, and Ozark Gas Gathering, a 365-mile, fee-based, natural gas gathering system whose operations are regulated by the applicable state commissions. The transaction was initially funded by $218.0 million drawn on our available bank credit facility, $70.0 million borrowed under a credit facility with a subsidiary of Spectra Energy and $6.5 million from cash on hand. This transaction was partially refinanced through the issuance of 9.8 million common units to the public, representing limited partner interests, and 0.2 million general partner units to Spectra Energy in the second quarter of 2009. Spectra Energy’s ownership of our partnership decreased from 84% to 74% as a result of the issuance of 9.8 million common units to the public. See Note 12 for further discussion related to the debt and Note 17 for a discussion of the sale of common units.
The following unaudited pro forma information has been prepared as if the acquisition had occurred on January 1, 2009 and January 1, 2008, respectively.
| 2009 | 2008 | |||||
| (in millions, except per-unit amounts) | ||||||
| Operating revenues |
$ | 199.5 | $ | 187.3 | ||
| Net income |
150.4 | 123.7 | ||||
| Basic and diluted net income per limited partner unit |
1.81 | 1.52 | ||||
The assets and liabilities of NOARK were recorded at their respective fair values as of May 4, 2009 and the results of NOARK’s operations are included in the Consolidated Financial Statements beginning as of the effective date of the acquisition. For Ozark Gas Transmission, which records assets and liabilities resulting from the regulated rate making process, the fair values of the individual tangible and intangible assets and liabilities are considered to approximate their carrying values.
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The following table summarizes the fair values of the assets acquired and liabilities assumed.
| Purchase Price Allocation |
||||
| (in millions) | ||||
| Purchase price |
$ | 294.5 | ||
| Receivables, net |
5.1 | |||
| Current assets — other |
1.2 | |||
| Property, plant and equipment, net |
139.3 | |||
| Regulatory assets and deferred debits |
5.3 | |||
| Current liabilities |
(5.0 | ) | ||
| Deferred credits and other liabilities |
(1.0 | ) | ||
| Total assets acquired/liabilities assumed |
$ | 144.9 | ||
| Goodwill |
$ | 149.6 | ||
The purchase price is greater than the sum of fair values of the net assets acquired, resulting in goodwill as noted above. The purchase price reflects our plans for increased optimization of the assets through higher utilization and new or expanded services to be provided, as well as increased operating efficiencies that we expect to create as a result of our operational experience associated with our existing assets. All of the goodwill is recorded in the Gas Transportation and Storage segment.
3. Transactions with Affiliates
In the normal course of business, we provide natural gas transportation, gathering, storage and other services to Spectra Energy and its affiliates.
In addition, pursuant to an agreement with Spectra Energy, Spectra Energy and its affiliates perform centralized corporate functions for us, including legal, accounting, compliance, treasury, information technology and other areas. We reimburse Spectra Energy for the expenses to provide these services as well as other expenses it incurs on our behalf, such as salaries of personnel performing services for our benefit and the cost of employee benefits and general and administrative expenses associated with such personnel, capital expenditures, maintenance and repair costs, taxes and direct expenses, including operating expenses and certain allocated operating expenses associated with the ownership and operation of the contributed assets. Spectra Energy and its affiliates charge such expenses based on the cost of actual services provided or using various allocation methodologies based on our percentage of assets, employees, earnings or other measures, as compared to Spectra Energy’s other affiliates. In 2008, we also entered into interest rate swap agreements with Spectra Energy to mitigate our exposure to variable interest rates.
Transactions with affiliates are summarized in the tables below:
Consolidated Statements of Operations
| 2009 | 2008 | 2007 | |||||||
| (in millions) | |||||||||
| Operating, maintenance and other expenses |
$ | 35.6 | $ | 23.4 | $ | 3.3 | |||
| Interest expense |
5.2 | 1.5 | 0.6 | ||||||
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Consolidated Balance Sheets
| December 31, | ||||||
| 2009 | 2008 | |||||
| (in millions) | ||||||
| Receivables |
$ | 0.6 | $ | 0.8 | ||
| Natural gas imbalance receivables |
1.7 | 2.5 | ||||
| Current assets — other |
0.6 | 0.5 | ||||
| Accounts payable |
11.4 | 7.6 | ||||
| Note payable |
27.5 | 50.0 | ||||
| Current liabilities — other |
0.4 | — | ||||
| Deferred credits and other liabilities — other |
4.8 | 5.6 | ||||
In accordance with our partnership formation agreements, East Tennessee transferred $13.4 million of certain working capital balances to Spectra Energy immediately prior to the formation of our partnership on July 2, 2007. These balances were primarily comprised of accounts receivable and advances from Spectra Energy totaling $20.5 million, net of tax liabilities retained by Spectra Energy of $7.1 million.
See also Notes 1, 9, 12, 13 and 16 for discussion of other specific related party transactions.
Our Gas Transportation and Storage segment aligns our operations with the chief operating decision maker’s view of the business. This business segment is considered to be our sole reportable segment.
Gas Transportation and Storage includes East Tennessee, Ozark and Saltville. This segment provides interstate transportation, storage and gathering services of natural gas, and the storage and redelivery of LNG for customers in the southeastern United States, Oklahoma, Arkansas and Missouri. Substantially all of our operations are subject to the FERC and the Department of Transportation’s (DOT’s) rules and regulations.
The remainder of our operations is presented as “Other.” While it is not considered a business segment, Other primarily includes our equity investments in Gulfstream and Market Hub, other investments and certain unallocated corporate costs.
Gulfstream provides interstate natural gas pipeline transportation for customers in central and southern Florida. Gulfstream’s operations are subject to the rules and regulations of the FERC and DOT.
Market Hub owns and operates two natural gas storage facilities, Moss Bluff and Egan, which are located in southeast Texas and south central Louisiana, respectively. Market Hub’s operations are subject to the rules and regulations of DOT. Moss Bluff is also subject to the rules and regulations of the Texas Railroad Commission. Egan is also subject to the rules and regulations of the FERC.
Management evaluates segment performance based on earnings before interest and taxes from continuing operations (EBIT). On a segment basis, EBIT represents all profits from continuing operations (both operating and non-operating) before deducting interest and income taxes.
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Business Segment Data
| Total Revenues |
Segment EBIT/ Consolidated Earnings Before Income Taxes |
Depreciation and Amortization |
Capital and Investment Expenditures |
Segment/ Total Assets | |||||||||||
| (in millions) | |||||||||||||||
| 2009 |
|||||||||||||||
| Gas Transportation and Storage |
$ | 178.9 | $ | 96.7 | $ | 28.5 | $ | 20.3 | $ | 1,286.7 | |||||
| Other |
— | 56.9 | — | 36.7 | 525.8 | ||||||||||
| Total |
178.9 | 153.6 | 28.5 | 57.0 | 1,812.5 | ||||||||||
| Interest income |
— | 0.2 | — | — | — | ||||||||||
| Interest expense |
— | 16.7 | — | — | — | ||||||||||
| Total consolidated |
$ | 178.9 | $ | 137.1 | $ | 28.5 | $ | 57.0 | $ | 1,812.5 | |||||
| 2008 |
|||||||||||||||
| Gas Transportation and Storage |
$ | 124.9 | $ | 61.5 | $ | 26.3 | $ | 47.0 | $ | 977.7 | |||||
| Other |
— | 52.7 | — | 88.6 | 623.8 | ||||||||||
| Total |
124.9 | 114.2 | 26.3 | 135.6 | 1,601.5 | ||||||||||
| Interest income |
— | 3.5 | — | — | — | ||||||||||
| Interest expense |
— | 17.8 | — | — | — | ||||||||||
| Total consolidated |
$ | 124.9 | $ | 99.9 | $ | 26.3 | $ | 135.6 | $ | 1,601.5 | |||||
| 2007 |
|||||||||||||||
| Gas Transportation and Storage |
$ | 121.1 | $ | 64.2 | $ | 26.4 | $ | 30.4 | |||||||
| Other |
— | 52.4 | — | 28.3 | |||||||||||
| Total |
121.1 | 116.6 | 26.4 | 58.7 | |||||||||||
| Interest income |
— | 5.5 | — | — | |||||||||||
| Interest expense |
— | 17.1 | — | — | |||||||||||
| Total consolidated |
$ | 121.1 | $ | 105.0 | $ | 26.4 | $ | 58.7 | |||||||
Regulatory Assets. 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 | |||||||
| 2009 | 2008 | |||||||
| (in millions) | ||||||||
| Regulatory Assets(a)(b) |
||||||||
| Regulatory asset related to income taxes(c) |
$ | 8.6 | $ | 8.7 | (d) | |||
| Vacation accrual (non-current) |
1.6 | 1.3 | 2010 | |||||
| Deferred debt expense/premium(f) |
4.6 | — | (e) | |||||
| Fuel tracker(g) |
0.6 | — | 2010 | |||||
| Total Regulatory Assets |
$ | 15.4 | $ | 10.0 | ||||
| (a) | Included in Regulatory Assets and Deferred Debits, unless otherwise noted. |
| (b) | All regulatory assets are excluded from rate base unless otherwise noted. |
| (c) | All amounts are expected to be included in future rate filings. |
| (d) | Amortized over the life of the related property, plant and equipment. |
| (e) | Prepayment penalty being amortized over the life of the retired debt. |
| (f) | Included in rate base. |
| (g) | Included in Current Assets. |
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There were no regulatory liabilities as of December 31, 2009 or 2008.
Rate Related Information
East Tennessee. East Tennessee placed into effect new rates approved by the FERC in November 2005 as a result of a rate settlement with customers. The settlement agreement includes a five-year rate moratorium and certain operational changes and expires on October 31, 2010. Following the expiration of the settlement agreement, East Tennessee’s rates will remain the same, subject to further negotiation or a future rate proceeding.
Saltville. On September 1, 2008, Saltville placed into effect new rates approved by the FERC as a result of a settlement with customers associated with a rate proceeding. This settlement includes a rate moratorium until October 1, 2011. Following expiration of the moratorium, Saltville’s rates will remain the same, subject to further negotiation or a future rate proceeding. Also pursuant to the settlement, Saltville is required to file a rate case by October 1, 2013.
Gulfstream. Gulfstream operates under rates approved by the FERC in 2007. In June 2007, the FERC issued an order approving Gulfstream’s Phase III expansion project. That order also required Gulfstream to file a Cost and Revenue Study three years after the Phase III facilities go in service. The projected filing date would be the fall of 2011.
Ozark Gas Transmission. Ozark Gas Transmission operates under rates established as a result of an uncontested settlement agreement with customers approved by the FERC in 2000.
Management believes that the effects of these matters will not have a material adverse effect on our future consolidated results of operations, financial position or cash flows.
Income taxes with respect to our East Tennessee and Saltville operations were calculated by us in 2007 on the basis of their separate company income and deductions in accordance with established practices of Spectra Energy.
In conjunction with the contribution by Spectra Energy of the ownership of East Tennessee to us immediately prior to the IPO, $110.5 million of federal income tax liabilities outstanding at June 30, 2007 were eliminated and recorded as a benefit to Income Tax Expense (Benefit) on the Consolidated Statements of Operations. Effective July 2, 2007, as a result of our MLP structure, we are no longer subject to federal income taxes, but are still subject to Tennessee state income tax.
On April 4, 2008, we completed the Saltville acquisition from Spectra Energy. Accordingly, the income tax effects associated with Saltville’s operations prior to the acquisition are reflected in the Consolidated Statements of Operations. In addition, in the second quarter of 2008, in connection with the acquisition and the resulting change in tax status of Saltville, $2.5 million of deferred income tax liabilities were eliminated and recorded as a benefit to Income Tax Expense (Benefit).
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The following details the components of income tax expense (benefit):
| 2009 | 2008 | 2007 | |||||||||
| (in millions) | |||||||||||
| Current income taxes |
|||||||||||
| Federal(a) |
$ | — | $ | 0.3 | $ | 5.2 | |||||
| State |
— | 0.3 | 0.5 | ||||||||
| Total current income taxes |
— | 0.6 | 5.7 | ||||||||
| Deferred income taxes |
|||||||||||
| Federal(b) |
— | (2.0 | ) | (105.3 | ) | ||||||
| State |
1.2 | — | 1.7 | ||||||||
| Total deferred income taxes |
1.2 | (2.0 | ) | (103.6 | ) | ||||||
| Total income tax expense (benefit) |
$ | 1.2 | $ | (1.4 | ) | $ | (97.9 | ) | |||
| (a) | We were subject to federal income taxes prior to the formation of the MLP on July 2, 2007 and Saltville was subject to federal income taxes prior to the acquisition on April 4, 2008. |
| (b) | Includes a $2.5 million benefit in 2008 and a $110.5 million benefit in 2007 related to the elimination of accumulated deferred income tax liabilities. |
Reconciliation of Income Tax Expense at the U.S. Federal Statutory Tax Rate to Actual Tax Expense (Benefit)
| 2009 | 2008 | 2007 | ||||||||||
| (in millions) | ||||||||||||
| Income tax expense, computed at the statutory rate of 35% |
$ | 48.0 | $ | 35.0 | $ | 36.7 | ||||||
| State income tax, net of federal income tax effect(a) |
1.2 | 0.6 | 1.7 | |||||||||
| Entities not subject to income tax |
(48.0 | ) | (34.5 | ) | (25.8 | ) | ||||||
| Change in tax status |
— | (2.5 | ) | (110.5 | ) | |||||||
| Total income tax expense (benefit) |
$ | 1.2 | $ | (1.4 | ) | $ | (97.9 | ) | ||||
| Effective tax rate |
0.9 | % | (b) | (b) | ||||||||
| (a) | Includes federal income tax effects prior to the formation of the MLP. |
| (b) | Not meaningful. |
Net Deferred Income Tax Liability Components
| December 31, | ||||||||
| 2009 | 2008 | |||||||
| (in millions) | ||||||||
| State deferred income tax, net of federal tax effect |
$ | (10.0 | ) | $ | (8.8 | ) | ||
The above deferred tax amounts have been classified in the Consolidated Balance Sheets as Deferred Credits and Other Liabilities.
No material increases or decreases related to uncertain tax benefits were recorded in 2009, 2008 or 2007.
7. Net Income Per Limited Partner Unit and Cash Distributions
Following the adoption of a new accounting standard in January 2009, our calculation of net income per limited partner unit does not reflect an allocation of undistributed earnings to the IDR holders beyond amounts
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distributable to IDR holders under the terms of the partnership agreement. Prior to the new standard, the “two class” method of computing net income per limited partner unit was utilized whereby, we calculated net income per limited partner unit as if all the earnings for the period had been distributed, which resulted in an additional allocation of income to the general partner (the IDR holder) in quarterly periods where an assumed incentive distribution, calculated as if all earnings for the period had been distributed, exceeded the actual incentive distribution. We retrospectively applied the new standard to all periods presented and this application did not result in a material change in net income per limited partner unit for 2008 or 2007.
The following table presents our net income per limited partner unit calculations.
| 2009 | 2008 | 2007(a) | |||||||
| (in millions, except per-unit amounts) | |||||||||
| Net income |
$ | 135.9 | $ | 101.3 | $ | 202.9 | |||
| Less: |
|||||||||
| Net income attributable to predecessor operations |
— | 1.6 | 156.7 | ||||||
| General partner’s interest in net income — 2% |
2.7 | 2.0 | 0.9 | ||||||
| General partner’s interest in net income attributable to incentive distribution rights |
3.0 | 0.5 | — | ||||||
| Limited partners’ interest in net income |
$ | 130.2 | $ | 97.2 | $ | 45.3 | |||
| Weighted average limited partner units outstanding — basic and diluted |
76.4 | 69.4 | 66.2 | ||||||
| Net income per limited partner unit — basic and diluted |
$ | 1.71 | $ | 1.40 | $ | 0.68 | |||
| (a) | Net income per limited partner unit data for 2007 is only presented for the period since our IPO on July 2, 2007. |
The partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our Available Cash, as defined, to unitholders of record on the applicable record date.
Available Cash. Available Cash, for any quarter, consists of all cash on hand at the end of that quarter:
| • | less the amount of cash reserves established by the general partner to: |
| • | provide for the proper conduct of business, |
| • | comply with applicable law, any debt instrument or other agreement, or |
| • | provide funds for distributions to the unitholders and to the general partner for any one or more of the next four quarters, |
| • | plus, if the general partner so determines, all or a portion of cash on hand on the date of determination of Available Cash for the quarter. |
Subordinated Units. All of the subordinated units are held by wholly owned subsidiaries of Spectra Energy. The partnership agreement provides that, during the subordination period, the common unitholders have the right to receive distributions of Available Cash each quarter in an amount equal to $0.30 per common unit (the Minimum Quarterly Distribution), plus any arrearages in the payment of the Minimum Quarterly Distribution on the common units from prior quarters, before any distributions of Available Cash may be made on the subordinated units. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be Available Cash to be distributed on the common units. The subordination period will end on the first business day after we have earned and paid at least the Minimum Quarterly Distribution on each outstanding limited partner unit and general partner unit for any three consecutive, non-overlapping four quarter periods ending on or after June 30, 2010. The subordination period also will end upon the removal of our general partner other than for cause if the
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units held by our general partner and its affiliates are not voted in favor of such removal. When the subordination period ends, all remaining subordinated units will convert to common units, on a one-for-one basis, and the common units will no longer be entitled to arrearages.
Incentive Distribution Rights. The general partner holds incentive distribution rights in accordance with the partnership agreement as follows:
| Total Quarterly Distribution |
Marginal Percentage Interest in Distributions |
|||||||
| Target Per-Unit Amount |
Common and Subordinated Unitholders |
General Partner |
||||||
| Minimum Quarterly Distribution |
$0.30 | 98 | % | 2 | % | |||
| First Target Distribution |
up to $0.345 | 98 | % | 2 | % | |||
| Second Target Distribution |
above $0.345 up to $0.375 | 85 | % | 15 | % | |||
| Third Target Distribution |
above $0.375 up to $0.45 | 75 | % | 25 | % | |||
| Thereafter |
above $0.45 | 50 | % | 50 | % | |||
To the extent these incentive distributions are made to the general partner, there will be more Available Cash proportionately allocated to the general partner than to holders of common and subordinated units.
In 2007, we invested a portion of the proceeds from our IPO in financial instruments, including money market and debt securities that frequently had stated maturities of 20 years or more. These investments, which totaled $31.6 million as of December 31, 2008, were pledged as collateral against our term loan and were classified as Other Investments on the Consolidated Balance Sheet. There was no term loan outstanding or investments pledged as collateral at December 31, 2009. We received proceeds on sales of $31.6 million of these investments in 2009. We purchased $1,132.0 million and received proceeds on sales of $1,255.0 million of these investments in 2008, and purchased $1,439.0 million and received proceeds on sales of $1,284.4 million of these investments in 2007. Purchases and sales of available-for-sale securities are presented on a gross basis and are classified within Cash Flows from Investing Activities on the Consolidated Statements of Cash Flows.
The estimated fair values of long-term investments at December 31, 2008, classified as available-for-sale, are as follows:
| December 31, 2008 | |||||||||
| Gross Unrealized Holding Gains |
Gross Unrealized Holding Losses |
Estimated Fair Value | |||||||
| (in millions) | |||||||||
| Corporate debt securities |
$ | — | $ | — | $ | 24.7 | |||
| Money market funds |
— | — | 6.9 | ||||||
| Total long-term investments |
$ | — | $ | — | $ | 31.6 | |||
The average contractual maturity of the above securities was either less than one year at December 31, 2008 or the securities had been sold as of the date of this report.
9. Investments in Unconsolidated Affiliates
As of December 31, 2009, our investments in unconsolidated affiliates consisted of a 24.5% interest in Gulfstream and a 50% interest in Market Hub.
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In May 2009, Gulfstream issued $300.0 million aggregate principal amount of 6.95% Senior Notes due 2016. Net proceeds were distributed to its members based upon their ownership percentages, which resulted in the distribution of $72.7 million to us.
In 2009, we received total distributions of $109.1 million from Gulfstream. Of these distributions, $38.6 million were included in Cash Flows from Operating Activities — Distributions Received From Unconsolidated Affiliates and $70.5 million were included in Cash Flows from Investing Activities — Distributions Received From Unconsolidated Affiliates. We received distributions of $28.5 million in 2008 and $16.8 million in 2007, all which were included in Cash Flows from Operating Activities — Distributions Received From Unconsolidated Affiliates on the Consolidated Statements of Cash Flows.
We received distributions from Market Hub of $35.7 million in 2009, $43.2 million in 2008 and $5.9 million in 2007, which were included in Cash Flows from Operating Activities — Distributions Received From Unconsolidated Affiliates.
Our share of cumulative undistributed earnings of Market Hub totaled $151.3 million at December 31, 2009. Gulfstream had no cumulative undistributed earnings at December 31, 2009.
As of December 31, 2009 and 2008, the carrying amounts of Gulfstream and Market Hub approximated the amount of underlying equity in their respective net assets.
Investments in Unconsolidated Affiliates
| December 31, | ||||||
| 2009 | 2008 | |||||
| (in millions) | ||||||
| Gulfstream |
$ | 184.2 | $ | 253.3 | ||
| Market Hub |
352.1 | 320.0 | ||||
| Total |
$ | 536.3 | $ | 573.3 | ||
Equity in Earnings of Unconsolidated Affiliates
| 2009 | 2008 | 2007 | |||||||
| (in millions) | |||||||||
| Gulfstream |
$ | 30.4 | $ | 27.5 | $ | 23.5 | |||
| Market Hub |
40.3 | 33.9 | 32.1 | ||||||
| Total |
$ | 70.7 | $ | 61.4 | $ | 55.6 | |||
All of our goodwill is in our Gas Transportation and Storage segment. There were no changes in goodwill between December 31, 2007 and 2008. Changes in the balance of goodwill since December 31, 2008 follow (in millions):
| Balance at December 31, 2008 |
$ | 118.3 | |
| Increase due to the acquisition of NOARK(a) |
149.6 | ||
| Balance at December 31, 2009 |
$ | 267.9 | |
| (a) | See Note 2 for further discussion. |
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No impairments of goodwill were recorded in 2009, 2008 or 2007. Based on the results of our annual impairment testing, the fair value of our reporting unit at December 31, 2009 significantly exceeded its carrying value. See Note 1 for discussion of goodwill impairment testing and a change in 2009 of the goodwill impairment test date.
11. Property, Plant and Equipment
| Estimated Useful Life |
December 31, | |||||||||
| 2009 | 2008 | |||||||||
| (years) | (in millions) | |||||||||
| Plant |
||||||||||
| Natural gas transmission |
15-100 | $ | 976.7 | $ | 840.6 | |||||
| Storage |
17-35 | 114.5 | 113.9 | |||||||
| Gathering and processing facilities |
40 | 10.9 | — | |||||||
| Equipment |
5-15 | 5.8 | 3.9 | |||||||
| Vehicles |
3-5 | 3.4 | 2.7 | |||||||
| Land |
— | 2.3 | 2.1 | |||||||
| Construction in process |
— | 3.8 | — | |||||||
| Other |
5-50 | 6.9 | 6.4 | |||||||
| Total property, plant and equipment |
1,124.3 | 969.6 | ||||||||
| Total accumulated depreciation |
(179.0 | ) | (154.4 | ) | ||||||
| Total net property, plant and equipment |
$ | 945.3 | $ | 815.2 | ||||||
Substantially all of our property, plant and equipment is regulated with estimated useful lives based on rates approved by the FERC. Composite weighted-average depreciation rates were 2.8% for 2009, 2.8% for 2008 and 3.0% for 2007. We had no material capital leases at December 31, 2009 or December 31, 2008.
Summary of Debt and Related Terms
| Interest Rate | Year Due | December 31, | |||||||||||
| 2009 | 2008 | ||||||||||||
| (in millions) | |||||||||||||
| East Tennessee notes payable |
5.71 | % | 2012 | $ | 150.0 | $ | 150.0 | ||||||
| Credit facility — revolving(a) |
0.59 | % | 2012 | 240.0 | 209.0 | ||||||||
| Credit facility — term (b) |
— | — | — | 31.0 | |||||||||
| Note payable — affiliate(a) |
0.23 | % | 2012 | 27.5 | 50.0 | ||||||||
| Total debt |
417.5 | 440.0 | |||||||||||
| Note payable — affiliate(c) |
(27.5 | ) | (50.0 | ) | |||||||||
| Total long-term debt |
$ | 390.0 | $ | 390.0 | |||||||||
| (a) | Unsecured borrowings bearing interest based on a one-month London InterBank Offering Rate. |
| (b) | Secured by $31.6 million of investments classified as Other Investments on the Consolidated Balance Sheet. |
| (c) | This note is payable on demand to Market Hub and therefore classified as current. Net repayments were $22.5 million in 2009. |
All scheduled debt repayments are in 2012, corresponding to the year due for all outstanding long-term debt instruments. 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.
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East Tennessee’s debt agreement contains financial covenants which limit the amount of debt that can be outstanding as a percentage of total capital. Failure to maintain the covenants could require East Tennessee to immediately pay down the outstanding balance. As of December 31, 2009, East Tennessee was in compliance with those covenants. In addition, the debt agreement allows for acceleration of payments or termination of the agreements due to nonpayment, or to the acceleration of other significant indebtedness of the borrower or some of its subsidiaries, if any. The debt agreement does not contain provisions that trigger an acceleration of indebtedness based solely on the occurrence of a material adverse change in our financial condition or results of operations.
| Credit Facility Summary |
Expiration Date |
Credit Facility Capacity |
Outstanding as of December 31, 2009 | |||||
| Revolving Credit | ||||||||
| (in millions) | ||||||||
| Spectra Energy Partners, LP |
2012 | $ | 500.0 | $ | 240.0 | |||
Effective as of July 2, 2007, we entered into a five-year $500.0 million credit agreement that included both term and revolving borrowing capacity, of which we borrowed $194.0 million of term borrowings and $125.0 million of revolving borrowings upon the closing of the IPO. The term loans were repaid in 2008 and 2009 and that feature of the credit facility is no longer available.
The credit facility prohibits us from making distributions of Available Cash to unitholders if any default or event of default, as defined, exists. In addition, the credit facility contains covenants, among others, limiting our ability to make other restricted distributions or dividends on account of the purchase, redemption, retirement, acquisition, cancellation or termination of partnership interests, and is also subject to certain financial covenants. These financial covenants include financial leverage and interest coverage ratios. The terms of the credit agreement require us to maintain a ratio of total debt to Adjusted Earnings Before Interest, Taxes, Depreciation and Amortization (EBITDA), as defined in the credit agreement, of 5.0 or less. The terms of the credit agreement also require us to maintain a ratio of Adjusted EBITDA, to interest expense of 2.5 or greater. As of December 31, 2009, we were in compliance with those covenants. The credit facility 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.
On May 4, 2009, as part of the NOARK acquisition, we borrowed $70.0 million under a credit facility with a subsidiary of Spectra Energy. This borrowing carried interest at an annual rate of 9.75%. We repaid the $70.0 million and the associated interest payable on May 27, 2009 with the proceeds from our sale of common units and the credit facility was terminated. See Note 17 for further discussion on the sale of common units.
The following table presents, for each of the fair value hierarchy levels, assets and liabilities that are measured at fair value on a recurring basis:
| Description |
Consolidated Balance Sheet Caption |
December 31, 2009 | ||||||||||||
| Total | Level 1 | Level 2 | Level 3 | |||||||||||
| (in millions) | ||||||||||||||
| Interest rate swap liabilities |
Current liabilities — other |
$ | 0.4 | $ | — | $ | 0.4 | $ | — | |||||
| Interest rate swap liabilities |
Deferred credits and other liabilities — other |
0.4 | — | 0.4 | — | |||||||||
| Interest rate swap liabilities |
Deferred credits and other liabilities — other — affiliates |
4.8 | — | 4.8 | — | |||||||||
| Total Liabilities |
$ | 5.6 | $ | — | $ | 5.6 | $ | — | ||||||
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| Description |
Consolidated Balance Sheet Caption | December 31, 2008 | ||||||||||||
| Total | Level 1 | Level 2 | Level 3 | |||||||||||
| (in millions) | ||||||||||||||
| Corporate debt securities |
Other investments | $ | 24.7 | $ | — | $ | 24.7 | $ | — | |||||
| Money market funds |
Other investments | 6.9 | 6.9 | — | — | |||||||||
| Total Assets |
$ | 31.6 | $ | 6.9 | $ | 24.7 | $ | — | ||||||
| Interest rate swap liabilities |
Deferred credits and other liabilities — other — affiliates |
$ | 5.6 | $ | — | $ | 5.6 | $ | — | |||||
| Total Liabilities |
$ | 5.6 | $ | — | $ | 5.6 | $ | — | ||||||
Level 1. Level 1 valuations represent quoted unadjusted prices for identical instruments in active markets.
Level 2 Valuation Techniques. Fair values of our financial instruments, which primarily include interest rate swaps, and previously held corporate debt securities that were actively traded in the secondary market, are determined based on market-based prices. These valuations may include inputs such as quoted market prices of the exact or similar instruments or alternative pricing sources that may include models or matrix pricing tools, with reasonable levels of price transparency.
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. Estimates determined as of December 31, 2009 and 2008 are not necessarily indicative of the amounts we could have realized in current markets.
| December 31, 2009 | December 31, 2008 | |||||||||||
| Book Value |
Approximate Fair Value |
Book Value |
Approximate Fair Value | |||||||||
| (in millions) | ||||||||||||
| Long-term debt |
$ | 390.0 | $ | 394.5 | $ | 390.0 | $ | 381.9 | ||||
| Corporate debt securities and money market funds |
— | — | 31.6 | 31.6 | ||||||||
The fair values of long-term debt consider the terms of the related debt absent the impacts of hedging activities. The fair value of cash and cash equivalents, accounts receivable, accounts payable and note payable — affiliates are not materially different from their carrying amounts because of the short-term nature of these instruments or because the stated rates approximate market rates.
During 2009 and 2008, there were no adjustments to assets and liabilities measured at fair value on a nonrecurring basis.
East Tennessee has a long-term customer contract that began in 2002 with billed amounts that decline annually over the term of the contract. The revenues billed annually over the 20 year term of the contract range from $9.9 million to $6.2 million. The annual amount of revenue recognized is $9.4 million, with the difference deferred in Other within Deferred Credits and Other Liabilities on the accompanying Consolidated Balance Sheets. The deferred revenue for this contract was $2.9 million as of December 31, 2009 and $2.7 million as of December 31, 2008.
15. 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
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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 regulations regarding air and water quality, hazardous and solid waste disposal and other environmental matters. We believe there are no matters outstanding that upon resolution will have a material adverse effect on our consolidated results of operations, financial position or cash flows.
Litigation. We are involved in legal, tax and regulatory proceedings in various forums, including matters regarding contracts, performance and other matters, arising in the ordinary course of business, some of which involve substantial monetary amounts. We have insurance coverage for certain of these losses should they be incurred. We believe that the final disposition of these proceedings will not have a material adverse effect on our consolidated results of operations, financial position or cash flows.
Leases. We lease assets in several areas of operations. Rental expense for these leases was $1.9 million in 2009, $2.0 million in 2008 and $2.0 million in 2007. Future minimum rental payments under operating leases are $0.1 million for each year from 2010 through 2014.
16. Risk Management and Hedging Activities
Interest Rate (Cash Flow) Hedges. Changes in interest rates expose us to risk as a result of our issuance of variable and fixed-rate debt. We manage our interest rate exposure by limiting our variable-rate exposures and by monitoring the effects of market changes in interest rates. We also enter into financial derivative instruments, including, but not limited to, interest rate swaps to manage and mitigate interest rate risk exposure.
Derivative Portfolio Carrying Value as of December 31, 2009
| Description |
Maturity in 2010 |
Maturity in 2011 |
Maturity in 2012 |
Maturity in 2013 and Thereafter |
Total Carrying Value | ||||||||||
| (in millions) | |||||||||||||||
| Interest rate swap liabilities |
$ | 0.4 | $ | 4.8 | $ | 0.4 | $ | — | $ | 5.6 | |||||
The amounts in the table above represent the liabilities for unrealized gains and losses on mark-to-market and hedging transactions on our Consolidated Balance Sheet and do not include derivative positions of our equity investments.
See Note 13 for information regarding the presentation of these derivative positions on our Consolidated Balance Sheets.
In June 2008, we entered into a series of two and three-year interest rate swap agreements with Spectra Energy to mitigate our exposure to variable interest rates on $140.0 million of loans outstanding under the revolving credit facility. In February 2009, we entered into a series of three-year interest rate swap agreements with third parties to mitigate our exposure to variable interest rates on $40.0 million of loans outstanding under the revolving credit facility. As of December 31, 2009, the total notional amount of our interest rate swaps was $180.0 million. These interest rate swaps were designated as effective cash flow hedges. Through December 31, 2009, these hedges resulted in no ineffectiveness, and unrealized net losses on the agreements have been deferred in AOCI in the Consolidated Balance Sheets. It is estimated that $4.5 million of losses reported in AOCI at December 31, 2009 will be reclassified into earnings during the next 12 months.
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The effective portion of gains (losses) recognized in Other Comprehensive Income follows:
| Cash Flow Hedging Derivatives |
2009 | 2008 | 2007 | ||||||||
| (in millions) | |||||||||||
| Interest rate swaps |
$ | (4.9 | ) | $ | (6.2 | ) | $ | — | |||
The reclassifications from Other Comprehensive Income into income on derivatives follow:
| Cash Flow Hedging Derivatives |
Consolidated Statements of Operations Caption |
2009 | 2008 | 2007 | ||||||||
| (in millions) | ||||||||||||
| Interest rate swaps |
Interest expense | $ | 4.9 | $ | 0.5 | $ | (0.3 | ) | ||||
Credit Risk. Our principal customers for natural gas transportation, storage and gathering services are industrial end-users, marketers, exploration and production companies, local distribution companies and utilities located primarily throughout the southern and southeastern United States. We have concentrations of receivables from natural gas utilities and their affiliates, industrial customers and marketers throughout these regions. These concentrations of customers may affect our overall credit risk in that risk factors can negatively affect the credit quality of the entire sector. Where exposed to credit risk, we analyze the counterparties’ financial condition prior to entering into an agreement, establish credit limits and monitor the appropriateness of those limits on an ongoing basis. We also obtain cash, letters of credit or other acceptable forms of security from customers to provide credit support, where appropriate, based on our financial analysis of the customer and the regulatory or contractual terms and conditions applicable to each transaction.
In the second quarter of 2009, we issued 9.8 million common units to the public, representing limited partner interests, and 0.2 million general partner units to Spectra Energy, and received net proceeds of $212.2 million. As further discussed in Note 2 and Note 12, we used the net proceeds from the offering to repay $142.2 million drawn on our available bank credit facility and $70.0 million drawn on the credit facility with a subsidiary of Spectra Energy.
Phantom units are granted under a Long-Term Incentive Plan to certain employees of Spectra Energy and vest over three years. We awarded 10,000 common phantom units in 2009, 5,000 units in 2008 and 120,500 units in 2007. The total fair value of the units vested was not significant in 2009, 2008 and 2007.
| Phantom Unit Awards |
|||
| (in thousands) | |||
| Outstanding at December 31, 2008 |
74 | ||
| Granted |
10 | ||
| Vested |
(2 | ) | |
| Forfeited |
(1 | ) | |
| Outstanding at December 31, 2009 |
81 | ||
| Awards expected to vest |
69 | ||
We account for the phantom units as liability awards. Compensation expense for these awards of $2.2 million was recorded in 2009. As of December 31, 2009 and assuming no change in fair value, we expect to recognize $0.5 million of future compensation cost related to phantom awards in 2010.
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19. Quarterly Financial Data (Unaudited)
Our consolidated results of operations by quarter for the years ended December 31, 2009 and 2008 were as follows:
| First Quarter |
Second Quarter |
Third Quarter |
Fourth Quarter |
Total | |||||||||||
| (in millions, except per-unit amounts) | |||||||||||||||
| 2009 |
|||||||||||||||
| Operating revenues |
$ | 35.6 | $ | 41.3 | $ | 49.8 | $ | 52.2 | $ | 178.9 | |||||
| Operating income |
16.0 | 20.7 | 26.1 | 20.0 | 82.8 | ||||||||||
| Net income |
28.5 | 33.6 | 40.4 | 33.4 | 135.9 | ||||||||||
| Net income per limited partner unit(a) |
0.39 | 0.44 | 0.48 | 0.39 | 1.71 | ||||||||||
| 2008 |
|||||||||||||||
| Operating revenues |
$ | 32.5 | $ | 29.7 | $ | 29.5 | $ | 33.2 | $ | 124.9 | |||||
| Operating income |
15.7 | 13.0 | 10.3 | 12.9 | 51.9 | ||||||||||
| Net income |
24.1 | 27.5 | 24.3 | 25.4 | 101.3 | ||||||||||
| Net income per limited partner unit(a) |
0.33 | 0.38 | 0.34 | 0.35 | 1.40 | ||||||||||
| (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. |
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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, 2009: |
|||||||||||||||
| Allowance for doubtful accounts |
$ | 0.5 | $ | — | $ | — | $ | 0.4 | $ | 0.1 | |||||
| Other |
— | — | — | — | — | ||||||||||
| $ | 0.5 | $ | — | $ | — | $ | 0.4 | $ | 0.1 | ||||||
| December 31, 2008: |
|||||||||||||||
| Allowance for doubtful accounts |
$ | 0.3 | $ | 0.3 | $ | — | $ | 0.1 | $ | 0.5 | |||||
| Other(b) |
1.7 | — | — | 1.7 | — | ||||||||||
| $ | 2.0 | $ | 0.3 | $ | — | $ | 1.8 | $ | 0.5 | ||||||
| December 31, 2007: |
|||||||||||||||
| Allowance for doubtful accounts |
$ | 0.3 | $ | 0.1 | $ | — | $ | 0.1 | $ | 0.3 | |||||
| Other(b) |
5.0 | — | — | 3.3 | 1.7 | ||||||||||
| $ | 5.3 | $ | 0.1 | $ | — | $ | 3.4 | $ | 2.0 | ||||||
| (a) | Principally cash payments and reserve reversals. |
| (b) | Principally a right-of-way dispute. |
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, 2009, and, based upon this evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that these controls and procedures are effective.
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, 2009 and found no change that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.
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Management’s Annual Report on Internal Control over Financial Reporting
The report of management required under this Item 9A is contained in Item 8. Financial Statements and Supplementary Data, Management’s Annual Report on Internal Control over Financial Reporting.
Attestation Report of Independent Registered Public Accounting Firm
The attestation report required under this Item 9A is contained in Item 8. Financial Statements and Supplementary Data, Report of Independent Registered Public Accounting Firm.
None.
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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 nine members, four of whom are independent as defined under the independence standards established by the New York Stock Exchange (NYSE). The NYSE does not require a listed limited partnership to have a majority of independent directors on its general partner’s Board of Directors or to establish a compensation committee or a nominating committee. However, the Board of Directors of the General Partner has established an audit committee (the Audit Committee) and a conflicts committee (the Conflicts Committee) to address conflict situations, each consisting of Steven D. Arnold, Stewart A. Bliss, Nora Mead Brownell and J.D. Woodward, III.
The Board of Directors of the General Partner annually review the independence of directors and affirmatively makes a determination that each director expected to be independent has no material relationship with the General Partner, either directly or indirectly as a partner, unitholder or officer of an organization that has a relationship with the General Partner. The members of the Audit Committee and Conflicts Committee each meet the independence and experience standards established by the NYSE and the Exchange Act, as amended, to serve on an audit committee of a board of directors.
The officers of the General Partner manage the day-to-day affairs of our business. All of our executive management personnel are employees of Spectra Energy and devote a portion of their time to our business and affairs. We also utilize a significant number of employees of Spectra Energy to operate our business and provide general and administrative services. We reimburse Spectra Energy for allocated expenses of operational personnel who perform services for our benefit and for allocated general and administrative expenses.
The General Partner does not receive any management fee or other compensation for its management of our partnership under the omnibus agreement with Spectra Energy (Omnibus Agreement) or otherwise. Under the terms of the Omnibus Agreement, we reimburse Spectra Energy up to $3.0 million annually for the provision of various general and administrative services for our benefit, which amount is adjusted for inflation until July 2010. We also reimburse Spectra Energy for direct expenses incurred on our behalf and expenses allocated to us as a result of becoming a public entity. The partnership agreement provides that the General Partner will determine the expenses that are allocable to us.
Meeting Attendance and Preparation
Members of the General Partner’s Board of Directors attended at least 75% of regular board meetings and meetings of the committees on which they serve, either in person or telephonically. In addition, directors are expected to be prepared for each meeting of the board by reviewing materials distributed in advance.
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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 J. Rizzo |
53 | President, Chief Executive Officer and Director | ||
| Laura Buss Sayavedra |
42 | Vice President and Chief Financial Officer | ||
| Fred J. Fowler |
64 | Chairman | ||
| Steven D. Arnold |
49 | Director | ||
| Stewart A. Bliss |
76 | Director | ||
| Nora Mead Brownell |
63 | Director | ||
| Patrick J. Hester |
59 | Director | ||
| Theopolis Holeman |
60 | Director | ||
| R. Mark Fiedorek |
47 | Director | ||
| J.D. Woodward, III |
60 | 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 J. Rizzo was elected to the Board of Directors of Spectra Energy Partners GP, LLC in May 2007 and was named President and Chief Executive Officer in December 2008. He also serves as Group Vice President of U.S. Regulatory Affairs for Spectra Energy Corp, which was spun off from Duke Energy Corporation and has done so since January 2007. Mr. Rizzo previously served as Group Vice President for Duke Energy Gas Transmission — Northeast Pipelines from March 2004 until assuming his current position. Prior to then, Mr. Rizzo served as Executive Vice President of Duke Energy Gas Transmission from February 2003 until March 2004; and Senior Vice President Marketing and Capacity Management from March 2002 until February 2003. Mr. Rizzo was first elected to serve as a director because of his experience serving Spectra Energy Corp in leadership roles in the areas of marketing, pricing, regulatory affairs, risk management and systems planning.
Laura Buss Sayavedra was named to her current position in May 2008. Prior to that, she was Vice President, Strategic Development and Analysis for Spectra Energy Corp, which was spun off from Duke Energy Corporation. She previously served at Duke Energy Gas Transmission as General Manager, Strategic Planning and Development from July 2005 to December 2006. Prior to then, she served as Vice President, Operations and Analytics of Duke Energy North America from May 2004 to June 2005 and Senior Director of Energy Marketing from January 2003 to April 2004.
Fred J. Fowler was elected to the Board of Directors of Spectra Energy Partners GP, LLC as its Chairman in December 2008. He retired as President and Chief Executive Officer of Spectra Energy Corp in December 2008, a position he held since its inception in January 2007. Mr. Fowler previously served as Group Executive and President of Duke Energy Gas Transmission from April 2006. Prior to then, he was President and Chief Operating Officer in November 2002 to April 2006. Mr. Fowler was elected to the board of EnCana Corp effective February 1, 2010. Mr. Fowler was elected serve as a director because of his extensive knowledge and experience of the energy industry and its participants, as well as a deep understanding of our assets, customers and regulatory environments.
Steven D. Arnold was elected to the Board of Directors of Spectra Energy Partners GP, LLC in May 2007 and serves on the Audit Committee and on the Conflicts Committee as Chairman. Mr. Arnold is engaged in private investment management and consulting services in Houston, Texas through 3 Lights Management Co., serving as its President since inception in 2000. Mr. Arnold currently serves on the Advisory Boards of Avalon Advisors, LP, in Texas and Alliance Real Estate Value Funds in Colorado. Mr. Arnold was elected to serve as a director because of his financial expertise. Mr. Arnold brings a strong risk assessment and strategic expertise to the board.
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Stewart A. Bliss was elected to the Board of Directors of Spectra Energy Partners GP, LLC in June 2007 and chairs the Audit Committee and serves on the Conflicts Committee. Mr. Bliss has been an independent financial consultant and senior business advisor in Denver, Colorado for many years, with expertise that also includes mergers and acquisitions. In early 2007, he served as interim director of the Colorado Department of Economic Development and International Trade. Mr. Bliss was a senior advisor with Green Manning & Bunch, Ltd., a Denver-based investment banking firm from 2000 until 2007. Until 2007, he served as lead director and chair of the audit committee on Kinder Morgan Inc.’s Board of Directors. Mr. Bliss currently serves as a member of the Colorado Commission on Judicial Discipline, is a Trustee of The Colorado School of Mines and a member of the board of The Colorado History Museum/Colorado Justice Center Building, Inc. Mr. Bliss was elected to serve as a director because he brings knowledge and experience of the energy industry as well as valuable knowledge on public company governance and audit issues.
Nora Mead Brownell was elected to the Board of Directors of Spectra Energy Partners GP, LLC in May 2007 and serves on our Audit Committee and the Conflicts Committee. In May 2001, Ms. Brownell was confirmed as Commissioner of the Federal Energy Regulatory Commission where she served until the expiration of her term in June 2006. Ms. Brownell also currently serves on the Board of Directors of Comverge, Inc., an energy technology company and ONCOR, a regulated electric distribution and transmission company. Ms. Brownell is co-founder and principal of ESPY Solutions, a woman-owned-business offering strategic consulting. Ms. Brownell was elected to serve as a director because she brings a diverse background that includes experience in business and the regulatory arenas.
Patrick J. Hester was elected to the Board of Directors of Spectra Energy Partners GP, LLC in October 2008. He also serves as interim General Counsel for Spectra Energy Corp and Associate General Counsel for Spectra Energy Corp’s Northeast region. Mr. Hester previously served as Vice President, Project Management and Development for Duke Energy Gas Transmission from 2005 until he assumed his current position. Previously he was General Counsel for Duke Energy Gas Transmission from 2003. Mr. Hester was elected a director because of his engineering and project expertise in the gas transportation business. He brings a strong operational, legal and regulatory expertise to the Board.
Theopolis Holeman was elected to the Board of Directors of Spectra Energy Partners GP, LLC in September 2009. Mr. Holeman was named Group Vice President of Spectra Energy Corp’s U.S. Operations in October 2008, and is responsible for storage and operations, environmental health and safety and procurement. Previously, Mr. Holeman served as Group Vice president of Power Delivery for Duke Energy Corporation. Mr. Holeman brings a strong operational expertise to the Board.
R. Mark Fiedorek was elected to the Board of Directors of Spectra Energy Partners GP, LLC in December 2008. He also serves as Group Vice President of Spectra Energy Corp’s U.S. Transmission and Storage — Southeast. He previously served as Vice President of Asset Optimization and Marketer Services since 2002 until 2007 when he was named to his current position with Spectra Energy Corp. Mr. Fiedorek was elected as a director because he has served in a variety of senior positions at Spectra Energy Corp focusing on the natural gas transmission business, primarily in the supply, operations and marketer services areas.
J.D. Woodward, III was elected to the board in September 2009. Mr. Woodward is President of Woodward Development Inc., a real estate and energy investment firm and a managing member of Woodward-Apple Springs, LLC, an owner and operator of natural gas midstream assets in East Texas. He retired in 2006 from Atmos Energy as Senior Vice President of Non-Utility Operations. Mr. Woodward was selected to serve as a director because he understands the operations of a large corporation, with a particular focus on customer issues. Mr. Woodward is an experienced senior executive with sound business experience.
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 SEC and the NYSE initial reports of ownership and reports of changes in ownership of our common units and other equity securities.
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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 2009.
Audit Committee
The Board of Directors of the General Partner has a standing audit committee composed of Steven D. Arnold, Stewart A. Bliss, Nora Mead Brownell and J.D. Woodward, III, each of whom is able to understand fundamental financial statements and at least one of whom has past experience in accounting or related financial management experience. The Board has determined that each member of the Audit Committee is independent under Section 303A.02 of the NYSE listing standards and Section 10A(m)(3) of the Exchange Act, as amended. In making the independence determination, the Board considered the requirements of the NYSE. The Audit Committee has adopted a charter, which has been ratified and approved by the Board of Directors.
Mr. Bliss has been designated by the Board of Directors as the Audit Committee’s financial expert meeting the requirements promulgated by the SEC based upon his education and employment experience as more fully detailed in Mr. Bliss’s biography set forth above.
The Audit Committee assists the Board of Directors in its oversight of the integrity of our financial statements and compliance with legal and regulatory requirements and corporate policies and controls. The Audit Committee has the sole authority to retain and terminate our independent registered public accounting firm, approve all auditing services and related fees and terms thereof, and pre-approve any non-audit services to be rendered by our independent registered public accounting firm. The Audit Committee is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm has unrestricted access to the Audit Committee.
Conflicts Committee
The Board of Directors has a standing Conflicts Committee, which is comprised of Steven D. Arnold, Stewart A. Bliss, Nora Mead Brownell and J.D. Woodward, III. The Conflicts Committee reviews specific matters that the Board of Directors believes may involve conflicts of interest. The Conflicts Committee will determine if the resolution of the conflict of interest is in the best interest of our partnership. The members of the Conflicts Committee may not be officers, employees or security holders of the General Partner, or directors, officers or employees of its affiliates. Any matters approved by the Conflicts Committee in good faith will be conclusively deemed to be fair and reasonable to us, approved by all of our partners, and not a breach by the General Partner of any duties it may owe us or our unitholders.
Principles for Corporate Governance and Code of Business Ethics
We have adopted Corporate Governance Guidelines that outline the important policies and practices regarding our governance. We have also adopted a Code of Business Ethics applicable to the persons serving as the General Partner’s directors and Spectra Energy has adopted a Code of Business Ethics applicable to persons serving as the General Partner’s officers, all of whom are employees of Spectra Energy.
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.
Communications by Unitholders
Unitholders and other interested parties may communicate with any and all members of the Board of Directors, including nonmanagement 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
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Directors at the following address and fax number; Name of the Director(s), c/o President, Spectra Energy Partners, LP, 5400 Westheimer Court, Houston, Texas 77056 fax: (713) 989-1818.
Report of the Audit Committee
The Audit Committee oversees our financial reporting process on behalf of the Board of Directors. Management has the primary responsibility for the financial statements and the reporting process including the systems of internal controls. The Audit Committee operates under a written charter approved by the Board of Directors. The charter, among other things, provides that the Audit Committee has authority to appoint, retain and oversee the independent auditor and is available on our website at www.spectraenergypartners.com/investorrelations/governance.
In this context, the Audit Committee:
| • | reviewed and discussed the audited financial statements in this annual report on Form 10-K with management, including a discussion of the quality, not just the acceptability, of the accounting principles, the reasonableness of significant judgments and the clarity of disclosures in the financial statements; |
| • | reviewed with Deloitte & Touche, LLP, our independent auditors, who are responsible for expressing an opinion on the conformity of the audited financial statements with generally accepted accounting principles, their judgments as to the quality and acceptability of our accounting principles and such other matters as are required to be discussed with the Audit Committee under generally accepted auditing standards; |
| • | received the written disclosures and the letter required by applicable requirements of the Public Company Accounting Oversight Board regarding Deloitte’s communications with the audit committee concerning independence from Spectra Energy Partners and its subsidiaries, and has discussed with Deloitte the firm’s independence; |
| • | discussed with Deloitte & Touche, LLP the matters required to be discussed by Statement on Auditing Standards No. 61, as amended (AICPA, Professional Standards, Vol. 1. AU section 380), as adopted by the Public Company Accounting Oversight Board in Rule 3200T; |
| • | discussed with Spectra Energy’s internal auditors and Deloitte & Touche, LLP the overall scope and plans for their respective audits. The Audit Committee meets with the internal auditors and Deloitte & Touche, LLP, with and without management present, to discuss the results of their examinations, their evaluations of our internal controls and the overall quality of our financial reporting; |
| • | based on the foregoing reviews and discussions, recommended to the Board of Directors that the audited financial statements be included in the annual report on Form 10-K for the year ended December 31, 2009, for filing with the SEC; and |
| • | approved the selection and appointment of Deloitte & Touche, LLP to serve as our independent auditors. |
This report has been furnished by the members of the Audit Committee of the Board of Directors:
Audit Committee
Steven D. Arnold
Stewart A. Bliss
Nora Mead Brownell
J.D. Woodward, III
March 11, 2010
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.
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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 discussion and analysis is intended to provide information about the objectives and policies regarding compensation for the officers of the general partner of our partnership listed in the Summary Compensation Table. We do not directly employ any of the persons responsible for managing our business and we do not have a compensation committee. We are managed by our general partner, the executive officers of which are employees of Spectra Energy. Our reimbursement for the compensation of executive officers is governed by the Omnibus Agreement and is generally based on time allocated to us during a period.
Compensation paid or awarded by us in 2009 to our Chief Executive Officer (our principal executive officer) and our Chief Financial Officer (our principal financial officer, and together with our principal executive officer, our “named executive officers”) reflects the total compensation paid by Spectra Energy, which includes compensation that is allocated to us pursuant to Spectra Energy’s allocation methodology and subject to the terms of the Omnibus Agreement. The Compensation Committee of Spectra Energy (Compensation Committee) has ultimate decision making authority with respect to the compensation of our named executive officers other than with respect to awards of equity in our partnership, for which our Board retains control. The elements of compensation discussed below, other than our partnership equity based compensation, and Spectra Energy’s decisions with respect to determinations on payments, was not subject to approvals by the Board of Directors of our general partner. Compensation of our executive officers was approved by the Compensation Committee of the Board of Directors of Spectra Energy or its delegate. 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.
With respect to compensation objectives and decisions regarding our named executive officers for 2009, the Compensation Committee approved the cash compensation, and recommended equity based compensation, of our named executive officers based on its compensation philosophy, which is to reward both continued employment and performance through a combination of short-term bonus incentives and long-term equity compensation. Senior management of Spectra Energy typically 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 2009 compensation for the named executive officers in a manner consistent with its current compensation philosophy. All compensation determinations are discretionary and are, as noted above, subject to Spectra Energy’s decision-making authority.
The elements of Spectra Energy’s compensation program discussed below are intended to provide a compensation package designed to drive performance and reward contributions in support of the business strategies of Spectra Energy and its affiliates at the corporate, partnership and individual levels. Accordingly, a significant portion of the compensation provided to our executive officers has been in the form of short-term and long-term incentives.
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Committee Advisors
The Compensation Committee has engaged ExeQuity, LLP, an independent consulting firm, to report directly to the Compensation Committee with respect to matters related to executive compensation, best practices and analysis of meeting materials prepared by management. ExeQuity generally confers with the Chair of the Compensation Committee and the Compensation Committee itself and discusses compensation matters with management on a limited basis. In addition, ExeQuity meets with the Committee in executive session without the presence of management following each meeting. ExeQuity performs no other services for Spectra Energy other than its services as independent consultant to the Compensation Committee.
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 motivating well qualified executives.
The following table sets forth the principal components of compensation for our named executive officers:
| Component |
Description |
Rationale | ||
| Salary | Compensation paid in cash throughout the year. | Provides compensation for performing day-to-day responsibilities. | ||
| Short-Term Incentive | Annual cash payment based on the achievement of defined financial and individual performance goals. | Makes significant percentage of cash compensation contingent on specific financial targets and individual 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 units and phantom awards. | Rewards long-term company performance, establishes economic alignment of executives with unitholders, 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 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 motivated through our compensation programs to successfully execute our long term objectives. We believe that hiring objectives cannot be achieved unless we offer compensation opportunities that are competitive in the marketplace. Accordingly, we use comparable market median data as a starting point for determining the adequacy of the compensation opportunities provided to our executives. The Compensation Committee considers market trends from general industry survey data. Specifically, the Compensation Committee has chosen to use the Towers Perrin 2009 Compensation Data Base© General Industry Survey as a source of market information because the Committee believes that the survey provides a reliable indication of compensation practices in companies that are comparable in size as measured by revenues.
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External Market Conditions and Individual Factors. In addition to using benchmark survey data, the Compensation Committee also takes into account external market conditions and individual factors when establishing the total compensation of each named executive officer. Some of these factors include the executive’s level of experience, the executive’s tenure and responsibilities, the executive’s position, competitive pressures for that position within the industry, economic developments, the condition of labor markets and the financial and market performance of the Company.
Risk Assessment of Total Compensation. The overall compensation mix of short-term and long-term compensation opportunities for our executives, as well as the components of these incentive opportunities are balanced to mitigate undue risk. No single measure of the short-term compensation program is greater than 25% of an individual’s targeted award. Half of each executive’s long-term opportunity is contingent on the performance of Spectra Energy’s stock relative to its peers and stock ownership levels are required by each executive.
2009 Compensation Opportunities
The following table shows the 2009 target direct pay opportunities for our named executive officers.
2009 Target Pay Opportunity
| Name |
Salary | Short-Term Incentive Target Opportunity |
Long-Term Incentive Target Opportunity |
Total Target Pay Opportunity | ||||||||
| Gregory J. Rizzo |
$ | 315,188 | 50 | % | 100 | % | $ | 787,970 | ||||
| Laura Buss Sayavedra |
$ | 205,000 | 40 | % | 50 | % | $ | 389,500 | ||||
Salary. At the beginning of 2009, the Compensation Committee considered whether adjustments to salaries were appropriate and adjusted salaries of the named executive officers at that time, based upon job responsibilities, level of experience, individual performance, comparisons to the salaries of executives in similar positions obtained from market surveys and internal comparisons. The Compensation Committee approved salary adjustments for Mr. Rizzo and other members of Spectra Energy management approved salary adjustments for Ms. Sayavedra.
Short-Term Incentives. Short-term incentive opportunities, awarded under the Spectra Energy Executive Short-Term Incentive (STI) Plan for 2009, were designed to compensate executives for individual and company performance during the year based on goals set at the beginning of the year. The threshold, target and maximum incentive opportunities for each participant in the STI Plan during 2009 were established as a percentage of base salary. Bonuses were earned based on the achievement of individual, corporate and/or business unit goals as determined by the Compensation Committee. Target STI awards expressed as a percentage of base annual salary for our named executive officers in 2009 are reflected in the “2009 Target Pay Opportunity” table above.
Under guidelines adopted for the 2009 STI program, participants were eligible to receive up to 190% of the amount of their STI target, depending on actual performance. Up to 200% of the target bonus amount contingent on financial or operational measures could be paid if performance at a specified maximum level was achieved. The maximum that could be earned for performance on individual measures was 150% of target. The amount that could be paid for performance at a specified minimum level for any measure was 50% of the target amount. 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 individual goals and financial objectives related to management responsibilities for Spectra Energy and Spectra Energy Partners. The STI payments were based on the achievement of individual goals and financial objectives including Spectra Energy’s Ongoing Earnings per Share (EPS), Spectra Energy Transmission, LLC (Spectra Energy Transmission) Earnings Before Interest and Taxes (EBIT), Spectra Energy Transmission Return on Capital Employed (ROCE), Spectra Energy Partners Distributable Cash, Spectra Energy Partners ROCE and Spectra Energy O&M Cost and Safety Initiative goals.
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2009 Target Incentive Payment Opportunity
| Measures |
Mr. Rizzo | Ms. Sayavedra | ||
| Spectra Energy Ongoing EPS |
20% | 20% | ||
| Spectra Energy Transmission Return on Capital Employed |
12.5% | — | ||
| Spectra Energy Transmission EBIT |
10% | — | ||
| Spectra Energy Partners Return on Capital Employed |
10% | 20% | ||
| Spectra Energy Partners Distributable Cash |
12.5% | 25% | ||
| O&M Cost and Safety Initiatives |
15% | 15% | ||
| Individual |
20% | 20% |
A summary of the 2009 individual objectives for each named executive officer and each objective weighting are shown in the following table.
| Objective |
Mr. Rizzo | Ms. Sayavedra | ||
| Enhancement of Spectra Energy Partners’ financial strength |
25% | 35% | ||
| Enhancement of Spectra Energy Partners’ standing in the investment community |
— | 20% | ||
| Management of strategic initiatives |
25% | 35% | ||
| Transition of Spectra Energy-related responsibilities |
— | 10% | ||
| Leadership of Spectra Energy’s regulatory strategy |
25% | — | ||
| FERC compliance |
25% | — |
Determination of 2009 Short-Term Incentive Payments
At the end of the 2009 cycle, management prepared a report on the achievement of financial, project and operational goals. These results were reviewed and approved by the Compensation Committee in February 2010 along with a review of the achievement of the named executive officers’ individual goals, including a calculation of the percentage achievement of each for purposes of the STI program. For the named executive officers, performance for each individual objective was calculated and reviewed by the Compensation Committee for Mr. Rizzo and by members of Spectra Energy’s management for Ms. Sayavedra, which then approved the final performance results and payment of bonuses.
The amounts set forth below show target amounts for achieving the threshold, target and maximum levels established for each financial goal as well as the actual result. The percentage of the target opportunity achieved is shown in parentheses. For each category, achievement of the Threshold, Target and Maximum amounts would result in the payment of 50%, 100% and 200%, respectively, of the target level. For instance, the short-term incentive payment for an executive associated with Spectra Energy’s EPS results was calculated as 20% of such executive’s target bonus opportunity multiplied by the actual percentage achieved, which was 80%.
| Measures |
Threshold | Target | Maximum | Actual | |||||||||||
| Spectra Energy Ongoing EPS |
$ | 1.00 | $ | 1.30 | $ | 1.83 | $ | 1.18 (80%) | |||||||
| Spectra Energy Transmission Return on Capital Employed |
10.1 | % | 10.6 | % | 11.7 | % | 11.2% (155%) | ||||||||
| Spectra Energy Transmission EBIT* |
$ | 1,375 | $ | 1,450 | $ | 1,600 | $ | 1,543(162%) | |||||||
| Spectra Energy Partners Return on Capital Employed |
7.8 | % | 8.2 | % | 9.0 | % | 9.0% (200%) | ||||||||
| Spectra Energy Partners Distributable Cash* |
$ | 145 | $ | 153 | $ | 168 | $ | 158.1 (134%) | |||||||
| * | In millions. |
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The following table is a summary of the payments made to each of our named executive officers together with the ratings achieved for individual goals. Satisfaction of individual goals at the Threshold, Target and Maximum levels results in the payment of 50%, 100% and 150%, respectively, of the target level.
2009 STI Awards
| Name |
Short-Term Incentive Award |
Actual Individual Award as a Percent of Target Individual Award |
Actual Payout as a Percent of Target Short-Term Incentive Award |
||||||
| Gregory J. Rizzo |
$ | 205,799 | 141 | % | 131 | % | |||
| Laura Buss Sayavedra |
$ | 108,998 | 143 | % | 133 | % | |||
In calculating final bonus amounts, the Compensation Committee applied a reduction in earned amounts for Mr. Rizzo and Ms. Sayavedra due to not fully meeting the safety goals and expectations for employees and contractors for 2009.
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.
Spectra Energy’s 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 restricted 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.
The performance unit awards comprise 50% of the target value of annual long-term compensation and are earned based on how Spectra Energy performs relative to a group of energy companies over a three-year period. The companies in Spectra Energy’s long-term incentive peer group are:
| Ameren Corp. |
CenterPoint Energy | Consolidated Edison | ||
| Dominion Resources |
DTE Energy | El Paso Corp. | ||
| Enbridge, Inc. |
Equitable Resources | NiSource | ||
| National Fuel Gas Co. |
ONEOK, Inc. | PG&E Corp. | ||
| Public Service Enterprise Group |
Questar Corp. | Sempra Energy | ||
| Southern Union Company |
TransCanada Corp. | Williams Companies | ||
| Xcel Energy |
||||
The performance 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 Units |
||
| 80th Percentile or Higher |
200 | % | |
| 50th Percentile (Target) |
100 | % | |
| 30th Percentile |
50 | % | |
| Below 30th Percentile |
0 | % |
The Compensation Committee approved these payout levels after a review of similar plans in place by many of the companies in the peer group, after a review of the historical returns of the peer group and indices that track energy company performance, and after consultations with Spectra Energy’s outside compensation advisors. Once earned, performance units will be converted to shares of Spectra Energy common stock.
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Phantom units comprised the remaining 50% 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 units and phantom units at the time that units vest.
The table below shows long-term incentive awards granted to our named executive officers in 2009:
| Name |
Expected Value of Long-Term Incentive/Equity Grants as a Percentage of Base Salary |
Number of Performance Units Granted |
Number of Phantom Units Granted | ||||
| Gregory J. Rizzo |
100 | % | 13,400 | 12,600 | |||
| Laura Buss Sayavedra |
50 | % | 4,400 | 4,100 |
In addition to the awards above, Mr. Rizzo received a grant of 10,000 Spectra Energy Partners phantom units on February 26, 2009 in recognition of his appointment to his current position. These units cliff vest three years from the date of grant.
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 the 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 of 1986, as amended, 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 of 1986, as amended, did not exist.
Perquisites and Personal Benefits. Spectra Energy makes its private aircraft available to our executive officers for business use only and our executive officers are not allowed to initiate personal trips on corporate or chartered aircraft. However, executive officers are permitted to bring their spouse or personal guests on business-related flights when space is available. When the executive officer’s use of aircraft or a guest’s travel does not meet the Internal Revenue Service’s (IRS) standard for business use, the cost of that travel is imputed as income to the officer.
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Compensation Committee Report
The Audit Committee of the Board reviewed and discussed with management the Compensation Discussion and Analysis contained in this Annual Report on Form 10-K and, based on these reviews and discussions, recommended that the Compensation Discussion and Analysis be included in this Annual Report on Form 10-K.
Steven D. Arnold
Stewart A. Bliss
Nora Mead Brownell
J.D. Woodward, III
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EXECUTIVE COMPENSATION
The table below sets forth compensation of Spectra Energy Partners’ named executive officers for 2008 and 2009. Compensation information for Mr. Rizzo and Ms. Sayavedra is presented only for the years in which they were a named executive officer.
SUMMARY COMPENSATION TABLE
| Name and Principal Position |
Year | Salary ($) |
Bonus ($) |
Stock Awards ($)(1) |
Option Awards ($) |
Non-Equity Incentive Plan Compensation ($)(2) |
Change in Pension Value and Nonqualified Deferred Compensation Earnings ($)(3) |
All Other Compensation ($)(4) |
Total ($) | |||||||||
| Gregory J. Rizzo(5) |
2009 | 315,188 | — | 574,446 | — | 205,799 | 115,348 | 32,996 | 1,243,777 | |||||||||
| President and Chief Executive Officer |
2008 | 307,500 | — | 331,330 | — | 198,842 | 78,857 | 35,014 | 951,543 | |||||||||
| Laura Buss Sayavedra(6) |
2009 | 205,001 | — | 119,636 | — | 108,998 | 33,908 | 16,283 | 483,826 | |||||||||
| Vice President and Chief Financial Officer |
2008 | 194,272 | — | 202,587 | — | 116,607 | 12,915 | 15,666 | 542,047 | |||||||||
| (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 and phantom share awards granted each year. The aggregate dollar amount was determined without regard to any estimate of forfeitures related to service-based vesting conditions. |
| (2) | This column includes amounts payable under the Spectra STI Plan with respect to the 2009 and 2008 performance periods. Unless deferred, these amounts were paid in March 2010 and March 2009, respectively. |
| (3) | This column includes the amounts listed below. These figures represent the change in value during the twelve month period ending December 31. |
| Gregory J. Rizzo |
Laura Buss Sayavedra | |||||
| Change in actuarial present value of accumulated benefit under the Spectra Energy Retirement Cash Balance Plan for the period beginning on January 1, 2009 and ending on December 31, 2009 |
$ | 74,370 | $ | 27,320 | ||
| Change in actuarial present value of accumulated benefit under the Spectra Energy Executive Cash Balance Plan for the period beginning on January 1, 2009 and ending on December 31, 2009 |
40,978 | 6,588 | ||||
| Total |
$ | 115,348 | $ | 33,908 | ||
| (4) | All Other Compensation column includes the following for 2009: |
| Gregory J. Rizzo |
Laura Buss Sayavedra | |||||
| Matching contributions under the Spectra Energy Retirement Savings Plan |
$ | 14,700 | $ | 14,700 | ||
| Premiums for life insurance coverage provided under Life Insurance Plans |
1,604 | 433 | ||||
| Make-whole matching contribution credits under the Spectra Energy Executive Savings Plan |
16,142 | — | ||||
| Charitable contributions made in the name of the Executive under Spectra Energy’s matching gift policy |
550 | 1,150 | ||||
| Total |
$ | 32,996 | $ | 16,283 | ||
| (5) | Mr. Rizzo became President and Chief Executive Officer effective December 1, 2008. Compensation for the entire fiscal year 2008 is disclosed for Mr. Rizzo. |
| (6) | Ms. Sayavedra became Vice President and Chief Financial Officer effective July 1, 2008. Compensation for the entire fiscal year 2008 is disclosed for Ms. Sayavedra. |
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2009 GRANTS OF PLAN-BASED AWARDS
| 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 ($)(3) | ||||||||||||||||
| Name |
Grant Date |
Threshold | Target | Maximum | Threshold | Target | Maximum | |||||||||||||
| ($) | ($) | ($) | (#) | (#) | (#) | |||||||||||||||
| Gregory J. Rizzo |
78,797 | 157,594 | 299,429 | |||||||||||||||||
| Gregory J. Rizzo |
2/24/2009 | 2/23/2009 | 6,700 | 13,400 | 26,800 | 199,526 | ||||||||||||||
| Gregory J. Rizzo |
2/24/2009 | 2/23/2009 | 12,600 | 166,320 | ||||||||||||||||
| Gregory J. Rizzo |
2/26/2009 | 2/26/2009 | 10,000 | 208,600 | ||||||||||||||||
| Laura Buss Sayavedra |
41,000 | 82,000 | 155,800 | |||||||||||||||||
| Laura Buss Sayavedra |
2/24/2009 | 2/23/2009 | 2,200 | 4,400 | 8,800 | 65,516 | ||||||||||||||
| Laura Buss Sayavedra |
2/24/2009 | 2/23/2009 | 4,100 | 54,120 | ||||||||||||||||
| (1) | The awards reflected in the Estimated Possible Payouts Under Non-Equity Incentive Plan Awards column were granted for the 2009 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 24, 2009 were made in shares of Spectra Energy common stock and were granted under the terms of the Spectra Energy Corp 2007 Long-Term Incentive Plan. Awards reflected in these columns with a grant date of February 26, 2009 were made in units of Spectra Energy Partners and were granted under the terms of the Spectra Energy Partners 2007 Long-Term Incentive Plan. |
| (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 shares and performance shares granted on February 24, 2009 is $13.20 and $14.89, respectively. The per unit full grant date fair value of the phantom units granted on February 26, 2009 is $20.86. |
When Duke Energy spun-off its gas businesses to form Spectra Energy, equitable adjustments were made with respect to outstanding stock options and other forms of equity awards originally denominated in shares of Duke Energy common stock. All such awards were adjusted into two separate awards, one denominated in shares of Duke Energy common stock and one denominated in shares of Spectra Energy common stock. The number of shares of Spectra Energy common stock distributed to award holders was equal to the number of Spectra Energy shares that a shareholder of Duke Energy common stock would have received effective on the January 2, 2007 spin date (i.e., a ratio of 0.5 shares of Spectra Energy common stock for every one share of Duke Energy common stock). With respect to stock options, the per share option exercise price of the original Duke Energy stock option was proportionally allocated between the two types of stock options taking into account the distribution ratio and the relative per share trading prices following the distribution. The resulting Duke Energy and Spectra Energy awards continue to be subject to the vesting schedule under the original Duke Energy award agreement. For purposes of vesting of options and phantom stock and the post-termination exercise periods applicable to the options, continued employment with Spectra Energy is considered to be continued employment with the issuer of the options or shares of phantom stock. The adjustments preserved, but did not increase, the value of the equity awards.
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OUTSTANDING EQUITY AWARDS AT 2009 FISCAL YEAR-END
| Option Awards | Stock Awards | |||||||||||||||||||
| Name |
Number of Securities Underlying Unexercised Options (#) Exercisable |
Number of Securities Underlying Unexercised Options (#) Unexercisable(1) |
Option Exercise Price ($)(2) |
Option Expiration Date |
Number of Shares or Units of Stock That Have Not Vested (#)(3)(4) |
Market Value of Shares or Units of Stock That Have Not Vested ($) |
Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested (#)(5) |
Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested ($) | ||||||||||||
| Gregory J. Rizzo(7) |
SE | 3,800 | 36.86 | |||||||||||||||||
| DUK | 7,600 | 24.39 | 12/20/2010 | |||||||||||||||||
| SE | 3,850 | 32.44 | ||||||||||||||||||
| DUK | 7,700 | 21.47 | 12/19/2011 | |||||||||||||||||
| SE | 1,700 | 32.54 | ||||||||||||||||||
| DUK | 3,400 | 21.54 | 4/1/2012 | |||||||||||||||||
| SE | 1,612 | 11.86 | 2/25/2013 | |||||||||||||||||
| SE | 512 | 12.52 | 4/1/2013 | |||||||||||||||||
| SE | 25,467 | 12,733 | 25.64 | 2/27/2017 | ||||||||||||||||
| SE | 26,482 | 543,146 | ||||||||||||||||||
| SEP | 13,700 | 405,109 | ||||||||||||||||||
| DUK | 2,964 | 51,010 | ||||||||||||||||||
| Total | 999,265 | |||||||||||||||||||
| SE | 19,600 | 401,996 | ||||||||||||||||||
| Laura Buss Sayavedra(6) |
SE | 1,100 | 36.86 | |||||||||||||||||
| DUK | 2,200 | 24.39 | 12/20/2010 | |||||||||||||||||
| SE | 1,350 | 32.44 | ||||||||||||||||||
| DUK | 2,700 | 21.47 | 12/19/2011 | |||||||||||||||||
| SE | 825 | 11.86 | 2/25/2013 | |||||||||||||||||
| SE | 6,734 | 3,366 | 25.64 | 2/27/2017 | ||||||||||||||||
| SE | 8,059 | 165,290 | ||||||||||||||||||
| SEP | 4,335 | 128,186 | ||||||||||||||||||
| DUK | 718 | 12,357 | ||||||||||||||||||
| Total | 305,833 | |||||||||||||||||||
| SE | 6,400 | 131,264 | ||||||||||||||||||
| (1) | On February 27, 2007, Mr. Rizzo and Ms. Sayavedra received stock options that vest in three equal installments on the first three anniversaries of the date of grant. |
| (2) | For options granted February 27, 2007, the exercise price is equal to the closing price of Spectra Energy common stock on the date of grant. For options granted prior to December 31, 2006, the exercise price for the original Duke Energy options is equal to the closing price of Duke Energy common stock on the date of grant. In connection with the spin-off of Spectra Energy effective January 2, 2007, all Duke Energy equity awards were adjusted to reflect the change in the price of Duke Energy common stock that occurred as a result of the spin-off, and an additional award denominated in Spectra Energy common shares was granted. The adjustments preserved, but did not increase, the value of the equity awards. The following chart indicates the original and adjusted exercise prices of each Duke Energy stock option. In addition, the chart indicates exercise prices for stock options granted on January 2, 2007 at Spectra Energy associated to each grant date at Duke Energy: |
| Date of Grant |
Duke Energy Original Option Exercise Price |
Duke Energy Adjusted Option Exercise Price |
Spectra Energy Option Exercise Price Granted on January 2, 2007 | ||||||
| December 20, 2000 |
$ | 42.81 | $ | 24.39 | $ | 36.86 | |||
| December 19, 2001 |
37.68 | 21.47 | 32.44 | ||||||
| April 1, 2002 |
37.80 | 21.54 | 32.54 | ||||||
| February 25, 2003 |
13.77 | 7.85 | 11.86 | ||||||
| April 1, 2003 |
14.54 | 8.29 | 12.52 | ||||||
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| (3) | Mr. Rizzo and Ms. Sayavedra received Spectra Energy and Duke Energy phantom shares as follows: |
| a. | On February 24, 2009, February 26, 2008 and February 27, 2007, Spectra Energy shares were granted which, subject to certain exceptions, vest on the third anniversary of the date of grant. |
| b. | On February 28, 2005 and April 4, 2006, Duke Energy shares were granted which, subject to certain exceptions, vest in equal installments on the first five anniversaries of the date of grant. Outstanding Duke Energy shares and corresponding Spectra Energy shares related to this award are included above. |
| (4) | Mr. Rizzo and Ms. Sayavedra received Spectra Energy Partners phantom units on July 2, 2007 each of which, subject to certain exceptions, vest on the third anniversary of the date of grant. |
| (5) | Mr. Rizzo and Ms. Sayavedra received performance shares on February 26, 2008 and February 24, 2009 that, subject to certain exceptions, are eligible for vesting on December 31, 2010 and December 31, 2011, respectively. Pursuant to Instruction 3 to Item 402(f)(2) of Regulation S-K, performance shares are listed at the target number of shares. |
| (6) | On October 1, 2008, Ms. Sayavedra received a grant in the amount of 5,000 units, which, subject to certain exceptions, vest in equal installments on the first three anniversaries of the date of grant. |
| (7) | On February 26, 2009, Mr. Rizzo received a grant in the amount of 10,000 units, which, subject to certain exceptions, vest on the third anniversary of the date of grant. |
2009 OPTION EXERCISES AND STOCK VESTED
| Option Awards | Stock Awards | |||||||
| Name |
Number of Shares Acquired on Exercise(#) |
Value Realized on Exercise($)(1) |
Number of Shares Acquired on Vesting(#) |
Value Realized on Vesting($)(2) | ||||
| Gregory J. Rizzo |
||||||||
| Spectra Energy |
988 | 13,768 | ||||||
| Duke Energy |
4,250 | 34,017 | 1,976 | 27,328 | ||||
| Total |
41,096 | |||||||
| Laura Buss Sayavedra |
||||||||
| Spectra Energy |
238 | 3,320 | ||||||
| Spectra Energy Partners |
1,665 | 40,376 | ||||||
| Duke Energy |
476 | 6,586 | ||||||
| Total |
50,282 | |||||||
| (1) | The value realized upon exercise was calculated based on the closing price of a share of Duke Energy common stock on the date of option exercise. |
| (2) | The value realized upon vesting of stock awards was calculated based on the closing price of a share of common stock or unit for the respective equity on the respective vesting date. |
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.
Each of the Spectra Energy Partners executive officers actively participated in pension plans sponsored by Spectra Energy or an affiliate in 2009. 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.
Each of the Spectra Energy Partners executive officers who participates in the RCBP has satisfied the eligibility requirements to receive his or her account benefit upon termination of employment. The RCBP benefit is payable in the form of a lump sum in the amount credited to the hypothetical account at the time of benefit commencement. Payment is also available in the form of an annuity based on the actuarial equivalent of the account balance.
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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.
Each of the Spectra Energy Partners executive officers was eligible to participate in the Spectra Energy Executive Cash Balance Plan (“ECBP”), which is a noncontributory, defined benefit retirement plan that is not intended to satisfy the requirements for qualification under Section 401(a) of the Internal Revenue Code. Benefits earned under the ECBP are attributable to (a) compensation in excess of the annual compensation limit ($245,000 for 2009) under the Internal Revenue Code that applies to the determination of pay credits under the RCBP, (b) certain deferred compensation that is not recognized by the RCBP, (c) restoration of benefits in excess of a defined benefit plan maximum annual benefit limit ($195,000 for 2009) under the Internal Revenue Code that applies to the RCBP, and (d) supplemental benefits granted to a particular participant. Generally, benefits earned under the RCBP and the ECBP vest upon completion of three years of service, and, with certain exceptions, vested benefits generally become payable upon termination of employment with Spectra Energy.
Spectra Energy has established a grantor trust that is subject to the claims of our creditors into which funds related to the ECBP are deposited. Funds deposited into the trust are managed by an independent trustee subject to guidelines provided by us.
The following table provides information related to each plan that provides for payments or other benefits at, following or in connection with retirement, determined as of December 31, 2009.
PENSION BENEFITS
| Name |
Plan Name |
Number of Years Credited Service (#) |
Present Value of Accumulated Benefit ($) |
Payments During Last Fiscal Year ($) | ||||
| Gregory J. Rizzo |
Spectra Energy Retirement Cash Balance Plan | 30.34 | 467,294 | — | ||||
| Gregory J. Rizzo |
Spectra Energy Executive Cash Balance Plan | 30.34 | 222,583 | — | ||||
| Laura Buss Sayavedra |
Spectra Energy Retirement Cash Balance Plan | 14.15 | 136,396 | — | ||||
| Laura Buss Sayavedra |
Spectra Energy Executive Cash Balance Plan | 14.15 | 13,652 | — |
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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 Corp 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 into which funds related to the Spectra Energy Executive Savings Plan are deposited. Funds deposited into the trust are managed by an independent trustee subject to guidelines provided by us.
The Spectra Energy Executive Savings Plan and the Spectra Energy Retirement Savings Plan became effective with the spin-off of Spectra Energy. These plans contain the same provisions as the predecessor plans sponsored by Duke Energy, and individual benefit accruals were transferred from the Duke Energy plans to the Spectra Energy plans effective with the spin-off of Spectra Energy. Participants received credit for investment in 0.5 of a share of Spectra Energy common stock for each share of Duke Energy common stock held in the Duke Energy Common Stock Fund.
NONQUALIFIED DEFERRED COMPENSATION
| Name |
Executive Contributions in Last FY ($)(1) |
Registrant Contributions in Last FY($)(2) |
Aggregate Earnings in Last FY ($) |
Aggregate Withdrawals/ Distributions ($) |
Aggregate Balance at Last FYE ($) | |||||
| Gregory J. Rizzo |
9,942 | 35,852 | 61,825 | — | 399,332 | |||||
| Laura Buss Sayavedra |
— | — | — | — | — |
| (1) | Executive contributions credited to the plan in 2009 include amounts reported as “Salary” in the Summary Compensation Table as well as “Non-Equity Incentive Plan Compensation” paid in 2009 but reported in the table as compensation earned in 2008. |
| (2) | Reflects make-whole matching contribution credits made in 2009 under the plan with respect to elective salary deferrals made by executives during 2008 and 2009. See footnote 4 to the “Summary Compensation Table” for the amount of make-whole matching contribution credits made with respect to elective compensation deferrals made by executives during 2009. |
Potential Payments Upon Termination of Employment or Change in Control
Under certain circumstances, each Spectra Energy Partners executive officer would be entitled to compensation in the event his or her employment terminates. The amount of the compensation is contingent upon a variety of factors, including the circumstances under which employment is terminated. The relevant agreements and terms of awards applicable to named executive officers are described below, followed by a table that quantifies the amount that would become payable to each Spectra Energy Partners executive officer as a result of his or her termination of employment. The amounts shown assume that such termination was effective as of December 31, 2009 and are estimates of the amounts that would be paid. The actual amounts that would be paid can only be determined at the time of named executive officer’s termination of employment.
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The following table summarizes the consequences under Duke Energy’s long-term incentive award agreements, without giving effect to the change in control agreements described below, that would occur in the event of a change in control or the termination of employment of a Spectra Energy Partners executive officer.
| Event |
Consequences | |
| Change in Control |
Phantom Shares — continue to vest | |
| Termination with cause |
Phantom Shares — the executive’s right to unvested portion of award terminates immediately | |
| Voluntary termination (not retirement eligible) |
Phantom Shares — the executive’s right to unvested portion of award terminates immediately | |
| Involuntary termination without cause (not retirement eligible) |
Phantom Shares — prorated portion of award vests | |
| Voluntary termination or involuntary termination without cause (retirement eligible) |
Phantom Shares — continue to vest | |
| Involuntary termination after a Change in Control |
Phantom Shares — award vests | |
| Death or Disability |
Phantom Shares — prorated portion of award vests | |
The following table summarizes the consequences under Spectra Energy and Spectra Energy Partners’ long-term incentive award agreements, without giving effect to the change in control agreements described below, that would occur in the event of a change in control or the termination of employment of a Spectra Energy Partners executive officer.
| Event |
Consequences | |
| Change in Control |
Phantom Shares — continue to vest Performance Shares — award vests based on target performance Options — award vests | |
| Termination with cause |
Phantom Shares, Performance Shares and Options — the executive’s right to unvested portion of award terminates immediately | |
| Voluntary termination (not retirement eligible) |
Phantom Shares, Performance Shares and Options — the executive’s right to unvested portion of award terminates immediately | |
| Involuntary termination without cause (not retirement eligible) |
Phantom Shares — prorated portion of award vests Performance Shares — prorated portion of award vests based on actual performance after performance period ends Options — the executive’s right to unvested shares terminates immediately | |
| Voluntary termination or involuntary termination without cause (retirement eligible) |
Phantom Shares — prorated portion of award continues to vest Performance Shares — prorated portion of award vests based on actual performance after performance period ends Options — continue to vest | |
| Involuntary termination after a Change in Control |
Phantom Shares — award vests Performance Shares — award vests based on target performance Options — award vests | |
| Death or Disability |
Phantom Shares — award vests Performance Shares — award vests based on target performance Options — award vests | |
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Effective with the formation of Spectra Energy, Mr. Rizzo entered into a Change in Control Agreement with Spectra Energy. The agreement has an initial term of two years, after which the agreement automatically extends from the first date of each month for one additional month, 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 bonus 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 bonus 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 $50,000 for the cost of certain legal fees incurred in connection with claims under the agreements. In the event that any of the payments or benefits provided for in the Change in Control Agreement otherwise would constitute an “excess parachute payment” (as defined in Section 280G of the Internal Revenue Code), the amount of payments or benefits would be reduced to the maximum level that would not result in excise tax under Section 4999 of the Internal Revenue Code if such reduction would cause the executive to retain an after-tax amount in excess of what would be retained if no reduction were made. In the event a named executive officer becomes entitled to payments and benefits under a change in control agreement, he or she would be subject to a one-year noncompetition and nonsolicitation provision from the date of termination, in addition to certain confidentiality and cooperation provisions.
POTENTIAL PAYMENTS UPON TERMINATION OF
EMPLOYMENT OR A CHANGE IN CONTROL (“CIC”)
| Name and Triggering Event(1) |
Cash Severance Payment ($)(2) |
Incremental Retirement Plan Benefit ($)(3) |
Welfare and Similar Benefits ($)(4) |
Stock Awards ($)(5) |
Option Awards ($)(6) |
Total Payments ($) | ||||||
| Gregory J. Rizzo |
||||||||||||
| Change in Control |
— | — | — | 422,772 | — | 422,772 | ||||||
| Voluntary termination or involuntary termination with cause |
— | — | 12,123 | — | — | 12,123 | ||||||
| Involuntary termination without cause |
— | — | 12,123 | 550,330 | — | 562,453 | ||||||
| Involuntary or good reason termination after a CIC |
945,564 | 156,040 | 37,831 | 1,481,968 | — | 2,621,403 | ||||||
| Death or Disability |
— | — | 12,123 | 1,443,458 | — | 1,455,581 | ||||||
| Laura Buss Sayavedra |
||||||||||||
| Change in Control |
— | — | — | 138,024 | — | 138,024 | ||||||
| Voluntary termination or involuntary termination with cause |
— | — | 7,885 | — | — | 7,885 | ||||||
| Involuntary termination without cause |
— | — | 7,885 | 173,124 | — | 181,009 | ||||||
| Involuntary or good reason termination after a CIC |
— | — | 7,885 | 464,026 | — | 471,911 | ||||||
| Death or Disability |
— | — | 7,885 | 454,629 | — | 462,514 | ||||||
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| (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, 2009. |
| (2) | Amounts listed under “Cash Severance Payment” are payable under the terms of Mr. Rizzo’s change in control agreement. The severance benefits set forth above do not include accrued salary and bonus payments earned through December 31, 2009; however, such amounts are reflected in the Summary Compensation Table above. |
| (3) | Pursuant to Mr. Rizzo’s Change in Control Agreement, amounts listed under “Incremental Retirement Plan Benefit” represent the additional amounts that would be credited in respect of the Spectra Energy Retirement Cash Balance Plan, Spectra Energy Executive Cash Balance Plan, Spectra Energy Retirement Savings Plan and the Spectra Energy Executive Savings Plan in the event he continued to be employed by Spectra Energy, at his rate of base salary as in effect on December 31, 2009, for two additional years. |
| (4) | Amounts listed under “Welfare and Other Benefits” include the maximum accrued vacation allowed under Company policy and the amount that would be paid to Mr. Rizzo who has entered into a Change in Control Agreement in lieu of providing continued welfare benefits for 24 months. |
| (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. The value of phantom shares is included in termination upon a change in control event; however, phantom shares vest after a change in control upon an involuntary termination, but are forfeit for a voluntary good reason termination. |
| (6) | The number of shares of common stock underlying options for which vesting is accelerated upon the applicable termination event for Mr. Rizzo and Ms. Sayavedra were 12,733 and 3,366, respectively. The exercise price for these options is higher than the price of Spectra Energy common stock on December 31, 2009 and therefore, the amounts listed under “Option Awards” is zero. |
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 each Spectra Energy Partners executive officer’s termination of employment. The amounts described in the table do not include compensation to which each Spectra Energy Partners executive officer would be entitled without regard to his or her termination of employment, including (a) base salary and short-term incentives that have been earned but not yet paid, and (b) amounts that have been earned, but not yet paid, under the terms of the plans listed under the “Pension Benefits” and “Nonqualified Deferred Compensation” tables.
With respect to Mr. Rizzo, the amounts shown above do not reflect the fact that if, in the event that payments to the executive in connection with a change in control otherwise would result in an excise tax under Section 4999 of the Internal Revenue Code of 1986, as amended, 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, Spectra Energy Partners and Duke Energy stock awards and option 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 2009; (b) as price for Spectra Energy common stock of $20.51, for Spectra Energy Partners units of $29.57 and for Duke Energy common stock of $17.21, all of which were the closing prices on December 31, 2009; (c) the continuation of Spectra Energy’s and Duke Energy’s dividend and Spectra Energy Partners’ distribution at the rate in effect on December 31, 2009; and (d) performance at the target level with respect to performance shares.
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Index to Financial Statements
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 2009.
Director Compensation Program. Under the director compensation program approved by our general partner, each director receives an annual cash retainer of $55,000 and a grant of a number of common units equal to $40,000 divided by the closing price of our common units on the NYSE on the date of grant. Each Committee Chair also receives an annual cash retainer of $20,000. In addition, the Chairman of the Board receives an additional annual retainer of $60,000, 50% of which is paid in cash and 50% of which is paid in common units. The Chairman is also provided with office space and administrative support.
Charitable Giving Program. Members of the board of our general partner are eligible to participate in the Spectra Energy Foundation Matching Gifts Program under which Spectra Energy Corp will match contributions to qualifying institutions of up to $5,000 per director per calendar year.
Expense Reimbursement. Non-employee directors are reimbursed for expenses reasonably incurred in connection with attendance and participation at Board and Committee meetings.
The following table describes the compensation earned during 2009 by each individual who served as an outside director during 2009.
DIRECTOR COMPENSATION
| Name |
Fees Earned or Paid in Cash ($) |
Stock Awards ($) (1) |
Options Awards ($) |
Change in Pension Value and Nonqualified Deferred Compensation Earnings ($) |
All Other Compensation ($) |
Total ($) | ||||||
| Stephen D. Arnold |
75,000 | 40,009 | — | — | — | 115,009 | ||||||
| Stewart A. Bliss |
75,000 | 40,009 | — | — | — | 115,009 | ||||||
| Nora Mead Brownell |
55,000 | 40,009 | — | — | — | 95,009 | ||||||
| Fred J. Fowler |
84,000 | 109,699 | — | — | — | 193,699 | ||||||
| J.D. Woodward, III |
27,500 | 40,009 | — | — | — | 67,509 |
| (1) | This column reflects the aggregate grant date fair value of the equity awarded computed in accordance with FASB ASC Topic 718. |
The value of all perquisites and other personal benefits or property received by each director in 2009 was less than $10,000 and are not included in the above table.
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Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.
The following table sets forth the beneficial ownership of Spectra Energy Partners’ units as of February 15, 2010 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 |
Subordinated Units Beneficially Owned |
Percentage of Subordinated Units Beneficially Owned |
Percentage of Total Common and Subordinated Units Beneficially Owned |
||||||||
| Spectra Energy Corp(2) |
37,337,521 | 63.6 | % | 21,638,730 | 100.0 | % | 73.4 | % | |||||
| Spectra Energy Transmission LLC |
11,920,493 | 20.3 | % | 5,037,637 | 23.3 | % | 21.1 | % | |||||
| Spectra Energy Southeast Pipeline Corp. |
25,417,028 | 43.3 | % | 16,601,093 | 76.7 | % | 52.3 | % | |||||
| Fred J. Fowler |
14,388 | * | — | — | * | ||||||||
| R. Mark Fiedorek |
11,500 | * | — | — | * | ||||||||
| Patrick J. Hester |
— | * | — | — | * | ||||||||
| Theopolis Holeman |
— | * | — | — | * | ||||||||
| Gregory J. Rizzo |
5,000 | * | — | — | * | ||||||||
| Laura Buss Sayavedra |
1,474 | * | — | — | * | ||||||||
| Steven D. Arnold |
32,175 | * | — | — | * | ||||||||
| Nora Mead Brownell |
11,425 | * | — | — | * | ||||||||
| Stewart A. Bliss |
5,675 | * | — | — | * | ||||||||
| J.D. Woodward, III |
27,395 | * | — | — | * | ||||||||
| All directors and executive officers as a group (ten persons) |
109,032 | * | — | — | * |
| (*) | Less than 1% of units outstanding. |
| (1) | Unless otherwise indicated, the address for all beneficial owners in this table is 5400 Westheimer Court, Houston, TX 77056. |
| (2) | Spectra Energy is the ultimate parent company of each of Spectra Energy Transmission, Spectra Energy Southeast Pipeline Corp. and Spectra Energy Partners (DE) GP, LP and may, therefore, be deemed to beneficially own the units held by each of these entities. |
The following table lists the beneficial owners of 5% or more of Spectra Energy Partner’s outstanding common units as of February 17, 2010. This information is based on the most recently available reports filed with the SEC and provided to us by the company listed.
| Common Units | |||||
| Name and Address of Beneficial Owner |
Beneficially Owned | Percentage | |||
| Neuberger Berman Group LLC (1) |
4,013,564 | 6.837 | % | ||
| 2200 Ross Avenue, 31st Floor, Dallas, TX 75201-2761 |
|||||
| (1) | According to the Schedule 13G filed on February 17, 2009 by Neuberger Berman Group LLC, these units are beneficially owned by its clients, and it has shared voting power with respect to 3,596,824 units and shared dispositive power with respect to 4,013,564 units. |
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Equity Compensation Plan Information
The following table summarizes information about Spectra Energy Partners’ equity compensation plan as of December 31, 2009.
| 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 | 801,275 | |||
| Total |
— | n/a | 801,275 | |||
| (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 37,337,521 common units and 21,638,730 subordinated units as of December 31, 2009, representing an aggregate 73% 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 37,337,521 common units, 21,638,730 subordinated units, and 2% to the General Partner. In addition, if distributions exceed the minimum quarterly distribution and other higher target distribution levels, the General Partner will be entitled to increasing percentages of the distributions, up to 50% of the distributions above the highest target distribution level. |
| Payments to the General Partner and its affiliates |
Spectra Energy Partners reimburses Spectra Energy and its affiliates for the payment of certain operating expenses and for the provision of various general and administrative services for the benefit of Spectra Energy Partners. |
| Withdrawal or removal the General Partner |
If the General Partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests. |
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Liquidation Stage
| Liquidation |
Upon Spectra Energy Partners’ liquidation, the partners, including the General Partner, will be entitled to receive liquidating distributions according to their respective capital account balances. |
Omnibus Agreement
In connection with its IPO, Spectra Energy Partners entered into an omnibus agreement with Spectra Energy, its general partner and others that addresses the following matters:
| • | Spectra Energy Partners’ obligation to reimburse Spectra Energy for the payment of direct operating expenses it incurs on Spectra Energy Partners’ behalf in connection with Spectra Energy Partners’ business and operations; |
| • | Spectra Energy Partners’ obligation to reimburse Spectra Energy for providing it allocated corporate, general and administrative services, which reimbursement is capped at $3.0 million per year, subject to adjustment for inflation and increases in connection with expansions of operations through the acquisition or construction of new assets or businesses with the concurrence of Spectra Energy Partners’ Conflicts Committee; and |
| • | Spectra Energy’s obligation to indemnify Spectra Energy Partners’ for certain liabilities and Spectra Energy Partners’ obligation to indemnify Spectra Energy for certain liabilities. |
The General Partner and its affiliates also receive payments from Spectra Energy Partners pursuant to the contractual arrangements described below under the caption “Contracts with Affiliates.”
Any or all of the provisions of the Omnibus Agreement, other than the indemnification provisions described below, is terminable by Spectra Energy at its option if the General Partner is removed without cause and units held by the General Partner and its affiliates are not voted in favor of that removal. The Omnibus Agreement (other than the indemnification provisions) will also terminate in the event of a change of control of Spectra Energy Partners, its general partner or the general partner of its general partner.
Reimbursement of Operating and General and Administrative Expense
Under the Omnibus Agreement, Spectra Energy Partners reimburses Spectra Energy for the payment of certain operating expenses and for the provision of various corporate, general and administrative services (which corporate, general and administrative expenses are capped at $3.0 million annually, subject to increases as described above) for Spectra Energy Partners’ benefit.
Pursuant to these arrangements, Spectra Energy performs centralized corporate functions for Spectra Energy Partners, including legal, accounting, compliance, treasury, insurance, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit and tax. Spectra Energy Partners reimburses Spectra Energy for the expenses to provide these services as well as other expenses it incurs on Spectra Energy Partners’ behalf, such as salaries of personnel performing services for Spectra Energy Partners’ benefit and the cost of Spectra Energy employee benefits and general and administrative expenses associated with such personnel; capital expenditures; maintenance and repair costs; taxes; and direct expenses, including operating expenses and certain allocated operating expenses, associated with the ownership and operation of the contributed assets.
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
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its affiliates may acquire, construct or dispose of additional transportation and storage or other assets in the future without any obligation to offer Spectra Energy Partners the opportunity to purchase or construct those assets.
Indemnification
Under the Omnibus Agreement, Spectra Energy agreed to indemnify Spectra Energy Partners for three years after the closing of the IPO against certain potential environmental and toxic tort claims, losses and expenses associated with the operation of the assets and occurring before July 2, 2007, the closing date of the IPO. The maximum liability of Spectra Energy for this indemnification obligation will not exceed $15.0 million and Spectra Energy will not have any obligation under this indemnification until aggregate losses exceed $250,000. Spectra Energy has no indemnification obligations with respect to environmental claims made as a result of additions to or modifications of environmental laws relating to pollution or protection of the environment or natural resources promulgated after July 2, 2007. Spectra Energy Partners has agreed to indemnify Spectra Energy against environmental liabilities related to Spectra Energy Partners’ assets to the extent Spectra Energy is not required to indemnify Spectra Energy Partners.
Additionally, Spectra Energy will indemnify Spectra Energy Partners for losses attributable to title defects, failures to obtain consents or permits necessary for the transfer of the contributed assets, retained assets and liabilities (including preclosing litigation relating to contributed assets) and income taxes attributable to pre-closing operations. Spectra Energy Partners will indemnify Spectra Energy for all losses attributable to the postclosing operations of the assets contributed to Spectra Energy Partners, to the extent not subject to Spectra Energy’s indemnification obligations.
Contracts with Affiliates
Gulfstream Limited Liability Company Agreement
In connection with the closing of the IPO, Spectra Energy contributed to Spectra Energy Partners 49.0% of its 50.0% interest in Gulfstream. Currently, Spectra Energy Partners owns a 24.5% interest in Gulfstream, Spectra Energy owns a 25.5% interest and affiliates of The Williams Companies, Inc. (Williams) own a 50.0% interest. Gulfstream’s second amended and restated limited liability company agreement governs the ownership and management of Gulfstream and provides for quarterly distributions equal to 100% of its available cash, which is defined to include Gulfstream’s cash and cash equivalents on hand at the end of the quarter less any reserves that may be deemed appropriate by the Gulfstream management committee for the operation of its business (including reserves for its future maintenance capital expenditures and for its anticipated future credit needs) or for its compliance with laws or other agreements.
The management committee representatives of Spectra Energy and Williams jointly make the determinations related to Gulfstream’s available cash. In addition, because Spectra Energy Partners holds less than a 25% interest in Gulfstream, under the terms of the limited liability company agreement, Spectra Energy and Williams are able to collectively make all decisions with respect to the operation of Gulfstream without Spectra Energy Partners’ approval, other than those decisions relating to (1) a dissolution of Gulfstream, (2) Gulfstream’s entrance into bankruptcy proceedings, (3) Gulfstream’s conducting any activity or business that may generate income for federal income tax purposes that may not be “qualifying income,” or (4) an amendment of Gulfstream’s limited liability company agreement or its certificate of formation.
Under the Gulfstream limited liability company agreement, each member’s interest is subject to transfer restrictions, including a right of first offer in favor of the other members except in the case of certain transfers to affiliates. Accordingly, if a member identifies a potential third-party purchaser for all or a portion of its interest, that member must first offer the other members the opportunity to acquire the interest that it proposes to sell on the same terms and conditions as proposed by such potential purchaser.
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Market Hub General Partnership Agreement
In connection with the closing of the IPO, Spectra Energy contributed to Spectra Energy Partners 50.0% of its interest in Market Hub. Currently, Spectra Energy Partners owns a 50.0% interest in Market Hub and Spectra Energy owns a 50.0% interest. A partnership agreement governs the ownership and management of Market Hub and provides for quarterly distributions equal to 100% of its available cash, which is defined to include Market Hub’s cash and cash equivalents on hand at the end of the quarter less any reserves that may be deemed appropriate by the Market Hub management committee for the operation of its business (including reserves for its future maintenance capital expenditures and for its anticipated future credit needs) or for its compliance with law or other agreements.
A management committee comprised of an equal number of representatives of Spectra Energy and Spectra Energy Partners jointly make the determinations related to Market Hub’s available cash.
Storage and Transportation Related Arrangements
Spectra Energy Partners charges transportation and storage fees to Spectra Energy and its respective affiliates. Management anticipates continuing to provide these services to Spectra Energy and its respective affiliates in the ordinary course of business.
East Tennessee. East Tennessee is a party under a pipeline balancing agreement with Texas Eastern Transmission, LP (Texas Eastern), a Spectra Energy affiliate. The agreement was entered into in accordance with East Tennessee’s FERC gas tariff and provides for the monthly balancing of natural gas at receipt and delivery points with Texas Eastern interconnecting with East Tennessee’s pipeline system.
Market Hub. Texas Eastern has entered into a variety of storage service agreements with Moss Bluff and Egan. At Egan, interruptible service agreements were made under a FERC approved gas tariff, using rates negotiated at arms-length between the parties. At Moss Bluff, interruptible and firm storage service agreements are subject to the Statement of Operating Conditions on file with the FERC. Storage service agreements between Moss Bluff and Texas Eastern include rates negotiated at arms-length between the parties. In addition, each of Moss Bluff and Egan have entered into agreements with Texas Eastern as an interconnecting pipeline to provide for monthly gas balancing at receipt and delivery points between the parties.
Board Leadership and Risk Oversight
The board of our General Partner is currently led by our Chairman, Mr. Fowler. While our policies allow for the positions of the Office of Chairman and the Chief Executive Officer to be held by the same person we believe that leadership of the board of directors is best conducted by a separate Chairman. In exercising its duties to our unitholders, our board members should not be conflicted in any way. We have procedures that are specified in our partnership agreement to address potential conflicts, which include referring transactions that present a conflict to our Conflicts Committee. We believe that this board leadership structure is appropriate in maximizing the effectiveness of our board oversight and in providing perspective to our business that is independent from management.
The board has responsibility for oversight of our risk management process and receives regular reports from our executives and from Spectra Energy regarding the risks faced in our business. The board exercises its risk oversight responsibilities through the Audit Committee, with respect to financial reporting and compliance risks. In addition, the Compensation Committee of Spectra Energy provides oversight with respect to risks that may be created by our compensation programs. Spectra Energy’s management has undertaken, and the Compensation 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.
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Director Independence
See Item 10. Directors, Executive Officers and Corporate Governance for information about the independence of the General Partner’s board of directors and its committees.
Item 14. Principal Accounting Fees and Services.
The following table presents fees for professional services rendered by Deloitte & Touche LLP, and the member firms of Deloitte Touche Tohmatsu and their respective affiliates (collectively, Deloitte) for us for 2009 and 2008:
| Type of Fees |
2009 | 2008 | ||||
| (in millions) | ||||||
| Audit Fees(a) |
$ | 0.8 | $ | 0.8 | ||
| Audit-Related Fees(b) |
0.2 | 0.3 | ||||
| Total Fees: |
$ | 1.0 | $ | 1.1 | ||
| (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. |
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.
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PART IV
Item 15. Exhibits, Financial Statement Schedules.
(a) Consolidated Financial Statements, Supplemental Financial Data and Supplemental Schedules included in Part II of this annual report are as follows:
Spectra Energy Partners, LP:
Report of Independent Registered Public Accounting Firm
Consolidated Statements of Operations
Consolidated Balance Sheets
Consolidated Statements of Cash Flows
Consolidated Statements of Partners’ Capital / Predecessor Equity and Comprehensive Income
Notes to Consolidated Financial Statements
Schedule II — Consolidated Valuation and Qualifying Accounts and Reserves
Separate Financial Statements of Subsidiaries not Consolidated Pursuant to Rule 3-09 of Regulation S-X:
Gulfstream Natural Gas System, L.L.C.:
Report of Independent Registered Public Accounting Firm
Statements of Operations
Balance Sheets
Statements of Cash Flows
Statements of Members’ Equity and Comprehensive Income
Notes to Financial Statements
Market Hub Partners Holding:
Report of Independent Registered Public Accounting Firm
Consolidated Statements of Operations
Consolidated Balance Sheets
Consolidated Statements of Cash Flows
Consolidated Statements of Partners’ Capital
Notes to Consolidated Financial Statements
All other schedules are omitted because they are not required or because the required information is included in the Consolidated Financial Statements or Notes.
(c) Exhibits — See Exhibit Index at the end of this Annual Report on Form 10-K.
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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: March 11, 2010 |
/s/ GREGORY J. RIZZO | |||
| Gregory J. Rizzo President and Chief Executive Officer Spectra Energy Partners GP, LLC | ||||
| Date: March 11, 2010 |
/s/ LAURA BUSS SAYAVEDRA | |||
| Laura Buss Sayavedra Vice President and Chief Financial Officer Spectra Energy Partners GP, LLC | ||||
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.
| /s/ GREGORY J. RIZZO (i) Gregory J. Rizzo |
President and Chief Executive Officer (Principal Executive Officer and Director) | |
| /s/ LAURA BUSS SAYAVEDRA (ii) Laura Buss Sayavedra |
Vice President and Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer) | |
| * (iii) Fred J. Fowler |
Chairman of the Board of Directors | |
| * Steven D. Arnold |
Director | |
| * Stewart A. Bliss |
Director | |
| * Nora Mead Brownell |
Director | |
| * R. Mark Fiedorek |
Director | |
| * Patrick J. Hester |
Director | |
| * |
Director | |
| Theopolis Holeman | ||
| * J.D. Woodward, III |
Director | |
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Date: March 11, 2010
Gregory J. Rizzo, 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/ GREGORY J. RIZZO | |
| Gregory J. Rizzo Attorney-In-Fact | ||
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Index to Financial Statements
GULFSTREAM NATURAL GAS SYSTEM, L.L.C.
INDEX TO FINANCIAL STATEMENTS
| Page | ||
| Financial Statements: |
||
| F-2 | ||
| Statements of Operations for the years ended December 31, 2009, 2008 and 2007 |
F-3 | |
| F-4 | ||
| Statements of Cash Flows for the years ended December 31, 2009, 2008 and 2007 |
F-5 | |
| F-6 | ||
| F-7 | ||
F-1
Table of Contents
Index to Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Members of Gulfstream Natural Gas System, L.L.C.
Houston, Texas
We have audited the accompanying balance sheets of Gulfstream Natural Gas System, L.L.C., (the “Company”), as of December 31, 2009 and 2008, and the related statements of operations, members’ equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2009. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards as established by the Auditing Standards Board (United States) and in accordance with the auditing standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material respects, the financial position of Gulfstream Natural Gas System, L.L.C. as of December 31, 2009 and 2008, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2009 in conformity with accounting principles generally accepted in the United States of America.
/s/ Deloitte & Touche LLP
Houston, Texas
February 17, 2010
F-2
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Index to Financial Statements
GULFSTREAM NATURAL GAS SYSTEM, L.L.C.
STATEMENTS OF OPERATIONS
| Years Ended December 31, | ||||||||||
| 2009 | 2008 | 2007 | ||||||||
| (In millions) | ||||||||||
| Operating Revenues |
||||||||||
| Transportation of natural gas |
$ | 250.0 | $ | 204.4 | $ | 183.7 | ||||
| Other |
1.5 | 2.3 | 1.6 | |||||||
| Total operating revenues |
251.5 | 206.7 | 185.3 | |||||||
| Operating Expenses |
||||||||||
| Operating, maintenance and other |
4.5 | 5.7 | 1.0 | |||||||
| Operating, maintenance and other — affiliates |
14.6 | 12.6 | 9.2 | |||||||
| Depreciation and amortization |
34.5 | 30.3 | 30.0 | |||||||
| Property and other taxes |
14.0 | 12.8 | 5.7 | |||||||
| Total operating expenses |
67.6 | 61.4 | 45.9 | |||||||
| Loss on Sale of Assets |
— | (0.6 | ) | — | ||||||
| Operating Income |
183.9 | 144.7 | 139.4 | |||||||
| Other Income and Expenses |
1.4 | 11.1 | 3.9 | |||||||
| Interest Expense |
61.3 | 45.0 | 47.9 | |||||||
| Net Income |
$ | 124.0 | $ | 110.8 | $ | 95.4 | ||||
See Notes to Financial Statements.
F-3
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Index to Financial Statements
GULFSTREAM NATURAL GAS SYSTEM, L.L.C.
BALANCE SHEETS
| December 31, | ||||||
| 2009 | 2008 | |||||
| (In millions) | ||||||
| ASSETS | ||||||
| Current Assets |
||||||
| Cash and cash equivalents |
$ | 63.0 | $ | 63.0 | ||
| Receivables (net of allowance for doubtful accounts of $0.1 and $0.3 at December 31, 2009 and 2008, respectively) |
22.3 | 22.1 | ||||
| Inventory |
4.9 | 7.9 | ||||
| Other |
4.3 | 2.1 | ||||
| Total current assets |
94.5 | 95.1 | ||||
| Property, Plant and Equipment |
||||||
| Cost |
2,036.5 | 1,996.1 | ||||
| Less accumulated depreciation and amortization |
212.0 | 178.1 | ||||
| Net property, plant and equipment |
1,824.5 | 1,818.0 | ||||
| Regulatory Assets and Deferred Debits |
||||||
| Regulatory tax asset |
24.4 | 24.3 | ||||
| Unamortized debt expense |
8.2 | 6.6 | ||||
| Other |
— | 0.3 | ||||
| Total regulatory assets and deferred debits |
32.6 | 31.2 | ||||
| Total Assets |
$ | 1,951.6 | $ | 1,944.3 | ||
| LIABILITIES AND MEMBERS’ EQUITY | ||||||
| Current Liabilities |
||||||
| Accounts payable |
$ | 6.2 | $ | 20.3 | ||
| Accounts payable — affiliates |
2.3 | 1.4 | ||||
| Taxes accrued |
2.1 | 3.1 | ||||
| Interest accrued |
10.0 | 8.2 | ||||
| Accrued liabilities |
2.2 | 0.5 | ||||
| Fuel tracker liabilities |
3.7 | — | ||||
| Natural gas imbalance payables |
— | 2.7 | ||||
| Total current liabilities |
26.5 | 36.2 | ||||
| Long-term Debt |
1,148.8 | 849.6 | ||||
| Other Long-term Liabilities |
— | 0.1 | ||||
| Commitments and Contingencies |
||||||
| Members’ Equity |
||||||
| Members’ equity |
764.7 | 1,045.5 | ||||
| Accumulated other comprehensive income |
11.6 | 12.9 | ||||
| Total members’ equity |
776.3 | 1,058.4 | ||||
| Total Liabilities and Members’ Equity |
$ | 1,951.6 | $ | 1,944.3 | ||
See Notes to Financial Statements.
F-4
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Index to Financial Statements
GULFSTREAM NATURAL GAS SYSTEM, L.L.C.
STATEMENTS OF CASH FLOWS
| Years Ended December 31, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
| (In millions) | ||||||||||||
| CASH FLOWS FROM OPERATING ACTIVITIES |
||||||||||||
| Net income |
$ | 124.0 | $ | 110.8 | $ | 95.4 | ||||||
| Adjustments to reconcile net income to net cash provided by operating activities: |
||||||||||||
| Depreciation and amortization |
35.4 | 31.0 | 30.6 | |||||||||
| Loss on sale of assets |
— | 0.6 | — | |||||||||
| Allowance for funds used during construction — equity |
(0.6 | ) | (7.8 | ) | (1.8 | ) | ||||||
| Reclassification adjustments from accumulated other comprehensive income into net income |
(1.3 | ) | (1.3 | ) | (1.3 | ) | ||||||
| Decrease (increase) in: |
||||||||||||
| Receivables |
(3.0 | ) | (5.8 | ) | (1.2 | ) | ||||||
| Other current assets |
4.6 | (6.7 | ) | (4.7 | ) | |||||||
| Increase (decrease) in: |
||||||||||||
| Accounts payable |
1.7 | 2.2 | 1.1 | |||||||||
| Taxes accrued |
(1.0 | ) | (2.7 | ) | (8.2 | ) | ||||||
| Interest accrued |
1.8 | — | — | |||||||||
| Accrued liabilities |
1.7 | (5.5 | ) | — | ||||||||
| Fuel tracker liabilities |
— | (0.1 | ) | — | ||||||||
| Other current liabilities |
(0.5 | ) | — | 1.0 | ||||||||
| Other, assets |
(3.4 | ) | 1.6 | (3.0 | ) | |||||||
| Other, liabilities |
— | — | (0.2 | ) | ||||||||
| Net cash provided by operating activities |
159.4 | 116.3 | 107.7 | |||||||||
| CASH FLOWS FROM INVESTING ACTIVITIES |
||||||||||||
| Capital expenditures |
(53.5 | ) | (191.4 | ) | (71.2 | ) | ||||||
| Proceeds on sale of assets |
— | 1.4 | — | |||||||||
| Net cash used in investing activities |
(53.5 | ) | (190.0 | ) | (71.2 | ) | ||||||
| CASH FLOWS FROM FINANCING ACTIVITIES |
||||||||||||
| Capital contributions from members |
40.2 | 179.4 | 76.4 | |||||||||
| Distributions to members |
(445.1 | ) | (116.4 | ) | (68.6 | ) | ||||||
| Proceeds from the issuance of long-term debt |
299.0 | — | — | |||||||||
| Net cash provided by (used in) financing activities |
(105.9 | ) | 63.0 | 7.8 | ||||||||
| Net increase (decrease) in cash and cash equivalents |
— | (10.7 | ) | 44.3 | ||||||||
| Cash and cash equivalents at beginning of period |
63.0 | 73.7 | 29.4 | |||||||||
| Cash and cash equivalents at end of period |
$ | 63.0 | $ | 63.0 | $ | 73.7 | ||||||
| Supplemental Disclosures |
||||||||||||
| Cash paid for interest, net of amount capitalized |
$ | 60.1 | $ | 49.5 | $ | 49.0 | ||||||
| Significant non-cash transaction: |
||||||||||||
| Property, plant and equipment accruals |
$ | 4.9 | $ | 19.8 | $ | 5.6 | ||||||
See Notes to Financial Statements.
F-5
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Index to Financial Statements
GULFSTREAM NATURAL GAS SYSTEM, L.L.C.
STATEMENTS OF MEMBERS’ EQUITY AND COMPREHENSIVE INCOME
| Spectra Energy Corp |
Spectra Energy Partners, LP |
The Williams Companies, Inc. |
Total | |||||||||||||
| (In millions) | ||||||||||||||||
| Balance December 31, 2006 |
$ | 391.0 | $ | — | $ | 391.1 | $ | 782.1 | ||||||||
| Net income attributable to the period January 1, 2007 through July 2, 2007 |
17.3 | — | 17.2 | 34.5 | ||||||||||||
| Net income attributable to the period July 3, 2007 through December 31, 2007 |
15.5 | 14.9 | 30.5 | 60.9 | ||||||||||||
| Reclassification of cash flow hedges into earnings attributable to the period January 1, 2007 through July 2, 2007 |
(0.3 | ) | — | (0.3 | ) | (0.6 | ) | |||||||||
| Reclassification of cash flow hedges into earnings attributable to the period July 3, 2007 through December 31, 2007 |
(0.2 | ) | (0.2 | ) | (0.3 | ) | (0.7 | ) | ||||||||
| Total comprehensive income |
94.1 | |||||||||||||||
| Ownership change |
(197.1 | ) | 197.1 | — | — | |||||||||||
| Capital contributions from members |
20.3 | 17.9 | 38.2 | 76.4 | ||||||||||||
| Distributions to members |
(21.2 | ) | (13.1 | ) | (34.3 | ) | (68.6 | ) | ||||||||
| Attributed deferred tax benefit |
0.2 | 0.1 | 0.2 | 0.5 | ||||||||||||
| Balance December 31, 2007 |
225.5 | 216.7 | 442.3 | 884.5 | ||||||||||||
| Net income |
28.3 | 27.1 | 55.4 | 110.8 | ||||||||||||
| Reclassification of cash flow hedges into earnings |
(0.3 | ) | (0.3 | ) | (0.7 | ) | (1.3 | ) | ||||||||
| Total comprehensive income |
109.5 | |||||||||||||||
| Capital contributions from members |
45.7 | 44.0 | 89.7 | 179.4 | ||||||||||||
| Distributions to members |
(29.7 | ) | (28.5 | ) | (58.2 | ) | (116.4 | ) | ||||||||
| Attributed deferred tax benefit |
0.4 | 0.3 | 0.7 | 1.4 | ||||||||||||
| Balance December 31, 2008 |
269.9 | 259.3 | 529.2 | 1,058.4 | ||||||||||||
| Net income |
31.6 | 30.4 | 62.0 | 124.0 | ||||||||||||
| Reclassification of cash flow hedges into earnings |
(0.3 | ) | (0.3 | ) | (0.7 | ) | (1.3 | ) | ||||||||
| Total comprehensive income |
122.7 | |||||||||||||||
| Capital contributions from members |
10.3 | 9.8 | 20.1 | 40.2 | ||||||||||||
| Distributions to members |
(113.5 | ) | (109.0 | ) | (222.6 | ) | (445.1 | ) | ||||||||
| Attributed deferred tax benefit |
— | — | 0.1 | 0.1 | ||||||||||||
| Balance December 31, 2009 |
$ | 198.0 | $ | 190.2 | $ | 388.1 | $ | 776.3 | ||||||||
See Notes to Financial Statements.
F-6
Table of Contents
Index to Financial Statements
GULFSTREAM NATURAL GAS SYSTEM, L.L.C.
Notes to Financial Statements
1. Summary of Operations and Significant Accounting Policies
Nature of Operations. Gulfstream Natural Gas System, L.L.C. (collectively, “we”, “our”, “us” and “company”) owns an approximate 745-mile interstate natural gas pipeline system and is owned 25.5% by a subsidiary of Spectra Energy Corp (Spectra Energy), 24.5% by Spectra Energy Partners, LP (Spectra Energy Partners) and 50% by a subsidiary of The Williams Companies, Inc. (Williams). We are operated under joint management by Spectra Energy, which provides the business functions, and Williams, which provides the technical functions. We transport natural gas from Mississippi and Alabama, crossing the Gulf of Mexico to markets in central and southern Florida. Our interstate natural gas transmission operations are subject to the rules and regulations of the Federal Energy Regulatory Commission (FERC). We were formed on May 17, 1999 as a Delaware limited liability company.
On July 2, 2007, immediately prior to the closing of Spectra Energy Partners’ initial public offering (IPO), Spectra Energy contributed to Spectra Energy Partners a 24.5% interest in us. Spectra Energy indirectly owned 100% of Spectra Energy Partners prior to the closing of the IPO.
Basis of Presentation. The financial statements reflect the results of operations, financial position and cash flows of our company. The financial statements do not include any of the assets, liabilities, revenues or expenses of the members.
Use of Estimates. To conform with generally accepted accounting principles (GAAP) in the United States, we make estimates and assumptions that affect the amounts reported in the Financial Statements and Notes to Financial Statements. Although these estimates are based on our best available knowledge at the time, actual results could differ.
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 in the rate-setting process in a period different from the period in which the amounts would be recorded by an unregulated enterprise. Accordingly, we record assets and liabilities that result from the regulated ratemaking process that 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 applicable to other regulated entities. Based on this continual assessment, we believe our existing regulatory assets are probable of recovery. These regulatory assets and liabilities are primarily classified in the Balance Sheets as Other Current Assets, Regulatory Assets and Deferred Debits, and Current Liabilities. We periodically 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 3 for further discussion.
Revenue Recognition. Revenues from the transportation of natural gas are recognized when the service is provided. Revenues related to these services provided but not yet billed are estimated each month. These estimates are generally based on contract data, regulatory information and preliminary throughput and allocation measurements. Final bills for the current month are billed and collected in the following month. Differences between actual and estimated unbilled revenues are immaterial.
F-7
Table of Contents
Index to Financial Statements
Customers accounting for 10% or more of revenues during 2009, 2008 and 2007 are as follows:
| % of Revenues | |||||||||
| Customer |
2009 | 2008 | 2007 | ||||||
| Florida Power & Light Company |
52 | % | 49 | % | 50 | % | |||
| Florida Power Corporation |
27 | 25 | 22 | ||||||
| TECO Energy and affiliates |
(a | ) | 10 | 10 | |||||
| (a) | Percentage less than 10%. |
Allowance for Funds Used During Construction (AFUDC). AFUDC, which represents the estimated debt and equity costs of capital funds necessary to finance the construction and expansion of certain new regulated facilities, consists of two components, an equity component and an interest expense component. The equity component is a non-cash item. AFUDC is capitalized as a component of Property, Plant and Equipment cost, with offsetting credits to the Statements of Operations through Other Income and Expenses, Net for the equity component and Interest Expense for the interest expense component. After construction is completed, we are permitted to recover these costs through inclusion in the rate base and in the depreciation provision. The total amount of AFUDC included in the Statements of Operations was $0.9 million in 2009 (an equity component of $0.6 million and an interest expense component of $0.3 million), $11.6 million in 2008 (an equity component of $7.8 million and an interest expense component of $3.8 million) and $2.7 million in 2007 (an equity component of $1.7 million and an interest expense component of $1.0 million).
Income Taxes. We are not subject to income tax, but rather our taxable income or loss is reported on the respective income tax returns of our members. Accordingly, there is no federal tax provision in these financial statements. Since we are not responsible for the attributed income taxes, amounts related to the tax gross-up of AFUDC equity are carried in the individual capital accounts of our members. The deferred income tax effect of the AFUDC equity gross up of $24.4 million at December 31, 2009 and $24.3 million at December 31, 2008 is classified in the Balance Sheets as Regulatory Assets and Deferred Debits.
Cash and Cash Equivalents. Highly liquid investments with original maturities of three months or less at the date of acquisition are considered cash equivalents.
Inventory. Inventory consists primarily of other materials and supplies and is recorded at cost, using average cost.
Natural Gas Imbalances. The Balance Sheets include in-kind balances as a result of differences in gas volumes received and delivered for customers. Since settlement of imbalances is in-kind, changes in these balances do not have an effect on our Statements of Cash Flows. Natural gas volumes owed to or by us are valued at natural gas market index prices as of the balance sheet dates.
Cash Flow Hedges. In 2005, we entered into derivative transactions that are hedges of the future cash flows of forecasted transactions (cash flow hedges). For all hedge contracts, we provide 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 . We document hedging activity by transaction type (i.e. swaps) and risk management strategy (i.e. interest rate risk).
Changes in the fair value of a derivative designated and qualified as a cash flow hedge, to the extent effective, are included in Statements of Members’ Equity and Comprehensive Income as Accumulated Other Comprehensive Income (AOCI) until earnings are affected by the hedged transaction. We discontinue hedge accounting prospectively when it is determined that a derivative no longer qualifies as an effective hedge, or when it is no longer probable that the hedged forecasted transaction will occur. When hedge accounting is discontinued because the derivative no longer qualifies as an effective hedge, the derivative is subject to the mark-to-market model of accounting (MTM Model) prospectively. Gains and losses related to discontinued
F-8
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Index to Financial Statements
hedges that were previously accumulated in AOCI will remain in AOCI until the underlying contract is reflected in earnings; unless it is probable that the hedged forecasted transaction will not occur at which time associated deferred amounts in AOCI are immediately recognized in current earnings. All derivatives designated and accounted for as hedges are classified in the same category as the item being hedged in the Statements of Cash Flows. In addition, all components of each derivative gain or loss are included in the assessment of hedge effectiveness.
When available, quoted market prices or prices obtained through external sources are used to measure a contract’s fair value.
Property, Plant and Equipment. Property, plant and equipment are 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 cost of renewals and betterments that extend the useful life or increase the expected output of property, plant and equipment is also capitalized. The cost of repairs, replacements and major maintenance projects that do not extend the useful life or increase the expected output of property, plant and equipment is expensed as incurred. Depreciation is generally computed over the asset’s estimated useful life using the straight-line method.
When we retire regulated property, plant and equipment, we charge the original cost plus the cost of retirement, less salvage value, to accumulated depreciation and amortization. When we sell entire regulated operating units, or retire or sell non-regulated properties, the cost is removed from the property account and the related accumulated depreciation and amortization accounts are reduced. Any gain or loss is recorded in earnings, unless otherwise required by the FERC.
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 initially included in operating expenses. If and when it is determined that recovery of such costs through regulated revenues of the completed project is probable, the inception-to-date costs of the project are recognized as Property, Plant and Equipment and operating expenses are reduced.
Unamortized Debt Expense. Debt expenses incurred with the issuance of outstanding long-term debt are amortized over the terms of the debt issues. Any call premiums or unamortized expenses associated with refinancing higher-cost debt obligations to finance regulated assets and operations are amortized consistent with regulatory treatment of those items, where appropriate.
New Accounting Pronouncements — 2009. The following new accounting pronouncements were adopted during 2009 and the effect of such adoption, if applicable, has been presented in the accompanying Financial Statements:
ASC 105, “Generally Accepted Accounting Principles” (previously Statement of Financial Accounting Standards (SFAS) No. 168, “The FASB Accounting Standards CodificationTM and the Hierarchy of Generally Accepted Accounting Principles–A Replacement of FASB Statement No. 162”). This accounting standard results in the Financial Accounting Standards Board (FASB) Accounting Standards Codification (the Codification) becoming the source of authoritative U.S. GAAP recognized by the FASB to be applied by nongovernmental entities. Rules and interpretive releases of the Securities and Exchange Commission (SEC) are also considered sources of authoritative GAAP for SEC registrants. The Codification supersedes all then-existing non-SEC accounting and reporting standards. All other nongrandfathered, non-SEC accounting literature not included in the Codification is nonauthoritative. The adoption of the provisions of this accounting standard did not change the application of existing GAAP for us, and as a result, did not have any impact on our results of operations, financial position or cash flows.
F-9
Table of Contents
Index to Financial Statements
ASC 820, “Fair Value Measurement and Disclosures” (previously SFAS No. 157, “Fair Value Measurements”). This accounting standard defines fair value, establishes a framework for measuring fair value in GAAP and expands disclosures about fair value measurements. The FASB issued an amendment to this standard which delayed its effective date for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). The adoption of the provisions of this amended standard on January 1, 2009 did not have any impact on our results of operations, financial position or cash flows.
ASC 805, “Business Combinations” (previously SFAS 141R, “Business Combinations”). This accounting standard requires an acquiring entity in a business combination to recognize all and only the assets acquired and liabilities assumed in the transaction, establishes the acquisition-date fair value as the measurement objective for all assets acquired and liabilities assumed, and requires the acquirer to disclose to investors and other users all of the information they need to evaluate and understand the nature and financial effect of the business combination. This accounting standard applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. The adoption of the provisions of this standard on January 1, 2009 did not have an impact on our results of operations, financial position or cash flows.
ASC 815-10, “Derivatives and Hedging — Overall” (previously SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133”). This accounting standard expands the disclosure requirements related to derivative instruments and hedging activities with the intent to provide users of financial statements an enhanced understanding of how and why derivative instruments are used, how derivative instruments and related hedged items are accounted for and how they affect an entity’s financial position, financial performance and cash flows. We adopted the provisions of this standard effective January 1, 2009 as required.
ASC 275-10, “Risks and Uncertainties — Overall” and ASC 350-30, “Intangibles–Goodwill and Other — General Intangible Other than Goodwill” (previously FASB Staff Position (FSP) No. FAS 142-3, “Determination of the Useful Life of Intangible Assets”). These accounting standards amend the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset. The adoption of the provisions of these standards on January 1, 2009 had no impact on our results of operations, financial position or cash flows.
ASC 855-10, “Subsequent Events — Overall” (previously SFAS No. 165, “Subsequent Events”). This accounting standard establishes general standards for the accounting for and disclosure of events that occur subsequent to the balance sheet date but before the financial statements of an entity are issued or are available to be issued. The adoption of the provisions of this standard effective June 30, 2009 did not have any impact on our results of operations, financial position or cash flows.
2008 and 2007. There were no significant accounting pronouncements adopted during 2008 that had a material impact on our results of operations, financial position or cash flows.
Pending. The following new accounting pronouncements have been issued, but have not yet been adopted as of December 31, 2009:
ASC 810-10, “Consolidations-Overall” (previously SFAS No. 167, “Amendments to FASB Interpretation No. 46(R)).” In June 2009, the FASB issued this accounting standard which is intended to address (1) the effects on certain consolidation provisions as a result of the elimination of the concept of qualifying special-purpose entities and (2) constituent concerns about the application of certain consolidation provisions including those in which the accounting and disclosures do not always provide timely and useful information about an enterprise’s involvement in a variable interest entity. For us, this accounting standard must be applied as of January 1, 2010. The adoption of the provisions of this standard did not have any impact on our results of operations, financial position or cash flows.
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Index to Financial Statements
| 2. | Transactions with Affiliates |
Gulfstream Management & Operating Services, L.L.C. (GMOS), owned 50% by an affiliate of Spectra Energy and 50% by an affiliate of Williams, provides management, construction and operating services pursuant to agreements entered into with us and with affiliates of Spectra Energy and Williams. GMOS bills us for services rendered including labor and benefit costs, employee expenses, overhead costs and in some cases, third-party costs. Such amounts are reflected in the Statements of Operations as Operating, Maintenance and Other — Affiliates or in the Balance Sheets as Property, Plant and Equipment, as appropriate.
Transactions with affiliates are summarized in the tables below:
Statements of Operations
| 2009 | 2008 | 2007 | |||||||
| (in millions) | |||||||||
| Operating, maintenance and other expenses |
$ | 14.6 | $ | 12.6 | $ | 9.2 | |||
Balance Sheets
| December 31, | ||||||
| 2009 | 2008 | |||||
| (in millions) | ||||||
| Property, plant and equipment(a) |
$ | 3.1 | $ | 10.9 | ||
| Current assets — other |
1.7 | — | ||||
| Accounts payable |
2.3 | 1.4 | ||||
| (a) | Reflects additions to Property, Plant and Equipment billed from an affiliate in the respective year. |
| 3. | Regulatory Matters |
Regulatory Assets and Liabilities. We record assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for non-regulated entities. See Note 1 for further discussion.
Regulatory Assets and Liabilities
| December 31, | Recovery/Refund Period Ends | |||||||
| 2009 | 2008 | |||||||
| (in millions) | ||||||||
| Regulatory Assets(a) |
||||||||
| Regulatory asset related to income taxes(b) |
$ | 24.4 | $ | 24.3 | (c) | |||
| Gas purchase costs(d) |
2.2 | 1.0 | 2010 | |||||
| Total Regulatory Assets |
$ | 26.6 | $ | 25.3 | ||||
| Regulatory Liabilities(a) |
||||||||
| Gas purchase costs(e) |
$ | 3.7 | $ | — | 2010 | |||
| Total Regulatory Liabilities |
$ | 3.7 | $ | — | ||||
| (a) | All regulatory assets and liabilities are excluded from rate base unless otherwise noted. |
| (b) | Included in Regulatory Assets and Deferred Debits. |
| (c) | Amortized over the life of the related property, plant and equipment. |
| (d) | Included in Other Current Assets. |
| (e) | Included in Current Liabilities. |
Rate Related Information. Gulfstream operates under rates approved by FERC in 2007. In June 2007, the FERC issued an order approving our Phase III expansion project. That order also required us to file a Cost and Revenue Study three years after our Phase III facilities go in service. The projected filing date would be the fall of 2011.
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Index to Financial Statements
4. Property, Plant and Equipment
| Estimated Useful Life |
December 31, | |||||||||
| 2009 | 2008 | |||||||||
| (Years) | (in millions) | |||||||||
| Natural gas transmission |
60 | $ | 1,969.7 | $ | 1,844.7 | |||||
| Land |
— | 16.0 | 16.0 | |||||||
| Construction in process |
— | 6.8 | 88.7 | |||||||
| Other |
5-20 | 44.0 | 46.7 | |||||||
| Total property, plant and equipment |
2,036.5 | 1,996.1 | ||||||||
| Total accumulated depreciation |
(212.0 | ) | (178.1 | ) | ||||||
| Total net property, plant and equipment |
$ | 1,824.5 | $ | 1,818.0 | ||||||
All of our property, plant and equipment is regulated with estimated useful lives based on rates approved by the FERC. The composite weighted-average depreciation rates were 1.8% for 2009, 1.7% for 2008 and 1.8% for 2007.
5. Debt
Summary of Debt and Related Terms
| Year Due |
December 31, | |||||||||
| 2009 | 2008 | |||||||||
| (in millions) | ||||||||||
| Unsecured note payable, 5.56% |
2015 | $ | 500.0 | $ | 500.0 | |||||
| Unsecured note payable, 6.95% |
2016 | 300.0 | — | |||||||
| Unsecured note payable, 6.19% |
2025 | 350.0 | 350.0 | |||||||
| Unamortized debt discount |
(1.2 | ) | (0.4 | ) | ||||||
| Total long-term debt |
$ | 1,148.8 | $ | 849.6 | ||||||
All scheduled debt payments correspond to the year due and are not within the next five years.
On May 27, 2009, we issued $300.0 million aggregate principal amount of 6.95% Senior Notes due 2016. Net proceeds were distributed to our members based upon their ownership percentages.
6. Fair Value Measurements
The following table presents, for each of the fair value hierarchy levels, assets that are measured at fair value on a recurring basis:
| December 31, 2009 | ||||||||||||||
| Description |
Balance Sheet Caption |
Total | Level 1 | Level 2 | Level 3 | |||||||||
| (in millions) | ||||||||||||||
| Short-term money market securities |
Cash and cash equivalents | $ | 59.2 | $ | 59.2 | $ | — | $ | — | |||||
| Total Assets |
$ | 59.2 | $ | 59.2 | $ | — | $ | — | ||||||
| December 31, 2008 | ||||||||||||||
| Description |
Balance Sheet Caption |
Total | Level 1 | Level 2 | Level 3 | |||||||||
| (in millions) | ||||||||||||||
| Short-term money market securities |
Cash and cash equivalents | $ | 46.5 | $ | 46.5 | $ | — | $ | — | |||||
| Total Assets |
$ | 46.5 | $ | 46.5 | $ | — | $ | — | ||||||
F-12
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Index to Financial Statements
Level 1 valuations represent quoted unadjusted prices for identical instruments in active markets.
Financial Instruments. The fair value of our financial instruments, excluding derivatives included elsewhere in this Note, is summarized in the following table. Judgment is required in interpreting market data to develop the estimates of fair value. Accordingly, the estimates determined as of December 31, 2009 and 2008 are not necessarily indicative of the amounts we could have realized in current markets.
| December 31, | ||||||||||||
| 2009 | 2008 | |||||||||||
| Book Value | Approximate Fair Value |
Book Value | Approximate Fair Value | |||||||||
| (in millions) | ||||||||||||
| Long-term debt |
$ | 1,148.8 | $ | 1,190.4 | $ | 849.6 | $ | 748.1 | ||||
The fair value of cash and cash equivalents, accounts receivable and accounts payable are not materially different from their carrying amounts because of the short-term nature of these instruments or because stated rates approximate market rates.
During 2009, there were no adjustments to assets measured at fair value on a nonrecurring basis.
7. Hedging Activities and Credit Risk
Interest Rate (Cash Flow) Hedges. We are exposed to the impact of market fluctuations in interest rates. To protect from increasing interest rates and the resulting higher cost of the debt that was issued in 2005, we locked in existing interest rates by using financial derivatives (swaps) for hedge strategies. The total amount of the debt in 2005 was $850.0 million of which $500.0 million was hedged. The associated interest rate swaps were terminated on October 12, 2005, prior to the issuance of the related debt. These derivatives were initially recorded on the Balance Sheets at their fair value as AOCI. Deferred gains of $11.6 million in AOCI as of December 31, 2009 will continue to be amortized to interest expense over the term of the debt issued (November 2015.) The total amortization for 2009, 2008 and 2007 was $1.3 million.
Credit Risk. Our principal customers for natural gas transportation are utilities located throughout the state of Florida. We have concentrations of receivables from utilities throughout Florida. These concentrations of customers may affect our overall credit risk in that risk factors can negatively affect the credit quality of the entire sector. Where exposed to credit risk, we analyze the counterparties’ 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 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 transaction.
8. Commitments and Contingencies
General Insurance. We carry, either independently or through our owners, insurance consistent with companies engaged in similar commercial operations with similar type properties. Our insurance program includes (1) liability insurance covering our liabilities arising from bodily injury or property damage to third parties resulting from our operations including liabilities arising from the use of owned, non-owned and hired vehicles and (2) property insurance on an all-risk basis covering loss or damage to real and personal property owned or leased by our company. We also carry onshore business interruption insurance. All coverages are subject to certain deductibles, terms and conditions common for companies with similar types of operations.
Environmental. We are subject to various federal, state and local regulations regarding air and water quality, hazardous and solid waste disposals and other environmental matters. We believe there are no matters outstanding that upon resolution will have a material adverse effect on our results of operations, financial position or cash flows.
F-13
Table of Contents
Index to Financial Statements
Litigation. We are involved in legal, tax and regulatory proceedings in various forums, including matters regarding contracts, performance and other matters, arising in the ordinary course of business, some of which may involve substantial monetary amounts. We have insurance for certain of these losses should they be incurred. We believe that the final disposition of these proceedings will not have a material adverse effect on our results of operations, financial position or cash flows.
9. Subsequent Event
A distribution to members of $41.9 million was declared and paid on January 20, 2010.
We have evaluated significant events and transactions that occurred from January 1, 2010 through the date of this report and have determined that there were no events or transactions other than those disclosed in this report, if any, that would require recognition or disclosure in our Financial Statements for the year ended December 31, 2009.
F-14
Table of Contents
Index to Financial Statements
CONSOLIDATED FINANCIAL STATEMENTS OF
MARKET HUB PARTNERS HOLDING
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
F-15
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Index to Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Partners of Market Hub Partners Holding
Houston, Texas
We have audited the accompanying consolidated balance sheets of Market Hub Partners Holding and subsidiaries (the “Partnership”) as of December 31, 2009 and 2008, and the related consolidated statements of operations, partners’ capital, and cash flows for each of the three years in the period ended December 31, 2009. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards as established by the Auditing Standards Board (United States) and in accordance with the auditing standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Market Hub Partners Holding and subsidiaries as of December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009 in conformity with accounting principles generally accepted in the United States of America.
/S/ Deloitte & Touche LLP
Houston, Texas
March 11, 2010
F-16
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Index to Financial Statements
CONSOLIDATED STATEMENTS OF OPERATIONS
(In millions)
| Years Ended December 31, | |||||||||
| 2009 | 2008 | 2007 | |||||||
| Operating Revenues |
|||||||||
| Salt cavern storage |
$ | 96.8 | $ | 82.6 | $ | 71.0 | |||
| Salt cavern storage — affiliates |
3.6 | 3.6 | 3.6 | ||||||
| Hub services and other |
10.3 | 5.6 | 9.9 | ||||||
| Hub services and other — affiliates |
4.8 | 6.2 | 6.8 | ||||||
| Total operating revenues |
115.5 | 98.0 | 91.3 | ||||||
| Operating Expenses |
|||||||||
| Operating, maintenance and other |
8.6 | 6.5 | 18.8 | ||||||
| Operating, maintenance and other — affiliates |
10.8 | 10.4 | 2.5 | ||||||
| Depreciation and amortization |
12.1 | 10.6 | 9.1 | ||||||
| Property and other taxes |
3.2 | 3.1 | 2.3 | ||||||
| Total operating expenses |
34.7 | 30.6 | 32.7 | ||||||
| Gains on Sales of Other Assets |
— | — | 7.0 | ||||||
| Operating Income |
80.8 | 67.4 | 65.6 | ||||||
| Other Income and Expenses |
— | 0.2 | — | ||||||
| Interest Income |
— | 0.2 | — | ||||||
| Interest Income — Affiliates |
0.3 | 2.9 | 2.3 | ||||||
| Interest Expense — Affiliates |
0.1 | 1.0 | 3.6 | ||||||
| Earnings Before Income Taxes |
81.0 | 69.7 | 64.3 | ||||||
| Income Tax Expense |
0.2 | 0.4 | 0.1 | ||||||
| Net Income |
$ | 80.8 | $ | 69.3 | $ | 64.2 | |||
See Notes to Consolidated Financial Statements.
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Index to Financial Statements
CONSOLIDATED BALANCE SHEETS
(In millions)
| December 31, | ||||||
| 2009 | 2008 | |||||
| ASSETS | ||||||
| Current Assets |
||||||
| Cash and cash equivalents |
$ | 20.2 | $ | 18.3 | ||
| Receivables (net of allowance for doubtful accounts of less than $0.1 million at December 31, 2009 and 2008) |
10.3 | 8.2 | ||||
| Receivables — affiliates |
1.4 | 1.7 | ||||
| Natural gas imbalance receivables |
0.7 | 3.8 | ||||
| Natural gas imbalance receivables — affiliates |
9.6 | 10.3 | ||||
| Notes receivable — affiliates |
55.0 | 100.0 | ||||
| Other |
1.3 | 1.1 | ||||
| Total current assets |
98.5 | 143.4 | ||||
| Other Assets |
||||||
| Goodwill |
200.5 | 200.5 | ||||
| Other assets |
0.2 | 0.1 | ||||
| Total other assets |
200.7 | 200.6 | ||||
| Property, Plant and Equipment |
||||||
| Cost |
553.2 | 501.9 | ||||
| Less accumulated depreciation and amortization |
90.2 | 78.9 | ||||
| Net property, plant and equipment |
463.0 | 423.0 | ||||
| Total Assets |
$ | 762.2 | $ | 767.0 | ||
| LIABILITIES AND PARTNERS’ CAPITAL |
||||||
| Current Liabilities |
||||||
| Accounts payable |
$ | 0.7 | $ | 7.6 | ||
| Accounts payable — affiliates |
2.5 | 9.4 | ||||
| Taxes accrued |
1.2 | 2.0 | ||||
| Interest accrued — affiliates |
— | 7.0 | ||||
| Natural gas imbalance payables |
8.3 | 13.8 | ||||
| Natural gas imbalance payables — affiliates |
2.3 | 1.3 | ||||
| Collateral liabilities |
2.4 | 2.7 | ||||
| Collateral liabilities — affiliates |
40.0 | 80.0 | ||||
| Other |
0.2 | 1.8 | ||||
| Total current liabilities |
57.6 | 125.6 | ||||
| Deferred Credits and Other Liabilities |
||||||
| Advances payable — affiliates |
— | 1.0 | ||||
| Total deferred credits and other liabilities |
— | 1.0 | ||||
| Commitments and Contingencies |
||||||
| Partners’ Capital |
704.6 | 640.4 | ||||
| Total Liabilities and Partners’ Capital |
$ | 762.2 | $ | 767.0 | ||
See Notes to Consolidated Financial Statements.
F-18
Table of Contents
Index to Financial Statements
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
| Years Ended December 31, | ||||||||||||
| 2009 | 2008 | 2007 | ||||||||||
| CASH FLOWS FROM OPERATING ACTIVITIES |
||||||||||||
| Net income |
$ | 80.8 | $ | 69.3 | $ | 64.2 | ||||||
| Adjustments to reconcile net income to net cash provided by operating activities: |
||||||||||||
| Depreciation and amortization |
12.1 | 10.6 | 9.1 | |||||||||
| Gains on sales of other assets |
— | — | (7.0 | ) | ||||||||
| Decrease (increase) in: |
||||||||||||
| Receivables |
(2.1 | ) | (0.7 | ) | 2.9 | |||||||
| Receivables — affiliates |
0.3 | 0.8 | — | |||||||||
| Other current assets |
(0.8 | ) | (0.7 | ) | 0.5 | |||||||
| Other, assets |
(0.1 | ) | 0.1 | 4.5 | ||||||||
| Increase (decrease) in: |
||||||||||||
| Accounts payable |
0.2 | (2.6 | ) | 5.1 | ||||||||
| Accounts payable — affiliates |
(6.9 | ) | 5.6 | 1.3 | ||||||||
| Taxes accrued |
(0.8 | ) | 0.2 | (2.2 | ) | |||||||
| Interest accrued — affiliates |
(7.0 | ) | 1.0 | 3.4 | ||||||||
| Collateral liabilities |
(0.3 | ) | 0.5 | (1.4 | ) | |||||||
| Collateral liabilities — affiliates |
(40.0 | ) | — | — | ||||||||
| Other current liabilities |
(1.7 | ) | (1.3 | ) | (2.4 | ) | ||||||
| Net cash provided by operating activities |
33.7 | 82.8 | 78.0 | |||||||||
| CASH FLOWS FROM INVESTING ACTIVITIES |
||||||||||||
| Capital expenditures |
(59.2 | ) | (89.1 | ) | (49.7 | ) | ||||||
| Net decrease (increase) in advances receivable — affiliates |
— | — | 75.5 | |||||||||
| Net increase (decrease) in advances payable — affiliates |
0.1 | (0.1 | ) | 1.1 | ||||||||
| Collections from notes receivable—affiliates |
59.0 | — | — | |||||||||
| Issuances of notes receivable—affiliates |
(14.0 | ) | — | (100.0 | ) | |||||||
| Net proceeds from insurance claim — affiliates |
— | — | 9.2 | |||||||||
| Net cash used in investing activities |
(14.1 | ) | (89.2 | ) | (63.9 | ) | ||||||
| CASH FLOWS FROM FINANCING ACTIVITIES |
||||||||||||
| Distributions to partners |
(71.5 | ) | (86.3 | ) | (11.7 | ) | ||||||
| Capital contributions from partners |
53.8 | 89.3 | 19.3 | |||||||||
| Net cash provided by (used in) financing activities |
(17.7 | ) | 3.0 | 7.6 | ||||||||
| Net increase (decrease) in cash and cash equivalents |
1.9 | (3.4 | ) | 21.7 | ||||||||
| Cash and cash equivalents at beginning of period |
18.3 | 21.7 | — | |||||||||
| Cash and cash equivalents at end of period |
$ | 20.2 | $ | 18.3 | $ | 21.7 | ||||||
| Supplemental Disclosures |
||||||||||||
| Cash paid for interest—affiliates |
$ | 7.1 | $ | — | $ | — | ||||||
| Cash paid for income taxes |
0.5 | — | — | |||||||||
| Significant non-cash transactions: |
||||||||||||
| Transfers of assets to parent |
— | — | 19.6 | |||||||||
| Deemed contributions from parent |
(1.1 | ) | — | — | ||||||||
| Property, plant and equipment noncash accruals |
0.1 | 7.3 | 1.0 | |||||||||
| Intercompany property, plant and equipment transfers |
— | — | 4.7 | |||||||||
See Notes to Consolidated Financial Statements.
F-19
Table of Contents
Index to Financial Statements
CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
(In millions)
| Spectra Energy Corp |
Spectra Energy Partners, LP |
Total | ||||||||||
| Balance December 31, 2006 |
$ | 515.9 | $ | — | $ | 515.9 | ||||||
| Net income attributable to the period January 1, 2007 through July 2, 2007 |
29.1 | — | 29.1 | |||||||||
| Transfers of assets to parent |
(19.6 | ) | — | (19.6 | ) | |||||||
| Ownership change |
(262.7 | ) | 262.7 | — | ||||||||
| Net income attributable to the period July 3, 2007 through December 31, 2007 |
17.5 | 17.6 | 35.1 | |||||||||
| Capital contributions from partners |
9.6 | 9.7 | 19.3 | |||||||||
| Distributions to partners |
(5.8 | ) | (5.9 | ) | (11.7 | ) | ||||||
| Balance December 31, 2007 |
284.0 | 284.1 | 568.1 | |||||||||
| Net income |
34.7 | 34.6 | 69.3 | |||||||||
| Capital contributions from partners |
44.6 | 44.7 | 89.3 | |||||||||
| Distributions to partners |
(43.1 | ) | (43.2 | ) | (86.3 | ) | ||||||
| Balance December 31, 2008 |
320.2 | 320.2 | 640.4 | |||||||||
| Net income |
40.4 | 40.4 | 80.8 | |||||||||
| Capital contributions from partners |
26.9 | 26.9 | 53.8 | |||||||||
| Distributions to partners |
(35.7 | ) | (35.8 | ) | (71.5 | ) | ||||||
| Deemed contributions from parent |
0.6 | 0.5 | 1.1 | |||||||||
| Balance December 31, 2009 |
$ | 352.4 | $ | 352.2 | $ | 704.6 | ||||||
See Notes to Consolidated Financial Statements.
F-20
Table of Contents
Index to Financial Statements
Notes to Consolidated Financial Statements
1. Summary of Operations and Significant Accounting Policies
Nature of Operations. Market Hub Partners Holding (collectively, “we”, “our”, and “us”), owns and operates two natural gas storage facilities: Moss Bluff, located near Houston, Texas and Egan, located in Acadia Parish, Louisiana. Our facilities provide producers, end-users, local distribution companies, pipelines and energy marketers with high deliverability storage services, as well as hub services, such as park and loan services, wheeling and title transfer. Our Egan facilities are subject to the rules and regulations of the Federal Energy Regulatory Commission (FERC). Moss Bluff is subject to oversight by the Texas Railroad Commission as an intrastate storage company. Moss Bluff, as a Hinshaw pipeline, must also comply with certain requirements under the FERC regulations.
Until July 2, 2007, we were a Delaware limited liability company that was wholly owned by Spectra Energy Corp (Spectra Energy). On July 2, 2007, immediately prior to the closing of Spectra Energy Partners, LP (Spectra Energy Partners) initial public offering (IPO), we were converted to a Delaware general partnership and Spectra Energy contributed 50% of its 100% ownership of us to Spectra Energy Partners.
Basis of Presentation. The Consolidated Financial Statements reflect the consolidated results of operations, financial position and cash flows of us and our subsidiaries. The Consolidated Financial Statements do not include any of the assets, liabilities, revenues or expenses of our partners.
Use of Estimates. To conform with generally accepted accounting principles (GAAP) in the United States, we make estimates and assumptions that affect the amounts reported in the Consolidated Financial Statements and Notes to Consolidated Financial Statements. Although these estimates are based on our best available knowledge at the time, actual results could differ.
Revenue Recognition. Revenues from the storage of natural gas and related hub services are recognized when the service is provided. Revenues related to these services provided but not yet billed are estimated each month. These estimates are generally based on contract data, regulatory information and preliminary storage and allocation measurements. Final bills for the current month are billed and collected in the following month. Differences between actual and estimated unbilled revenues are immaterial.
Customers accounting for 10% or more of consolidated revenues during 2009, 2008 or 2007 are as follows:
| % of Consolidated Revenues | |||||||||
| Customer |
2009 | 2008 | 2007 | ||||||
| Spectra Energy |
(a | ) | 10 | % | 11 | % | |||
| (a) | Percentage below 10% |
Income Taxes. We are not subject to federal income tax, but rather our taxable income or loss is reported on the respective income tax returns of our partners. Accordingly, there is no income tax provision recorded for us except Texas margin tax.
Cash and Cash Equivalents. Highly liquid investments with original maturities of three months or less at the date of acquisition are considered cash equivalents.
Inventory. Inventory consists primarily of natural gas held in storage and is recorded at the lower of cost or market value, primarily determined using the average cost method.
Natural Gas Imbalances. The Consolidated Balance Sheets include in-kind balances as a result of differences in gas volumes received and delivered for customers. Since settlement of imbalances is in-kind, changes in these balances do not have an effect on our Consolidated Statements of Cash Flows. Natural gas volumes owed to or by us are valued at natural gas market index prices as of the balance sheet dates.
F-21
Table of Contents
Index to Financial Statements
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. Prior to 2009, we performed the annual impairment testing of goodwill using August 31 as the measurement date. Our financial and strategic planning process, including the preparation of long-term cash flow projections, commences in October and typically concludes in January of the following year. These long-term cash flow projections are a key component in performing our annual impairment test of goodwill. This planning cycle historically created significant constraints in the availability of both information and human resources needed to provide the appropriate projections to be used in the goodwill impairment test using the August 31 test date. Accordingly, effective with our 2009 annual impairment test, we changed our goodwill impairment test date from August 31 to April 1. We believe that using the April 1 date will alleviate the information and resource constraints that historically existed during the third quarter and will better coincide with the completion of our long-term financial projections. We believe that this accounting change is to an alternative accounting principle that is preferable under the circumstances and did not result in the delay, acceleration or avoidance of an impairment charge. We have determined that this change in accounting principle does not result in adjustments to our 2008 or 2007 financial statements when applied retrospectively as our base assumptions used in the August 31 measurement date would not have changed significantly had we used April 1 as the measurement date. We completed our goodwill impairment test as of April 1, 2009 and no impairments were identified. No triggering events or changes in circumstances occurred during the period April 1, 2009 (our testing date) through December 31, 2009 that would warrant re-testing for goodwill impairment.
Impairment testing of goodwill consists of a two-step process. The first step involves a comparison of the implied fair value of a reporting unit with its carrying amount. If the carrying amount exceeds our fair value, the second step of the process involves a comparison of the fair value and the carrying value of the goodwill. If the carrying value of the goodwill exceeds the implied fair value of that goodwill, an impairment loss is recognized in an amount equal to the excess. Additional impairment tests are performed between the annual reviews if events or changes in circumstances make it more likely than not that our fair value is below our carrying amount.
We primarily use a discounted cash flow analysis to determine fair value. Key assumptions in the determination of fair value include the use of an appropriate discount rate and estimated future cash flows. In estimating cash flows, we incorporate expected long-term growth rates in key markets served by our operations, regulatory stability and the ability to renew contracts, as well as other factors that affect our revenue, expense and capital expenditure projections. We did not record any impairment of goodwill in 2009, 2008 or 2007, and there have been no additions, amortization or other changes in the carrying amount of goodwill during those years.
Property, Plant and Equipment. Property, plant and equipment are 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 cost of renewals and betterments that extend the useful life or increase the expected output of property, plant and equipment is also capitalized. The cost of repairs, replacements and major maintenance projects that do not extend the useful life or increase the expected output of property, plant and equipment, is expensed as incurred. Depreciation is generally computed over the asset’s estimated useful life using the straight-line method.
New Accounting Pronouncements — 2009. The following new accounting pronouncements were adopted during 2009 and the effect of such adoption, if applicable, has been presented in the accompanying Consolidated Financial Statements:
Accounting Standards Codification (ASC) 105, “Generally Accepted Accounting Principles” (previously Statement of Financial Accounting Standards (SFAS) No. 168, “The FASB Accounting Standards CodificationTM and the Hierarchy of Generally Accepted Accounting Principles — A Replacement of FASB Statement No. 162”). This accounting standard results in the Financial Accounting Standards Board (FASB) Accounting Standards Codification (the Codification) becoming the source of authoritative U.S. GAAP recognized by the FASB to be applied by nongovernmental entities. Rules and interpretive releases of the Securities and Exchange Commission
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Index to Financial Statements
(SEC) are also considered sources of authoritative GAAP for SEC registrants. The Codification supersedes all then-existing non-SEC accounting and reporting standards. All other nongrandfathered, non-SEC accounting literature not included in the Codification is nonauthoritative. The adoption of the provisions of this accounting standard did not change the application of existing GAAP for us, and as a result, did not have any impact on our consolidated results of operations, financial position or cash flows.
ASC 820, “Fair Value Measurement and Disclosures” (previously SFAS No. 157, “Fair Value Measurements”). This accounting standard defines fair value, establishes a framework for measuring fair value in GAAP and expands disclosures about fair value measurements. The FASB issued an amendment to this standard which delayed its effective date for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). The adoption of the provisions of this amended standard on January 1, 2009 for the measurement of our goodwill impairment test did not have any impact on our consolidated results of operations, financial position or cash flows.
ASC 805, “Business Combinations” (previously SFAS 141R, “Business Combinations”). This accounting standard requires an acquiring entity in a business combination to recognize all and only the assets acquired and liabilities assumed in the transaction, establishes the acquisition-date fair value as the measurement objective for all assets acquired and liabilities assumed, and requires the acquirer to disclose to investors and other users all of the information they need to evaluate and understand the nature and financial effect of the business combination. This standard applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. The adoption of the provisions of this standard on January 1, 2009 did not have an impact on our consolidated results of operations, financial position or cash flows.
ASC 275-10, “Risks and Uncertainties — Overall” and ASC 350-30, “Intangibles — Goodwill and Other — General Intangible Other than Goodwill” (previously FASB Staff Position (FSP) No. FAS 142-3, “Determination of the Useful Life of Intangible Assets”). These accounting standards amend the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset. The adoption of the provisions of these standards on January 1, 2009 had no impact on our consolidated results of operations, financial position or cash flows.
ASC 855-10, “Subsequent Events — Overall” (previously SFAS No. 165, “Subsequent Events”). This accounting standard establishes general standards for the accounting for and disclosure of events that occur subsequent to the balance sheet date but before the financial statements of an entity are issued or are available to be issued. The adoption of the provisions of this standard effective June 30, 2009 did not have any impact on our consolidated results of operations, financial position or cash flows.
2008 and 2007. There were no significant accounting pronouncements adopted during 2008 and 2007 that had a material impact on our consolidated results of operations, financial position or cash flows.
Pending. The following new accounting pronouncement was issued but not adopted as of December 31, 2009:
ASC 810-10, “Consolidations — Overall” (previously SFAS No. 167, “Amendments to FASB Interpretation No. 46(R)”). In June 2009, the FASB issued this accounting standard which is intended to address (1) the effects on certain consolidation provisions as a result of the elimination of the concept of qualifying special-purpose entities and (2) constituent concerns about the application of certain consolidation provisions including those in which the accounting and disclosures do not always provide timely and useful information about an enterprise’s involvement in a variable interest entity. For us, this accounting standard must be applied as of January 1, 2010. The adoption of the provisions of this standard did not have any impact on our consolidated results of operations, financial position or cash flows.
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Index to Financial Statements
2. Transactions with Affiliates
In the normal course of business, we provide storage and other services to Spectra Energy and its affiliates.
Operating, maintenance and other expenses include reimbursement of costs incurred by affiliates on behalf of us and allocations from Spectra Energy affiliates for various services and other costs. Affiliates charge such expenses based on the cost of actual services provided or using various allocation methodologies based on our percentage of assets, employees, earnings or other measures as compared to other affiliates.
Advances receivable from or payable to affiliates do not bear interest. Advances are carried as unsecured, open accounts and are not segregated between current and non-current amounts. Increases and decreases in advances generally result from the movement of funds to provide for our operations and capital expenditures.
Transactions with affiliates are summarized in the tables below:
Consolidated Statements of Operations
| 2009 | 2008 | 2007 | |||||||
| (in millions) | |||||||||
| Salt cavern storage |
$ | 3.6 | $ | 3.6 | $ | 3.6 | |||
| Hub services and other |
4.8 | 6.2 | 6.8 | ||||||
| Operating, maintenance and other |
10.8 | 10.4 | 2.5 | ||||||
| Gains on Sales of Other Assets |
— | — | 7.0 | ||||||
| Interest Income |
0.3 | 2.9 | 2.3 | ||||||
| Interest Expense |
0.1 | 1.0 | 3.6 | ||||||
Consolidated Balance Sheets
| December 31, | ||||||
| 2009 | 2008 | |||||
| (in millions) | ||||||
| Receivables |
$ | 1.4 | $ | 1.7 | ||
| Natural gas imbalance receivables |
9.6 | 10.3 | ||||
| Notes receivable |
55.0 | 100.0 | ||||
| Current assets — other |
0.4 | 0.8 | ||||
| Accounts payable |
2.5 | 9.4 | ||||
| Interest accrued |
— | 7.0 | ||||
| Natural gas imbalance payables |
2.3 | 1.3 | ||||
| Collateral liabilities |
40.0 | 80.0 | ||||
| Advances payable |
— | 1.0 | ||||
During 2007, we recorded $7.0 million of Gains on Sales of Other Assets within the Consolidated Statements of Operations, primarily reflecting property insurance proceeds received from affiliates associated with a 2004 cavern well-head fire at Moss Bluff.
In 2006, we received an $80.0 million security deposit from an affiliate for a gas loan contract with that affiliate. In 2009, we refunded $40.0 million of this security deposit to the affiliate based on a new gas loan contract. This contract will terminate in April 2010. We are required to pay a market rate of interest on the security deposit. Security deposits were $40.0 million and $80.0 million at December 31, 2009 and 2008, respectively, and are classified as Collateral Liabilities — Affiliates on the Consolidated Balance Sheets.
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Index to Financial Statements
Effective as of August 15, 2007, we received payment of advances receivable of $80.0 million and entered into five-year promissory notes with Spectra Energy Partners and Spectra Energy Capital, LLC, (Spectra Capital), a wholly owned subsidiary of Spectra Energy, to loan them up to $50.0 million each. The notes mature on August 15, 2012, however, any borrowings under the agreement are payable on demand and therefore have been classified within Current Assets in the Consolidated Balance Sheet. The promissory notes bear interest based on a one month London InterBank Offering Rate (LIBOR), and the interest rate at December 31, 2009 was 0.23%. As of December 31, 2009 and 2008, Spectra Energy Partners and Spectra Capital each had $27.5 million and $50.0 million of borrowings outstanding under the notes, respectively.
We received capital contributions from our partners of $53.8 million in 2009, $89.3 million in 2008 and $19.3 million in 2007. We made distributions to our partners of $71.5 million in 2009, $86.3 million in 2008 and $11.7 million in 2007.
In accordance with our formation agreements, we transferred certain balances to Spectra Energy on July 2, 2007. These balances were primarily comprised of accounts receivable and advances from Spectra Energy totaling $19.6 million in 2007 and $1.1 million in 2009. These assets and liabilities are classified in the Consolidated Statements of Partners’ Capital as Transfers of Assets to Parent and Deemed Contributions from Parent. These transactions were classified as noncash for purposes of the Consolidated Statements of Cash Flows.
| 3. | Property, Plant and Equipment |
| Estimated Useful Life |
December 31, | |||||||||
| 2009 | 2008 | |||||||||
| (years) | (in millions) | |||||||||
| Salt cavern storage facilities |
15-40 | $ | 510.0 | $ | 408.5 | |||||
| Land |
— | 12.4 | 12.4 | |||||||
| Construction in process |
— | 28.0 | 80.3 | |||||||
| Other |
5-40 | 2.8 | 0.7 | |||||||
| Total property, plant and equipment |
553.2 | 501.9 | ||||||||
| Total accumulated depreciation |
(90.2 | ) | (78.9 | ) | ||||||
| Total net property, plant and equipment |
$ | 463.0 | $ | 423.0 | ||||||
The composite weighted-average depreciation rates were 2.9% for 2009, 3.0% for 2008 and 2.9% for 2007.
| 4. | Credit Risk and Financial Instruments |
Credit Risk. Our principal customers for high deliverability natural gas storage services and hub services are pipelines, local distribution companies, producers, end-users, power generators and energy marketers. We have concentrations of receivables from these industry sectors. These concentrations of customers may affect our overall credit risk in that risk factors can negatively affect the credit quality of a particular sector. Where exposed to credit risk, we analyze the customers’ financial condition prior to entering into an agreement, establish credit limits and monitor the appropriateness of those limits on an ongoing basis. We also obtain parental guarantees, cash, letters of credit or other acceptable forms of security from customers, where appropriate based on our financial analysis of the customer and the regulatory or contractual terms and conditions applicable to each transaction.
Financial Instruments. The fair value of cash and cash equivalents, accounts receivable, notes receivable — affiliates and accounts payable are not materially different from their carrying amounts because of the short-term nature of these instruments or because the stated rates approximate market rates.
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Index to Financial Statements
| 5. | 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 regulations regarding air and water quality, hazardous and solid waste disposal, and other environmental matters. We believe there are no matters outstanding that will have a material adverse effect on our consolidated results of operations, financial position or cash flows.
Litigation. We are involved in legal, tax and regulatory proceedings in various forums including matters regarding contracts, performance and other matters, arising in the ordinary course of business, 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 adverse effect on our consolidated results of operations, financial position or cash flows.
| 6. | Subsequent Event |
A distribution to partners of $27.7 million was declared and paid on January 20, 2010.
We have evaluated significant events and transactions that occurred from January 1, 2010 through March 11, 2010 and have determined that there were no events or transactions other than those disclosed in this report, if any, that would require recognition or disclosure in our Consolidated Financial Statements for the year ended December 31, 2009.
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Index to Financial Statements
| 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). | |
| 3.1 | First Amended and Restated Agreement of Limited Partnership of Spectra Energy Partners, LP (filed as Exhibit 3.1 to Spectra Energy Partners, LP’s Form 8-K dated July 9, 2007). | |
| 3.2 | Amendment No. 1 to First Amended and Restated Agreement of Limited Partnership of Spectra Energy Partners, LP, dated April 11, 2008 (filed as Exhibit 10.1 to Spectra Energy Partners, LP’s Form 10-Q on May 14, 2008). | |
| 3.3 | Certificate of Limited Partnership of Spectra Energy Partners, LP (filed as Exhibit 3.1 to Spectra Energy Partner, LP’s Form S-1 on March 30, 2007, file no. 333-141687). | |
| 3.4 | First Amended and Restated Agreement of Limited Partnership Agreement of Spectra Energy Partners (DE) GP, LP (filed as Exhibit 3.2 to Spectra Energy Partners, LP’s Form 8-K dated July 9, 2007). | |
| 3.5 | Certificate of Limited Partnership of Spectra Energy Partners (DE) GP, LP (filed as Exhibit 3.3 to Spectra Energy Partner, LP’s Form S-1 on March 30, 2007, file no. 333-141687). | |
| 3.6 | First Amended and Restated Limited Liability Agreement of Spectra Energy Partners GP, LLC (filed as Exhibit 3.3 to Spectra Energy Partners, LP’s Form 8-K dated July 9, 2007). | |
| 3.7 | Certificate of Formation of Spectra Energy Partners GP, LLC (filed as Exhibit 3.5 to Spectra Energy Partner, LP’s Form S-1 on March 30, 2007, file no. 333-141687). | |
| 10.1 | Contribution, Conveyance and Assumption Agreement, dated July 2, 2007, by and among Spectra Energy Partners, LP, Spectra Energy Partners OLP, LP, Spectra Energy Partners GP, LLC, Spectra Energy Partners OLP GP, LLC, Spectra Energy Partners (DE) GP, LP, Spectra Energy Transmission, LLC, Spectra Energy Southeast Pipeline Corporation, East Tennessee Natural Gas, LLC, Egan Hub Storage, LLC, Moss Bluff Hub, LLC and Market Hub Partners Holding, LLC (filed as Exhibit 10.1 to Spectra Energy Partners, LP’s Form 8-K dated July 9, 2007). | |
| 10.2 | Omnibus Agreement, dated July 2, 2007, by and among Spectra Energy Partners, LP, Spectra Energy Partners (DE) GP, LP, Spectra Energy Partners GP, LLC and Spectra Energy Corp (filed as Exhibit 10.2 to Spectra Energy Partners, LP’s Form 8-K dated July 9, 2007). | |
| +10.3 | Long Term Incentive Plan of Spectra Energy Partners, LP (filed as Exhibit 10.3 to Spectra Energy Partners, LP’s Form 8-K dated July 9, 2007). | |
| +10.4 | Form of Phantom Unit Award Agreement under the Spectra Energy Partners, LP Long-Term Incentive Plan (filed as Exhibit 4.3 to Spectra Energy Partners, LP’s Form S-8 on July 2, 2007). | |
| 10.5 | General Partnership Agreement of Market Hub Partners Holding (filed as Exhibit 10.4 to Spectra Energy Partners, LP’s Form 8-K dated July 9, 2007). | |
| 10.6 | Credit Agreement, dated as of May 24, 2007 among Spectra Energy Partners OLP, LP, as the Borrower, Spectra Energy Partners, LP, as Parent Guarantor and Wachovia Bank, National Association, as Administrative Agent, Citibank, N.A., as Syndication Agent, and the other lenders party thereto (filed as Exhibit 10.6 to Spectra Energy Partner, LP’s Form 10-K/A on May 14, 2009). | |
Table of Contents
Index to Financial Statements
| Exhibit No. |
Exhibit Description | |
| 10.7 | First Amendment to Credit Agreement, dated as of September 30, 2007, by and among Spectra Energy Partners OLP, LP, as the Borrower, Spectra Energy Partners, LP, as Parent Guarantor and Wachovia Bank, National Association, as Administrative Agent, and the other lenders party thereto (filed as Exhibit 10.1 to Spectra Energy Partners, LP’s Form 8-K dated October 11, 2007). | |
| 10.8 | 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). | |
| 10.9 | 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 Partner, LP’s Form S-1/A on June 13, 2007, file no. 333-141687). | |
| 10.10 | Second Amended and Restated Limited Liability Company Agreement of Gulfstream Natural Gas System, L.L.C. (filed as Exhibit 10.6 to Spectra Energy Partner, LP’s Form S-1/A on June 4, 2007, file no. 333-141687). | |
| 10.11 | 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 Partner, LP’s Form 10-K/A on May 14, 2009). | |
| *12.1 | Computation of Ratio of Earnings to Fixed Charges. | |
| *21.1 | Subsidiaries of the Registrant. | |
| *23.1 | Consent of Deloitte & Touche LLP | |
| *23.2 | Consent of Deloitte & Touche LLP | |
| *23.3 | Consent of Deloitte & Touche LLP | |
| *24.1 | Power of Attorney. | |
| *31.1 | Certification of the Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |
| *31.2 | Certification of the Chief Financial Officer 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. | |
| * | Filed herewith. |
| + | Denotes management contract or compensatory plan or arrangement. |