Attached files
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
________________
Form 10-K
(Mark One)
|
R
|
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
|
|
For the fiscal year ended December 31, 2010
|
|
|
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 1-4101
Tennessee Gas Pipeline Company
(Exact Name of Registrant as Specified in Its Charter)
|
Delaware
|
74-1056569
|
|
(State or Other Jurisdiction of Incorporation or Organization)
|
(I.R.S. Employer Identification No.)
|
|
El Paso Building
|
|
|
1001 Louisiana Street
|
|
|
Houston, Texas
|
77002
|
|
(Address of Principal Executive Offices)
|
(Zip Code)
|
Telephone Number: (713) 420-2600
Securities registered pursuant to Section 12(b) of the Act: None
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 R
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes £ No R
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 R 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 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. R
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. (Check one):
|
Large accelerated filer £
|
Accelerated filer £
|
Non-accelerated filer R
(Do not check if a smaller reporting company)
|
Smaller Reporting Company £
|
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes £ No R
State the aggregate market value of the voting stock held by non-affiliates of the registrant: None
Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date.
Common Stock, par value $5 per share. Shares outstanding on February 25, 2011: 208
TENNESSEE GAS PIPELINE COMPANY MEETS THE CONDITIONS OF GENERAL INSTRUCTION I(1)(a) AND (b) TO FORM 10-K AND IS THEREFORE FILING THIS REPORT WITH A REDUCED DISCLOSURE FORMAT AS PERMITTED BY SUCH INSTRUCTION.
Documents Incorporated by Reference: None
TENNESSEE GAS PIPELINE COMPANY
|
Caption
|
Page
|
||
|
1
|
|||
|
5
|
|||
|
14
|
|||
|
14
|
|||
|
14
|
|||
|
14
|
|||
|
14
|
|||
|
*
|
|||
|
15
|
|||
|
21
|
|||
|
22
|
|||
|
44
|
|||
|
44
|
|||
|
44
|
|||
|
*
|
|||
|
*
|
|||
|
*
|
|||
|
*
|
|||
|
45
|
|||
|
46
|
|||
|
47
|
|||
____________
|
*
|
We have not included a response to this item in this document since no response is required pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.
|
|
|
Below is a list of terms that are common to our industry and used throughout this document: |
|
/d
|
=
|
per day
|
MMBtu
|
=
|
million British thermal units
|
|
|
BBtu
|
=
|
billion British thermal units
|
MMcf
|
=
|
million cubic feet
|
|
|
Bcf
|
=
|
billion cubic feet
|
TBtu
|
=
|
trillion British thermal units
|
|
|
LNG
|
=
|
liquefied natural gas
|
|
|
|
When we refer to cubic feet measurements, all measurements are at a pressure of 14.73 pounds per square inch.
When we refer to “us,” “we,” “our,” “ours,” or “the company,” we are describing Tennessee Gas Pipeline Company and/or our subsidiaries.
Overview and Strategy
We are a Delaware corporation incorporated in 1947, and an indirect wholly owned subsidiary of El Paso Corporation (El Paso). Our primary business consists of the interstate transportation and storage of natural gas. We conduct our business activities through our natural gas pipeline system and storage facilities as discussed below.
Our pipeline system and storage facilities operate under a tariff approved by the Federal Energy Regulatory Commission (FERC) that establishes rates, cost recovery mechanisms and other terms and conditions of services to our customers. The fees or rates established under our tariff are a function of our costs of providing services to our customers, including a reasonable return on our invested capital.
Our strategy is to enhance the value of our transportation and storage business by:
|
•
|
providing outstanding customer service;
|
|
•
|
successfully executing on time and on budget for our committed expansion projects;
|
|
•
|
developing new growth projects in our market and supply areas;
|
|
•
|
maintaining the integrity and ensuring the safety of our pipeline system and other assets;
|
|
•
|
optimizing our contract portfolio;
|
|
•
|
focusing on increasing utilization, efficiency and cost control in our operations; and
|
|
•
|
managing market segmentation and differentiation.
|
Pipeline System. Our pipeline system consists of approximately 14,100 miles of pipeline with a design capacity of approximately 7,208 MMcf/d. During 2010, 2009 and 2008, average throughput was 5,081 BBtu/d, 4,614 BBtu/d, and 4,864 BBtu/d. This multiple-line system begins in the natural gas producing regions of Louisiana, the Gulf of Mexico and south Texas and extends to the northeast section of the U.S., including the metropolitan areas of New York City and Boston. Our system also has interconnects at the U.S.-Mexico border and the U.S.-Canada border.
FERC Approved Project. As of December 31, 2010, we had the following significant FERC approved expansion project on our system. For a further discussion of other expansion projects, see Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations.
|
Project
|
Capacity
(MMcf/d)
|
Description
|
Anticipated
Completion or
In-Service Date
|
|||
|
300 Line Project
|
350
|
To add 128 miles of pipeline, and approximately 55,000 horsepower of compression at two new compressor stations and at certain existing compressor stations
|
November 2011
|
Underground Natural Gas Storage Facilities. Along our pipeline system, we have approximately 93 Bcf of underground working natural gas storage capacity. Of this amount, 29 Bcf is contracted from Bear Creek Storage Company, LLC (Bear Creek) located in Bienville Parish, Louisiana. Bear Creek is a joint venture equally owned by us and our affiliate, Southern Natural Gas Company (SNG). The facility has 58 Bcf of working storage capacity that is committed equally to SNG and us.
Markets and Competition
Our customers consist of natural gas distribution and industrial companies, electric generation companies, natural gas producers, other natural gas pipelines and natural gas marketing and trading companies. We provide transportation and storage services in both our natural gas supply and market areas. Our pipeline system connects with multiple pipelines that provide our customers with access to diverse sources of supply and various natural gas markets.
The natural gas industry is undergoing a major shift in supply sources. Production from conventional sources is declining while production from unconventional sources, such as shales, is rapidly increasing. This shift will affect the supply patterns, the flows and the rates that can be charged on pipeline systems. The impact will vary among pipelines according to the location and the number of competitors attached to these new supply sources. Our pipeline is connected to two major shale formations: the Haynesville shale in northern Louisiana and Texas and the Marcellus shale in Pennsylvania. It is possible that gas from these sources will increasingly displace receipts over time from traditional sources in south Texas and the Gulf of Mexico on our system. In addition, our system is near the Eagle Ford shale formation in south Texas, which could be a major source of supply into the system in the future and could impact the flows on the system and the array of shipper contracts.
Another change in the supply patterns is the reduction in imports from Canada. This decrease has been the result of declining production and increasing demand in Canada. This reduction has led to increased demand for domestic supplies and related transportation services over the last several years, a trend which is expected to continue in the future. The increase in demand for gas and transportation caused by the trend in Canada could be partially offset by imports of LNG. Imports of LNG have fluctuated in the past in response to changing gas prices within North America, Europe and Asia. LNG terminals and other regasification facilities can serve as alternate sources of supply for pipelines, enhancing their delivery capabilities and operational flexibility and complementing traditional supply transported into market areas. However, these LNG delivery systems also may compete with us for transportation of gas into market areas we serve.
Electric power generation has been the source of most of the growth in demand for natural gas over the last 10 years, and this trend is expected to continue in the future. The growth of natural gas in this sector is influenced by competition with coal and increased consumption of electricity as a result of recent economic growth. Short-term market shifts have been driven by relative costs of coal-fired generation versus gas-fired generation. A long-term market shift in the use of coal in power generation could be driven by environmental regulations. The future demand for natural gas could be increased by regulations limiting or discouraging coal use. However, natural gas demand could potentially be adversely affected by laws mandating or encouraging renewable power sources.
In response to changing market conditions, we have shifted from a traditional dependence solely on long-term contracts to an approach that balances short-term and long-term commitments. This shift, which can increase the volatility of our revenues, is due to changes in market conditions and competition driven by state utility deregulation, local distribution company mergers, new pipeline competition, shifts in supply sources, volatility in natural gas prices, demand for short-term capacity and new power generation markets.
We face competition in all our market areas and we compete with other interstate and intrastate pipelines for deliveries to multiple-connection customers who can take deliveries at alternative points. Natural gas delivered on our system competes with alternative energy sources used to generate electricity such as hydroelectric power, coal and fuel oil. In addition, we compete with pipelines and gathering systems for connection to new supply sources in Texas, the Gulf of Mexico, and the emerging shale basins.
For a further discussion of factors impacting our markets and competition, see Item 1A, Risk Factors.
Customers and Contracts
Our existing transportation and storage contracts expire at various times and in varying amounts of throughput capacity. Our ability to extend our existing customer contracts or remarket expiring contracted capacity is dependent on competitive alternatives, the regulatory environment at the federal, state and local levels and market supply and demand factors at the relevant dates these contracts are extended or expire. The duration of new or renegotiated contracts will be affected by current prices, competitive conditions and judgments concerning future market trends and volatility. Although we attempt to recontract or remarket our capacity at the maximum rates allowed under our tariff, we frequently enter into firm transportation contracts at amounts that are less than these maximum allowable rates to remain competitive.
The following table details our customer and contract information related to our pipeline system as of December 31, 2010. Firm customers reserve capacity on our pipeline system and storage facilities and are obligated to pay a monthly reservation or demand charge, regardless of the amount of natural gas they transport or store, for the term of their contracts. Interruptible customers are customers without reserved capacity that pay usage charges based on the volume of gas they transport, store, inject or withdraw.
|
Customer Information
|
Contract Information
|
|
|
Approximately 410 firm and interruptible customers.
|
Approximately 470 firm transportation contracts. Weighted average remaining contract term of approximately four years.
|
|
|
Major Customer:
National Grid USA and subsidiaries
(495 BBtu/d)
(332 BBtu/d)
|
Expire in 2012-2013.
Expire in 2014-2029.
|
Regulatory Environment
Our interstate natural gas transmission system and storage operations are regulated by the FERC under the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and the Energy Policy Act of 2005. We operate under tariffs approved by the FERC that establish rates, cost recovery mechanisms and other terms and conditions of services to our customers. The rates established under our tariffs are a function of our costs of providing services to our customers, including a reasonable return on our invested capital. Generally, the FERC’s authority extends to:
|
•
|
rates and charges for natural gas transportation and storage;
|
|
•
|
certification and construction of new facilities;
|
|
•
|
extension or abandonment of services and facilities;
|
|
•
|
maintenance of accounts and records;
|
|
•
|
relationships between pipelines and certain affiliates;
|
|
•
|
terms and conditions of service;
|
|
•
|
depreciation and amortization policies;
|
|
•
|
acquisition and disposition of facilities; and
|
|
•
|
initiation and discontinuation of services.
|
Our interstate pipeline system is also subject to federal, state and local safety and environmental statutes and regulations of the U.S. Department of Transportation and the U.S. Department of the Interior. We have ongoing inspection programs designed to keep our facilities in compliance with pipeline safety and environmental requirements and we believe that our system is in material compliance with the applicable regulations. For a further discussion of the potential impact of regulatory matters on us, see Item 1A, Risk Factors.
Environmental
A description of our environmental remediation activities is included in Part II, Item 8, Financial Statements and Supplementary Data, Note 8, and is incorporated herein by reference.
Employees
As of February 21, 2011, we had approximately 1,675 full-time employees, none of whom are subject to a collective bargaining arrangement.
CAUTIONARY STATEMENT FOR PURPOSES OF THE “SAFE HARBOR” PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
This report contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These forward-looking statements are based on assumptions or beliefs that we believe to be reasonable; however, assumed facts almost always vary from the actual results and such variances can be material. Where we express an expectation or belief as to future results, that expectation or belief is expressed in good faith and is believed to have a reasonable basis. We cannot assure you, however, that the stated expectation or belief will occur. The words “believe,” “expect,” “estimate,” “anticipate” and similar expressions will generally identify forward-looking statements. All of our forward-looking statements, whether written or oral, are expressly qualified by these and other cautionary statements. We disclaim any obligation to update any forward-looking statements to reflect events or circumstances after the date provided. With this in mind, you should consider the risks discussed elsewhere in this report and other documents we file with the Securities and Exchange Commission (SEC) from time to time and the following important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. If any of the following risks were actually to occur, our business, results of operations, financial condition and growth could be materially adversely affected.
Risks Related to Our Business
The success of our business depends on many factors beyond our control.
The results of our business are impacted in the long term by the volumes of natural gas we transport or store and the prices we are able to charge for these services. The volumes we transport and store depend on the actions of third parties that are based on factors beyond our control. Such factors include events that negatively impact our customers’ demand for natural gas and could expose our pipeline to the risk that we will not be able to renew contracts at expiration or that we will be required to discount our rates significantly upon renewal. We are also highly dependent on our customers and downstream pipelines to attach new and increased loads on their systems in order to grow our business. Further, state agencies that regulate our local distribution company customers could impose requirements that could impact demand for our services.
The volume of gas that we transport and store also depends on the availability of natural gas supplies that are attached to our pipeline system, including the need for producers to continue to develop additional gas supplies to offset the natural decline from existing wells connected to our system. This requires the development of additional natural gas reserves, obtaining additional supplies from interconnecting pipelines, and the development of LNG facilities on or near our system. There have been major shifts in supply basins over the last few years, especially with regard to the development of new natural gas shale plays and declining production from conventional sources of supplies as well as declining deliveries from Canada. A prolonged decline in energy prices could cause a decrease in these development activities and could cause a decrease in the volume of reserves available for transmission and storage through our system.
Furthermore, our ability to deliver gas to our shippers is dependent upon their ability to purchase and deliver gas at various receipt points into our system. On occasion, particularly during extreme weather conditions, the gas delivered by our shippers at the receipt points into our system is less than the gas that they take at delivery points from our system. This can cause operational problems and can negatively impact our ability to meet our shippers’ demand.
The agencies that regulate us and our customers could affect our profitability.
Our business is extensively regulated by the FERC, the U.S. Department of Transportation, the U.S. Department of Interior, the U.S. Coast Guard, the U.S. Department of Homeland Security and various state and local regulatory agencies whose actions have the potential to adversely affect our profitability. The FERC regulates most aspects of our business, including the terms and conditions of services offered, our relationships with affiliates, construction and abandonment of facilities and the rates charged by our pipeline (including establishing authorized rates of return). We periodically file to adjust the rates charged to our customers. In 2010, we filed a rate case that will establish new rates in 2011. There is a risk that the FERC may establish rates that are not acceptable to us and have a negative impact on us. In addition, our profitability is influenced by fluctuations in costs and our ability to recover any increases in our costs in the rates charged to our shippers. Our operating results can be negatively impacted to the extent that such costs increase in an amount greater than what we are permitted to recover in our rates or to the extent that there is a lag before we can file and obtain rate increases.
Our existing rates may also be challenged by complaint. The FERC commenced several proceedings in 2009 and 2010 against unaffiliated pipeline systems to reduce the rates they were charging their customers. There is a risk that the FERC or our customers could file similar complaints on us and that a successful complaint against our rates could have an adverse impact on us. For a discussion of our recent rate case filed with the FERC, see Part II, Item 8, Financial Statements and Supplementary Data, Note 8.
Certain of our transportation services are subject to negotiated rate contracts that may not allow us to recover our costs of providing the services.
Under FERC policy, interstate pipelines and their customers may execute contracts at a negotiated rate which may be above or below the FERC regulated recourse rate for that service. These negotiated rate contracts are generally not subject to adjustment for increased costs which could occur due to inflation, increases in the cost of capital or taxes or other factors relating to the specific facilities being used to perform the services. It is possible that costs to perform services under negotiated rate contracts will exceed the negotiated rates. Any shortfall of revenue, representing the difference between recourse rates and negotiated rates could result in either losses or lower rates of return in providing such services.
Our revenues are generated under contracts that must be renegotiated periodically.
Our revenues are generated under transportation and storage contracts which expire periodically and must be renegotiated, extended or replaced. If we are unable to extend or replace these contracts when they expire or renegotiate contract terms as favorable as the existing contracts, we could suffer a material reduction in our revenues, earnings and cash flows. For example, basis differentials between receipt and delivery points on our pipeline system could decrease over time and thereby negatively impact our ability to renew contracts at rates that were previously in place. Our ability to extend and replace contracts could be adversely affected by factors we cannot control, as discussed above. In addition, changes in state regulation of local distribution companies may cause them to negotiate short-term contracts or turn back their capacity when their contracts expire.
The expansion of our pipeline system by constructing new facilities subjects us to construction and other risks that may adversely affect us.
We frequently expand the capacity of our existing pipeline and storage facilities by constructing additional facilities. Construction of these facilities is subject to various regulatory, development and operational risks, including:
|
•
|
our ability to obtain necessary approvals and permits from the FERC and other regulatory agencies on a timely basis that are on terms that are acceptable to us, including the potential negative impact of delays and increased costs caused by general opposition to energy infrastructure development, especially in environmentally, culturally sensitive and more heavily populated areas;
|
|
•
|
the ability to access sufficient capital at reasonable rates to fund expansion projects, especially in periods of prolonged economic decline when we may be unable to access the capital markets;
|
|
•
|
the availability of skilled labor, equipment, and materials to complete expansion projects;
|
|
•
|
potential changes in federal, state and local statutes, regulations, and orders;
|
|
•
|
impediments on our ability to acquire rights-of-way or land rights on terms that are acceptable to us;
|
|
•
|
our ability to construct projects within anticipated costs, including the risk that we may incur cost overruns resulting from weather conditions, geologic conditions, inflation or increased costs of equipment, materials (such as steel and nickel), labor, contractor productivity, delays in construction due to various factors including delays in obtaining regulatory approvals or other factors beyond our control. These cost overruns could be material and we may not be able to recover such excess costs from our customers which could negatively impact the return on our investments or could result in financial impairments;
|
|
•
|
our ability to construct projects within anticipated time frames that would likely delay our collection of transportation charges under our contracts;
|
|
•
|
the failure of suppliers and contractors to meet their performance and warranty obligations; and
|
|
•
|
the lack of transportation, storage or throughput commitments.
|
Any of these risks could prevent a project from proceeding, delay its completion or increase its anticipated costs. There is also the risk that a downturn in the economy and its negative impact upon natural gas demand may result in either slower development in the potential for future expansion projects or adjustments in the contractual commitments supporting such projects. As a result, new facilities may be delayed or may not achieve our expected investment return.
We depend on a key customer for a significant portion of our revenues and the loss of this key customer could result in a decline in our revenues.
We rely on a key customer for a significant portion of our revenues. For the year ended December 31, 2010, National Grid USA and subsidiaries accounted for approximately 14 percent of our operating revenues. The loss of any material portion of the contracted volumes of this customer, as a result of competition, creditworthiness, inability to negotiate extensions, or replacements of contracts or otherwise, could have a material adverse effect on us. For additional information on our revenues from this customer, see Part II, Item 8, Financial Statements and Supplementary Data, Note 10.
The costs to maintain, repair and replace our pipeline system may exceed our expected levels.
Much of our pipeline infrastructure was originally constructed many years ago. The age of these assets may result in them being more costly to maintain and repair. We may also be required to replace certain facilities over time. In addition, our pipeline assets may be subject to the risk of failures or other incidents due to factors outside of our control (including due to third party excavation near our pipeline, unexpected degradation of our pipeline, as well as design, construction or manufacturing defects) that could result in personal injury or property damages. Much of our pipeline system is located in populated areas which increases the level of such risks. Such incidents could also result in unscheduled outages or periods of reduced operating flows which could result in a loss of our ability to serve our customers and a loss of revenues. Although we are targeted to complete our pipeline integrity program which includes the development and use of in-line inspection tools in high consequence areas by its required completion date at the end of 2012, we will continue to incur substantial expenditures beyond 2012 relating to the integrity and safety of our pipeline. In addition, as indicated above there is a risk that new regulations associated with pipeline safety and integrity issues will be adopted that could require us to incur additional material expenditures in the future. There is also a risk of gas loss and field degradation for our storage operations.
We do not own all of the land on which our pipeline and facilities are located, which could disrupt our operations.
We do not own all of the land on which our pipeline and facilities are located. We are subject to the risk that we do not have valid rights-of-way, that such rights-of-way may lapse or terminate, our facilities may not be properly located within the boundaries of such rights-of-way or the landowners otherwise interfere with our operations. Our loss of or interference with these rights could have a material adverse effect on us.
There are accounting principles that are unique to regulated interstate pipeline assets that could materially impact our recorded earnings.
Accounting policies for FERC regulated pipelines are in certain instances different from U.S. generally accepted accounting principles (GAAP) for non-regulated entities. For example, FERC accounting policies permit certain regulatory assets to be recorded on our balance sheet that would not typically be recorded for non-regulated entities. In determining whether to account for regulatory assets on our pipeline, we consider various factors including regulatory changes and the impact of competition to determine the probability of recovery of these assets. Currently, we have regulatory assets recorded on our balance sheet. If we determine that future recovery is no longer probable, then we could be required to write off the regulatory assets in the future. In addition, we capitalize a carrying cost (AFUDC) on equity funds related to our construction of long-lived assets. Equity amounts capitalized are included as other income on our income statement. To the extent that one of our expansion projects is not fully subscribed when it goes into service, we may experience a reduction in our earnings once the pipeline is placed into service.
The supply and demand for natural gas could be adversely affected by many factors outside of our control which could negatively affect us.
Our success depends on the supply and demand for natural gas. The degree to which our business is impacted by changes in supply or demand varies. For example, we are not significantly impacted in the short-term by reductions in the supply or demand for natural gas since we recover most of our revenues from reservation charges under longer-term contracts that are not dependent on the supply and demand of natural gas in the short-term. However, our business can be negatively impacted by sustained downturns in supply and demand for natural gas. One of the major factors that will impact natural gas demand will be the potential growth of natural gas in the power generation market, particularly driven by the speed and level of existing coal-fired power generation that is replaced with natural gas-fired power generation. In addition, the supply and demand for natural gas for our business will depend on many other factors outside of our control, which include, among others:
|
•
|
adverse changes in global economic conditions, including changes that negatively impact general demand for power generation and industrial loads for natural gas;
|
|
•
|
adverse changes in geopolitical factors and unexpected wars, terrorist activities and others acts of aggression;
|
|
•
|
technological advancements that may drive further increases in production from natural gas shales;
|
|
•
|
competition from imported LNG and Canadian supplies and alternate fuels;
|
|
•
|
increased prices of natural gas that could negatively impact demand;
|
|
•
|
increased costs to transport natural gas;
|
|
•
|
adoption of various energy efficiency and conservation measures; and
|
|
•
|
perceptions of customers on the availability and price volatility of natural gas prices over the longer-term.
|
The price for natural gas could be adversely affected by many factors outside of our control which could negatively affect us.
Our success depends upon the prices we receive for our natural gas. Natural gas prices historically have been volatile and are likely to continue to be volatile in the future, especially given current global geopolitical and economic conditions. There is a risk that commodity prices will remain depressed for sustained periods, especially in relation to natural gas prices which are at relatively low levels at this time. The degree to which our business is impacted by lower commodity prices varies. For example, we are not significantly impacted in the short-term by changes in natural gas prices. However, we can be negatively impacted in the long-term by sustained depression in commodity prices for natural gas, including reductions in our ability to renew transportation contracts on favorable terms, as well as to construct new pipeline infrastructure. The price for natural gas is subject to a variety of additional factors that are outside of our control, which include, among others:
|
•
|
changes in regional and domestic supply and demand;
|
|
•
|
changes in basis differentials among different supply basins that can negatively impact our ability to compete with supplies from other basins, including our ability to maintain transportation revenues and renew transportation contracts in supply basins that are not as competitive as other alternatives;
|
|
•
|
changes in the costs of transporting natural gas;
|
|
•
|
increased federal and state taxes, if any, on the transportation of natural gas;
|
|
•
|
the price and availability of supplies of alternative energy sources; and
|
|
•
|
the amount of capacity available to transport natural gas.
|
Our business is subject to competition from third parties which could negatively affect us.
The natural gas business is highly competitive. We compete with other interstate and intrastate pipeline companies as well as gatherers and storage companies in the transportation and storage of natural gas. We also compete with suppliers of alternate sources of energy, including electricity, coal and fuel oil. We frequently have one or more competitors in the supply basins and markets that we are connected to. This includes growing competition in many of the markets that we serve, including many of the markets in the northeast.
Our operations are subject to operational hazards and uninsured risks which could negatively affect us.
Our operations are subject to the inherent risks including fires, earthquakes, adverse weather conditions (such as extreme cold or heat, hurricanes, tornadoes, lightning and flooding) and other natural disasters; terrorist activity or acts of aggression; the collision of equipment of third parties on our infrastructure (such as damage caused to our underground pipeline by third party excavation or construction); explosions, pipeline failures, mechanical and process safety failures, events causing our facilities to operate below expected levels of capacity or efficiency; uncontrollable flows of natural gas, release of pollution or contaminants into the environment (including discharges of toxic gases or substances) and other environmental hazards. Each of these risks could result in (a) damage or destruction of our facilities, (b) damages and injuries to persons and property or (c) business interruptions while damaged energy infrastructure is repaired or replaced, each of which could cause us to suffer substantial losses. Our offshore operations may encounter additional marine perils, including hurricanes and other adverse weather conditions, damage from collisions with vessels, and governmental regulations. In addition, although the potential effects of climate change on our operations (such as hurricanes, flooding, etc.) are uncertain at this time, changes in climate patterns as a result of global emissions of greenhouse gas (GHG) could have a negative impact upon our operations in the future, particularly with regard to any of our facilities that are located in or near the Gulf of Mexico and other coastal regions.
While we maintain insurance against some of these risks in amounts that we believe are reasonable, our insurance coverages have material deductibles, self-insurance levels, limits on our maximum recovery and do not cover all risks. For example, we do not carry or are unable to obtain insurance coverage on terms that we find acceptable for certain exposures including, but not limited to certain environmental exposures (including potential environmental fines and penalties), business interruption, named windstorm/hurricane exposures, and in limited circumstances, certain political risk exposures. The premiums and deductibles we pay for certain insurance policies are also subject to the risk of substantial increases over time that could negatively impact our financial results. In addition, we may not be able to renew existing insurance policies or procure desirable insurance on commercially reasonable terms. There is also a risk that our insurers may default on their coverage obligations. As a result, we could be adversely affected if a significant event occurs that is not fully covered by insurance.
We are subject to a complex set of laws and regulations that regulate the energy industry for which we have to incur substantial compliance and remediation costs.
Our operations are subject to a complex set of federal, state and local laws and regulations that tend to change from time to time and generally are becoming increasingly more stringent. In addition to the laws and regulations affecting our business, there are various laws and regulations that regulate various market practices in the industry, including antitrust laws and laws that prohibit fraud and manipulation in the markets in which we operate. The authority of the Federal Trade Commission and the FERC to impose penalties for violations of laws or regulation has generally increased over the last few years. In addition, our business is subject to laws and regulations that govern environmental, health and safety matters. These regulations include compliance obligations for air emissions, water quality, wastewater discharge and solid and hazardous waste disposal, as well as regulations designed for the protection of human health and safety and threatened or endangered species. Compliance obligations can result in significant costs to install and maintain pollution controls and to maintain measures to address personal and process safety and protection of the environment and animal habitat near our operations. We are often obligated to obtain permits or approvals in our operations from various federal, state and local authorities, which permits and approvals can be denied or delayed. In addition, we are exposed to fines and penalties to the extent that we fail to comply with the applicable laws and regulations, as well as the potential for limitations to be imposed on our operations. These regulations often impose remediation obligations associated with the investigation or clean-up of contaminated properties, as well as damage claims arising out of the contamination of properties or impact on natural resources. Finally, many of our assets are located and operate on federal, state, or local lands and are typically regulated by one or more federal, state or local agencies. For example, we operate assets that are located on federal lands located both onshore and offshore, which are regulated by the Department of the Interior, particularly by the Bureau of Land Management and the Bureau of Ocean Energy Management, Regulation and Enforcement.
The laws and regulations (and the interpretations thereof) that are applicable to our business could materially change in the future and increase the cost of our operations or otherwise negatively impact us.
The regulatory framework affecting our business is frequently subject to change, with the risk that either new laws and regulations may be enacted or existing laws and regulation may be amended. Such new or amended laws and regulations can materially affect our operations and our financial results. In this regard, there have been proposals to implement or amend federal, state, and local laws and regulations that could negatively impact our business, which includes among others:
|
•
|
Climate Change and other Emissions. There have been various legislative and regulatory proposals at the federal and state levels to address climate change and to regulate GHG emissions. The Environmental Protection Agency (EPA) and several state environmental agencies have already adopted regulations to regulate GHG emissions. Although natural gas as a fuel supply for power generation has the least GHG emissions of any fossil fuel, it is uncertain at this time what impact the existing and proposed regulations will have on the demand for natural gas and on our operations. This will largely depend on what regulations are ultimately adopted, including the level of any emission standards; the amount and costs of allowances, offsets and credits granted; and incentives and subsidies provided to other fossil fuels, nuclear power and renewable energy sources. Although the EPA has adopted a tailoring rule to regulate GHG emissions, it is not expected to materially impact our operations until 2016. However, the tailoring rule is subject to judicial reviews and such reviews could result in the EPA being required to regulate GHG emissions at lower levels that could subject us to regulation prior to 2016. There have also been various legislative and regulatory proposals at the federal and state levels to address various emissions from coal-fired power plants. Although such proposals will generally favor the use of natural gas fired power plants over coal-fired power plants, it remains uncertain what regulations will ultimately be adopted and when they will be adopted. Finally, there have been other various environmental regulatory proposals that could increase the cost of our environmental liabilities as well as increase our future compliance costs. For example, the EPA has proposed more stringent ozone standards, as well as implemented more stringent emission standards with regard to certain combustion engines on our pipeline system. It is uncertain what impact new environmental regulations might have on us until further definition is provided in the various legislative, regulatory and judicial branches. In addition, any regulations would likely increase our costs of compliance by requiring us to monitor emissions, install additional equipment to reduce carbon emissions and possibly to purchase emission credits, as well as potentially delay the receipt of permits and other regulatory approvals. While we may be able to include some or all of the costs associated with our environmental liabilities and environmental compliance in the rates charged by our pipeline and in the prices at which we sell natural gas, our ability to recover such costs is uncertain and may depend on events beyond our control including the outcome of future rate proceedings before the FERC and the provisions of any final regulations and legislation.
|
|
•
|
Renewable / Conservation Legislation. There have been various legislative and regulatory proposals at the federal and state levels to provide incentives and subsidies to (a) shift more power generation to renewable energy sources and (b) support technological advances to drive less energy consumption. These incentives and subsidies could have a negative impact on natural gas consumption and thus have negative impacts on our operations and financial results.
|
|
•
|
Pipeline Safety. Various legislative and regulatory reforms associated with pipeline safety and integrity issues have been recently proposed, including reforms that would require increased periodic inspections, installation of additional valves and other equipment on our pipeline and subjecting additional pipelines (including gathering and intrastate pipeline facilities) to more stringent regulation. It is uncertain what reforms, if any, will be adopted and what impact they might ultimately have on our operations or financial results.
|
We are exposed to the credit risk of our counterparties and our credit risk management may not be adequate to protect against such risk.
We are subject to the risk that our counterparties fail to make payments to us within the time required under our contracts. Our current largest exposure is associated with shippers under long-term transportation contracts on our pipeline system. Our credit procedures and policies may not be adequate to fully eliminate counterparty credit risk. In addition, in certain situations, we may assume certain additional credit risks for competitive reasons or otherwise. If our existing or future counterparties fail to pay and/or perform, we could be adversely affected. For example, we may not be able to effectively remarket capacity or enter into new contracts at similar terms during and after insolvency proceedings involving a customer.
We are exposed to the credit and performance risk of our key contractors and suppliers.
As an owner of energy infrastructure facilities with significant capital expenditures, we rely on contractors for certain construction and we rely on suppliers for key materials, supplies and services, including steel mills and pipe and tubular manufacturers. There is a risk that such contractors and suppliers may experience credit and performance issues that could adversely impact their ability to perform their contractual obligations with us, including their performance and warranty obligations. This could result in delays or defaults in performing such contractual obligations and increased costs to seek replacement contractors, each which could adversely impact us.
Our business requires the retention and recruitment of a skilled workforce and the loss of employees could result in the failure to implement our business plan.
Our business requires the retention and recruitment of a skilled workforce including engineers, technical personnel and other professionals. We compete with other companies in the energy industry for this skilled workforce. In addition, many of our current employees are retirement eligible, which have significant institutional knowledge that must be transferred to other employees. If we are unable to (a) retain our current employees, (b) successfully complete our knowledge transfer and/or (c) recruit new employees of comparable knowledge and experience, our business could be negatively impacted. In addition, we could experience increased costs to retain and recruit these professionals.
We have certain contingent liabilities that could exceed our estimates.
We have certain contingent liabilities associated with litigation and environmental matters. In this regard, although we have greatly reduced our litigation, regulatory and environmental exposures over the last several years, we continue to have contingent liabilities (see Part II, Item 8, Financial Statements and Supplementary Data, Note 8). Although we believe that we have established appropriate reserves for our litigation and environmental matters, we could be required to accrue additional amounts in the future and these amounts could be material.
We have also sold assets and either retained certain liabilities or indemnified certain purchasers against future liabilities related to assets sold, including liabilities associated with environmental and other representations that we have provided. Although we believe that we have established appropriate reserves for these liabilities, we could be required to accrue additional amounts in the future and these amounts could be material. We have experienced substantial reductions and turnover in the workforce that previously supported the ownership and operation of such assets which could result in difficulties in managing these retained liabilities, including a reduction in historical knowledge of the assets and business that is required to effectively manage these liabilities or defend any associated litigation or regulatory proceedings.
We are subject to interest rate risks.
Although a substantial portion of our debt capital structure has fixed interest rates, changes in market conditions, including potential increases in the deficits of foreign, federal and state governments, could have a negative impact on interest rates that could cause our financing costs to increase. Since interest rates are at historically low levels, it is anticipated that they will increase in the future.
Risks Related to Our Affiliation with El Paso
El Paso files reports, proxy statements and other information with the SEC under the Securities Exchange Act of 1934, as amended. Each prospective investor should consider this information and the matters disclosed therein in addition to the matters described in this report. Such information is not included herein or incorporated by reference into this report.
We are an indirect wholly owned subsidiary of El Paso.
As an indirect wholly owned subsidiary of El Paso, subject to limitations in our credit agreements and indentures, El Paso has substantial control over:
|
•
|
our payment of dividends;
|
|||||
|
•
|
decisions on our financing and capital raising activities;
|
|||||
|
•
|
mergers or other business combinations;
|
|||||
|
•
|
our acquisitions or dispositions of assets; and
|
|||||
|
•
|
our participation in El Paso’s cash management program.
|
|||||
El Paso may exercise such control in its interests and not necessarily in the interests of us or the holders of our long-term debt.
Our relationship with El Paso and its financial condition subjects us to potential risks that are beyond our control.
Due to our relationship with El Paso, adverse developments or announcements concerning El Paso or its other subsidiaries could adversely affect our financial condition, even if we have not suffered any similar development. The ratings assigned to El Paso’s senior unsecured indebtedness are below investment grade, currently rated Ba3 with a stable outlook by Moody’s Investor Service, BB- with a stable outlook by Standard & Poor’s and BB+ with a stable outlook by Fitch Ratings. The ratings assigned to our senior unsecured indebtedness are currently investment grade, with a Baa3 rating by Moody’s Investor Service and a BBB- rating by Fitch Ratings. Standard & Poor’s has assigned a below investment grade rating of BB to our senior unsecured indebtedness. There is a risk that these credit ratings may be adversely affected in the future as the credit rating agencies review their general credit requirements as well as review our and El Paso’s leverage, liquidity and credit profile. Any reduction in our or El Paso’s credit ratings could impact our ability to access the capital markets as well as our cost of capital.
El Paso provides cash management and other corporate services for us. Pursuant to El Paso’s cash management program, we transfer surplus cash to El Paso in exchange for an affiliated note receivable. In addition, we conduct commercial transactions with some of our affiliates. If El Paso or such affiliates are unable to meet their respective liquidity needs, we may not be able to access cash under the cash management program, or our affiliates may not be able to pay their obligations to us. However, we might still be required to satisfy affiliated payables we have established. Our inability to recover any affiliated receivables owed to us could adversely affect our financial position and cash flows. For a further discussion of these matters, see Part II, Item 8, Financial Statements and Supplementary Data, Note 12.
If El Paso is unable to renew its revolving credit facility that expires in November 2012, then it could negatively impact us.
We are a party to El Paso’s $1.5 billion credit agreement. We are only liable, however for our borrowings under the credit agreement, which were zero at December 31, 2010. El Paso’s credit agreement is due to expire November of 2012. Prior to maturity, El Paso plans to renew or extend this credit facility. The amount of credit capacity El Paso is able to obtain and the cost of such credit could have a negative impact on our liquidity position and financial results. In addition, the financial covenants set forth in any new facility may be more restrictive than the current facility and could reduce our financial and operating flexibility.
A default under El Paso’s $1.5 billion credit agreement by any party could accelerate our future borrowings, if any, under the credit agreement and our long-term debt, which could adversely affect our liquidity position.
Under the credit agreement, a default by El Paso, or any other borrower, could result in the acceleration of repayment of all outstanding borrowings, including the borrowings of any non-defaulting party. The acceleration of repayments of borrowings, if any, or the inability to borrow under the credit agreement, could adversely affect our liquidity position and, in turn, our financial condition.
We may be subject to a change in control if an event of default occurs under El Paso’s credit agreement.
Under El Paso’s $1.5 billion credit agreement, our common stock and the common stock of one of El Paso’s other subsidiaries are pledged as collateral. As a result, our ownership is subject to change if there is a default under the credit agreement and El Paso’s lenders exercise rights over their collateral, even if we do not have any borrowings outstanding under the credit agreement. For additional information concerning El Paso’s credit facility, see Part II, Item 8, Financial Statements and Supplementary Data, Note 7.
We have not included a response to this item since no response is required under Item 1B of Form 10-K.
A description of our properties is included in Item 1, Business, and is incorporated herein by reference.
We believe that we have satisfactory title to the properties owned and used in our business, subject to liens for taxes not yet payable, liens incident to minor encumbrances, liens for credit arrangements and easements and restrictions that do not materially detract from the value of these properties, our interests in these properties, or the use of these properties in our business. We believe that our properties are adequate and suitable for the conduct of our business in the future.
A description of our material legal proceedings is included in Part II, Item 8, Financial Statements and Supplementary Data, Note 8, and is incorporated herein by reference.
All of our common stock, par value $5 per share, is owned by an indirect subsidiary of El Paso and, accordingly, our stock is not publicly traded.
We pay dividends on our common stock from time to time from legally available funds that have been approved for payment by our Board of Directors. During 2010, we utilized $334 million of our note receivable from the cash management program to pay a dividend to our parent. No common stock dividends were declared or paid in 2009 or 2008.
Information has been omitted from this report pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.
The information required by this Item is presented in a reduced disclosure format pursuant to General Instruction I to Form 10-K. Our Management’s Discussion and Analysis (MD&A) should be read in conjunction with our consolidated financial statements and the accompanying footnotes. MD&A includes forward-looking statements that are subject to risks and uncertainties that may result in actual results differing from the statements we make. These risks and uncertainties are discussed further in Part I, Item 1A, Risk Factors.
Overview
Our primary business consists of the interstate transportation and storage of natural gas. We face varying degrees of competition from other existing and proposed pipelines and LNG facilities, as well as from alternative energy sources used to generate electricity such as hydroelectric power, coal and fuel oil. Our revenues from transportation and storage services consist of the following types.
|
Type
|
Description
|
Percent of 2010
Revenues
|
||
|
Reservation
|
Reservation revenues are from customers (referred to as firm customers) that reserve capacity on our pipeline system and storage facilities. These firm customers are obligated to pay a monthly reservation or demand charge, regardless of the amount of natural gas they transport or store, for the term of their contracts.
|
68
|
||
|
Usage and Other
|
Usage revenues are from both firm customers and interruptible customers (those without reserved capacity) that pay usage charges and provide fuel in-kind based on the volume of gas actually transported, stored, injected or withdrawn. We also earn revenue from other miscellaneous sources.
|
32
|
The FERC regulates the rates we can charge our customers. These rates are generally a function of the cost of providing services to our customers, including a reasonable return on our invested capital. Because of our regulated nature, our revenues have historically been relatively stable. However, our financial results can be subject to volatility due to factors such as changes in natural gas prices, changes in supply and demand, changes in gas flows, regulatory actions, competition, declines in the creditworthiness of our customers and weather. We also experience volatility in our financial results when the amounts of natural gas used in our operations differ from the amounts we recover from our customers for that purpose.
In response to changing market conditions, we have shifted from a traditional dependence solely on long-term contracts to an approach that balances short-term and long-term commitments. This shift, which can increase the volatility of our revenues, is due to changes in market conditions and competition driven by state utility deregulation, local distribution company mergers, new pipeline competition, shifts in supply sources, volatility in natural gas prices, demand for short-term capacity and new power generation markets.
We continue to manage the process of renewing expiring contracts to limit the risk of significant impacts on our revenues. Our ability to extend our existing customer contracts or remarket expiring contracted capacity is dependent on competitive alternatives, the regulatory environment at the federal, state and local levels and the market supply and demand factors at the relevant dates these contracts are extended or expire. The duration of new or renegotiated contracts will be affected by current prices, competitive conditions and judgments concerning future market trends and volatility. Subject to regulatory requirements, we attempt to recontract or remarket our capacity at the maximum rates allowed under our tariffs. However, we have entered into a substantial portion of firm transportation contracts at amounts that are less than these maximum allowable rates to remain competitive.
In November 2010, we filed a rate case with the FERC proposing an increase in base tariff rates, including a proposed change in our rate structure which is expected to increase the percentage of reservation revenues relative to revenues derived from excess fuel recoveries and throughput on our system. For a further discussion of our rate case, see our Results of Operations discussion below.
Our existing contracts expire at various times and in varying amounts of throughput capacity. The weighted average remaining contract term for our active contracts is approximately four years as of December 31, 2010. Below are the contract expiration portfolio and the associated revenue expirations for our firm transportation contracts as of December 31, 2010, including those with terms beginning in 2011 or later.
|
Contracted
Capacity
|
Percent of
Contracted Capacity
|
Reservation Revenue
|
Percent of
Reservation Revenue
|
|||||||||||||
| (BBtu/d) | (In millions) | |||||||||||||||
|
2011
|
594 | 7 | $ | 20 | 4 | |||||||||||
|
2012
|
2,607 | 33 | 106 | 19 | ||||||||||||
|
2013
|
1,226 | 15 | 45 | 8 | ||||||||||||
|
2014
|
735 | 9 | 30 | 6 | ||||||||||||
|
2015
|
843 | 11 | 45 | 8 | ||||||||||||
|
2016 and beyond
|
2,024 | 25 | 299 | 55 | ||||||||||||
|
Total
|
8,029 | 100 | $ | 545 | 100 | |||||||||||
Results of Operations
Our management uses earnings before interest expense and income taxes (EBIT) as a measure to assess the operating results and effectiveness of our business, which consists of consolidated operations as well as an investment in an unconsolidated affiliate. We believe EBIT is useful to investors to provide them with the same measure used by El Paso to evaluate our performance and so that investors may evaluate our operating results without regard to our financing methods. We define EBIT as net income adjusted for items such as (i) interest and debt expense, (ii) affiliated interest income, and (iii) income taxes. EBIT may not be comparable to measures used by other companies. Additionally, EBIT should be considered in conjunction with net income, income before income taxes and other performance measures such as operating income or operating cash flows. Below is a reconciliation of our EBIT to net income, our throughput volumes and an analysis and discussion of our results for the year ended December 31, 2010 compared with 2009.
Operating Results:
|
2010
|
2009
|
|||||||
|
(In millions,
|
||||||||
|
except for volumes)
|
||||||||
|
Operating revenues
|
$ | 845 | $ | 933 | ||||
|
Operating expenses
|
(577 | ) | (612 | ) | ||||
|
Operating income
|
268 | 321 | ||||||
|
Earnings from unconsolidated affiliate
|
14 | 11 | ||||||
|
Other income, net
|
23 | 13 | ||||||
|
EBIT
|
305 | 345 | ||||||
|
Interest and debt expense
|
(150 | ) | (155 | ) | ||||
|
Affiliated interest income, net
|
15 | 16 | ||||||
|
Income tax expense
|
(67 | ) | (79 | ) | ||||
|
Net income
|
$ | 103 | $ | 127 | ||||
|
Throughput volumes (BBtu/d)
|
5,081 | 4,614 | ||||||
EBIT Analysis:
|
|
Operating
Revenue
|
Operating
Expense
|
Other
|
Total
|
||||||||||||
|
Favorable/(Unfavorable)
|
||||||||||||||||
|
(In millions)
|
||||||||||||||||
|
Gas not used in operations and other natural gas sales
|
$ | (82 | ) | $ | 15 | $ | — | $ | (67 | ) | ||||||
|
Expansions
|
7 | (3 | ) | 11 | 15 | |||||||||||
|
Reservation and other services revenues
|
(12 | ) | — | — | (12 | ) | ||||||||||
|
Operating and general and administrative expenses
|
— | 15 | — | 15 | ||||||||||||
|
Hurricane repairs
|
— | 7 | — | 7 | ||||||||||||
|
Other(1)
|
(1 | ) | 1 | 2 | 2 | |||||||||||
|
Total impact on EBIT
|
$ | (88 | ) | $ | 35 | $ | 13 | $ | (40 | ) | ||||||
____________
(1) Consists of individually insignificant items.
Gas Not Used in Operations and Other Natural Gas Sales. The financial impact of gas not used in operations is based on the amount of natural gas we are allowed to retain according to our tariff, relative to the amounts of natural gas we use for operations and the price of natural gas. The financial impact of gas not used for operations is influenced by factors such as system throughput, changes in gas flows, facility enhancements and the ability to operate the system efficiently. Gas not used for operations results in revenues to us, which we recognize when the volumes are retained. For the year ended December 31, 2010 when compared with 2009, our EBIT was unfavorably impacted by approximately $78 million due to lower realized prices and lower volumes of gas not used in operations as a result of the shift in flow patterns and unfavorable revaluations of retained fuel volumes, partially offset by $15 million of lower electric compression usage.
Expansions. During 2010 and 2009, we benefited from increased reservation revenues due to expansion projects placed in service in 2009. These projects included the Carthage expansion project, the Concord Lateral expansion project, and the Blue Water expansion project. We capitalize a carrying cost (an allowance for funds used during construction or AFUDC) on equity funds related to our construction of long-lived assets that is recorded as other income on our income statements. For the year ended December 31, 2010, we benefited from an increase in other income of approximately $11 million when compared to 2009, associated with the equity portion of AFUDC on our expansion projects, partially offset by depreciation and operating expenses of the new facilities.
During 2011, we plan to spend approximately $464 million in capital on our backlog of expansion projects. Listed below is additional information related to our significant backlog projects.
|
•
|
300 Line Project. This expansion project involves the installation of eight looping segments in Pennsylvania and New Jersey totaling approximately 128 miles of pipeline and the addition of approximately 55,000 horsepower of compression following the installation of two new compressor stations and upgrades at seven existing compressor stations. Upon completion, we expect this project to increase natural gas delivery capacity in the region by approximately 350 MMcf/d. The expansion project will provide access to diversified natural gas supplies from the Gulf Coast, Appalachian, and Marcellus shale basin, and gas deliveries to points along the 300 Line path and into various interconnections with other pipelines in northern New Jersey, as well as an existing delivery point in White Plains, New York. All of the firm transportation capacity resulting from this project in the northeast U.S. market area is fully subscribed with one shipper based on a precedent agreement which was executed in the third quarter of 2009. During 2010, the FERC issued a favorable environmental assessment and we received certificate authorization from the FERC to construct the pipeline and compression facilities. In June 2010, we commenced construction on our compression facilities related to this project, with construction of the remaining facilities to occur in 2011. The expected cost for this project is approximately $660 million and is anticipated to be placed in service November 2011.
|
|
•
|
Northeast Upgrade Project. In 2010, we entered into precedent agreements with two shippers to provide 620 MMcf/d of additional firm transportation service from receipt points in the Marcellus shale basin to an interconnect in New Jersey. All of the firm transportation capacity is fully subscribed with these two shippers. This project includes approximately 40 miles of pipeline looping and approximately 22,310 horsepower of additional compression. Additionally, we are placing appurtenances in service to provide interim backhaul transport of natural gas. The expected cost for this project is approximately $400 million, and the project is anticipated to be placed in service in November 2013.
|
Reservation and Other Services Revenues. Throughput volumes on our system increased by 10 percent during 2010 compared to 2009. However, our reservation revenues were lower by approximately $10 million because long-haul transports have decreased due to a shift in receipts from the Gulf Coast region to the Rockies Express Pipeline interconnect in Ohio and the Marcellus shale basin, which is short-haul transportation and subject to lower rates. Offsetting these decreases was an increase of approximately $7 million in capacity sales from the Marcellus shale basin in the Northeast market area due to transportation contracts with shippers which were executed in 2009. We believe our Marcellus expansion projects (300 Line Project and Northeast Upgrade Project) will expand our presence from Marcellus to the New York and New England markets.
For the year ended December 31, 2010, our overall EBIT was unfavorably impacted by $6 million when compared to 2009 due to unfavorable price spreads on our interruptible services. Also unfavorably impacting our EBIT was an adjustment of $6 million to defer revenue on certain of our negotiated rate contracts to future periods. Offsetting these unfavorable impacts was an increase of $5 million in liquids, separation and dehydration sales due to higher contractual rates for the year ended December 31, 2010 compared to 2009.
If we determine there is a sufficient change in our revenues, costs or billing determinants, we have the option to file a rate case with the FERC to provide an opportunity to recover our prudently incurred costs. In November 2010, we filed a rate case with the FERC proposing an increase in base tariff rates, including a proposed change in our rate structure which is expected to increase the percentage of reservation revenues relative to revenues derived from excess fuel recoveries and throughput on our system. These new base tariff rates would increase revenue by approximately $203 million annually over previously effective tariff rates. In December 2010, the FERC issued an order accepting and suspending the effective date of the proposed rates to June 1, 2011, subject to refund, the outcome of a hearing and other proceedings. At this time, the outcome of this matter is not currently determinable. Although this rate case is intended to address significant factors leading to the loss in revenues or increased costs, it will not eliminate all ongoing business risks including competition and shifts in throughput.
Operating and General and Administrative Expenses. For the year ended December 31, 2010, our operating and general and administrative expenses were lower than 2009 primarily due to lower payroll costs, net of capitalization and reimbursement from affiliates.
Hurricane Repairs. Our EBIT was unfavorably impacted by $7 million in 2009 due to repair costs that were not recoverable from insurance due to losses which did not exceed our self-retention levels.
Other Matter
We entered into an agreement with an effective date of October 2010 to sell certain of our offshore pipeline assets and related facilities. We have filed an abandonment application with the FERC related to the sale. The sale is contingent upon receiving FERC approval of the abandonment application including the ability to recover in our future rates the difference between the regulatory net book value and the purchase price as well as the designation of certain facilities as non-jurisdictional. If approved, we expect to complete the sale of these assets by mid-2012 and we may incur a loss on the sale for financial accounting purposes. However, the outcome of FERC's approval of our application is currently undeterminable. As such, we have not considered the assets as held for sale.
Interest and Debt Expense
Interest and debt expense for the year ended December 31, 2010, was $5 million lower than in 2009 primarily due to a lower outstanding balance on our polychlorinated biphenyls (PCB) refund obligations.
Affiliated Interest Income, Net
The following table shows the average advances due from El Paso and the average short-term interest rates for the year ended December 31:
|
2010
|
2009
|
|||||||
|
(In millions, except for rates)
|
||||||||
|
Average advance due from El Paso
|
$ | 1,015 | $ | 931 | ||||
|
Average short-term interest rate
|
1.5 | % | 1.7 | % | ||||
Income Taxes
Our effective tax rate of 39 percent and 38 percent for the years ended December 31, 2010 and 2009 was higher than the statutory rate of 35 percent due to the effect of state income taxes. For a reconciliation of the statutory rate to the effective tax rates, see Item 8, Financial Statements and Supplementary Data, Note 3.
Liquidity and Capital Resources
Our primary sources of liquidity are cash flows from operating activities and amounts available to us under El Paso’s cash management program. At December 31, 2010, we had a note receivable from El Paso of approximately $1.0 billion of which approximately $0.4 billion was classified as current based on the net amount we anticipate using in the next twelve months considering available cash sources and needs. During 2010, we utilized $334 million of our note receivable from an El Paso affiliate to pay a dividend to our parent. See Item 8, Financial Statements and Supplementary Data, Note 12 for a further discussion of El Paso’s cash management program. Our primary uses of cash are for working capital, capital expenditures and debt service requirements. For the year ended December 31, 2010 compared with 2009, our operating cash flows decreased by approximately $120 million primarily due to lower revenues, payment of income taxes and settlement of refund obligations associated with our PCB liability. Our cash capital expenditures for the year ended December 31, 2010 and those planned for 2011 are listed below.
|
2010
|
Expected
2011
|
|||||||
|
(In millions)
|
||||||||
|
Maintenance(1)
|
$ | 94 | $ | 172 | ||||
|
Expansions
|
132 | 464 | ||||||
|
Other(2)
|
95 | 101 | ||||||
|
Total
|
$ | 321 | $ | 737 | ||||
____________
(1) Amount is net of insurance proceeds received.
(2) Relates to building renovations at our corporate facilities.
Our expected 2011 maintenance capital expenditures primarily relate to maintaining and improving the integrity of our pipeline, complying with regulations and ensuring the safe and reliable delivery of natural gas to our customers. Also included in our maintenance capital expenditures are amounts related to damage repairs for hurricanes that occurred in 2005 and 2008. Our expected expansion capital expenditures primarily relate to our 300 Line Project.
Although financial market conditions have improved, continued volatility in the financial markets could impact our longer-term access to capital for future growth projects as well as the cost of such capital. Additionally, although the impacts are difficult to quantify at this point, a prolonged recovery of the global economy could have adverse impacts on natural gas consumption and demand. However, we believe our exposure to changes in natural gas consumption and demand is partially mitigated by a revenue base that includes long-term contracts that are based on firm demand charges. In November 2010, we filed a rate case with the FERC proposing, among other things, a change in our rate structure. For a further discussion of our rate case, see our Results of Operations discussion above.
We believe we have adequate liquidity available to us to meet our capital requirements and our existing operating needs through cash flows from operating activities and amounts available to us under El Paso’s cash management program. In addition to the cash management program above, we are eligible to borrow amounts available under El Paso’s $1.5 billion credit agreement and are only liable for amounts we directly borrow. As of December 31, 2010, El Paso had approximately $0.9 billion of capacity remaining and available to us and our affiliates under this credit agreement, and none of the amount outstanding under the facility was issued or borrowed by us. While we do not anticipate a need to directly access the financial markets in 2011 for any of our operating activities or expansion capital needs based on liquidity available to us, market conditions may impact our ability to act opportunistically.
For further detail on our risk factors including potential adverse general economic conditions including our ability to access financial markets which could impact our operations and liquidity, see Part I, Item 1A, Risk Factors.
Commitments and Contingencies
For a further discussion of our commitments and contingencies, see Item 8, Financial Statements and Supplementary Data, Note 8, which is incorporated herein by reference.
We are exposed to the risk of changing interest rates. At December 31, 2010, we had an interest bearing note receivable from El Paso of approximately $1.0 billion, with a variable interest rate of 1.5% that is due upon demand. While we are exposed to changes in interest income based on changes to the variable interest rate, the fair value of this note receivable approximates the carrying value due to the note being due on demand and the market-based nature of the interest rate.
The table below shows the carrying value, the related weighted-average effective interest rates on our non-affiliated fixed rate long-term debt securities and the estimated fair value of these securities based on quoted market prices for the same or similar issues.
|
December 31, 2010
|
December 31, 2009
|
|||||||||||||||||||||||
|
|
Expected Fiscal Year of Maturity of
Carrying Amounts
|
|
|
|||||||||||||||||||||
|
|
2011
|
2016 and
Thereafter
|
Total
|
Fair
Value
|
Carrying
Amount
|
Fair
Value
|
||||||||||||||||||
|
(In millions, except for rates)
|
||||||||||||||||||||||||
|
Liabilities:
|
||||||||||||||||||||||||
|
Long-term debt— fixed rate
|
$ | 85 | $ | 1,766 | $ | 1,851 | $ | 2,071 | $ | 1,846 | $ | 2,086 | ||||||||||||
|
Average effective interest rate
|
8.0 | % | 7.8 | % | ||||||||||||||||||||
We are also exposed to risks associated with changes in natural gas prices on natural gas that we are allowed to retain, net of gas used in operations. Retained natural gas is used as fuel and to replace lost and unaccounted for natural gas. We are at risk if we retain less natural gas than needed for these purposes. Pricing volatility may also impact the value of under or over recoveries of retained natural gas, imbalances and system encroachments. We sell retained gas in excess of gas used in operations when such gas is not operationally necessary or when such gas needs to be removed from the system, which may subject us to both commodity price and locational price differences depending on when and where that gas is sold. In some cases, where we have made a determination that, by a certain point in time, it is operationally necessary to dispose of gas not used in operations, we use forward sales contracts, which include fixed price and variable price contracts within certain price constraints, to manage this risk. In December 2009, we entered into a contract with our affiliate, El Paso Marketing, L.P., to sell up to 22 TBtu of natural gas not used in our operations in 2011 at a price of $6.48 per MMBtu. In November 2010, we filed a rate case with the FERC proposing, among other things, a change in our rate structure which is expected to increase the percentage of reservation revenues relative to revenues derived from excess fuel recoveries and throughput on our system. For a further discussion of our rate case, see Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations.
MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined by the Securities and Exchange Commission (SEC) rules adopted under the Securities Exchange Act of 1934, as amended. Our internal control over financial reporting is 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. It consists of policies and procedures that:
|
•
|
pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;
|
|
•
|
provide reasonable assurance that transactions are recorded as necessary to permit preparation of the financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and
|
|
•
|
provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements.
|
Under the supervision and with the participation of management, including the President and Chief Financial Officer, we made an assessment of the effectiveness of our internal control over financial reporting as of December 31, 2010. In making this assessment, we used the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation, we concluded that our internal control over financial reporting was effective as of December 31, 2010.
Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholder of Tennessee Gas Pipeline Company
We have audited the accompanying consolidated balance sheets of Tennessee Gas Pipeline Company (the Company) as of December 31, 2010 and 2009, and the related consolidated statements of income, stockholder’s equity, and cash flows for each of the three years in the period ended December 31, 2010. Our audits also included the financial statement schedule listed in the Index at Item 15(a) for each of the three years in the period ended December 31, 2010. These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s 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, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Tennessee Gas Pipeline Company at December 31, 2010 and 2009, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2010, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
/s/ Ernst & Young LLP
Houston, Texas
February 28, 2011
TENNESSEE GAS PIPELINE COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(In millions)
|
Year Ended December 31,
|
||||||||||||
|
|
2010
|
2009
|
2008
|
|||||||||
|
Operating revenues
|
$ | 845 | $ | 933 | $ | 907 | ||||||
|
Operating expenses
|
||||||||||||
|
Operation and maintenance
|
328 | 370 | 386 | |||||||||
|
Depreciation and amortization
|
196 | 187 | 182 | |||||||||
|
Loss on long-lived assets
|
— | 1 | 25 | |||||||||
|
Taxes, other than income taxes
|
53 | 54 | 52 | |||||||||
| 577 | 612 | 645 | ||||||||||
|
Operating income
|
268 | 321 | 262 | |||||||||
|
Earnings from unconsolidated affiliate
|
14 | 11 | 13 | |||||||||
|
Other income, net
|
23 | 13 | 10 | |||||||||
|
Interest and debt expense
|
(150 | ) | (155 | ) | (136 | ) | ||||||
|
Affiliated interest income, net
|
15 | 16 | 33 | |||||||||
|
Income before income taxes
|
170 | 206 | 182 | |||||||||
|
Income tax expense
|
67 | 79 | 71 | |||||||||
|
Net income
|
$ | 103 | $ | 127 | $ | 111 | ||||||
See accompanying notes.
TENNESSEE GAS PIPELINE COMPANY
CONSOLIDATED BALANCE SHEETS
(In millions, except share amounts)
|
December 31,
|
||||||||
|
2010
|
2009
|
|||||||
|
ASSETS
|
||||||||
|
Current assets
|
||||||||
|
Cash and cash equivalents
|
$ | — | $ | — | ||||
|
Accounts and note receivable
|
||||||||
|
Customer
|
24 | 12 | ||||||
|
Affiliates
|
378 | 152 | ||||||
|
Other
|
51 | 13 | ||||||
|
Materials and supplies
|
44 | 43 | ||||||
|
Deferred income taxes
|
43 | 44 | ||||||
|
Other
|
5 | 8 | ||||||
|
Total current assets
|
545 | 272 | ||||||
|
Property, plant and equipment, at cost
|
4,951 | 4,680 | ||||||
|
Less accumulated depreciation and amortization
|
1,056 | 936 | ||||||
| 3,895 | 3,744 | |||||||
|
Additional acquisition cost assigned to utility plant, net
|
1,923 | 1,963 | ||||||
|
Total property, plant and equipment, net
|
5,818 | 5,707 | ||||||
|
Other assets
|
||||||||
|
Note receivable from affiliate
|
617 | 939 | ||||||
|
Investment in unconsolidated affiliate
|
56 | 79 | ||||||
|
Other
|
76 | 70 | ||||||
| 749 | 1,088 | |||||||
|
Total assets
|
$ | 7,112 | $ | 7,067 | ||||
|
LIABILITIES AND STOCKHOLDER’S EQUITY
|
||||||||
|
Current liabilities
|
||||||||
|
Accounts payable
|
||||||||
|
Trade
|
$ | 90 | $ | 60 | ||||
|
Affiliates
|
38 | 72 | ||||||
|
Other
|
57 | 47 | ||||||
|
Current maturities of long-term debt
|
86 | — | ||||||
|
Taxes payable
|
23 | 94 | ||||||
|
Contractual deposits
|
28 | 31 | ||||||
|
Asset retirement obligations
|
28 | 66 | ||||||
|
Accrued interest
|
33 | 33 | ||||||
|
Regulatory liabilities
|
78 | 28 | ||||||
|
Other
|
38 | 24 | ||||||
|
Total current liabilities
|
499 | 455 | ||||||
|
Long-term debt, less current maturities
|
1,765 | 1,846 | ||||||
|
Other liabilities
|
||||||||
|
Deferred income taxes
|
1,422 | 1,351 | ||||||
|
Regulatory liabilities
|
90 | 153 | ||||||
|
Other
|
35 | 64 | ||||||
| 1,547 | 1,568 | |||||||
|
Commitments and contingencies (Note 8)
|
||||||||
|
Stockholder’s equity
|
||||||||
|
Common stock, par value $5 per share; 300 shares authorized; 208 shares issued and outstanding
|
— | — | ||||||
|
Additional paid-in capital
|
2,209 | 2,209 | ||||||
|
Retained earnings
|
1,092 | 1,323 | ||||||
|
Note receivable from affiliate
|
— | (334 | ) | |||||
|
Total stockholder’s equity
|
3,301 | 3,198 | ||||||
|
Total liabilities and stockholder’s equity
|
$ | 7,112 | $ | 7,067 | ||||
See accompanying notes.
TENNESSEE GAS PIPELINE COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
|
Year Ended December 31,
|
||||||||||||
|
|
2010
|
2009
|
2008
|
|||||||||
|
Cash flows from operating activities
|
||||||||||||
|
Net income
|
$ | 103 | $ | 127 | $ | 111 | ||||||
|
Adjustments to reconcile net income to net cash from operating activities
|
||||||||||||
|
Depreciation and amortization
|
196 | 187 | 182 | |||||||||
|
Deferred income tax expense
|
72 | 2 | 14 | |||||||||
|
Earnings from unconsolidated affiliate, adjusted for cash distributions
|
8 | 2 | 3 | |||||||||
|
Loss on long-lived assets
|
— | 1 | 25 | |||||||||
|
Other non-cash income items
|
(16 | ) | (2 | ) | (4 | ) | ||||||
|
Asset and liability changes
|
||||||||||||
|
Accounts receivable
|
42 | 17 | 19 | |||||||||
|
Change in deferred purchase price from accounts receivable sales
|
(35 | ) | — | — | ||||||||
|
Accounts payable
|
(41 | ) | 36 | 10 | ||||||||
|
Taxes payable
|
(73 | ) | 17 | 45 | ||||||||
|
Other current assets
|
(3 | ) | (1 | ) | (5 | ) | ||||||
|
Other current liabilities
|
16 | 16 | (16 | ) | ||||||||
|
Non-current assets
|
(14 | ) | (24 | ) | — | |||||||
|
Non-current liabilities
|
(3 | ) | (10 | ) | 21 | |||||||
|
Net cash provided by operating activities
|
252 | 368 | 405 | |||||||||
|
Cash flows from investing activities
|
||||||||||||
|
Capital expenditures
|
(321 | ) | (361 | ) | (323 | ) | ||||||
|
Net change in notes receivable from affiliates
|
390 | (232 | ) | (100 | ) | |||||||
|
Return of capital from investment in unconsolidated affiliate
|
15 | — | — | |||||||||
|
Other
|
(2 | ) | (9 | ) | 18 | |||||||
|
Net cash provided by (used in) investing activities
|
82 | (602 | ) | (405 | ) | |||||||
|
Cash flows from financing activities
|
||||||||||||
|
Net proceeds from the issuance of long-term debt
|
— | 234 | — | |||||||||
|
Dividend paid to parent
|
(334 | ) | — | — | ||||||||
|
Net cash provided by (used in) financing activities
|
(334 | ) | 234 | — | ||||||||
|
Net change in cash and cash equivalents
|
— | — | — | |||||||||
|
Cash and cash equivalents
|
||||||||||||
|
Beginning of period
|
— | — | — | |||||||||
|
End of period
|
$ | — | $ | — | $ | — | ||||||
|
Supplemental cash flow information
|
||||||||||||
|
Interest paid, net of amounts capitalized
|
$ | 133 | $ | 130 | $ | 120 | ||||||
|
Income tax payments
|
78 | 60 | 12 | |||||||||
See accompanying notes.
TENNESSEE GAS PIPELINE COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDER’S EQUITY
(In millions, except share amounts)
|
Common Stock
|
Additional
Paid-in
|
Retained
|
Note Receivable from
|
Total
Stockholder’s
|
|||||||||||||||||||||
|
Shares
|
Amount
|
Capital
|
Earnings
|
Affiliate
|
Equity | ||||||||||||||||||||
|
January 1, 2008
|
208 | $ | — | $ | 2,209 | $ | 1,085 | $ | — | $ | 3,294 | ||||||||||||||
|
Net income
|
111 | 111 | |||||||||||||||||||||||
|
Reclassification of note receivable from affiliate (Note 12)
|
— | (334 | ) | (334 | ) | ||||||||||||||||||||
|
December 31, 2008
|
208 | — | 2,209 | 1,196 | (334 | ) | 3,071 | ||||||||||||||||||
|
Net income
|
127 | 127 | |||||||||||||||||||||||
|
December 31, 2009
|
208 | — | 2,209 | 1,323 | (334 | ) | 3,198 | ||||||||||||||||||
|
Net income
|
103 | 103 | |||||||||||||||||||||||
|
Reclassification of note receivable from affiliate (Note 12)
|
334 | 334 | |||||||||||||||||||||||
|
Dividend paid to parent
|
(334 | ) | (334 | ) | |||||||||||||||||||||
|
December 31, 2010
|
208 | $ | — | $ | 2,209 | $ | 1,092 | $ | — | $ | 3,301 | ||||||||||||||
See accompanying notes.
TENNESSEE GAS PIPELINE COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Summary of Significant Accounting Policies
Basis of Presentation and Principles of Consolidation
We are a Delaware corporation incorporated in 1947, and an indirect wholly owned subsidiary of El Paso Corporation (El Paso). Our consolidated financial statements are prepared in accordance with U.S. generally accepted accounting principles (GAAP) and include the accounts of all consolidated subsidiaries after the elimination of intercompany accounts and transactions.
We consolidate entities when we have the ability to control or direct the operating and financial decisions of the entity or when we have a significant interest in the entity that gives us the ability to direct the activities that are significant to that entity. The determination of our ability to control, direct or exert significant influence over an entity involves the use of judgment. We apply the equity method of accounting where we can exert significant influence over, but do not control or direct the policies, decisions or activities of an entity. We use the cost method of accounting where we are unable to exert significant influence over the entity.
Use of Estimates
The preparation of our financial statements requires the use of estimates and assumptions that affect the amounts we report as assets, liabilities, revenues and expenses and our disclosures in these financial statements. Actual results can, and often do, differ from those estimates.
Regulated Operations
Our natural gas pipeline and storage operations are subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC) and follow the Financial Accounting Standards Board’s (FASB) accounting standards for regulated operations. Under these standards, we record regulatory assets and liabilities that would not be recorded for non-regulated entities. Regulatory assets and liabilities represent probable future revenues or expenses associated with certain charges or credits that are expected to be recovered from or refunded to customers through the rate making process. Items to which we apply regulatory accounting requirements include certain postretirement employee benefit plan costs, loss on reacquired debt, taxes related to an equity return component on regulated capital projects and certain costs related to gas not used in operations and other costs included in, or expected to be included in, future rates.
Cash and Cash Equivalents
We consider short-term investments with an original maturity of less than three months to be cash equivalents.
Allowance for Doubtful Accounts
We establish provisions for losses on accounts receivable and for natural gas imbalances due from shippers and operators if we determine that we will not collect all or part of the outstanding balance. We regularly review collectability and establish or adjust our allowance as necessary using the specific identification method.
Materials and Supplies
We value materials and supplies at the lower of cost or market value with cost determined using the average cost method.
Natural Gas Imbalances
Natural gas imbalances occur when the amount of natural gas delivered from or received by the pipeline differs from the contractual amount to be delivered or received. We value these imbalances due to or from shippers and operators utilizing current index prices. Imbalances are settled either as cash outs or in-kind, subject to the terms of our tariff.
Imbalances due from others are reported in our balance sheet as either accounts receivable from customers or accounts receivable from affiliates. Imbalances owed to others are reported on the balance sheet as either accounts payable or accounts payable to affiliates. We classify all imbalances as current as we expect to settle them within a year.
Property, Plant and Equipment
Our property, plant and equipment is recorded at its original cost of construction or, upon acquisition, at either the fair value of the assets acquired or the cost to the entity that first placed the asset in service. For assets we construct, we capitalize direct costs, such as labor and materials, and indirect costs, such as overhead, interest and an equity return component, as allowed by the FERC. We capitalize major units of property replacements or improvements and expense minor items.
We use the composite (group) method to depreciate regulated property, plant and equipment. Under this method, assets with similar useful lives and other characteristics are grouped and depreciated as one asset. We apply the depreciation rate approved in our rate settlements to the total cost of the group until its net book value equals its salvage value. We re-evaluate depreciation rates each time we file with the FERC for an increase or decrease in our transportation and storage rates. Currently, our depreciation rates vary from one percent to 25 percent per year.
When we retire regulated property, plant and equipment, we charge accumulated depreciation and amortization for the original cost of the assets in addition to the cost to remove, sell or dispose of the assets, less their salvage value. We do not recognize a gain or loss unless we sell an entire operating unit, as defined by the FERC. We include gains or losses on dispositions of operating units in operation and maintenance expense in our income statements. For properties not subject to regulation by the FERC, we reduce property, plant and equipment for its original cost, less accumulated depreciation and salvage value with any remaining gain or loss recorded in income.
Included in our property balances are additional acquisition costs, which represent the excess purchase costs associated with purchase business combinations allocated to us. These costs are amortized on a straight-line basis and are not recoverable in our rates under current FERC policies.
We capitalize a carrying cost (an allowance for funds used during construction or AFUDC) on debt and equity funds related to the construction of long-lived assets. This carrying cost consists of a return on the investment financed by debt and a return on the investment financed by equity. The debt portion is calculated based on the average cost of debt. Interest costs capitalized are included as a reduction to interest and debt expense on our income statement. The equity portion is calculated based on the most recent FERC approved rate of return. Equity amounts capitalized are included in other income on our income statements.
Asset and Investment Divestitures/Impairments
We evaluate assets and investments for impairment when events or circumstances indicate that their carrying values may not be recovered. These events include market declines that are believed to be other than temporary, changes in the manner in which we intend to use a long-lived asset, decisions to sell an asset or investment and adverse changes in the legal or business environment such as adverse actions by regulators. If an event occurs, we evaluate the recoverability of our carrying value based on either (i) the long-lived asset’s ability to generate future cash flows on an undiscounted basis or (ii) the fair value of the investment in an unconsolidated affiliate. If an impairment is indicated, or if we decide to sell a long-lived asset or group of assets, we adjust the carrying value of the asset downward, if necessary, to its estimated fair value. Our fair value estimates are generally based on market data obtained through the sales process or an analysis of expected discounted cash flows.
Revenue Recognition
Our revenues are primarily generated from natural gas transportation and storage services. Revenues for all services are based on the thermal quantity of gas delivered or subscribed at a price specified in the contract. For our transportation and storage services, we recognize reservation revenues on firm contracted capacity ratably over the contract period. For interruptible or volumetric-based services, we record revenues when physical deliveries of natural gas are made at the agreed upon delivery point or when gas is injected or withdrawn from the storage facility. For contracts with step-up or step-down rate provisions that are not related to changes in levels of service, we recognize reservation revenues ratably over the contract life. Gas not used in operations is based on the volumes of natural gas we are allowed to retain relative to the amounts of gas we use for operating purposes. We recognize revenue on gas not used in operations from our shippers when we retain the volumes at the market price required under our tariffs. We are subject to FERC regulations and, as a result, revenues we collect may be subject to refund in a rate proceeding. We establish reserves for these potential refunds.
Environmental Costs and Other Contingencies
Environmental Costs. We record liabilities at their undiscounted amounts on our balance sheet as other current and long-term liabilities when environmental assessments indicate that remediation efforts are probable and the costs can be reasonably estimated. Estimates of our liabilities are based on currently available facts, existing technology and presently enacted laws and regulations, taking into consideration the likely effects of other societal and economic factors, and include estimates of associated legal costs. These amounts also consider prior experience in remediating contaminated sites, other companies’ clean-up experience and data released by the Environmental Protection Agency (EPA) or other organizations. Our estimates are subject to revision in future periods based on actual costs or new circumstances. We capitalize costs that benefit future periods and we recognize a current period charge in operation and maintenance expense when clean-up efforts do not benefit future periods.
We evaluate any amounts paid directly or reimbursed by government sponsored programs and potential recoveries or reimbursements of remediation costs from third parties, including insurance coverage, separately from our liability. Recovery is evaluated based on the creditworthiness or solvency of the third party, among other factors. When recovery is assured, we record and report an asset separately from the associated liability on our balance sheet.
Other Contingencies. We recognize liabilities for other contingencies when we have an exposure that indicates it is both probable that a liability has been incurred and the amount of loss can be reasonably estimated. Where the most likely outcome of a contingency can be reasonably estimated, we accrue a liability for that amount. Where the most likely outcome cannot be estimated, a range of potential losses is established and if no one amount in that range is more likely than any other, the low end of the range is accrued.
Income Taxes
El Paso maintains a tax accrual policy to record both regular and alternative minimum taxes for companies included in its consolidated federal and state income tax returns. The policy provides, among other things, that (i) each company in a taxable income position will accrue a current expense equivalent to its federal and state income taxes, and (ii) each company in a tax loss position will accrue a benefit to the extent its deductions, including general business credits, can be utilized in the consolidated returns. El Paso pays all consolidated U.S. federal and state income taxes directly to the appropriate taxing jurisdictions and, under a separate tax billing agreement, El Paso may bill or refund its subsidiaries for their portion of these income tax payments.
We record income taxes on a separate return basis. Pursuant to El Paso’s policy, we record current income taxes based on our taxable income and we provide for deferred income taxes to reflect estimated future tax payments and receipts. Deferred taxes represent the tax impacts of differences between the financial statement and tax bases of assets and liabilities and carryovers at each year end. We account for tax credits under the flow-through method, which reduces the provision for income taxes in the year the tax credits first become available. We reduce deferred tax assets by a valuation allowance when, based on our estimates, it is more likely than not that a portion of those assets will not be realized in a future period. The estimates utilized in the recognition of deferred tax assets are subject to revision, either up or down, in future periods based on new facts or circumstances.
Accounting for Asset Retirement Obligations
We record a liability for legal obligations associated with the replacement, removal or retirement of our long-lived assets in the period the obligation is incurred. Our asset retirement liabilities are initially recorded at their estimated fair value with a corresponding increase to property, plant and equipment. This increase in property, plant and equipment is then depreciated over the useful life of the asset to which that liability relates. An ongoing expense is recognized for changes in the value of the liability as a result of the passage of time, which we record as depreciation and amortization expense in our income statement. We have the ability to recover certain of these costs from our customers and have recorded an asset (rather than expense) associated with the accretion of the liabilities described above.
Postretirement Benefits
We maintain a postretirement benefit plan covering certain of our former employees. This plan requires us to make contributions to fund the benefits to be paid under the plan. These contributions are invested until the benefits are paid to plan participants. The net benefit cost of this plan is recorded in our income statement and is a function of many factors including benefits earned during the year by plan participants (which is a function of factors such as the level of benefits provided under the plan, actuarial assumptions and the passage of time), expected returns on plan assets and amortization of certain deferred gains and losses. For a further discussion of our policies with respect to our postretirement benefit plan, see Note 9.
In accounting for our postretirement benefit plan, we record an asset or liability based on the over funded or under funded status of the plan. Any deferred amounts related to unrecognized gains and losses or changes in actuarial assumptions are recorded as either a regulatory asset or liability.
2. Loss on Long-Lived Assets
During 2008, we recorded impairments of $25 million, including an impairment related to our Essex-Middlesex lateral project due to its prolonged permitting process.
3. Income Taxes
Components of Income Tax Expense. The following table reflects the components of income tax expense included in net income for each of the three years ended December 31:
|
2010
|
2009
|
2008
|
||||||||||
|
(In millions)
|
||||||||||||
|
Current
|
||||||||||||
|
Federal
|
$ | (8 | )(1) | $ | 76 | $ | 54 | |||||
|
State
|
3 | 1 | 3 | |||||||||
| (5 | ) | 77 | 57 | |||||||||
|
Deferred
|
||||||||||||
|
Federal
|
64 | (7 | ) | 7 | ||||||||
|
State
|
8 | 9 | 7 | |||||||||
| 72 | 2 | 14 | ||||||||||
|
Total income tax expense
|
$ | 67 | $ | 79 | $ | 71 | ||||||
____________
(1) During 2010, we utilized a portion of our net operating loss carryover which resulted in a tax benefit for the year ended December 31, 2010.
|
|
|
Effective Tax Rate Reconciliation. Our income tax expense differs from the amount computed by applying the statutory federal income tax rate of 35 percent for the following reasons for each of the three years ended December 31:
|
2010
|
2009
|
2008
|
||||||||||
|
(In millions, except for rates)
|
||||||||||||
|
Income tax expense at the statutory federal rate of 35%
|
$ | 60 | $ | 72 | $ | 64 | ||||||
|
State income taxes, net of federal income tax effect
|
7 | 7 | 7 | |||||||||
|
Income tax expense
|
$ | 67 | $ | 79 | $ | 71 | ||||||
|
Effective tax rate
|
39 | % | 38 | % | 39 | % | ||||||
Deferred Tax Assets and Liabilities. The following are the components of our net deferred tax liability at December 31:
|
2010
|
2009
|
|||||||
|
(In millions)
|
||||||||
|
Deferred tax liabilities
|
||||||||
|
Property, plant and equipment
|
$ | 1,500 | $ | 1,494 | ||||
|
Other
|
6 | 7 | ||||||
|
Total deferred tax liability
|
1,506 | 1,501 | ||||||
|
Deferred tax assets
|
||||||||
|
Net operating loss and credit carryovers
|
||||||||
|
U.S. federal
|
26 | 54 | ||||||
|
State
|
19 | 21 | ||||||
|
Other liabilities
|
81 | 119 | ||||||
|
Total deferred tax asset
|
126 | 194 | ||||||
|
Net deferred tax liability
|
$ | 1,380 | $ | 1,307 | ||||
We believe it is more likely than not that we will realize the benefit of our deferred tax assets due to expected future taxable income, including the effect of future reversals of existing taxable temporary differences primarily related to depreciation.
Net Operating Loss (NOL) Carryovers. The table below presents the details of our federal and state NOL carryover periods as of December 31, 2010:
|
2011
|
2012-2015 | 2016-2020 | 2021-2030 |
Total
|
||||||||||||||||
| (In millions) | ||||||||||||||||||||
|
U.S. federal NOL
|
$ | — | $ | — | $ | — | $ | 73 | $ | 73 | ||||||||||
|
State NOL
|
1 | 97 | 281 | 153 | 532 | |||||||||||||||
Usage of our U.S. federal carryovers is subject to the limitations provided under Sections 382 and 383 of the Internal Revenue Code as well as the separate return limitation year rules of IRS regulations.
Unrecognized Tax Benefits. El Paso files consolidated U.S. federal and certain state tax returns which include our taxable income. In certain states, we file and pay taxes directly to the state taxing authorities. With a few exceptions, we and El Paso are no longer subject to state and local income tax examinations by tax authorities for years prior to 1999 and U.S. income tax examinations for years prior to 2007. For years in which our returns are still subject to review, our unrecognized tax benefits could increase or decrease our income tax expense and our effective income tax rates as these matters are finalized. We are currently unable to estimate the range of potential impacts the resolution of any contested matters could have on our financial statements. The following table shows the change in our unrecognized tax benefits:
|
2010
|
2009
|
|||||||
|
(In millions)
|
||||||||
|
Amount at January 1
|
$ | 16 | $ | 17 | ||||
|
Addition:
|
||||||||
|
Tax positions taken in prior years
|
6 | — | ||||||
|
Reduction:
|
||||||||
|
Settlements with taxing authorities
|
(4 | ) | (1 | ) | ||||
|
Amount at December 31
|
$ | 18 | $ | 16 | ||||
As of December 31, 2010 and 2009, approximately $15 million (net of federal tax benefits) of unrecognized tax benefits and associated interest and penalties would affect our income tax expense and our effective income tax rate if recognized in future periods. While the amount of our unrecognized tax benefits could change in the next twelve months, we do not expect this change to have a significant impact on our results of operations or financial position.
We classify interest and penalties related to unrecognized tax benefits as income taxes in our financial statements. As of December 31, 2010 and 2009, we had liabilities for interest and penalties related to our unrecognized tax benefits of approximately $4 million and $7 million. During both 2010 and 2009, we accrued less than $1 million of interest. In addition, during 2010 we settled a state tax audit which generated a reduction of $3 million to the interest and penalties liability related to our unrecognized tax benefits.
4. Fair Value of Financial Instruments
At December 31, 2010 and 2009, the carrying amounts of cash and cash equivalents and trade receivables and payables represented fair value because of the short-term nature of these instruments. At December 31, 2010 and 2009, we had an interest bearing note receivable from El Paso of approximately $1.0 billion due upon demand, with a variable interest rate of 1.5%. While we are exposed to changes in interest income based on changes to the variable interest rate, the fair value of this note receivable approximates the carrying value due to the note being due on demand and the market-based nature of the interest rate.
In addition, the carrying amounts of our long-term debt and their estimated fair values, which are based on quoted market prices for the same or similar issues, are as follows at December 31:
|
2010
|
2009
|
|||||||||||||||
|
|
Carrying
Amount
|
Fair
Value
|
Carrying
Amount
|
Fair
Value
|
||||||||||||
|
(In millions)
|
||||||||||||||||
|
Long-term debt, including current maturities
|
$ | 1,851 | $ | 2,071 | $ | 1,846 | $ | 2,086 | ||||||||
5. Regulatory Assets and Liabilities
Our regulatory assets are included in other current and non-current assets on our balance sheets. Our regulatory asset and liability balances are recoverable or reimbursable over various periods. Below are the details of our regulatory assets and liabilities at December 31:
|
2010
|
2009
|
|||||||
|
(In millions)
|
||||||||
|
Current regulatory assets
|
$ | 3 | $ | 3 | ||||
|
Non-current regulatory assets
|
||||||||
|
Taxes on capitalized funds used during construction
|
38 | 31 | ||||||
|
Postretirement benefits
|
2 | 4 | ||||||
|
Other
|
6 | 14 | ||||||
|
Total non-current regulatory assets
|
46 | 49 | ||||||
|
Total regulatory assets
|
$ | 49 | $ | 52 | ||||
|
Current regulatory liabilities
|
||||||||
|
Environmental
|
$ | 78 | $ | 28 | ||||
|
Total current regulatory liabilities
|
78 | 28 | ||||||
|
Non-current regulatory liabilities
|
||||||||
|
Environmental
|
44 | 112 | ||||||
|
Postretirement benefits
|
35 | 29 | ||||||
|
Other
|
11 | 12 | ||||||
|
Total non-current regulatory liabilities
|
90 | 153 | ||||||
|
Total regulatory liabilities
|
$ | 168 | $ | 181 | ||||
The significant regulatory assets and liabilities include:
Taxes on Capitalized Funds Used During Construction. Regulatory asset balance established to offset the deferred tax for the equity component of the allowance for funds used during the construction of long-lived assets. Taxes on capitalized funds used during construction and the offsetting deferred income taxes are included in the rate base and are recovered over the depreciable lives of the long-lived asset to which they relate.
Postretirement Benefits. Represents unrecognized gains and losses or changes in actuarial assumptions related to our postretirement benefit plan and differences in the postretirement benefit related amounts expensed and the amounts recovered in rates. Postretirement benefit amounts have been included in the rate base computations and are recoverable in such periods as benefits are funded.
Environmental. Includes amounts collected, substantially in excess of certain polychlorinated biphenyls (PCB) environmental remediation costs to date, through a surcharge to our customers under a settlement approved by the FERC in November of 1995. At this time the environmental liability is not deducted from the rate base on which we are allowed to earn current return. For a further discussion of the PCB matter, see Note 8.
6. Property, Plant and Equipment
Additional Acquisition Costs. Included in our property balances are additional acquisition costs assigned to utility plant, which represent the excess of allocated purchase costs over the historical costs of the facilities. At December 31, 2010 and 2009, additional acquisition costs assigned to utility plant was approximately $2.4 billion and accumulated depreciation was approximately $458 million and $418 million, respectively. These additional acquisition costs are being amortized on a straight-line basis over 62 years using the same rates as the related assets, and are not recoverable in our rates under current FERC policies. Our amortization expense related to additional acquisition costs assigned to utility plant was approximately $40 million, $39 million and $41 million for the years ended December 31, 2010, 2009 and 2008.
Capitalized Costs During Construction. Interest costs capitalized were $6 million, $3 million and $3 million during the years ended December 31, 2010, 2009 and 2008. Equity amounts capitalized were $13 million, $6 million and $6 million (exclusive of taxes) during the years ended December 31, 2010, 2009 and 2008.
Construction Work In Progress. At December 31, 2010 and 2009, we had $406 million and $271 million of construction work in progress included in our property, plant and equipment.
Asset Retirement Obligations. We have legal obligations associated with the retirement of our natural gas pipeline, transmission facilities and storage wells. We have obligations to plug storage wells when we no longer plan to use them and when we abandon them. Our legal obligations associated with our natural gas transportation facilities primarily involve purging and sealing the pipeline if it is abandoned. We also have obligations to remove hazardous materials associated with our natural gas transmission facilities if they are ever demolished or replaced. We continue to evaluate our asset retirement obligations and future developments could impact the amounts we record.
Where we can reasonably estimate the asset retirement obligation, we accrue a liability based on an estimate of the timing and amount of settlement. In estimating our asset retirement obligations, we utilize several assumptions, including a projected inflation rate of 2.5 percent, and credit-adjusted discount rates that currently range from five to 12 percent based on when the liabilities were recorded. We record changes in these estimates based on changes in the expected amount and timing of payments to settle our obligations. We intend on operating and maintaining our natural gas pipeline and storage systems as long as supply and demand for natural gas exists, which we expect for the foreseeable future. Therefore, we believe that we cannot reasonably estimate the asset retirement obligation for the substantial majority of our natural gas pipeline and storage system assets because these assets have indeterminate lives.
The net asset retirement obligation as of December 31 reported on our balance sheets in current and other non-current liabilities, and the changes in the net liability for the years ended December 31 were as follows:
|
2010
|
2009
|
|||||||
|
(In millions)
|
||||||||
|
Net asset retirement obligation at January 1
|
$ | 91 | $ | 42 | ||||
|
Liabilities settled
|
(26 | ) | (6 | ) | ||||
|
Accretion expense
|
2 | 2 | ||||||
|
Liabilities incurred
|
5 | — | ||||||
|
Changes in estimate (1)
|
(43 | ) | 53 | |||||
|
Net asset retirement obligation at December 31(2)
|
$ | 29 | $ | 91 | ||||
____________
(1) Reflects updated information received on our hurricane related asset retirement obligations.
(2) For the years ended December 31, 2010 and 2009, approximately $28 million and $66 million of this amount are reflected in current liabilities.
7. Debt and Credit Facilities
Debt. Our long-term debt consisted of the following at December 31:
|
2010
|
2009
|
|||||||
|
(In millions)
|
||||||||
|
6.0% Debentures due December 2011
|
$ | 86 | $ | 86 | ||||
|
8.0% Notes due February 2016
|
250 | 250 | ||||||
|
7.5% Debentures due April 2017
|
300 | 300 | ||||||
|
7.0% Debentures due March 2027
|
300 | 300 | ||||||
|
7.0% Debentures due October 2028
|
400 | 400 | ||||||
|
8.375% Notes due June 2032
|
240 | 240 | ||||||
|
7.625% Debentures due April 2037
|
300 | 300 | ||||||
| 1,876 | 1,876 | |||||||
|
Less: Current maturities
|
86 | — | ||||||
|
Unamortized discount
|
25 | 30 | ||||||
|
Total long-term debt
|
$ | 1,765 | $ | 1,846 | ||||
In January 2009, we issued $250 million of 8.00% senior notes due in February 2016 and received proceeds of $234 million, net of issuance costs.
Credit Facility. We are eligible to borrow amounts available under El Paso’s $1.5 billion credit agreement and are only liable for amounts we directly borrow. As of December 31, 2010, El Paso had approximately $0.9 billion of capacity remaining and available to us and our affiliates under this credit agreement, and none of the amount outstanding under the facility was issued or borrowed by us. Our common stock and the common stock of another El Paso subsidiary are pledged as collateral under the credit agreement.
Under El Paso’s $1.5 billion credit agreement and our indentures, we are subject to a number of restrictions and covenants. The most restrictive of these include (i) limitations on the incurrence of additional debt, based on a ratio of debt to EBITDA (as defined in the agreements), which shall not exceed 5 to 1; (ii) limitations on the use of proceeds from borrowings; (iii) limitations, in some cases, on transactions with our affiliates; (iv) limitations on the incurrence of liens; and (v) potential limitations on our ability to declare and pay dividends. For the year ended December 31, 2010, we were in compliance with our debt-related covenants.
8. Commitments and Contingencies
Legal Proceedings
We and our affiliates are named defendants in numerous legal proceedings and claims that arise in the ordinary course of our business. For each of these matters, we evaluate the merits of the case or claim, our exposure to the matter, possible legal or settlement strategies and the likelihood of an unfavorable outcome. If we determine that an unfavorable outcome is probable and can be estimated, we establish the necessary accruals. While the outcome of these matters cannot be predicted with certainty, and there are still uncertainties related to the costs we may incur, based upon our evaluation and experience to date, we had no accruals for our outstanding legal proceedings at December 31, 2010. It is possible, however, that new information or future developments could require us to reassess our potential exposure related to these matters and establish accruals accordingly.
Environmental Matters
We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require us to remove or remedy the effect of the disposal or release of specified substances at current and former operating sites. At December 31, 2010 and 2009, we had accrued approximately $4 million and $5 million for expected remediation costs and associated onsite, offsite and groundwater technical studies and for related environmental legal costs; however, we estimate that our exposure could be as high as $7 million at December 31, 2010.
Our environmental remediation projects are in various stages of completion. Our recorded liabilities reflect our current estimates of amounts we will spend to remediate these sites. However, depending on the stage of completion or assessment, the ultimate extent of contamination or remediation required may not be known. As additional assessments occur or remediation efforts continue, we may incur additional liabilities.
PCB Cost Recoveries and Refund. Since 1994, we have been conducting remediation activities at certain of our compressor stations associated with PCBs and other hazardous materials. We have collected amounts, substantially in excess of remediation costs to date, through a surcharge to our customers under a settlement approved by the FERC in November of 1995. In November 2009, the FERC approved an amendment to the 1995 settlement that provides for interim refunds over a three year period of approximately $157 million of our collected amounts plus interest of 8%. Through December 31, 2010, we have refunded approximately $58 million to our customers. Our refund obligations are recorded as regulatory liabilities on our balance sheet and as of December 31, 2010, we have classified approximately $78 million as current liabilities based on the timing of when these amounts are expected to be refunded to our customers.
Superfund Matters. Included in our recorded environmental liabilities are projects where we have received notice that we have been designated or could be designated as a Potentially Responsible Party (PRP) under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), commonly known as Superfund, or state equivalents for four active sites. Liability under the federal CERCLA statute may be joint and several, meaning that we could be required to pay in excess of our pro rata share of remediation costs. We consider the financial strength of other PRPs in estimating our liabilities. Accruals for these issues are included in the environmental reserve discussed above.
We expect to make capital expenditures for environmental matters of approximately $9 million in the aggregate for 2011 through 2015, including capital expenditures associated with the impact of the EPA rule on emissions of hazardous air pollutants from reciprocating internal combustion engines which are subject to regulations which have to be in compliance by October 2013.
It is possible that new information or future developments could require us to reassess our potential exposure related to environmental matters. We may incur significant costs and liabilities in order to comply with existing environmental laws and regulations. It is also possible that other developments, such as increasingly strict environmental laws, regulations and orders of regulatory agencies, as well as claims for damages to property and the environment or injuries to employees and other persons resulting from our current or past operations, could result in substantial costs and liabilities in the future. As this information becomes available, or other relevant developments occur, we will adjust our accrual amounts accordingly. While there are still uncertainties related to the ultimate costs we may incur, based upon our evaluation and experience to date, we believe our reserves are adequate.
Rates and Regulatory Matter
Rate Case. In November 2010, we filed a rate case with the FERC proposing an increase in base tariff rates, including a proposed change in our rate structure. In December 2010, the FERC issued an order accepting and suspending the effective date of the proposed rates to June 1, 2011, subject to refund, the outcome of a hearing and other proceedings. At this time, the outcome of this matter is not currently determinable.
Other Commitments
Capital Commitments. At December 31, 2010, we had capital commitments of approximately $320 million primarily related to our 300 Line Project, all of which will be spent in 2011. We have other planned capital projects that are discretionary in nature, with no substantial contractual capital commitments made in advance of the actual expenditures.
Purchase Obligations. We have entered into unconditional purchase obligations primarily for transportation, storage and other services, totaling $103 million at December 31, 2010. Our annual obligations under these purchase obligations are $35 million in 2011, $25 million in 2012, $14 million in 2013, $7 million in 2014, $7 million in 2015, and $15 million in total thereafter.
Operating Leases. We lease property, facilities and equipment under various operating leases. Future minimum annual rental commitments under our operating leases at December 31, 2010, were as follows:
|
|
||||
|
Year Ending
December 31,
|
(In millions)
|
|||
|
2011
|
$ | 1 | ||
|
Thereafter
|
3 | |||
|
Total
|
$ | 4 | ||
Rental expense on our lease obligations for each of the years ended December 31, 2010, 2009 and 2008 was $2 million. These amounts include rent allocated to us from El Paso.
Other Commercial Commitments. We hold cancelable easements or rights-of-way arrangements from landowners permitting the use of land for the construction and operation of our pipeline system. Our obligations under these easements are not material to our results of operations.
9. Retirement Benefits
Pension and Retirement Savings Plans. El Paso maintains a pension plan and a retirement savings plan covering substantially all of its U.S. employees, including our former employees. The benefits under the pension plan are determined under a cash balance formula. Under its retirement savings plan, El Paso matches 75 percent of participant basic contributions up to six percent of eligible compensation and can make additional discretionary matching contributions depending on El Paso’s operating performance relative to its peers. El Paso is responsible for benefits accrued under its plans and allocates the related costs to its affiliates.
37
Postretirement Benefits Plan. We provide postretirement medical and life insurance benefits for a closed group of employees who were eligible to retire on December 31, 1996, and did so before July 1, 1997. Medical benefits for this closed group may be subject to deductibles, co-payment provisions, and other limitations and dollar caps on the amount of employer costs and El Paso reserves the right to change these benefits. Employees in this group who retire after July 1, 1997 continue to receive limited postretirement life insurance benefits. Our postretirement benefit plan costs are prefunded to the extent these costs are recoverable through our rates. To the extent actual costs differ from the amounts recovered in rates, a regulatory asset or liability is recorded. We expect to contribute $5 million to our postretirement benefit plan in 2011.
Accumulated Postretirement Benefit Obligation, Plan Assets and Funded Status. In accounting for our postretirement benefit plan, we record an asset or liability based on the over funded or under funded status. Any deferred amounts related to unrecognized gains and losses or changes in actuarial assumptions are recorded either as a regulatory asset or liability as allowed by the FERC. These amounts would otherwise be recorded in accumulated other comprehensive income for non-regulated entities.
The table below provides information about our postretirement benefit plan.
|
December 31,
|
||||||||
|
2010
|
2009
|
|||||||
|
(In millions)
|
||||||||
|
Change in accumulated postretirement benefit obligation:
|
||||||||
|
Accumulated postretirement benefit obligation – beginning of period
|
$ | 18 | $ | 21 | ||||
|
Interest cost
|
1 | 1 | ||||||
|
Participant contributions
|
1 | 1 | ||||||
|
Actuarial gain
|
— | (4 | ) | |||||
|
Benefits paid(1)
|
(2 | ) | (1 | ) | ||||
|
Accumulated postretirement benefit obligation – end of period
|
$ | 18 | $ | 18 | ||||
|
Change in plan assets:
|
||||||||
|
Fair value of plan assets – beginning period
|
$ | 33 | $ | 23 | ||||
|
Actual return on plan assets
|
4 | 6 | ||||||
|
Employer contributions
|
5 | 4 | ||||||
|
Participant contributions
|
1 | 1 | ||||||
|
Benefits paid
|
(2 | ) | (1 | ) | ||||
|
Fair value of plan assets – end of period
|
$ | 41 | $ | 33 | ||||
|
Reconciliation of funded status:
|
||||||||
|
Fair value of plan assets
|
$ | 41 | $ | 33 | ||||
|
Less: accumulated postretirement benefit obligation
|
18 | 18 | ||||||
|
Net asset at December 31
|
$ | 23 | $ | 15 | ||||
____________
(1) Amounts shown net of a subsidy of less than $1 million for each of the years ended December 31, 2010 and 2009 related to the Medicare Prescription Drug, Improvement, and Modernization Act of 2003.
Plan Assets. The primary investment objective of our plan is to ensure that, over the long-term life of the plan an adequate pool of sufficiently liquid assets exists to meet the benefit obligations to retirees and beneficiaries. Investment objectives are long-term in nature covering typical market cycles. Any shortfall of investment performance compared to investment objectives is generally the result of economic and capital market conditions. Although actual allocations vary from time to time from our targeted allocations, the target allocations of our postretirement plan’s assets are 65 percent equity and 35 percent fixed income securities. We may invest plan assets in a manner that replicates, to the extent feasible, the Russell 3000 Index and the Barclays Capital Aggregate Bond Index to achieve equity and fixed income diversification, respectively.
We use various methods to determine the fair values of the assets in our other postretirement benefit plan, which are impacted by a number of factors, including the availability of observable market data over the contractual term of the underlying assets. We separate these assets into three levels (Level 1, 2 and 3) based on our assessment of the availability of this market data and the significance of non-observable data used to determine the fair value of these assets. As of December 31, 2010, assets were comprised of an exchange-traded mutual fund with a fair value of $2 million and common collective trust funds with a fair value of $39 million. As of December 31, 2009, assets were comprised of an exchange-traded mutual fund with a fair value of $2 million and common collective trust funds with a fair value of $31 million. Our exchange-traded mutual fund invests primarily in dollar-denominated securities, and its fair value (which is considered a Level 1 measurement) is determined based on the price quoted for the fund in actively traded markets. Our common collective trust funds are invested in approximately 65 percent equity and 35 percent fixed income securities, and their fair values (which are considered Level 2 measurements) are determined primarily based on the net asset value reported by the issuer, which is based on similar assets in active markets. Certain restrictions on withdrawals exist for these common collective trust funds where the issuer reserves the right to temporarily delay withdrawal in certain situations such as market conditions or at the issuer’s discretion. We do not have any assets that are considered Level 3 measurements. The methods described above may produce a fair value that may not be indicative of net realizable value or reflective of future fair values, and there have been no changes in the methodologies used at December 31, 2010 and 2009.
Expected Payment of Future Benefits. As of December 31, 2010, we expect the following benefit payments under our plan:
|
Year Ending
December 31,
|
Expected
Payments(1)
|
||||
|
(In millions)
|
|||||
|
2011
|
$ | 2 | |||
|
2012
|
2 | ||||
|
2013
|
2 | ||||
|
2014
|
2 | ||||
|
2015
|
2 | ||||
|
2016 - 2020
|
6 | ||||
____________
(1) Includes a reduction of less than $1 million in each of the years 2011 – 2015 and approximately $1 million in aggregate for 2016 – 2020 for an expected subsidy related to the Medicare Prescription Drug, Improvement, and Modernization Act of 2003.
Actuarial Assumptions and Sensitivity Analysis. Accumulated postretirement benefit obligations and net benefit costs are based on actuarial estimates and assumptions. The following table details the weighted average actuarial assumptions used in determining our postretirement plan obligations and net benefit costs for 2010, 2009 and 2008:
|
2010
|
2009
|
2008
|
||||||||||
|
(Percent)
|
||||||||||||
|
Assumptions related to benefit obligations at December 31:
|
||||||||||||
|
Discount rate
|
4.82 | 5.37 | 5.95 | |||||||||
|
Assumptions related to benefit costs for the year ended December 31:
|
||||||||||||
|
Discount rate
|
5.37 | 5.95 | 6.05 | |||||||||
|
Expected return on plan assets(1)
|
7.75 | 8.00 | 8.00 | |||||||||
____________
(1) The expected return on plan assets is a pre-tax rate of return based on our targeted portfolio of investments. Our postretirement benefit plan’s investment earnings are subject to unrelated business income taxes at a rate of 35%. The expected return on plan assets for our postretirement benefit plan is calculated using the after-tax rate of return.
Actuarial estimates for our postretirement benefits plan assumed a weighted average annual rate of increase in the per capita costs of covered health care benefits of 7.4 percent, gradually decreasing to 5.0 percent by the year 2016. A one-percentage point change would not have had a significant effect on the accumulated postretirement benefit obligation or interest cost as of and for the years ended December 31, 2010 and 2009.
Components of Net Benefit Income. For each of the years ended December 31, the components of net benefit income are as follows:
|
2010
|
2009
|
2008
|
||||||||||
|
(In millions)
|
||||||||||||
|
Interest cost
|
$ | 1 | $ | 1 | $ | 1 | ||||||
|
Expected return on plan assets
|
(2 | ) | (1 | ) | (1 | ) | ||||||
|
Net benefit income
|
$ | (1 | ) | $ | — | $ | — | |||||
10. Transactions with Major Customer
The following table shows revenues from our major customer for each of the three years ended December 31:
|
2010
|
2009
|
2008
|
||||||||||
|
(In millions)
|
||||||||||||
|
National Grid USA and subsidiaries
|
$ | 116 | $ | 109 | $ | 109 | ||||||
11. Accounts Receivable Sales Program
During 2009, we had an agreement to sell a senior interest in certain accounts receivable (which are short-term assets that generally settle within 60 days) to a third party financial institution (through a wholly-owned special purpose entity), and we retained a subordinated interest in those receivables. The sale of the senior interest qualified for sale accounting and was conducted to accelerate cash from these receivables, the proceeds from which were used to increase liquidity and lower our overall cost of capital. During the years ended December 31, 2009 and 2008, we received $481 million and $430 million of cash related to the sale of the senior interest, collected $462 million and $521 million from the subordinated interest we retained in the receivables, and recognized a loss of less than $1 million and approximately $1 million during 2009 and 2008 on these transactions. At December 31, 2009, the third party financial institution held $40 million of senior interest and we held $43 million of subordinated interest. Our subordinated interest was reflected in accounts receivable on our balance sheet. In January 2010, we terminated this accounts receivable sales program and paid $40 million to acquire the senior interest. We reflected the cash flows related to the accounts receivable sold under this program, changes in our retained subordinated interest, and cash paid to terminate the program, as operating cash flows on our statement of cash flows.
In the first quarter of 2010, we entered into a new accounts receivable sales program to continue to sell accounts receivable to the third party financial institution that qualifies for sale accounting under the updated accounting standards related to financial asset transfers. Under this program, we sell receivables in their entirety to the third party financial institution (through a wholly-owned special purpose entity). At December 31, 2010, the third party financial institution held $75 million of the accounts receivable we sold under the program. In connection with our accounts receivable sales, we receive a portion of the sales proceeds up front and receive an additional amount upon the collection of the underlying receivables (which we refer to as a deferred purchase price). Our ability to recover the deferred purchase price is based solely on the collection of the underlying receivables. During the year ended December 31, 2010, we sold approximately $943 million of accounts receivable to the third party financial institution, for which we received approximately $508 million of cash up front and had a deferred purchase price of approximately $435 million. We received approximately $399 million of cash related to the deferred purchase price when the underlying receivables were collected during 2010. As of December 31, 2010, we had not collected approximately $35 million of deferred purchase price related to our accounts receivable sales, which is reflected as other accounts receivable on our balance sheet (and was initially recorded at an amount which approximates its fair value using observable inputs other than quoted prices in active markets). We recognized a loss of less than $1 million on our accounts receivable sales for the year ended December 31, 2010. Because the cash received up front and the deferred purchase price relate to the sale or ultimate collection of the underlying receivables, and are not subject to significant other risks given their short term nature, we reflect all cash flows under the new accounts receivable sales program as operating cash flows on our statement of cash flows.
Under both the prior and current accounts receivable sales programs, we serviced the underlying receivables for a fee. The fair value of these servicing agreements as well as the fees earned were not material to our financial statements for the years ended December 31, 2010, 2009 and 2008.
The third party financial institution involved in both of these accounts receivable sales programs acquires interests in various financial assets and issues commercial paper to fund those acquisitions. We do not consolidate the third party financial institution because we do not have the power to control, direct, or exert significant influence over its overall activities since our receivables do not comprise a significant portion of its operations.
12. Investment in Unconsolidated Affiliate and Transactions with Affiliates
Investment in Unconsolidated Affiliate
Bear Creek Storage Company, LLC (Bear Creek). We have a 50 percent ownership interest in Bear Creek, a joint venture with Southern Natural Gas Company, our affiliate. We account for our investment in Bear Creek using the equity method of accounting. During 2010, 2009 and 2008, we received $14 million, $13 million and $16 million in cash distributions from Bear Creek. Also, during 2010, Bear Creek utilized its note receivable balance under the cash management program with El Paso to pay a cash distribution to its partners, including $23 million to us. Included in this amount was a return of capital of $15 million.
Summarized financial information for our proportionate share of Bear Creek as of and for the years ended December 31 is presented as follows:
|
2010
|
2009
|
2008
|
||||||||||
|
(In millions)
|
||||||||||||
|
Operating results data:
|
||||||||||||
|
Operating revenues
|
$ | 19 | $ | 18 | $ | 20 | ||||||
|
Operating expenses
|
5 | 7 | 8 | |||||||||
|
Income from operations and net income
|
14 | 11 | 13 | |||||||||
|
2010
|
2009
|
|||||||
|
(In millions)
|
||||||||
|
Financial position data:
|
||||||||
|
Current assets
|
$ | 5 | $ | 28 | ||||
|
Non-current assets
|
52 | 52 | ||||||
|
Current liabilities
|
2 | 1 | ||||||
|
Equity in net assets
|
55 | 79 | ||||||
Transactions with Affiliates
Cash Management Program and Other Note Receivable. We participate in El Paso’s cash management program which matches short-term cash surpluses and needs of participating affiliates, thus minimizing total borrowings from outside sources. El Paso uses the cash management program to settle intercompany transactions between participating affiliates. We have historically advanced cash to El Paso in exchange for an affiliated note receivable that is due upon demand. At December 31, 2010 and 2009, we had a note receivable from El Paso of $1.0 billion. We classified approximately $359 million of this receivable as current on our balance sheet at December 31, 2010, based on the net amount we anticipate using in the next twelve months considering available cash sources and needs. The interest rate on this variable rate note was 1.5% at December 31, 2010 and 2009.
At December 31, 2009, we had a non-interest bearing note receivable of $334 million from an El Paso affiliate reflected as a reduction of our stockholder’s equity. During 2010, we collected this note receivable and then immediately distributed the cash received to our parent.
Income Taxes. El Paso files consolidated U.S. federal and certain state tax returns which include our taxable income. In certain states, we file and pay taxes directly to the state taxing authorities. At December 31, 2010 and 2009, we had net federal and state income taxes receivable of $4 million and net federal and state income taxes payable of $75 million. The majority of these balances, as well as deferred income taxes and amounts associated with the resolution of unrecognized tax benefits, will become receivable from or payable to El Paso. See Note 1 for a discussion of our income tax policy.
Other Affiliate Balances. At December 31, 2010 and 2009, we had contractual deposits from our affiliates of $10 million and $9 million.
Affiliate Revenues and Expenses. We enter into transactions with our affiliates within the ordinary course of our business and the services are based on the same terms as non-affiliates. In addition, we store natural gas in an affiliated storage facility and utilize the pipeline system of an affiliate to transport some of our natural gas.
In December 2009, we entered into a contract with our affiliate, El Paso Marketing, L.P., to sell up to 22 TBtu of natural gas not used in our operations in 2011 at a price of $6.48 per MMBtu.
El Paso bills us directly for certain general and administrative costs and allocates a portion of its general and administrative costs to us. In addition to allocations from El Paso, we allocate costs to our pipeline affiliates for their proportionate share of our pipeline services. The allocations from El Paso and the allocations to our affiliates are based on the estimated level of effort devoted to our operations and the relative size of our and their earnings before interest expense and income taxes, gross property and payroll.
The following table shows overall revenues, expenses and reimbursements from our affiliates for each of the three years ended December 31:
|
2010
|
2009
|
2008
|
||||||||||
|
(In millions)
|
||||||||||||
|
Revenues
|
$ | 20 | $ | 16 | $ | 20 | ||||||
|
Operation and maintenance expenses
|
77 | 67 | 60 | |||||||||
|
Reimbursements of operating expenses
|
59 | 45 | 47 | |||||||||
13. Supplemental Selected Quarterly Financial Information (Unaudited)
Our financial information by quarter is summarized below. Due to the seasonal nature of our business, information for interim periods may not be indicative of our results of operations for the entire year.
|
Quarters Ended
|
||||||||||||||||||||
|
March 31
|
June 30
|
September 30
|
December 31
|
Total
|
||||||||||||||||
|
(In millions)
|
||||||||||||||||||||
|
2010
|
||||||||||||||||||||
|
Operating revenues
|
$ | 224 | $ | 200 | $ | 213 | $ | 208 | $ | 845 | ||||||||||
|
Operating income
|
89 | 59 | 65 | 55 | 268 | |||||||||||||||
|
Net income
|
39 | 20 | 28 | 16 | 103 | |||||||||||||||
|
2009
|
||||||||||||||||||||
|
Operating revenues
|
$ | 266 | $ | 217 | $ | 221 | $ | 229 | $ | 933 | ||||||||||
|
Operating income
|
114 | 70 | 64 | 73 | 321 | |||||||||||||||
|
Net income
|
53 | 25 | 20 | 29 | 127 | |||||||||||||||
SCHEDULE II
TENNESSEE GAS PIPELINE COMPANY
VALUATION AND QUALIFYING ACCOUNTS
Years Ended December 31, 2010, 2009 and 2008
(In millions)
|
Description
|
Balance at
Beginning
of Period
|
Charged to
Costs and
Expenses
|
Deductions
|
Balance
at End
of Period
|
||||||||||||
|
|
||||||||||||||||
|
2010
|
||||||||||||||||
|
Legal reserves
|
$ | 7 | $ | — | $ | (7 | ) | $ | — | |||||||
|
Environmental reserves
|
5 | 1 | (2 | )(1) | 4 | |||||||||||
|
2009
|
||||||||||||||||
|
Legal reserves
|
$ | — | $ | 7 | $ | — | $ | 7 | ||||||||
|
Environmental reserves
|
6 | — | (1 | )(1) | 5 | |||||||||||
|
2008
|
||||||||||||||||
|
Environmental reserves
|
$ | 10 | $ | (2 | ) | $ | (2 | )(1) | $ | 6 | ||||||
_________
(1) Primarily payments made for environmental remediation activities.
None.
Evaluation of Disclosure Controls and Procedures
As of December 31, 2010, we carried out an evaluation under the supervision and with the participation of our management, including our President and Chief Financial Officer (CFO), as to the effectiveness, design and operation of our disclosure controls and procedures. This evaluation considered the various processes carried out under the direction of our disclosure committee in an effort to ensure that information required to be disclosed in the U.S. Securities and Exchange Commission reports we file or submit under the Securities Exchange Act of 1934, as amended (Exchange Act) is accurate, complete and timely. Our management, including our President and CFO, does not expect that our disclosure controls and procedures or our internal controls will prevent and/or detect all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within our company have been detected. Our disclosure controls and procedures are designed to provide reasonable assurance of achieving their objectives and our President and CFO concluded that our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) were effective as of December 31, 2010. See Item 8, Financial Statements and Supplementary Data under Management’s Annual Report on Internal Control Over Financial Reporting.
Changes in Internal Control Over Financial Reporting
There were no changes in our internal control over financial reporting during the fourth quarter of 2010 that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.
None.
Item 10, “Directors, Executive Officers and Corporate Governance;” Item 11, “Executive Compensation;” Item 12, “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters;” and Item 13, “Certain Relationships and Related Transactions, and Director Independence” have been omitted from this report pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.
Audit Fees
The audit fees for the years ended December 31, 2010 and 2009 of $982,000 and $878,000, respectively, were primarily for professional services rendered by Ernst & Young LLP for the audits of the consolidated financial statements of Tennessee Gas Pipeline Company and its subsidiaries as well as the review of documents filed with the SEC, related consents in both 2010 and 2009 and the issuance of a comfort letter in 2009.
All Other Fees
No other audit-related, tax or other services were provided by our independent registered public accounting firm for the years ended December 31, 2010 and 2009.
Policy for Approval of Audit and Non-Audit Fees
We are an indirect wholly owned subsidiary of El Paso and do not have a separate audit committee. El Paso’s Audit Committee has adopted a pre-approval policy for audit and non-audit services. For a description of El Paso’s pre-approval policies for audit and non-audit related services, see El Paso Corporation’s proxy statement for its 2011 Annual Meeting of Stockholders.
|
(a)
|
The following documents are filed as a part of this report:
|
1. Financial statements
The following consolidated financial statements are included in Part II, Item 8 of this report:
|
Page
|
|
|
Report of Independent Registered Public Accounting Firm
|
23
|
|
Consolidated Statements of Income
|
24
|
|
Consolidated Balance Sheets
|
25
|
|
Consolidated Statements of Cash Flows
|
26
|
|
Consolidated Statements of Stockholder’s Equity
|
27
|
|
Notes to Consolidated Financial Statements
|
28
|
2. Financial statement schedules
|
Schedule II — Valuation and Qualifying Accounts
|
43
|
All other schedules are omitted because they are not applicable, or the required information is disclosed in the financial statements or accompanying notes.
3. Exhibits
The Exhibit Index, which follows the signature page to this report and is hereby incorporated herein by reference, sets forth a list of those exhibits filed herewith, and includes and identifies contracts or arrangements required to be filed as exhibits to this Form 10-K by Item 601(b)(10)(iii) of Regulation S-K.
The agreements included as exhibits to this report are intended to provide information regarding their terms and not to provide any other factual or disclosure information about us or the other parties to the agreements. The agreements may contain representations and warranties by the parties to the agreements, including us, solely for the benefit of the other parties to the applicable agreement and:
|
•
|
should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties if those statements prove to be inaccurate;
|
|
•
|
may have been qualified by disclosures that were made to the other party in connection with the negotiation of the applicable agreement, which disclosures are not necessarily reflected in the agreement;
|
|
•
|
may apply standards of materiality in a way that is different from what may be viewed as material to certain investors; and
|
|
•
|
were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement and are subject to more recent developments.
|
Accordingly, these representations and warranties may not describe the actual state of affairs as of the date they were made or at any other time.
Undertaking
We hereby undertake, pursuant to Regulation S-K, Item 601(b), paragraph (4)(iii), to furnish to the Securities and Exchange Commission upon request all constituent instruments defining the rights of holders of our long-term debt and consolidated subsidiaries not filed herewith for the reason that the total amount of securities authorized under any of such instruments does not exceed 10 percent of our total consolidated assets.
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Tennessee Gas Pipeline Company has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on the 28th day of February 2011.
|
TENNESSEE GAS PIPELINE COMPANY
|
|||
|
By:
|
/s/ Norman G. Holmes | ||
|
Norman G. Holmes
|
|||
|
President
|
|||
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of Tennessee Gas Pipeline Company and in the capacities and on the dates indicated:
|
Signature
|
Title
|
Date
|
| /s/ Norman G. Holmes |
President and Director
|
February 28, 2011
|
|
Norman G. Holmes
|
(Principal Executive Officer)
|
|
|
Executive Vice President and
|
||
| /s/ John R. Sult |
Chief Financial Officer
|
February 28, 2011
|
|
John R. Sult
|
(Principal Financial Officer)
|
|
| /s/ Rosa P. Jackson |
Vice President and Controller
|
February 28, 2011
|
|
Rosa P. Jackson
|
(Principal Accounting Officer)
|
|
| /s/ James C. Yardley | ||
|
James C. Yardley
|
Chairman of the Board and Director
|
February 28, 2011
|
| /s/ Daniel B. Martin | ||
|
Daniel B. Martin
|
Director
|
February 28, 2011
|
| /s/ Bryan W. Neskora | ||
|
Bryan W. Neskora
|
Director
|
February 28, 2011
|
TENNESSEE GAS PIPELINE COMPANY
EXHIBIT INDEX
December 31, 2010
Each exhibit identified below is filed as part of this report. Exhibits filed with this report are designated by “*”. All exhibits not so designated are incorporated herein by reference to a prior filing as indicated.
|
Exhibit
|
||
|
Number
|
Description
|
|
|
3.A
|
Restated Certificate of Incorporation dated May 11, 1999 (incorporated by reference to Exhibit 3.A to our Annual Report on Form 10-K for the year ended December 31, 2009, filed with the SEC on March 1, 2010).
|
|
|
3.B
|
By-laws dated as of June 2, 2008 (incorporated by reference to Exhibit 3.B to our Annual Report on Form 10-K for the year ended December 31, 2008, filed with the SEC on March 2, 2009).
|
|
|
4.A
|
Indenture dated as of March 4, 1997, between Tennessee Gas Pipeline Company and Wilmington Trust Company (as successor to JPMorgan Chase Bank, formerly known as The Chase Manhattan Bank), as Trustee (incorporated by reference to Exhibit 4.A to our Annual Report on Form 10-K for the year ended December 31, 2005, filed with the SEC on March 7, 2006).
|
|
|
4.A.1
|
First Supplemental Indenture dated as of March 13, 1997, between Tennessee Gas Pipeline Company and the Trustee (incorporated by reference to Exhibit 4.A.1 to our Annual Report on Form 10-K for the year ended December 31, 2005, filed with the SEC on March 7, 2006).
|
|
|
4.A.2
|
Second Supplemental Indenture dated as of March 13, 1997, between Tennessee Gas Pipeline Company and the Trustee (incorporated by reference to Exhibit 4.A.2 to our Annual Report on Form 10-K for the year ended December 31, 2005, filed with the SEC on March 7, 2006).
|
|
|
4.A.3
|
Third Supplemental Indenture dated as of March 13, 1997, between Tennessee Gas Pipeline Company and the Trustee (incorporated by reference to Exhibit 4.A.3 to our Annual Report on Form 10-K for the year ended December 31, 2005, filed with the SEC on March 7, 2006).
|
|
|
4.A.4
|
Fourth Supplemental Indenture dated as of October 9, 1998, between Tennessee Gas Pipeline Company and the Trustee (incorporated by reference to Exhibit 4.A.4 to our Annual Report on Form 10-K for the year ended December 31, 2004, filed with the SEC on March 7, 2006).
|
|
|
4.A.5
|
Fifth Supplemental Indenture dated June 10, 2002, between Tennessee Gas Pipeline Company and the Trustee (incorporated by reference to Exhibit 4.A.5 to our Annual Report on Form 10-K for the year ended December 31, 2008, filed with the SEC on March 2, 2009).
|
|
|
4.A.6
|
Sixth Supplemental Indenture dated as of January 27, 2009 between Tennessee Gas Pipeline Company and Wilmington Trust Company, as trustee, to indenture dated as of March 4, 1997 (incorporated by reference to Exhibit 4.A to our Current Report on Form 8-K filed with the SEC on January 29, 2009).
|
|
|
|
||
|
10.A
|
Third Amended and Restated Security Agreement dated as of November 16, 2007, made by among El Paso Corporation, El Paso Natural Gas Company, Tennessee Gas Pipeline Company, the several banks and other financial institutions from time to time parties thereto and JPMorgan Chase Bank, N.A., as administrative agent and as collateral agent (incorporated by reference to Exhibit 10.A to our Annual Report on Form 10-K for the year ended December 31, 2009, filed with the SEC on March 1, 2010).
|
|
10.B
|
Third Amended and Restated Security Agreement dated as of November 16, 2007, made by among El Paso Corporation, El Paso Natural Gas Company, Tennessee Gas Pipeline Company, the Subsidiary Grantors and certain other credit parties thereto and JPMorgan Chase Bank, N.A., not in its individual capacity, but solely as collateral agent for the Secured Parties and as the depository bank (incorporated by reference to Exhibit 10.B to our Annual Report on Form 10-K for the year ended December 31, 2009, filed with the SEC on March 1, 2010).
|
|
|
10.C
|
Third Amended and Restated Subsidiary Guarantee Agreement dated as of November 16, 2007, made by each of the Subsidiary Guarantors in favor of JPMorgan Chase Bank, N.A., as Collateral Agent (incorporated by reference to Exhibit 10.C to our Current Report on Form 8-K filed with the SEC on November 21, 2007).
|
|
|
10.D
|
Registration Rights Agreement, dated as of January 27, 2009, among Tennessee Gas Pipeline Company and Banc of America Securities LLC, Credit Suisse Securities (USA) LLC, Deutsche Bank Securities Inc., Greenwich Capital Markets, Inc., BMO Capital Markets Corp., BNP Paribas Securities Corp., SG Americas Securities, LLC, UBS Securities LLC, and Wells Fargo Securities, LLC (incorporated by reference to Exhibit 10.A to our Current Report on Form 8-K filed with the SEC on January 29, 2009).
|
|
|
21
|
Omitted pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.
|
|
|
*23
|
Consent of Independent Registered Public Accounting Firm Ernst & Young LLP.
|
|
|
*31.A
|
Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
|
|
|
*31.B
|
Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
|
|
|
*32.A
|
Certification of Principal Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
|
|
|
*32.B
|
Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
|
49