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, 2008 | |
OR | |
£ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
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 o No þ
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 þ No o
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 þ No o
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. þ
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 o | Accelerated filer o | Non-accelerated filer þ (Do not check if a smaller reporting company) | Smaller Reporting Company o |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ
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 March 2, 2009: 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
TABLE OF CONTENTS
Caption | Page | ||||
PART I | |||||
Item 1. | Business | 1 | |||
Item 1A. | Risk Factors | 4 | |||
Item 1B. | Unresolved Staff Comments | 10 | |||
Item 2. | Properties | 10 | |||
Item 3. | Legal Proceedings | 11 | |||
Item 4. | Submission of Matters to a Vote of Security Holders | * | |||
PART II | |||||
Item 5. | Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities | 11 | |||
Item 6. | Selected Financial Data | * | |||
Item 7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations | 12 | |||
Item 7A. | Quantitative and Qualitative Disclosures About Market Risk | 18 | |||
Item 8. | Financial Statements and Supplementary Data | 19 | |||
Item 9. | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure | 43 | |||
Item 9A. | Controls and Procedures | 43 | |||
Item 9A(T). | Controls and Procedures | 43 | |||
Item 9B. | Other Information | 43 | |||
PART III | |||||
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 | * | |||
Item 13. | Certain Relationships and Related Transactions, and Director Independence | * | |||
Item 14. | Principal Accountant Fees and Services | 44 | |||
PART IV | |||||
Item 15. | Exhibits and Financial Statement Schedules | 45 | |||
Signatures | 46 |
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* | 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 | LNG | = | liquefied natural gas |
BBtu | = | billion British thermal units | MMcf | = | million cubic feet |
Bcf | = | billion cubic feet | NGL | = | natural gas liquid |
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 “TGP”, we are describing Tennessee Gas Pipeline Company and/or our subsidiaries.
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PART I
ITEM 1. BUSINESS
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 tariffs approved by the Federal Energy Regulatory Commission (FERC) that establish rates, cost recovery mechanisms and other terms and conditions of services to our customers. The fees or 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.
Our strategy is to enhance the value of our transportation and storage business by:
• | Providing outstanding customer service; |
• | Successfully executing on our backlog of committed expansion projects; |
• | Developing new growth projects in our market and supply areas; |
• | Ensuring the safety of our pipeline system and assets; |
• | Optimizing our contract portfolio; |
• | Focusing on efficiency and synergies across our system; and |
• | Managing market segmentation and differentiation. |
Pipeline System. Our pipeline system consists of approximately 13,600 miles of pipeline with a design capacity of approximately 7,069 MMcf/d. During 2008, 2007 and 2006, average throughput was 4,864 BBtu/d, 4,880 BBtu/d and 4,534 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 Pipeline Expansion Projects. As of December 31, 2008, we had the following FERC-approved pipeline expansion projects on our system. For a further discussion of our other expansion projects including our $750 million 300 Line Expansion project, see Item 7, Management’s Discussion and Analysis of Financial Conditions and Results of Operations.
Project | Capacity(MMcf/d) | Description | Anticipated Completion Date | |||
Carthage Expansion Project | 98 | Installation of a new 7,700 horsepower compressor station in DeSoto Parish, Louisiana, abandonment of three 1,100 horsepower units and installation of a 10,310 horsepower gas turbine unit to upgrade and replace compression at our existing Compressor Station 47 located in Ouachita Parish, Louisiana, and the construction of 1.1 miles of 12 inch pipeline and meter facilities also located in Ouachita Parish, Louisiana. The facilities will enable us to provide 98MMcf/d of firm transportation service to Entergy Corporation under a long-term contract. | May 2009 | |||
Concord Lateral Expansion | 29 | Construction of a new 6,130 horsepower compressor station on our Line 200 system in Pelham, New Hampshire to enable us to provide 29 MMcf/d of incremental firm transportation service to EnergyNorth Natural Gas Company. | November 2009 |
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Storage Facilities. Along our system, we have approximately 92 Bcf of underground working natural gas storage capacity. Of this amount, 29 Bcf is contracted from Bear Creek Storage Company (Bear Creek), our affiliate. Bear Creek is a joint venture that we own equally with our affiliate, Southern Gas Storage Company, a subsidiary of Southern Natural Gas Company (SNG). Bear Creek owns and operates an underground natural gas storage facility located in Bienville Parish, Louisiana. The facility has 58 Bcf of working storage capacity. Bear Creek’s working storage capacity is committed equally to SNG and us under long-term contracts.
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.
Imported LNG has been a growing supply sector of the natural gas market. 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 a growing demand sector of the natural gas market. The growth of natural gas fired electric power benefits the natural gas industry by creating more demand for natural gas. This potential benefit is offset, in varying degrees, by increased generation efficiency, the more effective use of surplus electric capacity and the use and availability of other fuel sources for power generation. In addition, in several regions of the country, new additions in electric generating capacity have exceeded load growth and electric transmission capabilities out of those regions. These developments may inhibit owners of new power generation facilities from signing firm transportation contracts with natural gas pipelines.
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 expect growth of the natural gas market will be adversely affected by the current economic recession in the U.S. and global economies. The decline in economic activity will reduce industrial demand for natural gas and electricity, which will cause lower natural gas demand both directly in end-use markets and indirectly through lower power generation demand for natural gas. The demand for natural gas and electricity in the residential and commercial segments of the market will likely be less affected by the economy. The lower demand and the credit restrictions on investments in the current environment may also slow development of supply projects. However, we believe our exposure to changes in natural gas consumption and demand is largely mitigated by a revenue base that is significantly comprised of long term contracts that are based on firm demand charges and are less affected by a potential reduction in the actual usage or consumption of natural gas.
Our existing transportation and storage contracts mature 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. 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.
We face competition in the northeast, Appalachian, midwest and southeast market areas. 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 such as electricity, 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 from the Canadian border.
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The following table details our customer and contract information related to our pipeline system as of December 31, 2008. 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 470 firm and interruptible customers. | Approximately 510 firm transportation contracts. Weighted average remaining contract term of approximately four years. | ||||
Major Customer: National Grid USA and Subsidiaries (736 BBtu/d) | Expires in 2010-2027. |
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. 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.
Environmental
A description of our environmental 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 23, 2009, we had approximately 1,700 full-time employees, none of whom are subject to a collective bargaining arrangement.
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ITEM 1A. RISK FACTORS
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 actual results, and differences between assumed facts and actual results can be material, depending upon the circumstances. Where, based on assumptions, we or our management 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, be achieved or accomplished. 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 cautionary statements and any other cautionary statements that may accompany such forward-looking statements. In addition, we disclaim any obligation to update any forward-looking statements to reflect events or circumstances after the date of this report.
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 forward-looking statement made by us or on our behalf.
Risks Related to Our Business
Our success depends on factors beyond our control.
The financial results of our transportation and storage operations are impacted by the volumes of natural gas we transport or store and the prices we are able to charge for doing so. The volume of natural gas we are able to transport and store depends on the actions of third parties, including our customers, and is beyond our control. Further, the following factors, most of which are also beyond our control, may unfavorably impact our ability to maintain or increase current throughput, or to remarket unsubscribed capacity on our pipeline system:
• | service area competition; |
• | price competition; |
• | changes in regulation and action of regulatory bodies; |
• | weather conditions that impact natural gas throughput and storage levels; |
• | weather fluctuations or warming or cooling trends that may impact demand in the markets in which we do business, including trends potentially attributable to climate change; |
• | continued development of additional sources of gas supply that can be accessed; |
• | decreased natural gas demand due to various factors, including economic recession (as further discussed below) and increases in prices; |
• | legislative, regulatory or judicial actions, such as mandatory greenhouse gas regulations and/or legislation that could result in (i) changes in the demand for natural gas and oil, (ii) changes in the availability of or demand for alternative energy sources such as hydroelectric and nuclear power, wind and solar, and/or (iii) changes in the demand for less carbon intensive energy sources; |
• | availability and cost to fund ongoing maintenance and growth projects, especially in periods of prolonged economic decline; |
• | opposition to energy infrastructure development, especially in environmentally sensitive areas; |
• | adverse general economic conditions including prolonged recessionary periods that might negatively impact natural gas demand and the capital markets; and |
• | unfavorable movements in natural gas prices in certain supply and demand areas. |
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A substantial portion of our revenues are generated from firm transportation 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. Currently, a substantial portion of our revenues are under contracts that are discounted at rates below the maximum rates allowed under our tariff. For additional information on the expiration of our contract portfolio, see Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations. In particular, our ability to extend and replace contracts could be adversely affected by factors we cannot control, including:
• | competition by other pipelines, including the change in rates or upstream supply of existing pipeline competitors, as well as the proposed construction by other companies of additional pipeline capacity or LNG terminals in markets served by our interstate pipeline; |
• | changes in state regulation of local distribution companies, which may cause them to negotiate short-term contracts or turn back their capacity when their contracts expire; |
• | reduced demand and market conditions in the areas we serve; |
• | the availability of alternative energy sources or natural gas supply points; and |
• | legislative and/or regulatory actions. |
For 2008, our revenues from National Grid USA and Subsidiaries represented approximately 12 percent of our operating revenues. For additional information on our revenues from this customer, see Part II, Item 8, Financial Statements and Supplementary Data, Note 10. The loss of this customer or a decline in its creditworthiness could adversely affect our results of operations, financial position and cash flows.
We are exposed to the credit risk of our customers and our credit risk management may not be adequate to protect against such risk.
We are subject to the risk of delays in payment as well as losses resulting from nonpayment and/or nonperformance by our customers, including default risk associated with adverse economic conditions. Our credit procedures and policies may not be adequate to fully eliminate customer credit risk. If we fail to adequately assess the creditworthiness of our existing or future customers, and they fail to pay and/or perform due to an unanticipated deterioration in their creditworthiness and we are unable to remarket the capacity, our business, the results of our operations and our financial condition could be adversely affected. We may not be able to effectively remarket capacity during and after insolvency proceedings involving a shipper.
Fluctuations in energy commodity prices could adversely affect our business.
Revenues generated by our transportation and storage contracts depend on volumes and rates, both of which can be affected by the price of natural gas. Increased prices could result in a reduction of the volumes transported by our customers, including power companies that may not dispatch natural gas-fired power plants if natural gas prices increase. Increased prices could also result in industrial plant shutdowns or load losses to competitive fuels as well as local distribution companies’ loss of customer base. The success of our transmission and storage operations is subject to continued development of additional gas supplies to offset the natural decline from existing wells connected to our system, which requires the development of additional oil and natural gas reserves and obtaining additional supplies from interconnecting pipelines, primarily in the Gulf of Mexico. A 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.
We retain a fixed percentage of natural gas transported as provided in our tariff. This 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 fuel and to replace lost and unaccounted for natural gas. Pricing volatility may impact the value of under or over recoveries of retained natural gas, imbalances and system encroachments. If natural gas prices in the supply basins connected to our pipeline system are higher than prices in other natural gas producing regions, our ability to compete with other transporters may be negatively impacted on a short-term basis, as well as with respect to our long-term recontracting activities. Furthermore, fluctuations in pricing between supply sources and market areas could negatively impact our transportation revenues. As a result, significant prolonged changes in natural gas prices could have a material adverse effect on our financial condition, results of operations and liquidity. Fluctuations in energy prices are caused by a number of factors, including:
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• | regional, domestic and international supply and demand; |
• | availability and adequacy of transportation facilities; |
• | energy legislation and regulation; |
• | federal and state taxes, if any, on the sale or transportation and storage of natural gas and NGL; |
• | abundance of supplies of alternative energy sources; and |
• | political unrest among countries producing oil and LNG. |
The agencies that regulate us and our customers could affect our profitability.
Our business is regulated by the FERC, the U.S. Department of Transportation, the U.S. Department of the Interior and various state and local regulatory agencies whose actions have the potential to adversely affect our profitability. In particular, the FERC regulates the rates we are permitted to charge our customers for our services and sets authorized rates of return.
In April 2008, the FERC adopted a new policy that will allow master limited partnerships to be included in rate of return proxy groups for determining rates for services provided by interstate natural gas and oil pipelines. The FERC uses a discounted cash flow model that incorporates the use of proxy groups to develop a range of reasonable returns earned on equity interests in companies with corresponding risks. The FERC then assigns a rate of return on equity within that range to reflect specific risks of that pipeline when compared to the proxy group companies. The FERC’s policy statement concludes among other items that (i) there should be no cap on the level of distributions included in the current discounted cash flow methodology and (ii) there should be a downward adjustment to the long-term growth rate used for the equity cost of capital of natural gas pipeline master limited partnerships. Pursuant to the FERC’s jurisdiction over rates, existing rates may be challenged by complaint, and proposed rate increases may be challenged by protest. A successful complaint or protest against our rates could have an adverse impact on our revenues.
In a January 15, 2009 decision that discussed an individual pipeline’s rate of return, the FERC analyzed the operations of each company proposed for inclusion in that pipeline’s proxy group to determine whether each company to be included had commensurate risks to the pipeline whose rates were being determined. The FERC included in that proxy group two primarily gas pipeline master limited partnerships (with the adjusted gross domestic product) and a diversified company that had higher risk exploration, production and trading operations in addition to pipeline operations. Companies whose distribution, electric or natural gas liquids operations exceeded pipeline operations were excluded. In light of this, it is expected that pipeline returns on equity will be driven largely by fact-based proxy group determinations in each case.
Also, increased regulatory requirements relating to the integrity of our pipeline requires additional spending in order to maintain compliance with these requirements. Any additional requirements that are enacted could significantly increase the amount of these expenditures. Further, state agencies that regulate our local distribution company customers could impose requirements that could impact demand for our services.
Environmental compliance and remediation costs and the costs of environmental liabilities could exceed our estimates.
Our operations are subject to various environmental laws and regulations regarding compliance and remediation obligations. Compliance obligations can result in significant costs to install and maintain pollution controls, fines and penalties resulting from any failure to comply and potential limitations on our operations. Remediation obligations can result in significant costs associated with the investigation or clean up of contaminated properties (some of which have been designated as Superfund sites by the U.S. Environmental Protection Agency (EPA) under the Comprehensive Environmental Response, Compensation and Liability Act), as well as damage claims arising out of the contamination of properties or impact on natural resources. Although we believe we have established appropriate reserves for our environmental liabilities, it is not possible for us to estimate the exact amount and timing of all future expenditures related to environmental matters and we could be required to set aside additional amounts which could significantly impact our future consolidated results of operations, financial position, or cash flows. See Part II, Item 8, Financial Statements and Supplementary Data, Note 8.
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In estimating our environmental liabilities, we face uncertainties that include:
• | estimating pollution control and clean up costs, including sites where preliminary site investigation or assessments have been completed; |
• | discovering new sites or additional information at existing sites; |
• | receiving regulatory approval for remediation programs; |
• | quantifying liability under environmental laws that impose joint and several liability on all potentially responsible parties; |
• | evaluating and understanding environmental laws and regulations, including their interpretation and enforcement; and |
• | changing environmental laws and regulations that may increase our costs. |
In addition to potentially increasing the cost of our environmental liabilities, changing environmental laws and regulations may increase our future compliance costs, such as the costs of complying with ozone standards and potential mandatory greenhouse gas reporting and emission reductions. Future environmental compliance costs relating to greenhouse gases (GHGs) associated with our operations are not yet clear. Legislative and regulatory measures to address GHG emissions are in various phases of discussions or implementation at the international, national, regional and state levels. Various federal and state legislative proposals have been made over the last several years and it is possible that legislation may be enacted in the future that could negatively impact our operations and financial results. The level of such impact will likely depend upon whether any of our facilities will be directly responsible for compliance with GHG regulations and legislation; whether federal legislation will preempt any potentially conflicting state/regional GHG programs; whether cost containment measures will be available; the ability to recover compliance costs from our customers; and the manner in which allowances are provided. At the federal regulatory level, the EPA has requested public comments on the potential regulation of GHGs under the Clean Air Act. Some of the regulatory alternatives identified by the EPA in its request for comments, if eventually promulgated as final rules, would likely impact our operations and financial results. It is uncertain whether the EPA will proceed with adopting final rules or whether the regulation of GHGs will be addressed in federal and state legislation. Legislation and regulation are also in various stages of discussion or implementation in many of the states and regions in which we operate. Therefore, it is not yet possible to determine whether the regulations implementing the legislation will be material to our operations or our financial results.
Finally, several lawsuits have been filed seeking to force the federal government to regulate GHG emissions and individual companies to reduce the GHG emissions from their operations. These and other lawsuits may also result in decisions by federal and state courts and agencies that impact our operations and ability to obtain certifications and permits to construct future projects.
Although it is uncertain what impact these legislative, regulatory, and judicial actions might have on us until further definition is provided in those forums, there is a risk that such future measures could result in changes to our operations and to the consumption and demand for natural gas. Changes to our operations could include increased costs to (i) operate and maintain our facilities, (ii) install new emission controls on our facilities, (iii) construct new facilities, (iv) acquire allowances to authorize our GHG emissions, (v) pay any taxes related to our GHG emissions and (vi) administer and manage a GHG emissions program. While we may be able to include some or all of the costs associated with our environmental liabilities and environmental and GHG 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.
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Our operations are subject to operational hazards and uninsured risks.
Our operations are subject to the inherent risks normally associated with pipeline operations, including pipeline ruptures, explosions, pollution, release of toxic substances, fires, adverse weather conditions (such as hurricanes and flooding), terrorist activity or acts of aggression, and other hazards. Each of these risks could result in damage to or destruction of our facilities or damages or injuries to persons and property causing us to suffer substantial losses. Analyses performed by various governmental and private organizations indicate potential physical risks associated with climate change events (such as flooding, etc). Some of the studies indicate that potential impacts on energy infrastructure are highly uncertain and not well understood, including both the timing and potential magnitude of such impacts. As the science is better understood and analyzed, we will review the operational and uninsured risks to our facilities attributed to climate change.
While we maintain insurance against many of these risks to the extent and in amounts that we believe are reasonable, our insurance coverages have material deductibles as well as limits on our maximum recovery, and do not cover all risks. In addition, there is a risk that our insurers may default on their coverage obligations. As a result, our results of operations, cash flows or financial condition could be adversely affected if a significant event occurs that is not fully covered by insurance.
The expansion of our business by constructing new facilities subjects us to construction and other risks that may adversely affect our financial results.
We may expand the capacity of our existing pipeline or 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 by the FERC and other regulatory agencies on a timely basis and on terms that are acceptable to us; |
• | 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, including environmental requirements that prevent a project from proceeding or increase the anticipated cost of the project; |
• | impediments on our ability to acquire rights-of-way or land rights on a timely basis or 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 inflation or increased costs of equipment, materials, labor, contractor productivity or other factors beyond our control, that we may not be able to recover from our customers which may be material; |
• | the lack of future growth in natural gas supply and/or demand; 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 the downturn in the economy and its negative impact upon natural gas demand may result in either slower development in our 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, which could adversely affect our results of operations, cash flows or financial position.
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. If we are unable to retain and recruit employees such as engineers and other technical personnel, our business could be negatively impacted.
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Adverse general domestic economic conditions could negatively affect our operating results, financial condition or liquidity.
We, El Paso, and its subsidiaries are subject to the risks arising from adverse changes in general domestic economic conditions including recession or economic slowdown. Recently, the U.S. economy has experienced recession and the financial markets have experienced extreme volatility and instability. In response to the volatility in the financial markets, El Paso has also announced certain actions that are designed to reduce its need to access such financial markets, including reductions in the capital programs of certain of its operating subsidiaries and the sale of several non-core assets.
If we or El Paso experience prolonged periods of recession or slowed economic growth in the United States, demand growth from consumers for natural gas transported by us may continue to decrease, which could impact the development of our future expansion projects. Additionally, our or El Paso’s access to capital could continue to be impeded and the cost of capital we obtain could be higher. Finally, we are subject to the risks arising from changes in legislation and regulation associated with such recession or prolonged economic slowdown, including creating preference for renewables, as part of a legislative package to stimulate the economy. Any of these events, which are beyond our control, could negatively impact our business, results of operations, financial condition, and liquidity.
We are subject to financing and interest rate risk.
Our future success, financial condition and liquidity could be adversely affected based on our ability to access capital markets and obtain financing at cost effective rates. This is dependent on a number of factors in addition to general economic conditions discussed above, many of which we cannot control, including changes in:
• | our credit ratings; |
• | the structured and commercial financial markets; |
• | market perceptions of us or the natural gas and energy industry; |
• | tax rates due to new tax laws; and |
• | market prices for hydrocarbon products. |
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.
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 by Moody’s Investor Service, BB- by Standard & Poor’s and BB+ 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. El Paso and its subsidiaries, including us, are (i) on a stable outlook with Moody’s Investor Service and Fitch Ratings and (ii) on a negative outlook with Standard & Poor’s. There is a risk that these credit ratings may be adversely affected in the future as the credit rating agencies continue to 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 and collateral requirements.
9
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. For a further discussion of these matters, see Part II, Item 8, Financial Statements and Supplementary Data, Note 12.
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.
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.
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, 2008. 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 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.
ITEM 1B. UNRESOLVED STAFF COMMENTS
We have not included a response to this item since no response is required under Item 1B of Form 10-K.
ITEM 2. PROPERTIES
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.
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ITEM 3. LEGAL PROCEEDINGS
A description of our legal proceedings is included in Part II, Item 8, Financial Statements and Supplementary Data, Note 8, and is incorporated herein by reference.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Information has been omitted from this report pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.
PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
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. No common stock dividends were declared or paid in 2008 or 2007.
ITEM 6. SELECTED FINANCIAL DATA
Information has been omitted from this report pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.
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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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. Each of these businesses faces 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 Total Revenues in 2008 | ||
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. | 61 | ||
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. | 39 |
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, 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 our recontracting process to limit the risk of significant impacts on our revenues from expiring contracts. 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.
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Our existing contracts mature 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, 2008. Below are the contract expiration portfolio and the associated revenue expirations for our firm transportation contracts as of December 31, 2008, including those with terms beginning in 2009 or later.
BBtu/d | Percent of Total Contracted Capacity | Reservation Revenue | Percent of Total Reservation Revenue | |||||||||||||
(In millions) | ||||||||||||||||
2009 | 920 | 11 | $ | 6 | 1 | |||||||||||
2010 | 1,015 | 12 | 53 | 10 | ||||||||||||
2011 | 644 | 8 | 65 | 13 | ||||||||||||
2012 | 2,187 | 27 | 70 | 14 | ||||||||||||
2013 | 1,374 | 17 | 111 | 21 | ||||||||||||
2014 and beyond | 2,001 | 25 | 214 | 41 | ||||||||||||
Total | 8,141 | 100 | $ | 519 | 100 |
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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 because it allows them to evaluate more effectively our operating performance using the same performance measure analyzed internally by our management. We define EBIT as net income adjusted for (i) items that do not impact our income from continuing operations, (ii) income taxes, (iii) interest and debt expense and (iv) affiliated interest income. We exclude interest and debt expense from this measure so that investors may evaluate our operating results without regard to our financing methods. EBIT may not be comparable to measurements used by other companies. Additionally, EBIT should be considered in conjunction with net income 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, 2008 compared with 2007.
Operating Results:
2008 | 2007 | |||||||
(In millions, | ||||||||
except for volumes) | ||||||||
Operating revenues | $ | 907 | $ | 862 | ||||
Operating expenses | (645 | ) | (564 | ) | ||||
Operating income | 262 | 298 | ||||||
Earnings from unconsolidated affiliate | 13 | 13 | ||||||
Other income, net | 10 | 19 | ||||||
EBIT | 285 | 330 | ||||||
Interest and debt expense | (136 | ) | (130 | ) | ||||
Affiliated interest income, net | 33 | 44 | ||||||
Income taxes | (71 | ) | (91 | ) | ||||
Net income | $ | 111 | $ | 153 | ||||
Throughput volumes (BBtu/d) | 4,864 | 4,880 |
EBIT Analysis:
Revenue | Expense | Other | EBIT Impact | |||||||||||||
Favorable/(Unfavorable) | ||||||||||||||||
(In millions) | ||||||||||||||||
Services revenues | $ | 15 | $ | — | $ | — | $ | 15 | ||||||||
Expansions | 29 | (12 | ) | (4 | ) | 13 | ||||||||||
Gas not used in operations and other natural gas sales | 26 | — | — | 26 | ||||||||||||
Contract settlement | (10 | ) | — | — | (10 | ) | ||||||||||
Hurricanes | (10 | ) | (12 | ) | — | (22 | ) | |||||||||
Other operating and general and administrative costs | — | (31 | ) | — | (31 | ) | ||||||||||
Gain/loss on long-lived assets | — | (24 | ) | 2 | (22 | ) | ||||||||||
Allowance for funds used during construction | — | — | (8 | ) | (8 | ) | ||||||||||
Other(1) | (5 | ) | (2 | ) | 1 | (6 | ) | |||||||||
Total impact on EBIT | $ | 45 | $ | (81 | ) | $ | (9 | ) | $ | (45 | ) |
____________
(1) | Consists of individually insignificant items. |
Services Revenues. In 2008, we sold additional capacity in the northern and southern regions of our system as compared to the same period in 2007. This increase in revenue was partially offset by lower surcharges from certain firm customers in 2008.
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Expansions
Projects Placed in Service in 2008 and 2007. In July and September 2007, the Louisiana Deepwater Link and the Triple—T Extension projects were placed into service. These expansions increased gas supply attached to our system in excess of 900 MMcf/d. Revenues for these projects are based on throughput levels as natural gas reserves are developed. Also, in November 2007, the Northeast ConneXion—New England expansion project was placed into service. This project provides an additional 108 MMcf/d of capacity to meet growing demand for natural gas in the New England market area. In November 2008, we placed the Bluewater reconfiguration project into service. This increase in revenues was partially offset by depreciation and operating and maintenance expenses of the new facilities.
Committed Projects Not Yet Completed. We currently have the following projects in various stages of development:
Project | Anticipated In-Service Dates | Estimated Cost | FERC Approved | ||||
(In millions) | |||||||
Carthage Expansion | May 2009 | $ | 39 | Yes | |||
Concord Lateral Expansion | November 2009 | 21 | Yes | ||||
300 Line Expansion | November 2011 | 750 | No | ||||
Total Committed Expansion Backlog | $ | 810 |
300 Line Expansion. The 300 Line Expansion involves the installation of seven looping segments in Pennsylvania and New Jersey totaling approximately 128 miles of 30-inch pipeline, and the addition of approximately 52,000 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 293 MMcf/d. The 300 Line Expansion project will provide access to diversified natural gas supplies from Gulf Coast, Appalachian, Rockies, and Marcellus Shale supply areas, 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.
Gas Not Used in Operations and Other Natural Gas Sales. The financial impact of operational gas, net of gas used in operations, is based on the amount of natural gas we are allowed to retain and dispose of according to our tariff, relative to the amounts of natural gas we use for operating purposes and the price of natural gas. The financial impact of gas not needed for operations is influenced by factors such as system throughput, facility enhancements and the ability to operate the system efficiently. Gas not needed for operations results in revenues to us, which we recognize when the volumes are retained. During the year ended December 31, 2008 our EBIT was favorably impacted by higher volumes of gas not used in our operations compared to 2007.
Contract Settlement. In 2007, we received $10 million to settle our bankruptcy claim against USGen New England, Inc.
Hurricanes. During 2008, we incurred damage to sections of our Gulf Coast and offshore pipeline facilities due to Hurricanes Gustav and Ike. Our EBIT was unfavorably impacted by $29 million related to these hurricanes due to gas loss from various damaged pipelines, lower volume of gas not used in operations, lower usage revenue, and repair costs that will not be recovered from insurance due to losses not exceeding self-retention levels. See Liquidity and Capital Resources for a further discussion of the hurricanes.
Other Operating and General and Administrative Costs. During the year ended December 31, 2008, our operating and general and administrative expenses were higher than in 2007 primarily due to increased labor costs to support growth and customer activities, additional maintenance work required on our pipeline system and higher electric compression costs at certain compressor stations.
Gain/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. During 2007, we recorded a $7 million pretax gain on the sale of a pipeline lateral, and an impairment of $8 million related to a pipeline asset which was purchased to repair hurricane damage and not subsequently utilized.
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Allowance for Funds Used During Construction (AFUDC). AFUDC was lower during 2008 primarily due to a decrease in capital expenditures associated with hurricanes and expansion projects as compared to 2007.
Interest and Debt Expense
Interest and debt expense for the year ended December 31, 2008, was $6 million higher than in 2007 primarily due to lower allowance for funds used during construction in 2008 resulting from a decrease in capital expenditures associated with hurricanes and expansion projects as compared to 2007.
Affiliated Interest Income, Net
Affiliated interest income, net for the year ended December 31, 2008, was $11 million lower than in 2007 primarily due to lower average short-term interest rates partially offset by higher average advances to El Paso under its cash management program. The average short-term interest rate decreased from 6.2% in 2007 to 4.4% in 2008, and the average advances due from El Paso of $729 million in 2007 increased to $768 million in 2008.
Income Taxes
Our effective tax rate of 39 percent and 37 percent for the years ended December 31, 2008 and 2007 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
Liquidity Overview. Our primary sources of liquidity are cash flows from operating activities and El Paso’s cash management program. Our primary uses of cash are for working capital and capital expenditures. We have historically advanced cash to El Paso under its cash management program, which we reflect in investing activities in our statement of cash flows. At December 31, 2008, we had notes receivable from El Paso of approximately $800 million. We do not intend to settle these notes within twelve months and have therefore classified them as non-current on our balance sheet. See Item 8, Financial Statements, Note 12, for a further discussion of El Paso’s cash management program and our other affiliate notes receivable. We believe that cash flows from operating activities combined with amounts available to us under El Paso’s cash management program will be adequate to meet our capital requirements and our existing operating needs.
In addition to the cash management program, 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, 2008, El Paso had approximately $0.7 billion of capacity remaining and available to us under this credit facility agreement, none of which was issued or borrowed by us. For a further discussion of this credit agreement, see Item 8, Financial Statements and Supplementary Data, Note 7.
Extreme volatility in the financial markets, the energy industry and the global economy will likely continue through 2009. The global financial markets remain extremely volatile and it is uncertain whether recent U.S. and foreign government actions will successfully restore confidence and liquidity in the global financial markets. This could impact our longer-term access to capital for future growth projects as well as the cost of such capital. In January 2009, we issued $250 million of 8.00% senior notes due February 2016 for net proceeds of $235 million. Based on the liquidity available to us through cash on hand, our operating activities and El Paso’s cash management program, we do not anticipate having a need to fruther access the financial markets for the remainder of 2009 for any of our operating activities or expansion capital needs. Additionally, although the impacts are difficult to quantify at this point, a downward trend in 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 largely mitigated by a revenue base that is significantly comprised of long term contracts that are based on firm demand charges and are less affected by a potential reduction in the actual usage or consumption of natural gas.
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As of December 31, 2008, El Paso had approximately $1.0 billion of cash and approximately $1.2 billion of capacity available to it under various committed credit facilities. In light of the current economic climate and in response to the financial market volatility, El Paso, since November 2008, has generated approximately $1.2 billion of additional liquidity through three separate note offerings and has obtained additional revolving credit facility capacity and letter of credit capacity. Although we do not anticipate to further access the financial markets for the remainder of 2009, the volatility in the financial markets could impact our or El Paso’s ability to access these markets at reasonable rates in the future.
For further detail on our risk factors including adverse general economic conditions and our ability to access financial markets which could impact our operations and liquidity, see Part 1, Item 1A, Risk Factors.
Debt. In July 2008, we obtained the required consent necessary for certain amendments to the indenture governing our 6.0% debentures due 2011. These amendments permit us to convert from a corporation to a non-corporate legal entity such as a general partnership, limited partnership or limited liability company. In January 2009, we issued $250 million of 8.00% senior notes due in February 2016. The net proceeds of $235 million will be invested in short-term investments and used for capital expenditures and general corporate purposes.
Capital Expenditures. Our capital expenditures for the years ended December 31 were as follows:
2008 | 2007 | |||||||
(In millions) | ||||||||
Maintenance | $ | 198 | $ | 139 | ||||
Expansions | 83 | 181 | ||||||
Hurricanes(1) | — | 41 | ||||||
Other(2) | 42 | 3 | ||||||
Total | $ | 323 | $ | 364 |
____________
(1) | Amounts shown are net of insurance proceeds of $34 million and $47 million for 2008 and 2007, respectively. |
(2) | Relates to building renovations at our corporate facilities. |
Under our current plan for 2009, we have budgeted to spend (i) approximately $220 million for capital expenditures, net of insurance proceeds, primarily to maintain and improve the integrity of our pipeline, to comply with regulations and to ensure the safe and reliable delivery of natural gas to our customers and (ii) approximately $170 million to expand the capacity and services of our pipeline system.
Hurricanes Ike and Gustav. During the third quarter of 2008, our pipeline and certain of our facilities were damaged by Hurricanes Gustav and Ike. As of December 31, 2008, we had spent $30 million on these hurricanes. We continue to assess the damages resulting from these hurricanes and the corresponding impact on estimated costs to repair and/or abandon facilities. Although our estimates may change in the future, we currently estimate the total repair and abandonment costs to be approximately $112 million, a majority of which we expect will be capital and none of which are recoverable from insurance due to losses not exceeding self-retention levels.
Commitments and Contingencies
For a discussion of our commitments and contingencies, see Item 8, Financial Statements and Supplementary Data, Note 8, which is incorporated herein by reference.
New Accounting Pronouncements Issued But Not Yet Adopted
See Item 8, Financial Statements and Supplementary Data, Note 1, under New Accounting Pronouncements Issued But Not Yet Adopted, which is incorporated herein by reference.
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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We are exposed to the risk of changing interest rates. At December 31, 2008, we had interest bearing notes receivable from El Paso of approximately $800 million, with variable interest rates of 3.2% that are due upon demand. While we are exposed to changes in interest income based on changes to the variable interest rate, the fair value of these notes receivable approximates their carrying value due to the market-based nature of its interest rate and the fact that it is a demand note.
The table below shows the carrying value and related weighted-average effective interest rates on our non-affiliated fixed rate long-term debt securities estimated based on quoted market prices for the same or similar issues.
December 31, 2008 | ||||||||||||||||||||||||
Expected Fiscal Year of Maturity of Carrying Amounts | December 31, 2007 | |||||||||||||||||||||||
2011 | 2013 and Thereafter | Total | Fair Value | Carrying Amount | Fair Value | |||||||||||||||||||
(In millions, except for rates) | ||||||||||||||||||||||||
Liabilities: | ||||||||||||||||||||||||
Long-term debt— fixed rate | $ | 82 | $ | 1,523 | $ | 1,605 | $ | 1,311 | $ | 1,603 | $ | 1,745 | ||||||||||||
Average effective interest rate | 7.3 | % | 7.6 | % |
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.
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
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 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, 2008. 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 (COSO). Based on our evaluation, we concluded that our internal control over financial reporting was effective as of December 31, 2008.
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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, 2008 and 2007, 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, 2008. 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, 2008. 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, 2008 and 2007, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2008, 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.
As discussed in Notes 1 and 3 to the consolidated financial statements, effective January 1, 2007, the Company adopted the provisions of Financial Accounting Standards Board Interpretation No. 48, Accounting for Uncertainty in Income Taxes an interpretation of FASB Statement No. 109, and effective December 31, 2006 and January 1, 2008, the Company adopted the recognition and measurement date provisions, respectively, of Statement of Financial Accounting Standards No. 158, Employer’s Accounting for Defined Benefit Pension and Other Postretirement Plans — An Amendment of FASB Statements No. 87, 88, 106, and 132 (R).
/s/ Ernst & Young LLP
Houston, Texas
February 26, 2009
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TENNESSEE GAS PIPELINE COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(In millions)
Year Ended December 31, | ||||||||||||
2008 | 2007 | 2006 | ||||||||||
Operating revenues | $ | 907 | $ | 862 | $ | 793 | ||||||
Operating expenses | ||||||||||||
Operation and maintenance | 386 | 338 | 315 | |||||||||
Loss on long-lived assets | 25 | — | — | |||||||||
Depreciation and amortization | 182 | 170 | 164 | |||||||||
Taxes, other than income taxes | 52 | 56 | 55 | |||||||||
645 | 564 | 534 | ||||||||||
Operating income | 262 | 298 | 259 | |||||||||
Earnings from unconsolidated affiliate | 13 | 13 | 15 | |||||||||
Other income, net | 10 | 19 | 14 | |||||||||
Interest and debt expense | (136 | ) | (130 | ) | (129 | ) | ||||||
Affiliated interest income, net | 33 | 44 | 43 | |||||||||
Income before income taxes | 182 | 244 | 202 | |||||||||
Income taxes | 71 | 91 | 75 | |||||||||
Net income | $ | 111 | $ | 153 | $ | 127 |
See accompanying notes.
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TENNESSEE GAS PIPELINE COMPANY
CONSOLIDATED BALANCE SHEETS
(In millions, except share amounts)
December 31, | ||||||||
2008 | 2007 | |||||||
ASSETS | ||||||||
Current assets | ||||||||
Cash and cash equivalents | $ | — | $ | — | ||||
Accounts receivable | ||||||||
Customer | 24 | 14 | ||||||
Affiliates | 81 | 71 | ||||||
Other | 13 | 27 | ||||||
Materials and supplies | 41 | 34 | ||||||
Deferred income taxes | 8 | 10 | ||||||
Other | 10 | 9 | ||||||
Total current assets | 177 | 165 | ||||||
Property, plant and equipment, at cost | 4,365 | 4,048 | ||||||
Less accumulated depreciation and amortization | 884 | 740 | ||||||
3,481 | 3,308 | |||||||
Additional acquisition cost assigned to utility plant, net | 2,002 | 2,040 | ||||||
Total property, plant and equipment, net | 5,483 | 5,348 | ||||||
Other assets | ||||||||
Notes receivable from affiliate | 800 | 1,034 | ||||||
Investment in unconsolidated affiliate | 81 | 84 | ||||||
Other | 53 | 52 | ||||||
934 | 1,170 | |||||||
Total assets | $ | 6,594 | $ | 6,683 | ||||
LIABILITIES AND STOCKHOLDER’S EQUITY | ||||||||
Current liabilities | ||||||||
Accounts payable | ||||||||
Trade | $ | 54 | $ | 66 | ||||
Affiliates | 36 | 23 | ||||||
Other | 52 | 56 | ||||||
Taxes payable | 82 | 31 | ||||||
Accrued interest | 24 | 24 | ||||||
Contractual deposits | 60 | 32 | ||||||
Other | 31 | 17 | ||||||
Total current liabilities | 339 | 249 | ||||||
Long-term debt | 1,605 | 1,603 | ||||||
Other liabilities | ||||||||
Deferred income taxes | 1,314 | 1,302 | ||||||
Regulatory liabilities | 191 | 178 | ||||||
Other | 74 | 57 | ||||||
1,579 | 1,537 | |||||||
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 | 1,196 | 1,085 | ||||||
Note receivable from affiliate | (334 | — | ||||||
Total stockholder’s equity | 3,071 | 3,294 | ||||||
Total liabilities and stockholder’s equity | $ | 6,594 | $ | 6,683 |
See accompanying notes.
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TENNESSEE GAS PIPELINE COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
Year Ended December 31, | ||||||||||||
2008 | 2007 | 2006 | ||||||||||
Cash flows from operating activities | ||||||||||||
Net income | $ | 111 | $ | 153 | $ | 127 | ||||||
Adjustments to reconcile net income to net cash from operating activities | ||||||||||||
Depreciation and amortization | 182 | 170 | 164 | |||||||||
Deferred income taxes | 14 | 88 | 26 | |||||||||
Earnings from unconsolidated affiliate, adjusted for cash distributions | 3 | 14 | 2 | |||||||||
Loss on long-lived assets | 25 | — | — | |||||||||
Other non-cash income items | (4 | ) | (10 | ) | (6 | ) | ||||||
Asset and liability changes | ||||||||||||
Accounts receivable | 19 | 15 | 32 | |||||||||
Accounts payable | 10 | (15 | ) | 27 | ||||||||
Taxes payable | 45 | (40 | ) | 37 | ||||||||
Other current assets | (5 | ) | (6 | (3 | ) | |||||||
Other current liabilities | (16 | ) | (4 | ) | (21 | ) | ||||||
Non-current assets | — | (13 | ) | (8 | ) | |||||||
Non-current liabilities | 21 | (66 | ) | 12 | ||||||||
Net cash provided by operating activities | 405 | 286 | 389 | |||||||||
Cash flows from investing activities | ||||||||||||
Additions to property, plant and equipment | (323 | ) | (364 | ) | (421 | ) | ||||||
Net change in notes receivable from affiliates | (100 | ) | 39 | 25 | ||||||||
Proceeds from the sale of asset | — | 35 | — | |||||||||
Other | 18 | 4 | 7 | |||||||||
Net cash used in investing activities | (405 | ) | (286 | ) | (389 | ) | ||||||
Net change in cash and cash equivalents | — | — | — | |||||||||
Cash and cash equivalents | ||||||||||||
Beginning of period | — | — | — | |||||||||
End of period | $ | — | $ | — | $ | — |
See accompanying notes.
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TENNESSEE GAS PIPELINE COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDER’S EQUITY
(In millions)
Common Stock | Additional Paid-in | Retained | Note Receivable from | Accumulated Other Comprehensive | Total Stockholder’s | ||||||||||||||||||
Shares | Amount | Capital | Earnings | Affiliate | Income/(Loss) | Equity | |||||||||||||||||
January 1, 2006 | 208 | $ | — | $ | 2,207 | $ | 820 | $ | — | $ | — | $ | 3,027 | ||||||||||
Net income | 127 | 127 | |||||||||||||||||||||
Adoption of SFAS No. 158, net of income taxes of $2 | 3 | 3 | |||||||||||||||||||||
December 31, 2006 | 208 | — | 2,207 | 947 | — | 3 | 3,157 | ||||||||||||||||
Net income | 153 | 153 | |||||||||||||||||||||
Adoption of FIN No. 48, net of income taxes of $(8) (Note 3) | (15 | ) | (15 | ) | |||||||||||||||||||
Reclassification to regulatory liability (Note 9) | (3 | ) | (3 | ) | |||||||||||||||||||
Other | 2 | 2 | |||||||||||||||||||||
December 31, 2007 | 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 |
See accompanying notes.
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.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 majority owned and controlled subsidiaries after the elimination of intercompany accounts and transactions.
We consolidate entities when we either (i) have the ability to control the operating and financial decisions and policies of that entity or (ii) are allocated a majority of the entity’s losses and/or returns through our variable interests in that entity. The determination of our ability to control or exert significant influence over an entity and whether we are allocated a majority of the entity’s losses and/or returns involves the use of judgment. We apply the equity method of accounting where we can exert significant influence over, but do not control, the policies and decisions of an entity and where we are not allocated a majority of the entity’s losses and/or returns. 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) under the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and the Energy Policy Act of 2005. We follow the regulatory accounting principles prescribed under Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation. Under SFAS No. 71, we record regulatory assets and liabilities that would not be recorded under GAAP for non-regulated entities. Regulatory assets and liabilities represent probable future revenues or expenses associated with certain charges or credits that will 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, 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 collectibility 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.
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Natural Gas Imbalances
Natural gas imbalances occur when the actual amount of natural gas delivered from or received by a pipeline system or storage facility differs from the contractual amount delivered or received. We value these imbalances due to or from shippers and operators utilizing current index prices. Imbalances are settled in cash 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 trade 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 the fair value of the assets acquired. 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 lives and characteristics are grouped and depreciated as one asset. We apply the FERC-accepted depreciation rate to the total cost of the group until its net book value equals its salvage value. Currently, our depreciation rates vary from one percent to 25 percent per year. Using these rates, the remaining depreciable lives of these assets range from one to 34 years. We re-evaluate depreciation rates each time we file with the FERC for a change in our transportation and storage rates.
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. We include gains or losses on dispositions of operating units in operating income. 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 assigned to utility plant, which represent the excess of allocated purchase costs over the historical costs of the facilities. These costs are amortized on a straight-line basis over 62 years using the same rates as the related assets, and we do not recover these excess costs in our rates.
At December 31, 2008 and 2007, we had $207 million and $197 million of construction work in progress included in our property, plant and equipment.
We capitalize a carrying cost (an allowance for funds used during construction) on debt and equity funds related to our 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 our average cost of debt. Interest costs on debt amounts capitalized during the years ended December 31, 2008, 2007 and 2006, were $3 million, $6 million and $5 million. These debt amounts are included as a reduction to interest and debt expense on our income statement. The equity portion of capitalized costs is calculated using the most recent FERC-approved equity rate of return. The equity amounts capitalized (exclusive of any tax related impacts) during the years ended December 31, 2008, 2007 and 2006, were $6 million, $12 million and $8 million. These equity amounts are included as other non-operating income on our income statement.
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Asset and Investment 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. When an event occurs, we evaluate the recoverability of our long-lived assets’ carrying values 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. The magnitude of any impairment is impacted by a number of factors, including the nature of the assets being sold and our established time frame for completing the sale, among other factors.
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 over the contract period regardless of the amount of natural gas that is transported or stored. 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. Gas not used in operations is based on the volumes of natural gas we are allowed to retain relative to the amounts 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, when fully analyzed, 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.
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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.
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.
We evaluate our tax positions for all jurisdictions and for all years where the statute of limitations has not expired in accordance with Financial Accounting Standards Board (FASB) Interpretation (FIN) No. 48, Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109. FIN No. 48 requires companies to meet a more-likely-than-not threshold (i.e. a greater than 50 percent likelihood of a tax position being sustained under examination) prior to recording a benefit for their tax positions. Additionally, for tax positions meeting this more-likely-than-not threshold, the amount of benefit is limited to the largest benefit that has a greater than 50 percent probability of being realized upon effective settlement. For a further discussion of FIN No. 48, see Note 3.
Accounting for Asset Retirement Obligations
We account for our asset retirement obligations in accordance with SFAS No. 143, Accounting for Asset Retirement Obligations and FIN No. 47, Accounting for Conditional 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 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 long-lived asset to which that liability relates. An ongoing expense is also 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 depreciation of the property, plant and equipment and 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 out under the plan. These contributions are invested until the benefits are paid out to plan participants. We record net benefit cost related to this plan in our income statement. This net benefit cost is a function of many factors including benefits earned during the year by plan participants (which is a function of 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 plan, see Note 9.
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Effective December 31, 2006, we began accounting for our postretirement benefit plan under the recognition provisions of SFAS No.158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an Amendment of FASB Statements No. 87, 88, 106, and 132(R) and recorded a $3 million increase, net of income taxes of $2 million, to accumulated other comprehensive income related to the adoption of this standard. Under SFAS No. 158, we record an asset or liability for our postretirement benefit plan based on its over funded or under funded status. In March 2007, the FERC issued guidance requiring regulated pipeline companies to record a regulatory asset or liability for any deferred amounts related to unrecognized gains and losses or changes in actuarial assumptions that would otherwise be recorded in accumulated other comprehensive income for non-regulated entities. Upon adoption of this FERC guidance, we reclassified $3 million from accumulated other comprehensive income to a regulatory liability.
Effective January 1, 2008, we adopted the measurement date provisions of SFAS No. 158 and changed the measurement date of our postretirement benefit plan from September 30 to December 31. The adoption of the measurement date provisions of this standard did not have a material impact on our financial statements. For a further discussion of our application of SFAS No. 158, see Note 9.
New Accounting Pronouncements Issued But Not Yet Adopted
As of December 31, 2008, the following accounting standards had not yet been adopted by us.
Fair Value Measurements. We have adopted the provisions of SFAS No. 157, Fair Value Measurements in measuring the fair value of financial assets and liabilities in the financial statements. We have elected to defer the adoption of SFAS No. 157 for certain of our non-financial assets and liabilities until January 1, 2009, the adoption of which will not have a material impact on our financial statements.
Business Combinations. In December 2007, the FASB issued SFAS No. 141(R), Business Combinations, which provides revised guidance on the accounting for acquisitions of businesses. This standard changes the current guidance to require that all acquired assets, liabilities, minority interest and certain contingencies be measured at fair value, and certain other acquisition-related costs be expensed rather than capitalized. SFAS No. 141(R) will apply to acquisitions that are effective after December 31, 2008, and application of the standard to acquisitions prior to that date is not permitted.
Noncontrolling Interests. In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements, which provides guidance on the presentation of minority interest, subsequently renamed “noncontrolling interest”, in the financial statements. This standard requires that noncontrolling interest be presented as a separate component of equity rather than as a “mezzanine” item between liabilities and equity, and also requires that noncontrolling interest be presented as a separate caption in the income statement. This standard also requires all transactions with noncontrolling interest holders, including the issuance and repurchase of noncontrolling interests, be accounted for as equity transactions unless a change in control of the subsidiary occurs. We will adopt the provisions of this standard effective January 1, 2009. The adoption of this standard will not have a material impact our financial statements.
2. Gain (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. During 2007, we completed the sale of a pipeline lateral for approximately $35 million and recorded a $7 million pretax gain on the sale. During 2007, we also recorded a loss of $8 million related to a pipeline asset which was purchased to repair hurricane damage and not subsequently utilized.
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3. Income Taxes
Components of Income Taxes. The following table reflects the components of income taxes included in net income for each of the three years ended December 31:
2008 | 2007 | 2006 | ||||||||||
(In millions) | ||||||||||||
Current | ||||||||||||
Federal | $ | 54 | $ | (1 | ) | $ | 50 | |||||
State | 3 | 4 | (1 | ) | ||||||||
57 | 3 | 49 | ||||||||||
Deferred | ||||||||||||
Federal | 7 | 85 | 18 | |||||||||
State | 7 | 3 | 8 | |||||||||
14 | 88 | 26 | ||||||||||
Total income taxes | $ | 71 | $ | 91 | $ | 75 |
Effective Tax Rate Reconciliation. Our income taxes differ 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:
2008 | 2007 | 2006 | ||||||||||
(In millions, except for rates) | ||||||||||||
Income taxes at the statutory federal rate of 35% | $ | 64 | $ | 85 | $ | 71 | ||||||
State income taxes, net of federal income tax effect | 7 | 5 | 4 | |||||||||
Other | — | 1 | — | |||||||||
Income taxes | $ | 71 | $ | 91 | $ | 75 | ||||||
Effective tax rate | 39 | % | 37 | % | 37 | % |
Deferred Tax Assets and Liabilities. The following are the components of our net deferred tax liability at December 31:
2008 | 2007 | ||||||
(In millions) | |||||||
Deferred tax liabilities | |||||||
Property, plant and equipment | $ | 1,531 | $ | 1,510 | |||
Other | 13 | 11 | |||||
Total deferred tax liability | 1,544 | 1,521 | |||||
Deferred tax assets | |||||||
Net operating loss and credit carryovers | |||||||
U.S. federal | 22 | 23 | |||||
State | 37 | 43 | |||||
Other liabilities | 179 | 163 | |||||
Total deferred tax asset | 238 | 229 | |||||
Net deferred tax liability | $ | 1,306 | $ | 1,292 |
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, 2008:
2009 | 2010-2013 | 2014-2018 | 2019-2028 | Total | ||||||||||||||||
(In millions) | ||||||||||||||||||||
U.S. federal NOL | $ | — | $ | — | $ | — | $ | 64 | $ | 64 | ||||||||||
State NOL | 1 | 25 | 349 | 200 | 575 |
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.
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Unrecognized Tax Benefits (Liabilities) for Uncertain Tax Matters (FIN No. 48). 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 2005. In June 2008, the Internal Revenue Service’s examination of El Paso’s U.S. income tax returns for 2003 and 2004 was settled at the appellate level with approval by the Joint Committee on Taxation. The settlement of the issues raised in this examination did not materially impact our results of operations, financial condition or liquidity. For years in which our returns are still subject to review, our unrecognized tax benefits (liabilities for uncertain tax matters) 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.
Upon the adoption of FIN No. 48, and a related amendment to our tax sharing agreement with El Paso, we recorded a reduction of $15 million to the January 1, 2007 balance of retained earnings. As of December 31, 2008 and 2007, we had unrecognized tax benefits of $17 million, which has not changed since January 1, 2007. As of December 31, 2008 and 2007, approximately $15 million (net of federal tax benefits)of unrecognized tax benefits 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 recognize interest and penalties related to unrecognized tax benefits in income tax expense on our income statement. As of December 31, 2008 and 2007, we had liabilities for interest and penalties related to our unrecognized tax benefits of approximately $7 million and $6 million. During 2008, we accrued $1 million of interest. During 2007, we accrued $1 million of interest and paid $1 million related to a settlement with a taxing authority.
4. Financial Instruments
At December 31, 2008 and 2007, the carrying amounts of cash and cash equivalents and trade receivables and payables are representative of their fair value because of the short-term maturity of these instruments. At December 31, 2008 and 2007, we had interest bearing notes receivable from El Paso and other affiliates of approximately $800 million and $582 million due upon demand, with variable interest rates of 3.2% and 6.5%. While we are exposed to changes in interest income based on changes to the variable interest rate, the fair value of these notes receivable approximates their carrying value due to the market-based nature of its interest rate and the fact that it is a demand note.
In addition, the carrying amounts and estimated fair values of our long-term debt are based on quoted market prices for the same or similar issues and are as follows at December 31:
2008 | 2007 | |||||||||||||||
Carrying Amount | Fair Value | Carrying Amount | Fair Value | |||||||||||||
(In millions) | ||||||||||||||||
Long-term debt | $ | 1,605 | $ | 1,311 | $ | 1,603 | $ | 1,745 |
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5. Regulatory Assets and Liabilities
Below are the details of our regulatory assets and liabilities at December 31:
2008 | 2007 | |||||||
(In millions) | ||||||||
Current regulatory assets | $ | 2 | $ | — | ||||
Non-current regulatory assets | ||||||||
Taxes on capitalized funds used during construction | 29 | 26 | ||||||
Postretirement benefits | 10 | 7 | ||||||
Other | 8 | 4 | ||||||
Total non-current regulatory assets | 47 | 37 | ||||||
Total regulatory assets | $ | 49 | $ | 37 | ||||
Current regulatory liabilities | $ | 3 | $ | 3 | ||||
Non-current regulatory liabilities | ||||||||
Environmental liability | 157 | 143 | ||||||
Postretirement benefits | 22 | 25 | ||||||
SFAS No. 109 plant regulatory liability and other | 12 | 10 | ||||||
Total non-current regulatory liabilities | 191 | 178 | ||||||
Total regulatory liabilities | $ | 194 | $ | 181 |
6. Property, Plant and Equipment
Additional Acquisition Costs. At December 31, 2008 and 2007, additional acquisition costs assigned to utility plant was approximately $2.4 billion and accumulated depreciation was approximately $379 million and $338 million, respectively. These additional acquisition costs are being amortized over the life of the related pipeline assets. Our amortization expense related to additional acquisition costs assigned to utility plant was approximately $41 million, $39 million and $40 million for the years ended December 31, 2008, 2007 and 2006.
Asset Retirement Obligations. We have legal obligations associated with the retirement of our natural gas pipeline, transmission facilities and storage wells, as well as obligations related to El Paso’s corporate headquarters building. Our legal obligations primarily involve purging and sealing the pipelines if they are abandoned. We also have obligations to remove hazardous materials associated with our natural gas transmission facilities and in our corporate headquarters if these facilities are ever demolished, replaced, or renovated. 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 liability, we accrue a liability based on an estimate of the timing and amount of their settlement. In estimating the fair value of the liabilities associated with 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 six to nine percent based on when the liabilities were recorded. We record changes in estimates based on the expected amount and timing of payments to settle our asset retirement obligations. We intend on operating and maintaining our natural gas pipeline and storage system 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 liability for the substantial majority of our natural gas pipeline and storage system assets because these assets have indeterminate lives.
The net asset retirement liability as of December 31 reported on our balance sheet in other current and non-current liabilities, and the changes in the net liability for the years ended December 31, were as follows:
2008 | 2007 | |||||||
(In millions) | ||||||||
Net asset retirement liability at January 1 | $ | 17 | $ | 47 | ||||
Liabilities settled | (3 | ) | (34 | ) | ||||
Liabilities incurred | — | 3 | ||||||
Changes in estimate | 27 | — | ||||||
Accretion expense | 1 | 1 | ||||||
Net asset retirement liability at December 31(1) | $ | 42 | $ | 17 |
____________
(1) | For the years ended December 31, 2008 and 2007, approximately $5 million and $4 million of this amount is reflected in current liabilities. |
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7. Debt and Credit Facilities
Debt. Our long-term debt consisted of the following at December 31:
2008 | 2007 | |||||||
(In millions) | ||||||||
6.0% Debentures due December 2011 | $ | 86 | $ | 86 | ||||
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 | ||||||
1,626 | 1,626 | |||||||
Less: Unamortized discount | 21 | 23 | ||||||
Total long-term debt | $ | 1,605 | $ | 1,603 |
In July 2008, we obtained the required consent necessary for certain amendments to the indenture governing our 6.0% debentures due 2011. These amendments permit us to convert from a corporation to a non-corporate legal entity such as a general partnership, limited partnership or limited liability company. In January 2009, we issued $250 million of 8.00% senior notes due in February 2016 and received net proceeds of $235 million.
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, 2008, El Paso had approximately $0.7 billion of capacity remaining and available to us under this credit agreement, none of which 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, 2008, we were in compliance with our debt-related covenants.
8. Commitments and Contingencies
Legal Proceedings
Gas Measurement Cases. We and a number of our affiliates were named defendants in actions that generally allege mismeasurement of natural gas volumes and/or heating content resulting in the underpayment of royalties. The first set of cases was filed in 1997 by an individual under the False Claims Act and have been consolidated for pretrial purposes (In re: Natural Gas Royalties Qui Tam Litigation, U.S. District Court for the District of Wyoming). These complaints allege an industry-wide conspiracy to underreport the heating value as well as the volumes of the natural gas produced from federal and Native American lands. In October 2006, the U.S. District Judge issued an order dismissing all claims against all defendants. An appeal has been filed.
Similar allegations were filed in a second set of actions initiated in 1999 in Will Price, et al. v. Gas Pipelines and Their Predecessors, et al., in the District Court of Stevens County, Kansas. The plaintiffs currently seek certification of a class of royalty owners in wells on non-federal and non-Native American lands in Kansas, Wyoming and Colorado. Motions for class certification have been briefed and argued in the proceedings and the parties are awaiting the court’s ruling. The plaintiff seeks an unspecified amount of monetary damages in the form of additional royalty payments (along with interest, expenses and punitive damages) and injunctive relief with regard to future gas measurement practices. Our costs and legal exposure related to these lawsuits and claims are not currently determinable.
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In addition to the above proceedings, we and our subsidiaries and affiliates are named defendants in numerous lawsuits and governmental proceedings that arise in the ordinary course of our business. For each of these matters, we evaluate the merits of the case, 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, including those discussed above, 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 matters at December 31, 2008. It is possible, however, that new information or future developments could require us to reassess our potential exposure related to these matters and establish our 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 on the environment of the disposal or release of specified substances at current and former operating sites. At December 31, 2008, we had accrued approximately $6 million for expected remediation costs and associated onsite, offsite and groundwater technical studies and for related environmental legal costs.
Our accrual represents a combination of two estimation methodologies. First, where the most likely outcome can be reasonably estimated, that cost has been accrued. Second, where the most likely outcome cannot be estimated, a range of costs is established and if no one amount in that range is more likely than any other, the lower end of the expected range has been accrued. Our environmental remediation projects are in various stages of completion. Our recorded liabilities reflect our current estimates of amounts we will expend 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.
Below is a reconciliation of our accrued liability from January 1, 2008 to December 31, 2008 (in millions):
Balance at January 1, 2008 | $ | 10 | ||
Adjustments for remediation activities | (2 | ) | ||
Payments for remediation activities | (2 | ) | ||
Balance at December 31, 2008 | $ | 6 |
For 2009, we estimate that our total remediation expenditures will be approximately $2 million, which will be expended under government directed clean-up plans.
Polychlorinated Biphenyls (PCB) Cost Recoveries. Pursuant to a consent order executed with the EPA in May 1994, we have been conducting remediation activities at certain of our compressor stations associated with the presence of PCBs and other hazardous materials. In July 2008, we received approval from the EPA on our final program report for the consent order. Long-term monitoring and state required activities are continuing. We have recovered a substantial portion of the environmental costs identified in our PCB remediation project through a surcharge to our customers. A settlement with our customers, approved by the FERC in November 1995, established the surcharge mechanism. In May 2008, the FERC accepted our filing to extend the surcharge collection period through June 2010. As of December 31, 2008, we had pre-collected PCB costs of approximately $160 million, which includes interest. This pre-collected amount will be reduced by future eligible costs incurred for the remainder of the remediation project. To the extent actual eligible expenditures are less than the amounts pre-collected, we will refund to our customers the difference, plus carrying charges incurred up to the date of the refunds. At December 31, 2008, our regulatory liability for estimated future refund obligations to our customers was approximately $157 million. In compliance with the FERC’s order on our May 2008 filing, we engaged in discussions with our customers to ascertain the feasibility of amending the settlement to provide for an earlier refund of amounts collected in excess of estimated future eligible costs than would otherwise be required by the settlement while safeguarding our ability to recover costs of future remediation activities. On November 12, 2008, the FERC directed that a settlement judge be appointed in the proceeding to aid us and our customers in negotiating a potential early refund. We and our customers have reached an agreement in principle to settle this matter, pursuant to which we will refund amounts over a three year period commencing in 2009.
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Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) Matters. We have received notice that we could be designated, or have been asked for information to determine whether we could be designated, as a Potentially Responsible Party (PRP) with respect to four active sites under the CERCLA or state equivalents. We have sought to resolve our liability as a PRP at these sites through indemnification by third parties and settlements which provide for payment of our allocable share of remediation costs. As of December 31, 2008, we have estimated our share of the remediation costs at these sites to be between $1 million and $2 million. Because the clean-up costs are estimates and are subject to revision as more information becomes available about the extent of remediation required, and in some cases we have asserted a defense to any liability, our estimates could change. Moreover, liability under the federal CERCLA statute is joint and several, meaning that we could be required to pay in excess of our pro rata share of remediation costs. Our understanding of the financial strength of other PRPs has been considered, where appropriate, in estimating our liabilities. Accruals for these matters are included in the environmental reserve discussed above.
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.
Regulatory Matters
Notice of Proposed Rulemaking. In October 2007, the Minerals Management Service (MMS) issued a Notice of Proposed Rulemaking for Oil and Gas and Sulphur Operations in the Outer Continental Shelf (OCS) — Pipelines and Pipeline Rights-of-Way. If adopted, the proposed rules would substantially revise MMS OCS pipeline and rights-of-way regulations. The proposed rules would have the effect of: (1) increasing the financial obligations of entities, like us, which have pipelines and pipeline rights-of-way in the OCS; (2) increasing the regulatory requirements imposed on the operation and maintenance of existing pipelines and rights of way in the OCS; and (3) increasing the requirements and preconditions for obtaining new rights-of-way in the OCS.
Greenhouse Gas (GHG) Emissions. Legislative and regulatory measures to address GHG emissions are in various phases of discussions or implementation at the international, national, regional and state levels. In the United States, it is likely that federal legislation requiring GHG controls will be enacted in the next few years. In addition, the EPA is considering initiating a rulemaking to regulate GHGs under the Clean Air Act. Legislation and regulation are also in various stages of discussions or implementation in many of the states in which we operate. Additionally, lawsuits have been filed seeking to force the federal government to regulate GHG emissions and individual companies to reduce GHG emissions from their operations. These and other lawsuits may result in decisions by state and federal courts and agencies that could impact our operations and ability to obtain certifications and permits to construct future projects. Our costs and legal exposure related to GHG regulations are not currently determinable.
Commitments and Purchase Obligations
Capital Commitments. At December 31, 2008, we had capital commitments of approximately $100 million which will be spent in 2009. 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 $80 million at December 31, 2008. Our annual obligations under these purchase obligations are $34 million in 2009, $19 million in 2010, $10 million in 2011, $5 million in 2012, $3 million in 2013 and $9 million in total thereafter.
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Operating Leases and Other Commercial Commitments. We lease property, facilities and equipment under various operating leases. Minimum future annual rental commitments on our operating leases as of December 31, 2008, were as follows:
Year Ending December 31, | (In millions) | ||||
2009 | $ | 1 | |||
2010 | 1 | ||||
2011 | 1 | ||||
2012 | 1 | ||||
Thereafter | 2 | ||||
Total | $ | 6 |
Rental expense on our operating leases for each of the three years ended December 31, 2008, 2007 and 2006 was $2 million. These amounts include rent allocated to us from El Paso.
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 Benefits. El Paso maintains a pension plan and a retirement savings plan covering substantially all of its U.S. employees, including our 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. El Paso is responsible for benefits accrued under its plans and allocates the related costs to its affiliates.
Postretirement Benefits. We provide postretirement medical and life insurance benefits for a closed group of retirees 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 2009.
Effective December 31, 2006, we began accounting for our postretirement benefit plan under the recognition provisions of SFAS No. 158. Under SFAS No. 158, we record an asset or liability for our postretirement benefit plan based on its over funded or under funded status. In March 2007, the FERC issued guidance requiring regulated pipeline companies to record a regulatory asset or liability for any deferred amounts related to unrecognized gains and losses or changes in actuarial assumptions that would otherwise be recorded in accumulated other comprehensive income for non-regulated entities. Upon adoption of this FERC guidance, we reclassified $3 million from accumulated other comprehensive income to a regulatory liability.
Effective January 1, 2008, we adopted the measurement date provisions of SFAS No. 158 and changed the measurement date of our postretirement benefit plan from September 30 to December 31. The adoption of the measurement date provisions of this standard did not have a material impact on our financial statements.
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Accumulated Postretirement Benefit Obligations, Plan Assets and Funded Status. The table below provides information about our postretirement benefit plan. In 2008, we adopted the measurement date provisions of SFAS No. 158 and the information below for 2008 is presented and computed as of and for the fifteen months ended December 31, 2008. For 2007, the information is presented and computed as of and for the twelve months ended September 31, 2007.
December 31, 2008 | September 30, 2007 | |||||||
(In millions) | ||||||||
Change in accumulated postretirement benefit obligation: | ||||||||
Accumulated postretirement benefit obligation-beginning of period | $ | 22 | $ | 22 | ||||
Interest cost | 1 | 1 | ||||||
Participant contributions | 2 | 1 | ||||||
Benefits paid(1) | (4 | ) | (2 | ) | ||||
Accumulated postretirement benefit obligation-end of period | $ | 21 | $ | 22 | ||||
Change in plan assets: | ||||||||
Fair value of plan assets-beginning of period | $ | 29 | $ | 23 | ||||
Actual return on plan assets | (9 | ) | 2 | |||||
Employer contributions | 5 | 5 | ||||||
Participant contributions | 2 | 1 | ||||||
Benefits paid | (4 | ) | (2 | ) | ||||
Fair value of plan assets-end of period | $ | 23 | $ | 29 | ||||
Reconciliation of funded status: | ||||||||
Fair value of plan assets | $ | 23 | $ | 29 | ||||
Less: Accumulated postretirement benefit obligation | 21 | 22 | ||||||
Fourth quarter contributions | 1 | |||||||
Net asset at December 31 | $ | 2 | $ | 8 |
(1) Amounts shown are net of a subsidy related to 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 the result of general economic and capital market conditions. As a result of the general decline in the markets for debt and equity securities, the fair value of our plan’s assets and the funded status of our other postretirement benefit plan declined during 2008, which resulted in a decrease in our plan assets and regulatory liability when our plan’s assets and obligation were remeasured at December 31, 2008. The following table provides the target and actual asset allocations in our postretirement benefit plan as of December 31, 2008 and September 30, 2007:
Asset Category | Target | Actual 2008 | Actual 2007 | ||||||||||
(Percent) | |||||||||||||
Equity securities | 65 | 62 | 63 | ||||||||||
Debt securities | 35 | 33 | 33 | ||||||||||
Cash and cash equivalents | — | 5 | 4 | ||||||||||
Total | 100 | 100 | 100 |
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Expected Payment of Future Benefits. As of December 31, 2008, we expect the following payments (net of participant contributions and an expected subsidy related to the Medicare Prescription Drug, Improvement, and Modernization Act of 2003) under our plan (in millions):
Year Ending December 31, | ||||
2009 | $ | 2 | ||
2010 | 2 | |||
2011 | 2 | |||
2012 | 2 | |||
2013 | 2 | |||
2014 -2018 | 8 |
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 2008, 2007 and 2006:
2008 | 2007 | 2006 | ||||||||||
(Percent) | ||||||||||||
Assumptions related to benefit obligations at December 31, 2008 and September 30, 2007 and 2006 measurement dates: | ||||||||||||
Discount rate | 5.95 | 6.05 | 5.50 | |||||||||
Assumptions related to benefit costs at December 31: | ||||||||||||
Discount rate | 6.05 | 5.50 | 5.25 | |||||||||
Expected return on plan assets(1) | 8.00 | 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 tax 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 8.6 percent in 2008, gradually decreasing to 5.0 percent by the year 2015. Changes in our assumed health care cost trend rates do not have a material impact on the amounts reported for our interest costs or our accumulated postretirement benefit obligations.
Components of Net Benefit Income. For each of the years ended December 31, the components of net benefit income are as follows:
2008 | 2007 | 2006 | ||||||||||
(In millions) | ||||||||||||
Interest cost | $ | 1 | $ | 1 | $ | 1 | ||||||
Expected return on plan assets | (1 | ) | (1 | ) | (1 | ) | ||||||
Net postretirement benefit income | $ | — | $ | — | $ | — |
10. Transactions with Major Customer
The following table shows revenues from our major customer for each of the three years ended December 31:
2008 | 2007 | 2006 | ||||||||||
(In millions) | ||||||||||||
National Grid USA and Subsidiaries (1) | $ | 109 | $ | 77 | $ | 9 |
____________
(1) In 2007 and 2006, National Grid USA and Subsidiaries did not represent more than 10 percent of our revenues.
11. Supplemental Cash Flow Information
The following table contains supplemental cash flow information for each of the three years ended December 31:
2008 | 2007 | 2006 | ||||||||||
(In millions) | ||||||||||||
Interest paid, net of capitalized interest | $ | 120 | $ | 116 | $ | 119 | ||||||
Income tax payments | 12 | 121 | 13 |
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12. Investment in Unconsolidated Affiliate and Transactions with Affiliates
Investment in Unconsolidated Affiliate
Bear Creek Storage Company (Bear Creek). We have a 50 percent ownership interest in Bear Creek, a joint venture with Southern Gas Storage Company, our affiliate. We account for our investment in Bear Creek using the equity method of accounting. During 2008, 2007 and 2006, we received $16 million, $27 million and $17 million in dividends from Bear Creek.
Summarized financial information for our proportionate share of Bear Creek as of and for the years ended December 31 is presented as follows:
2008 | 2007 | 2006 | ||||||||||
(In millions) | ||||||||||||
Operating results data: | ||||||||||||
Operating revenues | $ | 20 | $ | 19 | $ | 20 | ||||||
Operating expenses | 8 | 8 | 7 | |||||||||
Income from continuing operations and net income | 13 | 13 | 15 |
2008 | 2007 | |||||||
(In millions) | ||||||||
Financial position data: | ||||||||
Current assets | $ | 27 | $ | 28 | ||||
Non-current assets | 55 | 58 | ||||||
Current liabilities | 1 | 2 | ||||||
Equity in net assets | 81 | 84 |
Transactions with Affiliates
Cash Management Program and Other Notes 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. In January 2008, El Paso repaid a separate variable interest rate note receivable of $118 million. At December 31, 2008 and 2007, we had notes receivable from El Paso of $800 million and $582 million. We do not intend to settle these notes within twelve months and have therefore classified them as non-current on our balance sheets. The interest rate on these notes at December 31, 2008 and 2007 was 3.2% and 6.5%.
At December 31, 2008 and 2007, we had non-interest bearing notes receivable of $334 million from an El Paso affiliate. During the fourth quarter of 2008, we reclassified these notes from non-current assets to a reduction of our stockholder’s equity based on increased uncertainties regarding the timing and method through which El Paso will settle these balances.
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, 2008 and 2007, we had federal and state income taxes payable of $58 million and $13 million. The majority of these balances, as well as deferred income taxes and amounts associated with the resolution of unrecognized tax benefits, will become payable to El Paso. See Note 1 for a discussion of our income tax policy.
During 2007, we amended our tax sharing agreement and intercompany tax billing policy with El Paso to clarify the billing of taxes and tax related items to El Paso’s subsidiaries. We also settled with El Paso certain tax attributes previously reflected as deferred income taxes in our financial statements for $77 million through El Paso’s cash management program. This settlement is reflected as operating activities in our statement of cash flows.
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Accounts Receivable Sales Program. We sell certain accounts receivable to a qualifying special purpose entity (QSPE) under SFAS No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities, whose purpose is solely to invest in our receivables. As of December 31, 2008 and 2007, we sold approximately $97 million and $96 million of receivable, received cash of approximately $38 million and $34 million and received subordinated beneficial interests of approximately $58 million and $61 million. In conjunction with the sale, the QSPE also issued senior beneficial interests on the receivables sold to a third party financial institution, which totaled $39 million and $35 million as of December 31, 2008 and 2007. We reflect the subordinated interests in receivables sold at their fair value on the date they are issued. These amounts (adjusted for subsequent collections) are recorded as accounts receivable from affiliate in our balance sheets. Our ability to recover our carrying value of our subordinated interests is based on the collectibility of the underlying receivables sold to the QSPE. We reflect accounts receivable sold under this program and changes in the subordinated beneficial interests as operating cash flows in our statement of cash flows. Under these agreements, we earn a fee for servicing the receivables and performing all administrative duties for the QSPE which is reflected as a reduction of operation and maintenance expense in our income statement. The fair value of these servicing and administrative agreements as well as the fees earned were not material to our financial statements for the years ended December 31, 2008 and 2007.
Other Affiliate Balances. At December 31, 2008 and 2007, we had contractual deposits from our affiliates of $9 million and $8 million.
Affiliate Revenues and Expenses. We enter into transactions with our affiliates within the ordinary course of business.
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 EBIT, gross property and payroll.
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 the normal course of our business based on the same terms as non-affiliates.
The following table shows overall revenues and charges from our affiliates for each of the three years ended December 31:
2008 | 2007 | 2006 | ||||||||||
(In millions) | ||||||||||||
Revenues from affiliates | $ | 20 | $ | 21 | $ | 22 | ||||||
Operation and maintenance expenses from affiliates | 60 | 57 | 56 | |||||||||
Reimbursements of operating expenses charged to affiliates(1) | 59 | 45 | 79 |
____________
(1) | Decrease in activity in 2007 is due to El Paso’s sale of its subsidiary, ANR Pipeline Company. |
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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) | ||||||||||||||||||||
2008 | ||||||||||||||||||||
Operating revenues | $ | 245 | $ | 217 | $ | 209 | $ | 236 | $ | 907 | ||||||||||
Operating income | 88 | 56 | 49 | 69 | 262 | |||||||||||||||
Net income | 43 | 22 | 16 | 30 | 111 | |||||||||||||||
2007 | ||||||||||||||||||||
Operating revenues | $ | 226 | $ | 220 | $ | 193 | $ | 223 | $ | 862 | ||||||||||
Operating income | 101 | 85 | 47 | 65 | 298 | |||||||||||||||
Net income | 55 | 43 | 22 | 33 | 153 |
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SCHEDULE II
TENNESSEE GAS PIPELINE COMPANY
VALUATION AND QUALIFYING ACCOUNTS
Years Ended December 31, 2008, 2007 and 2006
(In millions)
Description | Balance at Beginning of Period | Charged to Costs and Expenses | Deductions | Charged to Other Accounts | Balance at End of Period | |||||||||||||||
2008 | ||||||||||||||||||||
Environmental reserves | $ | 10 | $ | (2 | ) | $ | (2 | )(2) | $ | — | $ | 6 | ||||||||
2007 | ||||||||||||||||||||
Environmental reserves | $ | 15 | $ | (2 | )(1) | $ | (3 | )(2) | $ | — | $ | 10 | ||||||||
2006 | ||||||||||||||||||||
Allowance for doubtful accounts | $ | 1 | $ | — | $ | — | $ | (1 | ) | $ | — | |||||||||
Environmental reserves | $ | 32 | $ | (12 | )(1) | $ | (5 | )(2) | $ | — | $ | 15 |
____________
(1) | Represents a reduction in the estimated costs to complete our internal remediation projects. |
(2) | Primarily payments made for environmental remediation activities. |
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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
As of December 31, 2008, we carried out an evaluation under the supervision and with the participation of our management, including our President and Chief Financial Officer, 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 SEC reports we file or submit under the Exchange Act is accurate, complete and timely. Our management, including our President and Chief Financial Officer, 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 Chief Financial Officer have concluded that our disclosure controls and procedures are effective at a reasonable level of assurance at December 31, 2008. 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 2008 that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.
ITEM 9A(T). CONTROLS AND PROCEDURES
This annual report does not include an attestation report of our independent registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by our independent registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit us to provide only management’s report in this annual report. See Item 8, Financial Statements and Supplementary Data, under Management’s Annual Report on Internal Control Over Financial Reporting.
ITEM 9B. OTHER INFORMATION
None.
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PART III
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.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Audit Fees
The audit fees for the years ended December 31, 2008 and 2007 of $762,000 and $770,000, 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.
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, 2008 and 2007.
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 2009 Annual Meeting of Stockholders.
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PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(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 | |
Reports of Independent Registered Public Accounting Firms | 20 |
Consolidated Statements of Income | 21 |
Consolidated Balance Sheets | 22 |
Consolidated Statements of Cash Flows | 23 |
Consolidated Statements of Stockholder’s Equity | 24 |
Notes to Consolidated Financial Statements | 25 |
2. Financial statement schedules
Schedule II — Valuation and Qualifying Accounts | 42 |
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.
Undertaking
We hereby undertake, pursuant to Regulation S-K, Item 601(b), paragraph (4)(iii), to furnish to the U.S. SEC upon request all constituent instruments defining the rights of holders of our debt and our consolidated subsidiaries not filed as an exhibit hereto 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.
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SIGNATURES
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 2nd day of March 2009.
TENNESSEE GAS PIPELINE COMPANY | |||
By: | /s/ James C. Yardley | ||
James C. Yardley | |||
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/ James C. Yardley | Chairman of the Board and President | March 2, 2009 | ||
James C. Yardley | (Principal Executive Officer) | |||
/s/ John R. Sult | Senior Vice President, Chief Financial | March 2, 2009 | ||
John R. Sult | Officer and Controller (Principal Accounting and Financial Officer) | |||
/s/ Daniel B. Martin | Senior Vice President and Director | March 2, 2009 | ||
Daniel B. Martin | ||||
/s/ Bryan W. Neskora | Senior Vice President, Chief Commercial Officer and Director | March 2, 2009 | ||
Bryan W. Neskora | ||||
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TENNESSEE GAS PIPELINE COMPANY
EXHIBIT INDEX
December 31, 2008
Each exhibit identified below is a 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 (Exhibit 3.A to our Annual Report on Form 10-K for the year ended December 31, 2004, filed with the SEC on March 29, 2005). | |
*3.B | By-laws dated as of June 2, 2008. | |
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 (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 (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.2 | Second Supplemental Indenture dated as of March 13, 1997, between Tennessee Gas Pipeline Company and the Trustee (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 (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 (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. | |
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 (Exhibit 4.A to our Current Report on Form 8-K filed with the SEC on January 29, 2009). | |
10.A | Amended and Restated Credit Agreement dated as of July 31, 2006, among El Paso Corporation, Colorado Interstate Gas Company, 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. (Exhibit 10.A to our Current Report on Form 8-K filed with the SEC on August 2, 2006); Amendment No. 1 dated as of January 19, 2007 to the Amended and Restated Credit Agreement dated as of July 31, 2006 among El Paso Corporation, Colorado Interstate Gas Company, 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 (Exhibit 10.A.1 to our Annual Report on Form 10-K for the year ended December 31, 2006, filed with the SEC on February 28, 2007). |
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10.B | Amended and Restated Security Agreement dated as of July 31, 2006, among El Paso Corporation, Colorado Interstate Gas Company, El Paso Natural Gas Company, Tennessee Gas Pipeline Company, the Subsidiary Guarantors 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. (Exhibit 10.B to our Current Report on Form 8-K filed with the SEC on August 2, 2006). | |
10.C | First Tier Receivables Sale Agreement dated August 31, 2006, between Tennessee Gas Pipeline Company and TGP Finance Company, L.L.C. (Exhibit 10.A to our Current Report on Form 8-K filed with the SEC on September 8, 2006). | |
10.D | Second Tier Receivables Sale Agreement dated August 31, 2006, between TGP Finance Company, L.L.C. and TGP Funding Company, L.L.C. (Exhibit 10.B to our Current Report on Form 8-K filed with the SEC on September 8, 2006). | |
10.E.1 | Receivables Purchase Agreement dated August 31, 2006, among TGP Funding Company, L.L.C., as Seller, Tennessee Gas Pipeline Company, as Servicer, Starbird Funding Corporation, as the initial Conduit Investor and Committed Investor, the other investors from time to time parties thereto, BNP Paribas, New York Branch, as the initial Managing Agent, the other Managing Agents from time to time parties thereto, and BNP Paribas, New York Branch, as Program Agent (Exhibit 10.C to our Current Report on Form 8-K filed with the SEC on September 8, 2006). | |
10.E.2 | Amendment No 1., dated as of December 1, 2006, to the Receivables Purchase Agreement dated as of August 31, 2006, among TGP Funding Company, L.L.C., Tennessee Gas Pipeline Company, as initial Servicer, Starbird Funding Corporation and the other funding entities from time to time party hereto as Investors, BNP Paribas, New York Branch, and the other financial institutions from time to time party thereto as Managing Agents, and BNP Paribas, New York Branch, as Program Agent (Exhibit 10.A.1 to our Annual Report on Form 10-K for the year ended December 31, 2006, filed with the SEC on February 28, 2007). | |
10.E.3 | Amendment No. 2, dated as of August 29, 2007, to the Receivables Purchase Agreement dated as of August 31, 2006 among TGP Funding Company, L.L.C., Tennessee Gas Pipeline Company, as initial Servicer, Starbird Funding Corporation and the other funding entities from time to time party hereto as Investors, BNP Paribas, New York Branch, and the other financial institutions from time to time party hereto as Managing Agents, and BNP Paribas, New York Branch, as Program Agent (Exhibit 10.A to our Quarterly Report on Form 10-Q for the period ended September 30, 2007, filed with the SEC on November 6, 2007). | |
10.E.4 | Amendment No. 3, dated as of August 27, 2008, to the Receivables Purchase Agreement dated as of August 31, 2006 among TGP Funding Company, L.L.C., Tennessee Gas Pipeline Company, as initial Servicer, Starbird Funding Corporation and the other funding entities from time to time party hereto as Investors, BNP Paribas, New York Branch, and the other financial institutions from time to time party hereto as Managing Agents, and BNP Paribas, New York Branch, as Program Agent (Exhibit 10.A to our Quarterly Report on Form 10-Q for the period ended September 30, 2008, filed with the SEC on November 10, 2008). | |
*10.E.5 | Amendment No. 4, dated as of October 31, 2008, to the Receivables Purchase Agreement dated as of August 31, 2006 among TGP Funding Company, L.L.C., Tennessee Gas Pipeline Company, as initial Servicer, Starbird Funding Corporation and the other funding entities from time to time party hereto as Investors, BNP Paribas, New York Branch, and the other financial institutions from time to time party hereto as Managing Agents, and BNP Paribas, New York Branch, as Program Agent. |
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10.F | Third Amended and Restated Credit Agreement dated as of November 16, 2007, 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 (Exhibit 10.A to our Current Report on Form 8-K filed with the SEC on November 21, 2007). | |
10.G | 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 (Exhibit 10.B to our Current Report on Form 8-K filed with the SEC on November 21, 2007). | |
10.H | 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 (Exhibit 10.C to our Current Report on Form 8-K filed with the SEC on November 21, 2007). | |
10.I | 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 (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. | |
*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. |
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