TENNESSEE GAS PIPELINE COMPANY, L.L.C. - FORM 10-K

TENNESSEE GAS PIPELINE COMPANY, L.L.C. - FORM 10-K - February 27, 2012

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EXCEL - IDEA: XBRL DOCUMENT - TENNESSEE GAS PIPELINE COMPANY, L.L.C.	Financial_Report.xls
EX-23 - CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM ERNST & YOUNG LLP - TENNESSEE GAS PIPELINE COMPANY, L.L.C.	d269121dex23.htm
EX-3.A - CERTIFICATE OF CONVERSION OF TENNESSEE GAS PIPELINE COMPANY, L.L.C. - TENNESSEE GAS PIPELINE COMPANY, L.L.C.	d269121dex3a.htm
EX-4.A - INDENTURE DATED AS OF MARCH 4, 1997 - TENNESSEE GAS PIPELINE COMPANY, L.L.C.	d269121dex4a.htm
EX-3.B - FIRST AMENDED AND RESTATED LIMITED LIABILITY COMPANY AGREEMENT - TENNESSEE GAS PIPELINE COMPANY, L.L.C.	d269121dex3b.htm
EX-4.A.4 - FOURTH SUPPLEMENTAL INDENTURE DATED AS OF OCTOBER 9, 1998 - TENNESSEE GAS PIPELINE COMPANY, L.L.C.	d269121dex4a4.htm
EX-31.B - CERTIFICATION OF CHIEF FINANCIAL OFFICER - TENNESSEE GAS PIPELINE COMPANY, L.L.C.	d269121dex31b.htm
EX-4.A.3 - THIRD SUPPLEMENTAL INDENTURE DATED AS OF MARCH 13, 1997 - TENNESSEE GAS PIPELINE COMPANY, L.L.C.	d269121dex4a3.htm
EX-32.B - CERTIFICATION OF CHIEF FINANCIAL OFFICER - TENNESSEE GAS PIPELINE COMPANY, L.L.C.	d269121dex32b.htm
EX-4.A.7 - SEVENTH SUPPLEMENTAL INDENTURE DATED AS OF OCTOBER 1, 2011 - TENNESSEE GAS PIPELINE COMPANY, L.L.C.	d269121dex4a7.htm
EX-32.A - CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER - TENNESSEE GAS PIPELINE COMPANY, L.L.C.	d269121dex32a.htm
EX-4.A.2 - SECOND SUPPLEMENTAL INDENTURE DATED AS OF MARCH 13, 1997 - TENNESSEE GAS PIPELINE COMPANY, L.L.C.	d269121dex4a2.htm
EX-31.A - CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER - TENNESSEE GAS PIPELINE COMPANY, L.L.C.	d269121dex31a.htm
EX-4.A.1 - FIRST SUPPLEMENTAL INDENTURE DATED AS OF MARCH 13, 1997 - TENNESSEE GAS PIPELINE COMPANY, L.L.C.	d269121dex4a1.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)

þ	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2011

¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number 1-4101

Tennessee Gas Pipeline Company, L.L.C.

(Exact Name of Registrant as Specified in Its Charter)


Delaware		74-1056569
(State or Other Jurisdiction of		(I.R.S. Employer
Incorporation or Organization)		Identification No.)

El Paso Building
1001 Louisiana Street
Houston, Texas		77002
(Address of Principal Executive Offices)		(Zip Code)

Telephone Number: (713) 420-2600

Securities registered pursuant to Section 12(b) of the Act: None

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities
Act. Yes ¨ No 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 ¨ No þ

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 ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. 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):

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ¨ No þ

State the aggregate market value of the voting equity held by non-affiliates of the registrant: None

TENNESSEE GAS PIPELINE COMPANY, L.L.C. 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, L.L.C.

TABLE OF CONTENTS


Caption		Page

PART I
Item 1.	Business		1
Item 1A.	Risk Factors		5
Item 1B.	Unresolved Staff Comments		14
Item 2.	Properties		14
Item 3.	Legal Proceedings		14
Item 4.	Mine Safety Disclosures		14

PART II

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		14
Item 6.	Selected Financial Data		*
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		15
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		21
Item 8.	Financial Statements and Supplementary Data		22
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		46
Item 9A.	Controls and Procedures		46
Item 9B.	Other Information		46

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		47

PART IV

Item 15.	Exhibits and Financial Statement Schedules		48
	Signatures		49

*	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:

per day

MMBtu

million British thermal units

BBtu

billion British thermal units

MMcf

million cubic feet

Bcf

billion cubic feet

NGL

natural gas liquids

LNG

liquefied natural gas

TBtu

trillion British thermal units

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,” or “ours,” we are describing Tennessee Gas Pipeline Company, L.L.C. and/or our subsidiaries.

PART I

ITEM 1. BUSINESS

Overview and Strategy

We are a Delaware limited liability company, originally formed in 1947 as a corporation. Effective October 1, 2011, we converted our legal structure to a limited liability company and changed our name to Tennessee Gas Pipeline Company, L.L.C. We are owned 100 percent indirectly through a 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.

On October 16, 2011, El Paso announced a definitive agreement with Kinder Morgan, Inc. (KMI) whereby KMI will acquire El Paso in a transaction that valued El Paso at approximately $38 billion (based on the KMI stock price at that date), including the assumption of debt. The transaction has been approved by each company’s board of directors but remains subject to approvals of El Paso shareholders, the Federal Trade Commission (FTC) and other customary regulatory and other approvals. The approval of KMI shareholders will also be required, but a voting agreement has been executed by the majority of the shareholders of KMI to support the transaction. The completion of the merger may trigger change in control provisions in certain agreements (e.g. debt) to which we are a party.

Our pipeline system and storage facilities operate under a tariff approved by the Federal Energy Regulatory Commission (FERC) that establishes rates, cost recovery mechanisms and other terms and conditions of services to our customers. The fees or rates established under our tariff are a function of our costs of providing services to our customers, including a reasonable return on our invested capital.

Our strategy is to enhance the value of our transportation and storage business by:

•

focusing on customer service;

•

successfully executing on time and on budget for our committed expansion projects;

•

developing growth projects in our market and supply areas;

•

maintaining the safety of our pipeline system and other assets;

•

optimizing our contract portfolio;

•

successfully recontracting expiring contracts for transportation capacity;

•

focusing on increasing utilization, efficiency and cost control in our operations; and

•

managing market segmentation and differentiation.

Pipeline System. Our pipeline system consists of approximately 13,900 miles of pipeline with a design capacity of 7,549 MMcf/d. During 2011, 2010 and 2009, average throughput was 6,267 BBtu/d, 5,081 BBtu/d, and 4,614 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.

Storage Facilities. Along our pipeline system, we have 93 Bcf of underground working natural gas storage capacity through partially owned facilities or long-term contracts. Of the total capacity, 29 Bcf is contracted from Bear Creek Storage Company, L.L.C. (Bear Creek) located in Bienville Parish, Louisiana. Bear Creek is a joint venture equally owned by us and our affiliate, Southern Natural Gas Company, L.L.C. (SNG). The facility has 58 Bcf of working natural gas storage capacity that is committed equally to SNG and us.

Markets and Competition

We provide transportation and storage services in both our natural gas supply and market areas. Our pipeline system connects with multiple pipelines that provide our customers with access to diverse sources of supply and various natural gas markets.

The natural gas industry has experienced a major shift from conventional supply sources to unconventional sources, such as shales. In addition, the increase in oil prices has led to increased production of natural gas found in association with the production of oil. This shift has impacted supply patterns, gas flows and rates that can be charged on pipeline systems. The impact will vary among pipelines according to the location and the number of competitors attached to these new supply sources. Our pipeline is connected to major shale formations: the Haynesville Shale in northern Louisiana and Texas and the Marcellus Shale in Pennsylvania. Gas from these sources could continue to increasingly displace receipts over time from traditional sources such as south Texas and the Gulf of Mexico on our system. In addition, the Eagle Ford Shale in South Texas and the Utica Shale in Ohio/Pennsylvania offer a growing supply source which should provide additional benefit to us. Due to the economic uplift from oil and NGL production in these trends, drilling activity is growing rapidly and expected to do so for the next five years. Future production growth in the dry gas portion of these shales could be impacted by producer decisions to shift their activity to projects in different regions that contain liquids and offer a better economic return. A potential loss of dry gas volumes in the Marcellus Shale, however, may be offset by increased drilling in the liquid rich portion of the play as well as increased production from the Utica. An example of growing activity in a liquid rich play is occurring in the Eagle Ford Shale in South Texas, which could become a major source of supply into our system.

Another change in the supply patterns is the reduction in imports from Canada. This decrease has been the result of continuing declines in conventional Canadian production coupled with increasing demand in Canada. On the Southern border, exports to Mexico are increasing and may increase further over time as demand growth exceeds production growth in that country. In addition to these trends in Canada and Mexico, imports of LNG to the U.S. have been declining over the last several years in response to increased U.S. shale gas production which has resulted in a decline in U.S. natural gas prices relative to gas prices in Europe and Asia. The projected gas price disparity between U.S. and European/Asian markets suggests that North America could change from a net importer of LNG to a net exporter of LNG before the end of this decade. All of the aforementioned factors have led to increased demand for domestic U.S. supplies and related transportation services over the last several years, a trend which is likely to continue.

Electric power generation has been the source of most of the demand growth for natural gas over the last 10 years, and this trend is expected to continue. The growth of natural gas in this sector is influenced by competition with coal and economic growth. Short-term market shifts have been driven by relative electric generation costs of coal-fired plants versus gas-fired plants. A long-term market shift in the use of coal in power generation could be driven by environmental regulations. The future demand for natural gas could be increased by regulations limiting or discouraging coal use. However, natural gas demand could potentially be adversely affected by laws mandating or encouraging renewable power sources. Industrial demand has also grown recently with the economic recovery and low natural gas price environment, and this sector offers an opportunity for continued growth. In addition, a potential new and significant demand market for North American natural gas production is for LNG exports to Europe and Asia. Several Gulf Coast projects have received Department of Energy approval to export LNG to global markets beginning in the second half of this decade.

We face competition in all our market areas and we compete with other interstate and intrastate pipelines for deliveries to multiple-connection customers who can take deliveries at alternative points. Natural gas delivered on our system competes with alternative energy sources used to generate electricity such as hydroelectric power, coal and fuel oil. In addition, we compete with pipelines and gathering systems for connection to new supply sources in Texas, the Gulf of Mexico, and the emerging shale basins.

For a further discussion of factors impacting our markets and competition, see Item 1A. Risk Factors.

Customers and Contracts

We provide natural gas services to a variety of customers, including natural gas distribution and industrial companies, electric generation companies, natural gas producers, other natural gas pipelines and natural gas marketing and trading companies. Our existing transportation and storage contracts expire at various times and in varying amounts of throughput capacity. Our ability to extend our existing customer contracts or remarket expiring contracted capacity is dependent on competitive alternatives, the regulatory environment at the federal, state and local levels and market supply and demand factors at the relevant dates these contracts are extended or expire. The duration of new or renegotiated contracts will be affected by current prices, competitive conditions and judgments concerning future market trends and volatility. Although we attempt to recontract or remarket our capacity at the maximum rates allowed under our tariff, we frequently enter into firm transportation contracts at amounts that are less than these maximum allowable rates to remain competitive.

The following table details our customer and contract information related to our pipeline system as of December 31, 2011. 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 natural gas they transport, store, inject or withdraw.


Customer Information		Contract Information
Approximately 420 firm and interruptible customers.		Approximately 480 firm transportation contracts. Weighted average remaining contract term of approximately four years.

Major Customer: National Grid USA and subsidiaries (481 BBtu/d) (285 BBtu/d)		Expire in 2012-2014. Expire in 2015-2029.

Regulatory Environment

Our interstate natural gas transmission system and storage operations are regulated by the FERC under the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and the Energy Policy Act of 2005. We operate under a tariff approved by the FERC that establishes rates, cost recovery mechanisms and other terms and conditions of services to our customers. The rates established under our tariff are a function of our costs of providing services to our customers, including a reasonable return on our invested capital. Generally, the FERC’s authority also 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. For a further discussion of the potential impact of regulatory matters on us, see Item 1A. Risk Factors.

Environmental

A description of our environmental remediation activities is included in Part II, Item 8. Financial Statements and Supplementary Data, Note 7, and is incorporated herein by reference.

Employees

We do not have employees. Following our conversion to a limited liability company, our former employees continue to provide services to us under a master services agreement with an affiliated service company owned by El Paso. We are managed and operated by officers of El Paso and its affiliates. Under the master services agreement, we reimburse the affiliate for various general and administrative services performed for our benefit and for direct expenses incurred on our behalf.

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 the actual results and such variances can be material. Where we express an expectation or belief as to future results, that expectation or belief is expressed in good faith and is believed to have a reasonable basis. We cannot assure you, however, that the stated expectation or belief will occur. The words “believe,” “expect,” “estimate,” “anticipate,” and similar expressions will generally identify forward-looking statements. All of our forward-looking statements, whether written or oral, are expressly qualified by these and other cautionary statements. We disclaim any obligation to update any forward-looking statements to reflect events or circumstances after the date provided. With this in mind, you should consider the risks discussed elsewhere in this report and other documents we file with the Securities and Exchange Commission (SEC) from time to time and the following important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. If any of the following risks were actually to occur, our business, results of operations, financial condition and growth could be materially adversely affected.

Risks Related to Our Business

The success of our business depends on many factors beyond our control.

The results of our business are impacted in the long term by the volumes of natural gas we transport or store and the prices we are able to charge for these services. The volumes we transport and store depend on the actions of third parties that are based on factors beyond our control. Such factors include events that negatively impact our customers’ demand for natural gas and could expose our pipeline to the risk that we will not be able to renew contracts at expiration or that we will be required to discount our rates significantly upon renewal. We are also highly dependent on our customers and downstream pipelines to attach new and increased loads on their systems in order to grow our business. Further, state agencies that regulate our local distribution company customers could impose requirements that could impact demand for our services.

The volume of natural gas that we transport and store also depends on the availability of natural gas supplies that are accessible to our pipeline system, including the need for producers to continue to develop additional gas supplies to offset the natural decline from existing wells connected to our system. This requires the development of additional natural gas reserves, obtaining additional supplies from interconnecting pipelines, and the development of LNG facilities on or near our system. There have been major shifts in supply basins over the last few years, especially with regard to the development of new natural gas shale plays and declining production from conventional sources of supplies as well as declining deliveries from Canada. A prolonged decline in energy prices could cause a decrease in these development activities and could cause a decrease in the volume of reserves available for transmission and storage through our system.

Furthermore, our ability to deliver natural gas to our shippers is dependent upon their ability to purchase and deliver natural gas at various receipt points into our system. On occasion, particularly during extreme weather conditions, the natural gas delivered by our shippers at the receipt points into our system is less than the natural gas that they take at delivery points from our system. This can cause operational problems and can negatively impact our ability to meet our shippers’ demand.

With the recent rapid growth of shale production in the U.S. and the subsequent drop in natural gas prices, the need and incentive to import LNG to U.S. regasification terminals have greatly diminished. Actual U.S. LNG imports are now at their lowest levels in several years. If shale gas production continues to grow as expected, imports of LNG to the U.S. will remain at minimal levels.

The agencies that regulate us and our customers could affect our profitability.

Our business is extensively regulated by the FERC, the U.S. Department of Transportation, the U.S. Department of the Interior, the U.S. Coast Guard, the U.S. Department of Homeland Security and various state and local regulatory agencies who have the ability to issue regulations or enforcement orders that may adversely affect our profitability. The FERC regulates most aspects of our business, including the terms and conditions of services offered, our relationships with affiliates, construction and abandonment of facilities and the rates charged by our pipeline (including establishing authorized rates of return). We periodically file to adjust the rates charged to our customers. There is a risk that after a prescribed regulatory process the FERC may establish rates that are not acceptable to us and have a negative impact on us. In addition, our profitability is influenced by fluctuations in costs and our ability to recover any increases in our costs in the rates charged to our shippers. Our operating results can be negatively impacted to the extent that such costs increase in an amount greater than what we are permitted to recover in our rates or to the extent that there is a lag before we can file and obtain rate increases. For a discussion of our recent rate case filed with the FERC, see Part II, Item 8. Financial Statements and Supplementary Data, Note 7.

Our existing rates may also be challenged by complaint. The FERC commenced several proceedings against pipeline systems and storage facilities to reduce the rates they were charging their customers. There is a risk that the FERC or our customers could file similar complaints on us and that a successful complaint against our rates could have an adverse impact on us. For example, the FERC recently initiated an investigation concerning our affiliate, Bear Creek, and a successful complaint against its rates could have an adverse impact on us.

Certain of our transportation services are subject to negotiated rate contracts that may not allow us to recover our costs of providing the services.

Under FERC policy, interstate pipelines and their customers may execute contracts at a negotiated rate which may be above or below the FERC regulated recourse rate for that service. These negotiated rate contracts are generally not subject to adjustment for increased costs which could occur due to inflation, increases in the cost of capital or taxes or other factors relating to the specific facilities being used to perform the services. It is possible that costs to perform services under negotiated rate contracts will exceed the negotiated rates. Any shortfall of revenue, representing the difference between recourse rates and negotiated rates could result in either losses or lower rates of return in providing such services.

Our revenues are generated under contracts that must be renegotiated periodically.

Our revenues are generated under transportation and storage contracts which expire periodically and must be renegotiated, extended or replaced. If we are unable to extend or replace these contracts when they expire or are terminated or if we are unable to renegotiate contract terms as favorable as the existing contracts, we could suffer a material reduction in our revenues, earnings and cash flows. For example, basis differentials between receipt and delivery points on our pipeline system could remain low over time and thereby negatively impact our ability to renew contracts at rates that were previously in place. In addition, basis differentials often remain low during periods in which the price for natural gas is low, such as we are currently experiencing. Our ability to extend and replace contracts could be adversely affected by factors we cannot control, as discussed above. In addition, changes in state regulation of local distribution companies may cause them to negotiate short-term contracts or turn back their capacity when their contracts expire.

We may not succeed in an expansion of our pipeline system.

Our ability to engage in expansion projects will be subject to, among other things, approval of our member and numerous business, economic, regulatory, competitive and political uncertainties beyond our control. Therefore, we cannot assure you that any additional expansion projects will be undertaken or, if undertaken, will be successful.

The success of expansion projects may depend on, among others, the following factors:

•

other existing pipelines may provide transportation services to the area to which we are expanding;

•

other entities, upon obtaining the proper regulatory approvals, may construct new competing pipelines or increase the capacity of existing competing pipelines;

•

a competitor’s new or upgraded pipeline could offer transportation services that are more desirable to shippers because of costs, location, facilities or other factors;

•

shippers may be unwilling to sign long-term firm transportation contracts for service which would make use of a planned expansion;

•

we may be unable to obtain the requisite environmental and regulatory permits and approvals; and

•

the FERC may not grant us the required certificates for our expansion projects.

We may also require additional capital to fund any expansion project. If we fail to generate sufficient funds in the future, we may have to delay or abandon potential expansion projects which could require us to write off significant development costs. Moreover, if we are unable to obtain long term firm transportation contracts for volumes that would enable us to cover the costs of any such expansion and provide us with an acceptable rate of return, we may not proceed with such expansion. Also, a potential expansion may cost more than planned to complete and such excess cost may not be recoverable. Our inability to recover any such costs or expenditures could materially adversely affect our business, financial condition, cash flows and results of operations.

We depend on a key customer for a significant portion of our revenues and the loss of this key customer could result in a decline in our revenues.

We rely on a key customer for a significant portion of our revenues. For the year ended December 31, 2011, National Grid USA and subsidiaries accounted for approximately 14 percent of our operating revenues. The creditworthiness of our customers may be adversely impacted by negative effects in the economy, including low natural gas prices which can reduce liquidity and cash flows for some of our customers that produce natural gas. The loss of any material portion of the contracted volumes of this customer, as a result of competition, creditworthiness, inability to negotiate extensions, or replacements of contracts or otherwise, could have a material adverse effect on us. For additional information on our revenues from this customer, see Part II, Item 8. Financial Statements and Supplementary Data, Note 9.

The costs to maintain, repair and replace our pipeline system may exceed our expected levels.

Much of our pipeline infrastructure was originally constructed many years ago. The age of these assets may result in them being more costly to maintain and repair. We may also be required to replace certain facilities over time. In addition, our pipeline assets may be subject to the risk of failures or other incidents due to factors outside of our control (including due to third party excavation near our pipeline, unexpected degradation of our pipeline, erosion of soil, as well as design, construction or manufacturing defects) that could result in personal injury or property damages. Much of our pipeline system is located in populated areas which increases the level of such risks. Such incidents could also result in unscheduled outages or periods of reduced operating flows which could result in a loss of our ability to serve our customers and a loss of revenues. Although we are targeted to complete our pipeline integrity program which includes the development and use of in-line inspection tools in high consequence areas by its required completion date at the end of 2012, we will continue to incur substantial expenditures beyond 2012 relating to the integrity and safety of our pipeline. In addition, as indicated above there is a risk that new regulations or other regulatory actions associated with pipeline safety and integrity issues will be adopted that could require us to incur additional material expenditures in the future. We are also subject to inherent risks associated with our storage operations, including potential risk of gas losses and field degradation.

We do not own all of the land on which our pipeline and other related facilities are located, which could disrupt our operations.

We do not own all of the land on which our pipeline and other related facilities are located. We are subject to the risk that we do not have valid rights-of-way, that such rights-of-way may lapse or terminate, our facilities may not be properly located within the boundaries of such rights-of-way or the landowners otherwise interfere with our operations. Any loss of or interference with these rights could have a material adverse effect on us.

There are accounting principles that are unique to regulated interstate pipeline assets that could materially impact our recorded earnings.

Accounting policies for FERC regulated pipelines are in certain instances different from U.S. generally accepted accounting principles (GAAP) for nonregulated entities. For example, we are permitted to record certain regulatory assets on our balance sheet that would not typically be recorded under GAAP for nonregulated entities. In determining whether to account for regulatory assets on our pipeline, we consider various factors including regulatory changes and the impact of competition to determine the probability of recovery of these assets. Currently, we have regulatory assets recorded on our balance sheet. If we determine that future recovery is no longer probable, then we could be required to write off the regulatory assets in the future. In addition, we capitalize a carrying cost on equity funds related to our construction of long-lived assets. Equity amounts capitalized are included as other income on our income statement. To the extent that one of our expansion projects is not fully subscribed when it goes into service, we may experience a reduction in our earnings once the project is placed into service. We periodically evaluate the applicability of accounting standards

related to regulated operations, and consider factors such as regulatory changes and the impact of competition. If cost-based regulation ends or competition increases, we may have to evaluate our assets for impairment and write-off the associated regulatory assets, which could impact our future earnings.

The supply and demand for natural gas could be adversely affected by many factors outside of our control which could negatively affect us.

Our success depends on the supply and demand for natural gas. The degree to which our business is impacted by changes in supply or demand varies. For example, we are not significantly impacted in the short-term by reductions in the supply or demand for natural gas since we recover most of our revenues from reservation charges under longer-term contracts that are not dependent on the supply and demand of natural gas in the short-term. However, our business can be negatively impacted by sustained downturns in supply and demand for natural gas. One of the major factors that will impact natural gas demand will be the potential growth of natural gas in the power generation market, particularly driven by the speed and level of which coal-fired power generation is replaced with natural gas-fired power generation. One of the major factors that has been impacting natural gas supplies has been the significant growth in unconventional sources, such as from shale plays. In addition, the supply and demand for natural gas for our business will depend on many other factors outside of our control, which include, among others:

•

adverse changes in global economic conditions, including changes that negatively impact general demand for power generation and industrial loads for natural gas;

•

adverse changes in geopolitical factors and unexpected wars, terrorist activities and others acts of aggression;

•

adverse changes in domestic regulations that could impact the supply or demand for natural gas;

•

technological advancements that may drive further increases in production from natural gas shales;

•

competition from imported LNG and Canadian supplies, alternate fuels and renewable energy sources;

•

increased prices of natural gas that could negatively impact demand;

•

increased costs to transport natural gas;

•

adoption of various energy efficiency and conservation measures; and

•

perceptions of customers on the availability and price volatility of natural gas prices over the longer-term.

The price for natural gas could be adversely affected by many factors outside of our control which could negatively affect us.

Natural gas prices historically have been volatile and are likely to continue to be volatile in the future, especially given current global geopolitical and economic conditions. There is a risk that commodity prices, which are at relatively low levels at this time, could remain depressed for sustained periods. The degree to which our business is impacted by lower commodity prices varies. For example, we are not significantly impacted in the short-term by changes in natural gas prices. However, we can be negatively impacted in the long-term by sustained depression in commodity prices for natural gas, including reductions in differentials between receipt and delivery points on our system and in our ability to renew transportation contracts on favorable terms, as well as to construct new pipeline infrastructure. The price for natural gas is subject to a variety of additional factors that are outside of our control, which include, among others:

•

changes in regional and domestic supply and demand;

•

changes in basis differentials among different supply basins that can negatively impact our ability to compete with supplies from other basins, including our ability to maintain transportation revenues and renew transportation contracts in supply basins that are not as competitive as other alternatives;

•

changes in the costs of transporting natural gas;

•

increased federal and state taxes, if any, on the transportation of natural gas;

•

the price and availability of supplies of alternative energy sources; and

•

the amount of capacity available to transport natural gas.

Our business is subject to competition from third parties which could negatively affect us.

The natural gas business is highly competitive. We compete with other interstate and intrastate pipeline companies as well as gatherers and storage companies for the transportation and storage of natural gas. We also compete with suppliers of alternative energy sources used to generate electricity, such as coal and fuel oil. We frequently have one or more competitors in the supply basins and markets that we are connected to. This includes growing competition in many of the markets that we serve, including many of the markets in the northeast.

Our operations are subject to operational hazards and uninsured risks which could negatively affect us.

Our operations are subject to a number of inherent operational hazards and uninsured risks such as:

•

Adverse weather conditions, natural disasters, and/or other climate related matters – including extreme cold or heat, lightning and flooding, fires, hurricanes, tornadoes and other natural disasters. Although the potential effects of climate change on our operations (such as hurricanes, flooding, etc.) are uncertain at this time, changes in climate patterns as a result of global emissions of greenhouse gas (GHG) could also have a negative impact upon our operations in the future, particularly with regard to any of our facilities that are located in or near the Gulf of Mexico and other coastal regions.

•

Acts of aggression on critical energy infrastructure – including terrorist activity or “cyber security” events. We are subject to the ongoing risk that one of these incidents may occur which could significantly impact our business operations and/or financial results. Should one of these events occur in the future, it could impact our ability to operate or control our pipeline assets, our operations could be disrupted, property could be damaged and/or customer information could be stolen resulting in substantial loss of revenues, increased costs to respond or other financial loss, damage to reputation, increased regulation and litigation and/or inaccurate information reported from our operations to our financial applications, to our customers and to regulatory entities.

•

Other hazards – including the collision of third party equipment with our infrastructure (such as damage caused to our underground pipelines by third party excavation); explosions, pipeline failures, mechanical and process safety failures, events causing our facilities to operate below expected levels of capacity or efficiency; uncontrollable flows of natural gas, release of pollution or contaminants into the environment (including discharges of toxic gases or substances) and other environmental hazards.

Each of these risks could result in (a) damage or destruction of our facilities, (b) damages and injuries to persons and property or (c) business interruptions while damaged energy and/or technology infrastructure is repaired or replaced, each of which could cause us to suffer substantial losses. While we maintain insurance against some of these risks in amounts that we believe are reasonable, our insurance coverages have material deductibles, self-insurance levels, limits on our maximum recovery and do not cover all risks. For example, from time to time we may not carry, or may be unable to obtain on terms that we find acceptable, insurance coverage for certain exposures including, but not limited to, certain environmental exposures (including potential environmental fines and penalties), business interruption and named windstorm/hurricane exposures. The premiums and deductibles we pay for certain insurance policies are also subject to the risk of substantial increases over time that could negatively impact our financial results. In addition, we may not be able to renew existing insurance policies or procure desirable insurance on commercially reasonable terms. There is also a risk that our insurers may default on their coverage obligations or that amounts for which we are insured, or that the proceeds of such insurance will not compensate us fully for our losses. As a result, we could be adversely affected if a significant event occurs that is not fully covered by insurance.

We are subject to a complex set of laws and regulations that regulate the energy industry for which we have to incur substantial compliance and remediation costs.

Our operations are subject to a complex set of federal, state and local laws and regulations that tend to change from time to time and generally are becoming increasingly more stringent. In addition to the laws and regulations affecting our business, there are various laws and regulations that regulate various market practices in the industry, including antitrust laws and laws that prohibit fraud and manipulation in the markets in which we operate. The authority of the FTC and the FERC to impose penalties for violations of laws or regulations has generally increased over the last few years. In addition, our business is subject to laws and regulations that

govern environmental, health and safety matters. These regulations include compliance obligations for air emissions, water quality, wastewater discharge and solid and hazardous waste disposal, as well as regulations designed for the protection of human health and safety and threatened or endangered species. Compliance obligations can result in significant costs to install and maintain pollution controls and to maintain measures to address personal and process safety and protection of the environment and animal habitat near our operations. We are often obligated to obtain permits or approvals in our operations from various federal, state and local authorities, which permits and approvals (including renewals thereof) can be denied or delayed. In addition, we are exposed to fines and penalties to the extent that we fail to comply with the applicable laws and regulations, as well as the potential for limitations to be imposed on our operations. These regulations often impose remediation obligations associated with the investigation or clean-up of contaminated properties, as well as damage claims arising out of the contamination of properties or impact on natural resources. Finally, many of our assets are located and operate on federal, state, or local lands and are typically regulated by one or more federal, state or local agencies. For example, we operate assets that are located on federal lands both onshore and offshore, which are regulated by the U.S. Department of the Interior, particularly by the Bureau of Land Management and the Bureau of Ocean Energy Management, Regulation and Enforcement.

The laws and regulations (and the interpretations thereof) that are applicable to our business could materially change in the future and increase the cost of our operations or otherwise negatively impact us.

The regulatory framework affecting our business is frequently subject to change, with the risk that either new laws and regulations may be enacted or existing laws and regulations may be amended. Such new or amended laws and regulations can materially affect our operations and our financial results. In this regard, there have been proposals to adopt or amend federal, state, and local laws and regulations that could negatively impact our business, which includes among others:

•

Climate Change and other Emissions. The Environmental Protection Agency (EPA) and several state environmental agencies have adopted regulations to regulate GHG emissions. It is uncertain at this time what impact the existing and proposed regulations will have on the demand for natural gas and on our operations. This will largely depend on what regulations are ultimately adopted; how the requirements of these regulations are implemented; and incentives and subsidies provided to other fossil fuels, nuclear power and renewable energy sources. Although the EPA has adopted a tailoring rule to regulate GHG emissions, it is not expected to materially impact our existing operations until 2016. However, the tailoring rule is subject to judicial reviews and such reviews could result in the EPA being required to regulate GHG emissions at lower levels that could subject us to regulation prior to 2016. There have also been various legislative and regulatory proposals and final rules at the federal and state levels to address air emissions from power plants and industrial boilers. Although such rules and proposals will generally favor the use of natural gas over other fossil fuels such as coal, it remains uncertain what regulations will ultimately be adopted and when they will be adopted. Finally, there have been various other environmental regulatory proposals that could increase the cost of our environmental liabilities as well as increase our future compliance costs. For example, the EPA has implemented more stringent emission standards with regard to certain natural gas operations that will affect our business. It is uncertain what impact new environmental regulations might have on us until further definition is provided by the various legislative, regulatory and judicial branches. In addition, any regulations would likely increase our costs of compliance by potentially delaying the receipt of permits and other regulatory approvals; requiring us to monitor emissions, install additional equipment or modify facilities to reduce GHG and other emissions; purchase air emission credits; and utilize electric-driven compression at facilities to obtain regulatory permits and approvals in a timely manner. While we may be able to include some or all of the costs associated with our environmental liabilities and environmental compliance in the rates charged by our pipeline, our ability to recover such costs is uncertain and may depend on events beyond our control including the outcome of future rate proceedings before the FERC and the provisions of any final regulations and legislation.

•

Renewable / Conservation Legislation. There have been various legislative and regulatory proposals at the federal and state levels to provide incentives and subsidies to (a) shift more power generation to renewable energy sources and (b) support technological advances to drive less energy consumption. These incentives and subsidies could have a negative impact on natural gas consumption and thus have negative impacts on our operations and financial results.

•

Pipeline Safety. New federal legislation was enacted in December 2011 associated with pipeline safety and integrity issues, including changes that require installation of additional valves and other equipment on our pipeline and potential expansion of high consequence areas. The legislation requires the U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration to conduct various studies, which may ultimately result in additional regulations that could negatively affect our operations.

We are exposed to the credit risk of our counterparties and our credit risk management may not be adequate to protect against such risk.

We are subject to the risk that our counterparties fail to make payments to us within the time required under our contracts. Our current largest exposures are associated with shippers under long-term transportation contracts on our pipeline system. Our credit procedures and policies may not be adequate to fully eliminate counterparty credit risk. In addition, in certain situations, we may assume certain additional credit risks for competitive reasons or otherwise. If our existing or future counterparties fail to pay and/or perform, we could be adversely affected. For example, we may not be able to effectively remarket capacity or enter into new contracts at similar terms during and after insolvency proceedings involving a customer.

We are exposed to the credit and performance risk of our key contractors and suppliers.

As an owner of energy infrastructure facilities with significant capital expenditures, we rely on contractors for certain construction and we rely on suppliers for key materials, supplies and services, including steel mills and pipe and tubular manufacturers. There is a risk that such contractors and suppliers may experience credit and performance issues that could adversely impact their ability to perform their contractual obligations with us, including their performance and warranty obligations. This could result in delays or defaults in performing such contractual obligations and increased costs to seek replacement contractors, each which could adversely impact us.

We have certain contingent liabilities that could exceed our estimates.

We have certain contingent liabilities associated with litigation, regulatory and environmental matters and although we believe that we have established appropriate reserves for these matters, we could be required to accrue additional amounts in the future and these amounts could be material (see Part II, Item 8. Financial Statements and Supplementary Data, Note 7).

We have also sold assets and either retained certain liabilities or indemnified certain purchasers against future liabilities related to assets sold, including liabilities associated with environmental and other representations that we have provided. Although we believe that we have established appropriate reserves for these liabilities, we could be required to accrue additional amounts in the future and these amounts could be material.

We are subject to interest rate risks.

Although our debt capital structure has fixed interest rates, changes in market conditions, including potential increases in the deficits of foreign, federal and state governments, could have a negative impact on interest rates that could cause our future financing costs to increase. Since interest rates are at historically low levels, it is anticipated that they will increase in the future.

Risks Related to Our Affiliation with El Paso

El Paso files reports and other information with the SEC under the Securities Exchange Act of 1934, as amended. Each prospective investor should consider this information and the matters disclosed therein in addition to the matters described in this report. Such information is not included herein or incorporated by reference into this report.

We are an indirect wholly owned subsidiary of El Paso.

As an indirect wholly owned subsidiary of El Paso, subject to limitations in our credit agreements and indentures, El Paso has substantial control over:

•

our payment of dividends;

•

decisions on our financing and capital raising activities;

•

mergers or other business combinations;

•

our acquisitions or dispositions of assets; and

•

our participation in El Paso’s cash management program.

El Paso may exercise such control in its interests and not necessarily in the interests of us or the holders of our long-term debt.

Our relationship with El Paso and its financial condition subjects us to potential risks that are beyond our control.

Due to our relationship with El Paso, adverse developments or announcements concerning El Paso or its other subsidiaries could adversely affect our financial condition, even if we have not suffered any similar development. There is a risk that our or El Paso’s 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, and potential transactions. Following the announcement of El Paso’s proposed merger with KMI, Moody’s and Fitch adjusted their view of El Paso to a negative outlook, and Moody’s adjusted their view of us to a negative outlook. 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. Below are the ratings assigned to our and El Paso’s senior unsecured indebtedness at December 31, 2011.

Rating Agency

Moody’s Investor
Service

Standard &
Poor’s

Fitch Ratings

Credit Rating

TGP

Baa3

⁽¹⁾

⁽²⁾

BBB-

⁽¹⁾

El Paso

Ba3

⁽²⁾

BB-

⁽²⁾

BB+

⁽²⁾

(1)	Investment grade.

(2)	Non-investment grade.

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 any affiliated payables we have established. Our inability to recover any affiliated receivables owed to us could adversely affect our financial position and cash flows. For a further discussion of our affiliated transactions, see Part II, Item 8. Financial Statements and Supplementary Data, Note 11.

A default under El Paso’s $1.25 billion revolving 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 $1.25 billion revolving credit agreement. We are only liable, however for our borrowings under the credit agreement, which were zero at December 31, 2011. Under the credit agreement, a default by El Paso, or any other borrower, could result in the acceleration of repayment of all outstanding borrowings, including the borrowings of any non-defaulting party. The acceleration of repayments of borrowings, if any, or the inability to borrow under the credit agreement, could adversely affect our liquidity position and, in turn, our financial condition.

We may be subject to a change of control if an event of default occurs under El Paso’s credit agreement.

Under El Paso’s $1.25 billion credit agreement, our member interest 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 6.

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 El Paso is unable to retain and recruit employees such as engineers and other technical personnel, our business could be negatively impacted.

Risk Related to the Proposed Merger between Kinder Morgan and El Paso

Closing of the proposed transactions may trigger change in control provisions in certain agreements to which we are a party.

On October 16, 2011, El Paso announced a definitive agreement with KMI whereby KMI will acquire El Paso. As a result of the announcement, we were placed on negative outlook by Moody’s. During the pendency of the proposed transaction, a decrease in El Paso’s or Kinder Morgan’s perceived creditworthiness may have an adverse effect on our perceived creditworthiness, possibly resulting in a downgrade of credit ratings, tightening of credit under our existing credit facilities, increasing our borrowing costs or, upon completion of the transactions with KMI, could trigger certain change of control provisions to certain agreements to which we are a party. If we experience a credit downgrade in conjunction with the change of control and we are unable to negotiate waivers of those change of control provisions, the counterparties may exercise their rights and remedies under certain agreements, potentially requiring us to repurchase a portion of our outstanding debt. Even if we are able to negotiate waivers, the counterparties may require a fee for such waiver or seek to renegotiate the agreements on less favorable terms.

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.

ITEM 3. LEGAL PROCEEDINGS

A description of our material legal proceedings is included in Part II, Item 8. Financial Statements and Supplementary Data, Note 7, and is incorporated herein by reference.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our member interest is owned by an indirect subsidiary of El Paso and, accordingly is not publicly traded. Prior to converting to a limited liability company effective October 1, 2011, all of our common stock, par value $5 per share, was owned by the El Paso subsidiary and, accordingly, our stock was not publicly traded.

We make distributions to our member at the discretion of our member as defined in our limited liability company agreement. Prior to converting to limited liability company, we paid dividends on our common stock from time to time from legally available funds that were approved for payment by our Board of Directors. No cash distribution was paid in 2011 and no common stock dividends were declared or paid in 2009. During 2010, we utilized $334 million of our note receivable from the cash management program to pay a dividend to our parent.

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.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Overview

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. We have included a discussion in this MD&A of our business, results of operations, liquidity and capital resources, and a discussion of factors that may impact us as we operate in the future.

On October 16, 2011, El Paso announced a definitive agreement with KMI whereby KMI will acquire El Paso in a transaction that valued El Paso at approximately $38 billion (based on the KMI stock price at that date), including the assumption of debt. The transaction has been approved by each company’s board of directors but remains subject to approvals of El Paso shareholders, the FTC and other customary regulatory and other approvals. The approval of KMI shareholders will also be required, but a voting agreement has been executed by the majority of the shareholders of KMI to support the transaction. The completion of the merger may trigger change in control provisions in certain agreements (e.g. debt) to which we are a party.

Our Business

Our primary business consists of the interstate transportation and storage of natural gas. We face varying degrees of competition from other existing and proposed pipelines and LNG facilities, as well as from alternative energy sources used to generate electricity such as hydroelectric power, coal and fuel oil. Our revenues from transportation and storage services consist of the following types.


Type	Description	Percent of 2011 Revenues ⁽¹⁾
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.	80

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 (prior to our rate case settlement) based on the volume of gas actually transported, stored, injected or withdrawn. We also earn revenue from other miscellaneous sources.	20

(1) The revenue recorded for the regulatory liability adjustment of $40 million was excluded (see Results of Operations for future discussion).

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. In December 2011, the FERC approved our rate case settlement which became effective June 1, 2011. For a further discussion of our rate case settlement, see Results of Operations below. 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. In addition, our future earnings may be impacted by both positive and negative fluctuations in gas prices related to the revaluation of our fuel under or over recoveries, imbalances and system encroachments. Our tariff provides that the difference between the quantity of fuel retained and fuel used in operations and lost and unaccounted for will be flowed-through or charged to shippers. These fuel trackers remove the volumetric impact of over or under collecting fuel and lost and unaccounted for gas from our operating revenues.

We continue to manage the process of renewing expiring contracts to limit the risk of significant impacts on our revenues. Our ability to extend our existing customer contracts or remarket expiring contracted capacity is dependent on competitive alternatives, the regulatory environment at the federal, state and local levels and the market supply and demand factors at the relevant dates these contracts are extended or expire. The duration of new or renegotiated contracts will be affected by current prices, competitive conditions and judgments concerning future market trends and volatility. Subject to regulatory requirements, we attempt to recontract or remarket our capacity at the maximum rates allowed under our tariff, although at times, we enter into firm transportation contracts at amounts that are less than these maximum allowable rates to remain competitive.

Our existing contracts expire at various times and in varying amounts of throughput capacity. The weighted average remaining contract term for our active contracts is approximately four years as of December 31, 2011. Below are the contract expiration portfolio and the associated revenue expirations for our firm transportation contracts as of December 31, 2011, including those with terms beginning in 2012 or later.


	Contracted Capacity		Percent of Contracted Capacity		Reservation Revenue		Percent of Reservation Revenue
	(BBtu/d)		(In millions)
2012		2,444		28	$	100		14
2013		1,087		12		41		6
2014		1,580		18		139		20
2015		1,063		12		72		10
2016		287		3		28		4
2017 and beyond		2,369		27		322		46

Total		8,830		100	$	702		100

Results of Operations

Our management uses segment earnings before interest expense and income taxes (Segment 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 Segment EBIT is useful to investors to provide them with the same measure used by our management to evaluate our performance and so that investors may evaluate our operating results without regard to our financing methods. Segment EBIT is defined as net income adjusted for items such as (i) interest and debt expense, (ii) affiliated interest income, and (iii) income taxes. Segment EBIT may not be comparable to measures used by other companies. Additionally, Segment EBIT should be considered in conjunction with net income, income before income taxes and other performance measures such as operating income or operating cash flows. Below is a reconciliation of our Segment EBIT to net income, our throughput volumes and an analysis and discussion of our results for the year ended December 31, 2011 compared with 2010.

Operating Results:


	2011			2010
	(In millions, except for volumes)
Operating revenues	$	976		$	845
Operating expenses		(607	)		(577	)

Operating income		369			268
Earnings from unconsolidated affiliate		14			14
Other income, net		40			23

Segment EBIT		423			305
Interest and debt expense		(134	)		(150	)
Affiliated interest income, net		16			15
Income tax expense		(102	)		(67	)

Net income	$	203		$	103

Throughput volumes (BBtu/d)		6,267			5,081

Segment EBIT Analysis:


	Variance
	Operating Revenue			Operating Expense			Other		Total
	Favorable/(Unfavorable)
	(In millions)
Reservation and usage revenues	$	134		$	—		$	—	$	134
Gas not used in operations and other natural gas sales		(61	)		7			—		(54	)
Expansions		18			(3	)		15		30
Regulatory liability adjustment		40			—			—		40
Operating and general and administrative expenses		—			(32	)		—		(32	)
Other⁽¹⁾		—			(2	)		2		—

Total impact on Segment EBIT	$	131		$	(30	)	$	17	$	118

(1)	Consists of individually insignificant items.

Reservation and Usage Revenues. We experienced an overall net increase in our reservation and usage revenues of approximately $134 million for the year ended December 31, 2011 compared to 2010. The increase was primarily due to higher rates which became effective June 1, 2011 as a result of our November 2010 rate case, that is further discussed below, and higher throughput volumes due to increased supply in the Haynesville and Marcellus shale basins. Partially offsetting these favorable impacts were lower usage revenues on certain interruptible services due to lower basis differentials.

Gas Not Used in Operations and Other Natural Gas Sales. Effective June 1, 2011, we implemented a fuel volume tracker as part of our rate case filed with the FERC and as a result, we no longer recognize revenues associated with gas not used in operations which lowered our Segment EBIT by $67 million for the year ended December 31, 2011. In addition, we implemented an electric compression tracker as part of our rate case which resulted in lower electric compression expenses of $11 million. The unfavorable impacts associated with these operational activities are offset by higher reservation revenues discussed above. Prior to June 1, 2011, gas not used in operations resulted in revenues to us, which we recognized when the volumes were retained, valued at the market price specified in our tariff. During 2011, we experienced lower prices coupled with lower retained fuel volumes in excess of fuel used in operations primarily due to the shift in flow patterns, which unfavorably impacted our Segment EBIT by $10 million. Offsetting these unfavorable items were $8 million of other gas sales and $4 million of higher natural gas processing revenues recognized during 2011 compared to 2010.

Expansions. On November 1, 2011, we placed the 300 Line Project into service and as a result, our reservation revenues increased by $18 million in 2011. We also benefited from an increase in the equity portion of the allowance for funds used during construction or AFUDC related to this project and other expansion projects of $15 million in 2011, when compared to 2010. Partially offsetting these increases were depreciation and operating expenses of $3 million on the new facilities.

Below is additional information related to our significant expansion projects.

•

MPP Project. The MPP project consists of approximately 8 miles of 30-inch pipeline looping and modifications to four existing compressor stations in Pennsylvania which will provide natural gas transportation from the Marcellus shale supply area to existing delivery points on our system. Upon completion, we expect the MPP project to increase natural gas delivery capacity in the region by approximately 235 MMcf/d. All of the firm transportation capacity resulting from this project is fully subscribed with two shippers through executed precedent agreements. We filed a certificate application with the FERC in December 2011 and anticipate receiving approval in late 2012. Pending regulatory approvals, construction is expected to begin in 2013, with a November 2013 in-service date. The expected cost for this project is less than $100 million.

•

Northeast Upgrade Project. In 2010, we entered into precedent agreements with two shippers to provide 620 MMcf/d of additional firm transportation service from receipt points in the Marcellus shale basin to an interconnect in New Jersey. All of the firm transportation capacity is fully subscribed with these two shippers. This project includes approximately 40 miles of pipeline looping and approximately 22,310 horsepower of additional compression. Additionally, we are placing appurtenances in service to provide interim backhaul transport of natural gas. In March 2011, we filed an application with the FERC for certificate authorization to construct this project and we anticipate receiving approval in the first quarter of 2012. The expected cost for this project is approximately $400 million, and the project is anticipated to be placed in service in November 2013.

Regulatory Liability Adjustment. As provided by our rate case settlement in December 2011, we recorded a reduction to our net regulatory liabilities resulting from the elimination of certain regulatory assets and liabilities associated with our postretirement benefit plan and certain deferred taxes since these items were provided for under prior rate settlements and there is no funding requirement or cost recovery in our current rates for these items. For a further discussion, see Item 8. Financial Statements and Supplementary Data, Notes 4 and 7.

Operating and General and Administrative Expenses. Our operating and general and administrative expenses were higher in 2011 compared to 2010 primarily due to higher benefits and payroll costs of $16 million. Additionally, our Segment EBIT was unfavorably impacted during 2011 by $14 million of increased contractor costs due to repairs on our pipeline system.

Regulatory Matters

Rate Case. In December 2011, the FERC approved our settlement that resolved the outstanding issues arising from our general rate case filing. The settlement provides for, among other things, (i) an increase in our base tariff rates effective June 1, 2011, (ii) implementation of cost trackers for fuel and pipeline safety and greenhouse gas, (iii) significant contract extensions to October 2014, (iv) a filing requirement for our next general rate case to be effective no earlier than April 2014 but no later than November 2015, and (v) a revenue sharing mechanism with certain of our customers for certain revenues above an annual threshold. In addition, as part of the settlement, we will refund approximately $68 million to our customers by March 31, 2012. We believe our accruals established for this matter are adequate.

Assets Sale. In November 2011, the FERC issued an order approving, in part, and rejecting certain portions of our abandonment application related to our October 2010 agreement to sell certain of our offshore pipeline assets and related facilities. The sale was contingent upon receiving approval to collect in our future rates the difference between the regulatory net book value and the purchase price (loss) and the designation of certain facilities as non-jurisdictional. In December 2011, we filed a request for partial rehearing and stay of the November order. We are currently negotiating an amended purchase and sale agreement that includes additional offshore assets not included in the October 2010 agreement and we anticipate filing a new abandonment application with the FERC by mid-2012. However, the outcome of the negotiations and of the FERC’s approval of the application is currently undeterminable.

Cost and Revenue Study. In November 2011, our 50 percent owned affiliate, Bear Creek, along with other unaffiliated companies, received an order from the FERC related to an investigation into the rates charged to customers. The FERC ordered Bear Creek to file a full cost and revenue study within 75 days of the order. Bear Creek filed the cost and revenue study in January 2012 and the outcome of the proceeding is not expected to be material to our results of operations.

Interest and Debt Expense

Interest and debt expense for the year ended December 31, 2011, was $16 million lower than in 2010 due to an increase in capitalized AFUDC related to debt on our 300 Line Project and lower accruals related to our polychlorinated biphenyls (PCB) refund obligations. Additionally, we received a favorable franchise tax settlement in the third quarter of 2011 and as a result our accrued interest related to these taxes was lower compared to 2010.

Affiliated Interest Income, Net

The following table shows the average advances due from El Paso and the average short-term interest rates for the year ended December 31:


	2011			2010
	(In millions, except for rates)
Average advance due from El Paso	$	844		$	1,015
Average short-term interest rate		2.0	%		1.5	%

Income Taxes

Effective October 1, 2011, we changed our tax entity status from a corporation to a limited liability company. As a single member limited liability company, we will continue to record income taxes on a separate return basis and reflect current and deferred income taxes in our financial statements.

Our effective tax rates of 33 percent and 39 percent for the years ended December 31, 2011 and 2010 were different than the statutory rate of 35 percent due to the effect of state income taxes. During the fourth quarter of 2011, we recorded a $14 million deferred state tax benefit to correct the estimated effective tax rate applicable to differences in financial statement and tax bases of property, plant and equipment. For a reconciliation of the statutory rate to the effective tax rates, see Item 8. Financial Statements and Supplementary Data, Note 2.

Liquidity and Capital Resources

Our primary sources of liquidity are cash flows from operating activities and amounts available to us under El Paso’s cash management program while our primary uses of cash are for working capital, capital expenditures and debt service requirements. At December 31, 2011, we had a note receivable from El Paso of approximately $519 million. We do not intend to settle any amounts owed under this note within the next twelve months and therefore, classified it as non-current on our balance sheet. See Item 8. Financial Statements and Supplementary Data, Note 11 for a further discussion of El Paso’s cash management program.

For the year ended December 31, 2011 compared with 2010, our operating cash flows increased by $113 million primarily due to an increase in our reservation revenues as a result of higher tariff rates effective June 1, 2011. Partially offsetting these cash inflows were settlements of refund obligations associated with our PCB liability.

Our cash capital expenditures for the year ended December 31, 2011 are listed below.


	(In millions)
Expansions	$	480
Maintenance		158
Other⁽¹⁾		45

Total	$	683

(1)	Relates to building renovations at our corporate facilities prior to our distribution of these facilities to our parent in October 2011.

Although financial market conditions have improved, continued volatility in the financial markets could impact our longer-term access to capital for future growth projects as well as the cost of such capital. Additionally, although the impacts are difficult to quantify at this point, a prolonged recovery of the global economy could have adverse impacts on natural gas consumption and demand. However, we believe our exposure to changes in natural gas consumption and demand is 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.

We believe we have adequate liquidity available to us to meet our capital requirements and our existing operating needs through cash flows from operating activities and amounts available to us under El Paso’s cash management program. In addition, we are eligible to borrow amounts available under El Paso’s $1.25 billion revolving credit agreement and are only liable for amounts we directly borrow. During the first half of 2011, El Paso refinanced this credit facility and its collateral restrictions under the facility were modified providing El Paso’s master limited partnership the ability to acquire up to 100 percent ownership interests in us or another El Paso subsidiary, or some combination thereof. This credit facility provides for an elimination of collateral support upon El Paso achieving investment grade status by one of the rating agencies. Additionally, our cost to borrow under the El Paso credit facility has increased to LIBOR plus 2.25 percent. As of December 31, 2011, El Paso had approximately $620 million of capacity remaining and available to us and our affiliates under this credit agreement, and none of the amount outstanding under the facility was issued or

borrowed by us. For a further discussion of the credit facility, see Item 8. Financial Statements and Supplementary Data, Note 6. While we do not anticipate a need to directly access the financial markets in 2012 for any of our operating activities or expansion capital needs based on liquidity available to us, market conditions may impact our or El Paso’s ability to act opportunistically. Our future plans could also be impacted by the completion of El Paso’s announced acquisition by KMI.

For further detail on our risk factors including potential adverse general economic conditions including our ability to access financial markets which could impact our operations and liquidity, see Part I, Item 1A. Risk Factors.

Commitments and Contingencies

For a further discussion of our commitments and contingencies, see Item 8. Financial Statements and Supplementary Data, Note 7, which is incorporated herein by reference.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to the risk of changing interest rates. At December 31, 2011, we had an interest bearing note receivable from El Paso of approximately $519 million, with a variable interest rate of 2.5% that is due upon demand. While we are exposed to changes in interest income based on changes to the variable interest rate, the fair value of this note receivable approximates the carrying value due to the note being due on demand and the market-based nature of the interest rate.

The table below shows the carrying value, the related weighted-average effective interest rates on our non-affiliated fixed rate long-term debt securities and the estimated fair value of these securities which is based on quoted market prices for the same or similar issues.


	December 31, 2011										December 31, 2010
	Expected Fiscal Year of Maturity of Carrying Amounts								Fair		Carrying		Fair
	2012-2016			Thereafter			Total		Value		Amount		Value
	(In millions, except for rates)
Liabilities:
Long-term debt—fixed rate	$	243		$	1,525		$	1,768	$	2,096	$	1,851	$	2,071
Average effective interest rate		9.0	%		7.6	%

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 the Securities and Exchange Commission (SEC) rules adopted under the Securities Exchange Act of 1934, as amended. Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. It consists of policies and procedures that:

•

pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;

•

provide reasonable assurance that transactions are recorded as necessary to permit preparation of the financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and

•

provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements.

Under the supervision and with the participation of management, including the President and Chief Financial Officer, we made an assessment of the effectiveness of our internal control over financial reporting as of December 31, 2011. In making this assessment, we used the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation, we concluded that our internal control over financial reporting was effective as of December 31, 2011.

Report of Independent Registered Public Accounting Firm

The Member of Tennessee Gas Pipeline Company, L.L.C.

We have audited the accompanying consolidated balance sheets of Tennessee Gas Pipeline Company, L.L.C. (the Company) as of December 31, 2011 and 2010, and the related consolidated statements of income and comprehensive income, member’s equity/stockholder’s equity, and cash flows for each of the three years in the period ended December 31, 2011. 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, 2011. 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, L.L.C. at December 31, 2011 and 2010, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2011, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

/s/ Ernst & Young LLP

Houston, Texas

February 27, 2012

TENNESSEE GAS PIPELINE COMPANY, L.L.C.

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(In millions)


	Year Ended December 31,
	2011			2010			2009
Operating revenues	$	976		$	845		$	933

Operating expenses
Operation and maintenance		353			328			371
Depreciation and amortization		198			196			187
Taxes, other than income taxes		56			53			54

		607			577			612

Operating income		369			268			321
Earnings from unconsolidated affiliate		14			14			11
Other income, net		40			23			13
Interest and debt expense		(134	)		(150	)		(155	)
Affiliated interest income, net		16			15			16

Income before income taxes		305			170			206
Income tax expense		102			67			79

Net income		203			103			127

Other comprehensive income
Unrealized actuarial gains on postretirement benefit obligations (net of income taxes of $2 in 2011)		4			—			—

Comprehensive income	$	207		$	103		$	127

See accompanying notes.

TENNESSEE GAS PIPELINE COMPANY, L.L.C.

CONSOLIDATED BALANCE SHEETS

(In millions, except share amounts)


	December 31,
	2011		2010
ASSETS
Current assets
Cash and cash equivalents	$	—	$	—
Accounts and note receivable
Customer, net of allowance		8		24
Affiliates		20		378
Other		76		51
Materials and supplies		57		44
Deferred income taxes		52		43
Other		10		5

Total current assets		223		545

Property, plant and equipment, at cost		5,158		4,951
Less accumulated depreciation and amortization		1,002		1,056

		4,156		3,895
Additional acquisition cost assigned to utility plant, net		1,883		1,923

Total property, plant and equipment, net		6,039		5,818

Other long-term assets
Note receivable from affiliate		519		617
Investment in unconsolidated affiliate		57		56
Other		84		76

		660		749

Total assets	$	6,922	$	7,112

LIABILITIES AND MEMBER’S EQUITY/STOCKHOLDER’S EQUITY
Current liabilities
Accounts payable
Trade	$	80	$	90
Affiliates		45		38
Other		64		57
Current maturities of long-term debt		—		86
Taxes payable		23		23
Contractual deposits		29		28
Asset retirement obligations		22		28
Accrued interest		32		33
Accrued liabilities		73		13
Regulatory liabilities		40		78
Other		8		25

Total current liabilities		416		499

Long-term debt, less current maturities		1,768		1,765

Other long-term liabilities
Deferred income taxes		1,514		1,422
Regulatory liabilities		11		90
Other		30		35

		1,555		1,547

Commitments and contingencies (Note 7)
Member’s equity/stockholder’s equity
Common stock, par value $5 per share; 300 shares authorized; 208 shares issued and outstanding in 2010		—		—
Additional paid-in capital		—		2,209
Retained earnings		—		1,092
Member’s equity		3,179		—
Accumulated other comprehensive income		4		—

Total member’s equity/stockholder’s equity		3,183		3,301

Total liabilities and member’s equity/stockholder’s equity	$	6,922	$	7,112

See accompanying notes.

TENNESSEE GAS PIPELINE COMPANY, L.L.C.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)


	Year Ended December 31,
	2011			2010			2009
Cash flows from operating activities
Net income	$	203		$	103		$	127
Adjustments to reconcile net income to net cash from operating activities
Depreciation and amortization		198			196			187
Deferred income tax expense		85			72			2
Earnings from unconsolidated affiliate, adjusted for cash distributions		(1	)		8			2
Other non-cash income items		(70	)		(16	)		(1	)
Asset and liability changes
Accounts receivable		2			42			17
Change in deferred purchase price from accounts receivable sales		(28	)		(35	)		—
Accounts payable		8			(41	)		36
Income taxes payable		1			(73	)		17
Other asset changes		7			(17	)		(25	)
Other liability changes		(40	)		13			6

Net cash provided by operating activities		365			252			368

Cash flows from investing activities
Capital expenditures		(683	)		(321	)		(361	)
Net change in notes receivable from affiliates		400			390			(232	)
Return of capital from investment in unconsolidated affiliate		—			15			—
Other		4			(2	)		(9	)

Net cash provided by (used in) investing activities		(279	)		82			(602	)

Cash flows from financing activities
Net proceeds from issuance of long-term debt		—			—			234
Payments to retire long-term debt		(86	)		—			—
Dividend paid to parent		—			(334	)		—

Net cash provided by (used in) financing activities		(86	)		(334	)		234

Net change in cash and cash equivalents		—			—			—
Cash and cash equivalents
Beginning of period		—			—			—

End of period	$	—		$	—		$	—

Supplemental cash flow information
Interest paid, net of amounts capitalized	$	128		$	133		$	130
Income tax payments		12			78			60

See accompanying notes.

TENNESSEE GAS PIPELINE COMPANY, L.L.C.

CONSOLIDATED STATEMENTS OF MEMBER’S EQUITY/STOCKHOLDER’S EQUITY

(In millions, except share amounts)


	Common Stock					Additional Paid-in			Retained			Note Receivable from			Total Stockholder’s			Member’s			Accumulated Other Comprehensive		Total Member’s
	Shares			Amount		Capital			Earnings			Affiliate			Equity			Equity			Income		Equity
January 1, 2009		208		$	—	$	2,209		$	1,196		$	(334	)	$	3,071		$	—		$	—	$	—
Net income										127						127

December 31, 2009		208			—		2,209			1,323			(334	)		3,198			—			—		—
Net income										103						103
Reclassification of note receivable from affiliate (Note 11)													334			334
Dividend paid to parent										(334	)					(334	)

December 31, 2010		208			—		2,209			1,092			—			3,301			—			—		—
Net income
For the nine months ended September 30, 2011										125						125
For the three months ended December 31, 2011																			78					78
Conversion to limited liability company (October 1, 2011)		(208	)				(2,209	)		(1,217	)					(3,426	)		3,426					3,426
Non-cash distribution to parent (Note 11)																			(325	)				(325	)
Other comprehensive income																						4		4

December 31, 2011		—		$	—	$	—		$	—		$	—		$	—		$	3,179		$	4	$	3,183

See accompanying notes.

TENNESSEE GAS PIPELINE COMPANY, L.L.C.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Basis of Presentation and Significant Accounting Policies

Basis of Presentation

Our consolidated financial statements are prepared in accordance with U.S. generally accepted accounting principles (GAAP) and include the accounts of all consolidated subsidiaries after the elimination of intercompany accounts and transactions. Our financial statements for prior periods include reclassifications that were made to conform to the current year presentation, none of which impacted our reported net income, stockholder’s equity or cash flows from operating activities.

Principles of Consolidation

We consolidate entities when we have the ability to control or direct the operating and financial decisions of the entity or when we have a significant interest in the entity that gives us the ability to direct the activities that are significant to that entity. The determination of our ability to control, direct or exert significant influence over an entity involves the use of judgment. We apply the equity method of accounting where we can exert significant influence over, but do not control or direct the policies, decisions or activities of an entity. We use the cost method of accounting where we are unable to exert significant influence over the entity.

Use of Estimates

The preparation of our financial statements requires the use of estimates and assumptions that affect the amounts we report as assets, liabilities, revenues and expenses and our disclosures in these financial statements. Actual results can, and often do, differ from those estimates.

Regulated Operations

Our natural gas pipeline and storage operations are subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC) and follow the Financial Accounting Standards Board’s accounting standards for regulated operations. Under these standards, we record regulatory assets and liabilities that would not be recorded for non-regulated entities. Regulatory assets and liabilities represent probable future revenues or expenses associated with certain charges or credits that are expected to be recovered from or refunded to customers through the rate making process. Items to which we may record a regulatory asset or liability include certain postretirement employee benefit plan costs in periods prior to 2011 when our rate case was settled, loss on reacquired debt, taxes related to an equity return component on regulated capital projects and certain costs related to gas not used in operations and other costs included in, or expected to be included in, future rates. For further details of our regulatory assets and liabilities, see Note 4.

Cash and Cash Equivalents

We consider short-term investments with an original maturity of less than three months to be cash equivalents.

Allowance for Doubtful Accounts

We establish provisions for losses on accounts receivable and for natural gas imbalances due from shippers and operators if we determine that we will not collect all or part of the outstanding balance. We regularly review collectability and establish or adjust our allowance as necessary using the specific identification method.

Materials and Supplies

We value materials and supplies at the lower of cost or market value with cost determined using the average cost method.

Natural Gas Imbalances

Natural gas imbalances occur when the amount of natural gas delivered from or received by a pipeline system or storage facility differs from the contractual amount to be delivered or received. We value these imbalances due to or from shippers and operators utilizing current index prices. Imbalances are settled 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 either the fair value of the assets acquired or the cost to the entity that first placed the asset in service. For assets we construct, we capitalize direct costs, such as labor and materials, and indirect costs, such as overhead, interest and an equity return component, as allowed by the FERC. We capitalize major units of property replacements or improvements and expense minor items.

We use the composite (group) method to depreciate regulated property, plant and equipment. Under this method, assets with similar useful lives and other characteristics are grouped and depreciated as one asset. We apply the depreciation rate approved in our rate settlements to the total cost of the group until its net book value equals its salvage value. We re-evaluate depreciation rates each time we file with the FERC for an increase or decrease in our transportation and storage rates. Currently, our depreciation rates vary from one percent to 25 percent per year.

When we retire regulated property, plant and equipment, we charge accumulated depreciation and amortization for the original cost of the assets in addition to the cost to remove, sell or dispose of the assets, less their salvage value. We do not recognize a gain or loss unless we sell an entire operating unit, as determined by the FERC. We include gains or losses on dispositions of operating units in operation and maintenance expense in our income statements. For properties not subject to regulation by the FERC, we reduce property, plant and equipment for its original cost, less accumulated depreciation and salvage value with any remaining gain or loss recorded in income.

Included in our property balances are additional acquisition costs, which represent the excess purchase costs associated with purchase business combinations allocated to us. These costs are amortized on a straight-line basis and are not recoverable in our rates under current FERC policies.

Also included in our property balances are base gas and working gas at our storage facilities. We periodically evaluate natural gas volumes at our storage facilities for gas losses. When events or circumstances indicate a loss has occurred, we recognize a loss in our income statement or defer the loss as a regulatory asset on our balance sheet if deemed probable of recovery through future rates charged to our customers.

We capitalize a carrying cost (an allowance for funds used during construction or AFUDC) on debt and equity funds related to the construction of long-lived assets. This carrying cost consists of a return on the investment financed by debt and a return on the investment financed by equity. The debt portion is calculated based on the average cost of debt. Interest costs capitalized are included as a reduction to interest and debt expense on our income statements. The equity portion is calculated based on the most recent FERC approved rate of return. Equity amounts capitalized are included in other income on our income statements.

Asset and Investment Divestitures/Impairments

We evaluate assets and investments for impairment when events or circumstances indicate that their carrying values may not be recovered. These events include market declines that are believed to be other than temporary, changes in the manner in which we intend to use a long-lived asset, decisions to sell an asset or investment and adverse changes in the legal or business environment such as adverse actions by regulators. If an event occurs, we evaluate the recoverability of our carrying value based on either (i) the long-lived asset’s ability to generate future cash flows on an undiscounted basis or (ii) the fair value of the investment in an unconsolidated affiliate. If an impairment is indicated, or if we decide to sell a long-lived asset or group of assets, we adjust the carrying value of the asset downward, if necessary, to its estimated fair value. Our fair value estimates are generally based on assumptions market participants would use, including market data obtained through the sales process or an analysis of expected discounted cash flows.

Revenue Recognition

Our revenues are primarily generated from natural gas transportation and storage services. Revenues for all services are based on the thermal quantity of gas delivered or subscribed at a price specified in the contract. For our transportation and storage services, we recognize reservation revenues on firm contracted capacity ratably over the contract period. For interruptible or volumetric-based services, we record revenues when physical deliveries of natural gas are made at the agreed upon delivery point or when gas is injected or withdrawn from the storage facility. For contracts with step-up or step-down rate provisions that are not related to changes in levels of service, we recognize reservation revenues ratably over the contract life. Prior to the implementation of a fuel volume tracker effective June 1, 2011 as part of our rate case filed with the FERC, gas not used in operations was based on the volumes of natural gas we were allowed to retain relative to the amounts of natural gas we used for operating purposes. We recognized revenue on gas not used in operations from our shippers when we retained the volumes at the market price required under our tariff. We are subject to FERC regulations and, as a result, revenues we collect may be subject to refund in a rate proceeding. We establish reserves for these potential refunds.

Environmental Costs and Other Contingencies

Environmental Costs. We record liabilities at their undiscounted amounts on our balance sheet as other current and long-term liabilities when environmental assessments indicate that remediation efforts are probable and the costs can be reasonably estimated. Estimates of our liabilities are based on currently available facts, existing technology and presently enacted laws and regulations, taking into consideration the likely effects of other societal and economic factors, and include estimates of associated legal costs. These amounts also consider prior experience in remediating contaminated sites, other companies’ clean-up experience and data released by the Environmental Protection Agency (EPA) or other organizations. Our estimates are subject to revision in future periods based on actual costs or new circumstances. We capitalize costs that benefit future periods and we recognize a current period charge in operation and maintenance expense when clean-up efforts do not benefit future periods.

We evaluate any amounts paid directly or reimbursed by government sponsored programs and potential recoveries or reimbursements of remediation costs from third parties, including insurance coverage, separately from our liability. Recovery is evaluated based on the creditworthiness or solvency of the third party, among other factors. When recovery is assured, we record and report an asset separately from the associated liability on our balance sheet.

Other Contingencies. We recognize liabilities for other contingencies when we have an exposure that indicates it is both probable that a liability has been incurred and the amount of loss can be reasonably estimated. Where the most likely outcome of a contingency can be reasonably estimated, we accrue a liability for that amount. Where the most likely outcome cannot be estimated, a range of potential losses is established and if no one amount in that range is more likely than any other, the low end of the range is accrued.

Income Taxes

El Paso maintains a tax accrual policy to record both regular and alternative minimum taxes for companies included in its consolidated federal and state income tax returns. The policy provides, among other things, that (i) each company in a taxable income position will accrue a current expense equivalent to its federal and state income taxes, and (ii) each company in a tax loss position will accrue a benefit to the extent its deductions, including general business credits, can be utilized in the consolidated returns. El Paso pays all consolidated U.S. federal and state income taxes directly to the appropriate taxing jurisdictions and, under a separate tax billing agreement, El Paso may bill or refund its subsidiaries for their portion of these income tax payments. Prior to our conversion to a limited liability company which is further discussed below, we filed and paid taxes directly to certain state taxing authorities.

Effective October 1, 2011, we changed our tax entity status from a corporation to a limited liability company. As a single member limited liability company, we continue to record federal income taxes on a separate return basis. Pursuant to El Paso’s policy, we record current income taxes based on our taxable income and we provide for deferred income taxes to reflect estimated future tax payments and receipts. Deferred taxes represent the tax impacts of differences between the financial statement and tax bases of assets and liabilities and carryovers at each year end. We account for tax credits under the flow-through method, which reduces the provision for income taxes in the year the tax credits first become available. We reduce deferred tax assets by a valuation allowance when, based on our estimates, it is more likely than not that a portion of those assets will not be realized in a future period. The estimates utilized in the recognition of deferred tax assets are subject to revision, either up or down, in future periods based on new facts or circumstances.

Accounting for Asset Retirement Obligations

We record a liability for legal obligations associated with the replacement, removal or retirement of our long-lived assets in the period the obligation is incurred and estimable. Our asset retirement liabilities are initially recorded at their estimated fair value with a corresponding increase to property, plant and equipment. This increase in property, plant and equipment is then depreciated over the useful life of the asset to which that liability relates. An ongoing expense is recognized for changes in the value of the liability as a result of the passage of time, which we record as depreciation and amortization expense in our income statement. We have the ability to recover certain of these costs from our customers and have recorded an asset (rather than expense) associated with the accretion of the liabilities described above.

Postretirement Benefits

We maintain a postretirement benefit plan covering certain of our former employees. This plan requires us to make contributions to fund the benefits to be paid under the plan. These contributions are invested until the benefits are paid to plan participants. The net benefit cost of this plan is recorded in our income statement and is a function of many factors including benefits earned during the year by plan participants (which is a function of factors such as the level of benefits provided under the plan, actuarial assumptions and the passage of time), expected returns on plan assets and amortization of certain deferred gains and losses.

In accounting for our postretirement benefit plan, we record an asset or liability based on the over funded or under funded status of the plan. Any deferred amounts related to unrecognized gains and losses or changes in actuarial assumptions are recorded in accumulated other comprehensive income, a component of member’s equity, until those gains and losses are recognized in the income statement. For a further discussion of our policy with respect to our postretirement benefit plan, see Note 8.

2. Income Taxes

Components of Income Tax Expense. The following table reflects the components of income tax expense included in net income for each of the three years ended December 31.


	2011			2010			2009
	(In millions)
Current
Federal	$	13		$	(8	)⁽¹⁾	$	76
State		4			3			1

		17			(5	)		77

Deferred
Federal		96			64			(7	)
State		(11	)		8			9

		85			72			2

Total income tax expense	$	102		$	67		$	79

(1)	During 2010, we utilized a portion of our net operating loss carryover which resulted in a tax benefit for the year ended December 31, 2010.

Effective Tax Rate Reconciliation. Our income tax expense differs from the amount computed by applying the statutory federal income tax rate of 35 percent for the following reasons for each of the three years ended December 31:


	2011			2010			2009
	(In millions, except for rates)
Income tax expense at the statutory federal rate of 35%	$	107		$	60		$	72
State income taxes, net of federal income tax effect		(5	)		7			7

Income tax expense	$	102		$	67		$	79

Effective tax rate		33	%		39	%		38	%

During the fourth quarter of 2011, we recorded a $14 million deferred state tax benefit to correct the estimated effective tax rate applicable to differences in financial statement and tax bases of property, plant and equipment.

Deferred Tax Assets and Liabilities. The following are the components of our net deferred tax liability at December 31:


	2011		2010
	(In millions)
Deferred tax liabilities
Property, plant and equipment	$	1,787	$	1,500
Other		20		6

Total deferred tax liability		1,807		1,506

Deferred tax assets
Net operating loss and tax credit carryovers
U.S. Federal		250		26
State		30		19
Other liabilities		65		81

Total deferred tax asset		345		126

Net deferred tax liability	$	1,462	$	1,380

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, 2011:


	2012		2013-2016		2017-2021		2022-2031		Total
			(In millions)
U.S. federal NOL	$	—	$	—	$	63	$	652	$	715
State NOL		9		165		235		322		731

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 Internal Revenue Service regulations.

Unrecognized Tax Benefits. El Paso files consolidated U.S. federal and certain state tax returns which include our taxable income. Prior to our conversion to a limited liability company, we filed and paid taxes directly to certain 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 2001 and U.S. income tax examinations for years prior to 2007. For years in which our returns are still subject to review, our unrecognized tax benefits could increase or decrease our income tax expense and our effective income tax rates as these matters are finalized. We are currently unable to estimate the range of potential impacts the resolution of any contested matters could have on our financial statements. The following table shows the change in our unrecognized tax benefits:


	2011		2010
	(In millions)
Amount at January 1	$	18	$	16
Addition:
Tax positions taken in prior years		—		6
Tax positions taken in current year		1		—
Reduction:
Settlements with taxing authorities		—		(4	)

Amount at December 31	$	19	$	18

As of December 31, 2011 and 2010, approximately $16 million and $15 million (net of federal tax benefits) of unrecognized tax benefits and associated interest and penalties would affect our income tax expense and our effective income tax rate if recognized in future periods. While the amount of our unrecognized tax benefits could change in the next twelve months, we do not expect this change to have a significant impact on our results of operations or financial position.

We classify interest and penalties related to unrecognized tax benefits as income taxes in our financial statements. As of December 31, 2011 and 2010, we had liabilities for interest and penalties related to our unrecognized tax benefits of approximately $4 million. During 2011, 2010 and 2009, we accrued less than $1 million of interest. In addition, during 2010 we settled a state tax audit which generated a reduction of $3 million to the interest and penalties liability related to our unrecognized tax benefits.

3. Financial Instruments

At December 31, 2011 and 2010, the carrying amounts of cash and cash equivalents and trade receivables and payables represent fair value because of the short-term nature of these instruments. At December 31, 2011 and 2010, we had an interest bearing note receivable from El Paso of approximately $519 million and $976 million due upon demand, with a variable interest rate of 2.5% and 1.5%. While we are exposed to changes in interest income based on changes to the variable interest rate, the fair value of this note receivable approximates the carrying value due to the note being due on demand and the market-based nature of the interest rate.

In addition, the carrying amounts of our long-term debt and their estimated fair values, which are primarily based on quoted market prices for the same or similar issues (Level 2 fair value measurement), are as follows at December 31:


	2011				2010
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)
Long-term debt, including current maturities	$	1,768	$	2,096	$	1,851	$	2,071

4. Regulatory Assets and Liabilities

Our regulatory asset and liability balances are recoverable or reimbursable over various periods. Below are the details of our regulatory assets and liabilities at December 31:


	2011		2010
	(In millions)
Current regulatory assets⁽¹⁾	$	7	$	3

Non-current regulatory assets
Taxes on capitalized funds used during construction		50		38
Postretirement benefits		—		2
Other		5		6

Total non-current regulatory assets⁽¹⁾		55		46

Total regulatory assets	$	62	$	49

Current regulatory liabilities
Environmental	$	40	$	78

Total current regulatory liabilities		40		78

Non-current regulatory liabilities
Environmental		6		44
Postretirement benefits		—		35
Other ⁽²⁾		5		11

Total non-current regulatory liabilities		11		90

Total regulatory liabilities	$	51	$	168

(1)	Included in other current and long-term assets on our balance sheets.

(2)

As part of our rate case settlement in December 2011, we were required to eliminate our regulatory liability associated with certain deferred taxes. We reflected this adjustment as a net increase to our operating revenues of approximately $11 million. For a further discussion of our rate case, see Note 7.

The significant regulatory assets and liabilities include:

Taxes on Capitalized Funds Used During Construction. Represents the regulatory asset balance established to offset the deferred tax for the equity component of AFUDC. Taxes on capitalized funds used during construction and the offsetting deferred income taxes are included in the rate base and are recovered over the depreciable lives of the long-lived asset to which they relate.

Postretirement Benefits. These balances represented unrecognized gains and losses or changes in actuarial assumptions related to our postretirement benefit plan and differences in the postretirement benefit related amounts expensed and the amounts recovered in rates. As part of our rate case settlement in December 2011, we were required to reduce these balances. As such, we reclassified $4 million (net of income taxes of $2 million) to accumulated other comprehensive income which represented the unrecognized gain on our postretirement benefit plan at the time of the settlement. In addition, we recorded an increase to our operating revenues of approximately $29 million related to the remaining other postretirement benefit related costs. For a further discussion of our rate case, see Note 7.

Environmental. Includes amounts collected, substantially in excess of certain polychlorinated biphenyls (PCB) environmental remediation costs incurred to date, through a surcharge to our customers under a settlement approved by the FERC in November of 1995. This environmental liability is not deducted from the rate base on which we are allowed to earn a return. For a further discussion of the PCB matter, see Note 7.

5. Property, Plant and Equipment

Additional Acquisition Costs. Included in our property balances are additional acquisition costs assigned to utility plant, which represent the excess of allocated purchase costs over the historical costs of the facilities. At December 31, 2011 and 2010, additional acquisition costs assigned to utility plant was approximately $2.4 billion and accumulated depreciation was approximately $498 million and $458 million, respectively. These additional acquisition costs are being amortized on a straight-line basis over 62 years and are not recoverable in our rates under current FERC policies. Our amortization expense related to additional acquisition costs assigned to utility plant was approximately $40 million, $40 million and $39 million for the years ended December 31, 2011, 2010 and 2009.

Capitalized Costs During Construction. Interest costs capitalized are included as a reduction to interest and debt expense on our income statements and were $12 million, $6 million and $3 million during the years ended December 31, 2011, 2010 and 2009. Equity amounts capitalized are included in other income on our income statements and were $22 million, $13 million and $6 million (exclusive of taxes) during the years ended December 31, 2011, 2010 and 2009.

Construction Work-In-Progress. At December 31, 2011 and 2010, we had $134 million and $406 million of construction work-in-progress included in our property, plant and equipment.

Asset Retirement Obligations. We have legal obligations associated with the retirement of our natural gas pipeline, transmission facilities and storage wells. We have obligations to plug storage wells when we no longer plan to use them and when we abandon them. Our legal obligations associated with our natural gas transmission facilities primarily involve purging, sealing and possibly removing the facilities if they are abandoned. We also have obligations to remove hazardous materials associated with our natural gas transmission facilities if they are ever demolished or replaced. We continue to evaluate our asset retirement obligations and future developments could impact the amounts we record.

Where we can reasonably estimate the asset retirement obligation, we accrue a liability based on an estimate of the timing and amount of settlement. In estimating our asset retirement obligations, we utilize several assumptions, including a projected inflation rate of 2.5 percent, and credit-adjusted discount rates that currently range from five to 12 percent based on when the liabilities were recorded. We record changes in these estimates based on changes in the expected amount and timing of payments to settle our obligations. We intend on operating and maintaining our natural gas pipeline and storage systems as long as supply and demand for natural gas exists, which we expect for the foreseeable future. Therefore, we believe that we cannot reasonably estimate the asset retirement obligation for the substantial majority of our natural gas pipeline and storage system assets because these assets have indeterminate lives.

The net asset retirement obligation reported on our balance sheets in current and other long-term liabilities, and the changes in the net liability for the years ended December 31 were as follows:


	2011			2010
	(In millions)
Net asset retirement obligation at January 1	$	29		$	91
Liabilities settled		(2	)		(26	)
Accretion expense		—			2
Liabilities incurred		—			5
Changes in estimate⁽¹⁾		(4	)		(43	)

Net asset retirement obligation at December 31⁽²⁾	$	23		$	29

(1)	2010 amount reflects updated information received on our hurricane related asset retirement obligations.

(2)	For the years ended December 31, 2011 and 2010, approximately $22 million and $28 million of this amount are reflected as current liabilities on our balance sheets.

6. Debt and Credit Facilities

Debt. Our long-term debt consisted of the following at December 31:


	2011		2010
	(In millions)
6.0% Debentures due December 2011	$	—	$	86
8.0% Notes due February 2016		250		250
7.5% Debentures due April 2017		300		300
7.0% Debentures due March 2027		300		300
7.0% Debentures due October 2028		400		400
8.375% Notes due June 2032		240		240
7.625% Debentures due April 2037		300		300

		1,790		1,876
Less: Current maturities		—		86
Unamortized discount		22		25

Total long-term debt	$	1,768	$	1,765

Credit Facility. We are eligible to borrow amounts available under El Paso’s $1.25 billion revolving credit agreement and are only liable for amounts we directly borrow. During the first half of 2011, El Paso refinanced this credit facility and its collateral restrictions were modified providing El Paso’s master limited partnership the ability to acquire up to 100 percent ownership interests in us or another El Paso subsidiary, or some combination thereof. This credit facility provides for an elimination of collateral support upon El Paso achieving investment grade status by one of the rating agencies. Additionally, our current cost to borrow under the El Paso credit facility has increased to LIBOR plus 2.25 percent. As of December 31, 2011, El Paso had approximately $620 million of capacity remaining and available to us and our affiliates under this credit agreement, and none of the amount outstanding under the facility was issued or borrowed by us. Our member interest and the common stock of another El Paso subsidiary are pledged as collateral under the credit agreement.

Under El Paso’s $1.25 billion revolving 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, 2011, we were in compliance with our debt-related covenants.

7. Commitments and Contingencies

Legal Proceedings

We and our affiliates are named defendants in numerous legal proceedings and claims that arise in the ordinary course of our business. For each of these matters, we evaluate the merits of the case or claim, our exposure to the matter, possible legal or settlement strategies and the likelihood of an unfavorable outcome. If we determine that an unfavorable outcome is probable and can be estimated, we establish the necessary accruals. While the outcome of these matters cannot be predicted with certainty, and there are still uncertainties related to the costs we may incur, based upon our evaluation and experience to date, we believe we have established appropriate reserves for these matters. It is possible, however, that new information or future developments could require us to reassess our potential exposure related to these matters and adjust our accruals accordingly, and these adjustments could be material. At December 31, 2011, we had approximately $2 million accrued for our outstanding legal proceedings, which has not been reduced by $2 million of related insurance receivables.

Environmental Matters

We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require us to remove or remedy the effect of the disposal or release of specified substances at current and former operating sites. At December 31, 2011 and 2010, our accrual was approximately $5 million and $4 million for expected remediation costs and associated onsite, offsite and groundwater technical studies and for related environmental legal costs; however, we estimate that our exposure could be as high as $9 million at December 31, 2011. Our accrual at December 31, 2011 includes approximately $1 million for environmental contingencies related to properties we previously owned.

Our environmental remediation projects are in various stages of completion. Our recorded liabilities reflect our current estimates of amounts we will spend to remediate these sites. However, depending on the stage of completion or assessment, the ultimate extent of contamination or remediation required may not be known. As additional assessments occur or remediation efforts continue, we may incur additional liabilities.

PCB Cost Recoveries and Refund. Since 1994, we have been conducting remediation activities at certain of our compressor stations associated with PCBs and other hazardous materials. We have collected amounts, substantially in excess of remediation costs incurred to date, through a surcharge to our customers under a settlement approved by the FERC in November of 1995. In November 2009, the FERC approved an amendment to the 1995 settlement that provides for interim refunds over a three year period of approximately $157 million of our collected amounts plus interest of 8%. Through December 31, 2011, we have refunded approximately $138 million, including interest, to our customers. Our remaining refund obligations of approximately $40 million, including interest, are recorded as current regulatory liabilities on our balance sheet at December 31, 2011 and these amounts are expected to be refunded to our customers during 2012.

Superfund Matters. Included in our recorded environmental liabilities are projects where we have received notice that we have been designated or could be designated as a Potentially Responsible Party (PRP) under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), commonly known as Superfund, or state equivalents for four active sites. Liability under the federal CERCLA statute may be joint and several, meaning that we could be required to pay in excess of our pro rata share of remediation costs. We consider the financial strength of other PRPs in estimating our liabilities. Accruals for these matters are included in the environmental reserve discussed above.

For 2012, we estimate that our total remediation expenditures will be approximately $2 million, most of which will be expended under government directed clean-up plans. In addition, we expect to make capital expenditures for environmental matters of approximately $9 million in the aggregate for 2012 through 2016, including capital expenditures associated with the impact of the EPA rule on emissions of hazardous air pollutants from reciprocating internal combustion engines which are subject to regulations with which we have to be in compliance by October 2013.

It is possible that new information or future developments could require us to reassess our potential exposure related to environmental matters. We may incur significant costs and liabilities in order to comply with existing environmental laws and regulations. It is also possible that other developments, such as increasingly strict environmental laws, regulations and orders of regulatory agencies, as well as claims for damages to property and the environment or injuries to employees and other persons resulting from our current or past operations, could result in substantial costs and liabilities in the future. As this information becomes available, or other relevant developments occur, we will adjust our accrual amounts accordingly. While there are still uncertainties related to the ultimate costs we may incur, based upon our evaluation and experience to date, we believe our reserves are adequate.

Rates and Regulatory Matter

In December 2011, the FERC approved our settlement that resolved the outstanding issues arising from our general rate case filing. The settlement provides for, among other things, (i) an increase in our base tariff rates effective June 1, 2011, (ii) implementation of cost trackers for fuel and pipeline safety and greenhouse gas, (iii) significant contract extensions to October 2014, (iv) a filing requirement for our next general rate case to be effective no earlier than April 2014 but no later than November 2015, and (v) a revenue sharing mechanism with certain of our customers for certain revenues above an annual threshold. In addition, as part of the settlement, we will refund approximately $68 million to our customers by March 31, 2012. We believe our accruals established for this matter are adequate.

In addition to the provisions discussed above, the settlement also required us to reduce the net regulatory liabilities associated with our postretirement benefit plan and certain deferred taxes. We have reflected these adjustments as an increase to our operating revenues of approximately $40 million since these items were provided for under prior rate settlements and there is no funding requirement or cost recovery in our current rates for these items. For a further discussion of these regulatory assets and liabilities, see Note 4.

Other Commitments

Capital Commitments. At December 31, 2011, we had capital commitments of approximately $47 million primarily related to our Northeast Upgrade Project and 300 Line Project, of which $27 million is expected to be spent in 2012. 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 $178 million at December 31, 2011. Our annual obligations under these purchase obligations are $38 million in 2012, $27 million in 2013, $21 million in 2014, $16 million in 2015, $15 million in 2016, and $61 million in total thereafter.

Operating Leases. We lease property, facilities and equipment under various operating leases. Future minimum annual rental commitments under our operating leases at December 31, 2011, were as follows:


Year Ending December 31,	(In millions)
2012	$	1
2013		1
2014		1
2015		1
Thereafter		1

Total	$	5

Rental expense on our lease obligations for each of the years ended December 31, 2011, 2010 and 2009 were $2 million and is reflected in operation and maintenance expense on our income statements.

Other Commercial Commitments. We hold cancelable easements or rights-of-way arrangements from landowners permitting the use of land for the construction and operation of our pipeline system. Our obligations under these easements are not material to our results of operations.

8. Retirement Benefits

Pension and Retirement Savings Plans. El Paso maintains a pension plan, the El Paso Corporation Pension Plan, and a retirement savings plan covering substantially all of its U.S. employees, including our former employees. The benefits under the pension plan are determined under a cash balance formula. Under its retirement savings plan, El Paso matches 75 percent of participant basic contributions up to six percent of eligible compensation and can make additional discretionary matching contributions depending on El Paso’s operating performance relative to its peers. El Paso is responsible for benefits accrued under its plans and allocates the related costs to its affiliates.

Postretirement Benefits Plan. We provide postretirement medical and life insurance benefits for a closed group of employees who were eligible to retire on December 31, 1996, and did so before July 1, 1997, under the El Paso Corporation Retiree Benefits Plan. 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 were prefunded and were recoverable under prior rate case settlements. Currently, there is no cost recovery or related funding that is required as part of our current FERC approved rates, however, we can seek to recover any funding shortfall that may be required in the future. We do not anticipate making any contributions to our postretirement benefit plan in 2012. Contributions of approximately $2 million, $5 million, and $4 million were made for the years ended December 31, 2011, 2010, and 2009, respectively.

Accumulated Postretirement Benefit Obligation, Plan Assets and Funded Status. In accounting for our postretirement benefit plan, we record an asset or liability based on the over funded or under funded status. Any deferred amounts related to unrecognized gains and losses or changes in actuarial assumptions are recorded in accumulated other comprehensive income, a component of member’s equity, until those gains and losses are recognized in the income statement. Prior to our rate case settlement in December 2011, we recorded a regulatory asset or liability for these unrecognized amounts as allowed by the FERC. During 2011, we reclassified $4 million (net of income taxes of $2 million) from a regulatory liability to accumulated other comprehensive income pursuant to our rate case settlement whereby these amounts are no longer included in the rates we charge our customers.

The table below provides information about our postretirement benefit plan.


	December 31,
	2011			2010
	(In millions)
Change in accumulated postretirement benefit obligation:
Accumulated postretirement benefit obligation — beginning of period	$	18		$	18
Interest cost		1			1
Participant contributions		1			1
Benefits paid⁽¹⁾		(2	)		(2	)

Accumulated postretirement benefit obligation — end of period	$	18		$	18

Change in plan assets:
Fair value of plan assets — beginning of period	$	41		$	33
Actual return on plan assets		2			4
Employer contributions		2			5
Participant contributions		1			1
Benefits paid		(2	)		(2	)

Fair value of plan assets — end of period	$	44		$	41

Reconciliation of funded status:

Fair value of plan assets	$	44		$	41
Less: accumulated postretirement benefit obligation		18			18

Net asset at December 31	$	26		$	23

(1)	Amounts shown net of a subsidy of less than $1 million for each of the years ended December 31, 2011 and 2010 related to the Medicare Prescription Drug, Improvement, and Modernization Act of 2003.

Components of Accumulated Other Comprehensive Income. The amount recognized in accumulated other comprehensive income of $4 million at December 31, 2011, net of income taxes of $2 million, related to unrecognized gains. We anticipate that less than $1 million of our accumulated other comprehensive income will be recognized as part of our net periodic benefit income in 2012.

Plan Assets. The primary investment objective of our plan is to ensure that, over the long-term life of the plan an adequate pool of sufficiently liquid assets exists to meet the benefit obligations to retirees and beneficiaries. Investment objectives are long-term in nature covering typical market cycles. Any shortfall of investment performance compared to investment objectives is generally the result of economic and capital market conditions. Although actual allocations vary from time to time from our targeted allocations, the target allocations of our postretirement plan’s assets are 65 percent equity and 35 percent fixed income securities. We may invest plan assets in a manner that replicates, to the extent feasible, the Russell 3000 Index and the Barclays Capital Aggregate Bond Index to achieve equity and fixed income diversification, respectively.

We use various methods to determine the fair values of the assets in our other postretirement benefit plan, which are impacted by a number of factors, including the availability of observable market data over the contractual term of the underlying assets. We separate these assets into three levels (Level 1, 2 and 3) based on our assessment of the availability of this market data and the significance of non-observable data used to determine the fair value of these assets. As of December 31, 2011, assets were comprised of an exchange-traded mutual fund with a fair value of $2 million and common/collective trust funds with a fair value of $42 million. As of December 31, 2010, assets were comprised of an exchange-traded mutual fund with a fair value of $2 million and common/collective trust funds with a fair value of $39 million. Our exchange-traded mutual fund invests primarily in dollar-denominated securities, and its fair value (which is considered a Level 1 measurement) is determined based on the price quoted for the fund in actively traded markets. Our common/collective trust funds are invested in approximately 65 percent equity and 35 percent fixed income securities, and their fair values (which are considered Level 2 measurements) are determined primarily based on the net asset value reported by the issuer, which is based on similar assets in active markets. Certain restrictions on withdrawals exist for these common/collective trust funds where the issuer reserves the right to temporarily delay withdrawals in certain situations such as market conditions or at the issuer’s discretion. We do not have any assets that are considered Level 3 measurements. The methods described above may produce a fair value that may not be indicative of net realizable value or reflective of future fair values, and there have been no changes in the methodologies used at December 31, 2011 and 2010.

Expected Payment of Future Benefits. As of December 31, 2011, we expect the following benefit payments under our plan.


Year Ending December 31,	Expected Payments⁽¹⁾
Year Ending December 31,	(In millions)
2012	$	2
2013		2
2014		2
2015		1
2016		1
2017 - 2021		6

(1)	Includes a reduction of less than $1 million in each of the years 2012 – 2016 and approximately $1 million in aggregate for 2017 – 2021 for an expected subsidy related to the Medicare Prescription Drug, Improvement, and Modernization Act of 2003.

Actuarial Assumptions and Sensitivity Analysis. Accumulated postretirement benefit obligations and net benefit costs are based on actuarial estimates and assumptions. The following table details the weighted average actuarial assumptions used in determining our postretirement plan obligations and net benefit costs.


	2011		2010		2009
	(Percent)
Assumptions related to benefit obligations at December 31:
Discount rate		4.30		4.82		5.37
Assumptions related to benefit costs for the year ended December 31:
Discount rate		4.82		5.37		5.95
Expected return on plan assets⁽¹⁾		7.75		7.75		8.00

(1)	The expected return on plan assets listed in the table above is a pre-tax rate of return based on our portfolio of investments. We utilize an after-tax expected return on plan assets to determine our benefit costs, which is based on unrelated business income taxes at a rate of 35 percent.

Actuarial estimates for our postretirement benefits plan assumed a weighted average annual rate of increase in the per capita costs of covered health care benefits of 7.3 percent, gradually decreasing to 5.0 percent by the year 2019. A one-percentage point change would not have had a significant effect on the accumulated postretirement benefit obligation or interest costs as of and for the years ended December 31, 2011 and 2010.

Components of Net Benefit Income. For each of the years ended December 31, the components of net benefit income are as follows:


	2011			2010			2009
	(In millions)
Interest cost	$	1		$	1		$	1
Expected return on plan assets		(2	)		(2	)		(1	)

Net benefit income	$	(1	)	$	(1	)	$	—

9. Transactions with Major Customer

The following table shows revenues from our major customer for each of the three years ended December 31:


	2011		2010		2009
	(In millions)
National Grid USA and subsidiaries	$	132	$	116	$	109

10. Accounts Receivable Sales Program

We participate in an accounts receivable sales program where we sell receivables in their entirety to a third party financial institution (through a wholly-owned special purpose entity). The sale of these accounts receivable (which are short-term assets that generally settle within 60 days) qualify for sale accounting. The third party financial institution involved in our accounts receivable sales program acquires interests in various financial assets and issues commercial paper to fund those acquisitions. We do not consolidate the third party financial institution because we do not have the power to control, direct, or exert significant influence over its overall activities since our receivables do not comprise a significant portion of its operations.

In connection with our accounts receivable sales, we receive a portion of the sales proceeds up front and receive an additional amount upon the collection of the underlying receivables (which we refer to as a deferred purchase price). Our ability to recover the deferred purchase price is based solely on the collection of the underlying receivables. The tables below contain information related to our accounts receivable sales program.


	Year Ended December 31,
	2011		2010
	(In millions)
Accounts receivable sold to the third-party financial institution⁽¹⁾	$	981	$	943
Cash received for accounts receivable sold under the program		510		508
Deferred purchase price related to accounts receivable sold		471		435
Cash received related to the deferred purchase price		443		399
Amount paid in conjunction with terminated program⁽²⁾		—		40

(1)	During the years ended December 31, 2011 and 2010, losses recognized on the sale of accounts receivable were immaterial.

(2)

In January 2010, we terminated our previous accounts receivable sales program and paid $40 million to acquire the related senior interests in certain receivables under that program. During 2009, we sold approximately $943 million of accounts receivable under that program and our fees and losses related to the program were not material.


	As of December 31,
	2011		2010
	(In millions)
Accounts receivable sold and held by third-party financial institution	$	108	$	75
Uncollected deferred purchase price related to accounts receivable sold⁽¹⁾		63		35

(1)	Initially recorded at an amount which approximates its fair value using observable inputs other than quoted prices in active markets (Level 2 fair value measurement).

The deferred purchase price related to the accounts receivable sold is reflected as other accounts receivable on our balance sheet. Because the cash received up front and the deferred purchase price relate to the sale or ultimate collection of the underlying receivables, and are not subject to significant other risks given their short term nature, we reflect all cash flows under the accounts receivable sales program as operating cash flows on our statement of cash flows. Under the accounts receivable sales program, we service the underlying receivables for a fee. The fair value of this servicing agreement, as well as the fees earned, were not material to our financial statements for the years ended December 31, 2011, 2010 and 2009.

11. Investment in Unconsolidated Affiliate and Transactions with Affiliates

Investment in Unconsolidated Affiliate

Bear Creek Storage Company, L.L.C. (Bear Creek). We have a 50 percent ownership interest in Bear Creek, a joint venture equally owned with Southern Natural Gas Company, L.L.C. (SNG), our affiliate. We account for our investment in Bear Creek using the equity method of accounting. We and SNG provide storage services to our customers utilizing the Bear Creek storage facility. During 2011, 2010, and 2009, we received $13 million, $14 million and $13 million in cash distributions from Bear Creek. Also, during 2010, Bear Creek utilized its note receivable balance under the cash management program with El Paso to pay a cash distribution to its partners, including $23 million to us. Included in this amount was a return of capital of $15 million.

Summarized financial information of Bear Creek as of and for the years ended December 31 is presented as follows:


	2011		2010		2009
	(In millions)
Operating results data:
Operating revenues	$	38	$	38	$	37
Operating expenses		10		10		15
Income from continuing operations and net income		28		28		22


	2011		2010
	(In millions)
Financial position data:
Current assets	$	10	$	9
Non-current assets		105		105
Other current liabilities		1		4
Equity in net assets		114		110

In November 2011, Bear Creek, along with other unaffiliated companies, received an order from the FERC related to an investigation into the rates charged to customers. The FERC ordered Bear Creek to file a full cost and revenue study within 75 days of the order. Bear Creek filed the cost and revenue study in January 2012 and the outcome of the proceeding is not expected to be material to our results of operations.

Transactions with Affiliates

Cash Management Program and Other Note Receivable. We participate in El Paso’s cash management program which matches short-term cash surpluses and needs of participating affiliates, thus minimizing total borrowings from outside sources. El Paso uses the cash management program to settle intercompany transactions between participating affiliates. We have historically advanced cash to El Paso in exchange for an affiliated note receivable that is due upon demand. At December 31, 2011 and 2010, we had a note receivable from El Paso of $519 million and $976 million. We have classified this receivable as noncurrent on our balance sheet at December 31, 2011 as we do not anticipate using it in the next twelve months considering available cash sources and needs. The interest rate on this note is variable and was 2.5% and 1.5% at December 31, 2011 and 2010.

We had a non-interest bearing note receivable of $334 million from an El Paso affiliate. During 2010, we collected this note receivable and immediately distributed the cash received to our parent.

Distributions. In October 2011, we made a non-cash distribution of our corporate facilities and certain other assets and liabilities to our parent. The net distributions were approximately $325 million, which represents the historical costs of these assets and liabilities.

Income Taxes. El Paso files consolidated U.S. federal and certain state tax returns which include our taxable income. Prior to our conversion to a limited liability company which is further discussed in Notes 1 and 2, we filed and paid taxes directly to certain state taxing authorities. At December 31, 2011 and 2010, we had net federal and state income taxes receivable of $1 million and $4 million. The majority of these balances, as well as deferred income taxes and amounts associated with the resolution of unrecognized tax benefits, will become receivable from or payable to El Paso. See Note 1 for a discussion of our income tax policy.

Other Affiliate Balances. At December 31, 2011 and 2010, we had contractual deposits from our affiliates of $10 million.

Affiliate Revenues and Expenses. We enter into transactions with our affiliates within the ordinary course of our business and the services are based on the same terms as non-affiliates. In addition, we store natural gas in an affiliated storage facility and utilize the pipeline system of an affiliate to transport some of our natural gas.

During 2009, we entered into a contract with our affiliate, El Paso Marketing, L.P., to sell up to 22 TBtu of natural gas not used in our operations in 2011 at a price of $6.48 per MMBtu. During the first half of 2011, we sold 9.5 TBtu of natural gas not used in operations under this contract. In June 2011, we terminated our contract to sell gas to El Paso Marketing, L.P. in connection with the implementation of a fuel volume tracker as part of our rate case filed with the FERC.

Following our conversion to a limited liability company, we no longer have employees and our former employees continue to provide services to us under a master services agreement with an affiliated service company owned by El Paso. We are managed and operated by officers of El Paso and its affiliates. Under the master services agreement, we reimburse the affiliate for various general and administrative services performed for our benefit and for direct expenses incurred on our behalf. El Paso bills us directly for certain general and administrative costs and allocates a portion of its general and administrative costs to us. In addition to allocations from El Paso, we allocate costs to our pipeline affiliates for their proportionate share of our pipeline services. The allocations from El Paso and the allocations to our affiliates are based on the estimated level of effort devoted to our operations and the relative size of our and their earnings before interest expense and income taxes, gross property and payroll.

The following table shows revenues, expenses and reimbursements from our affiliates for each of the three years ended December 31:


	2011		2010		2009
	(In millions)
Revenues⁽¹⁾	$	90	$	20	$	16
Operation and maintenance expenses⁽²⁾		131		77		67
Reimbursements of operating expenses		77		59		45

(1)	During 2011, we sold 9.5 TBtu of natural gas not used in operations to our affiliate, El Paso Marketing, L.P.

(2)	Following our conversion to a limited liability company, we entered into a master services agreement with our affiliate in which we reimburse them for costs incurred on our behalf.

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)
2011
Operating revenues	$	234	$	216	$	224	$	302	$	976
Operating income		95		65		83		126		369
Net income		45		30		50		78		203
2010
Operating revenues	$	224	$	200	$	213	$	208	$	845
Operating income		89		59		65		55		268
Net income		39		20		28		16		103

SCHEDULE II

TENNESSEE GAS PIPELINE COMPANY, L.L.C.

VALUATION AND QUALIFYING ACCOUNTS

Years Ended December 31, 2011, 2010 and 2009

(In millions)


Description	Balance at Beginning of Period		Charged to Costs and Expenses		Deductions			Charged to Other Accounts		Balance at End of Period
2011
Legal reserves	$	—	$	3	$	(1	)	$	—	$	2
Environmental reserves		4		1		—			—		5
Regulatory reserves⁽²⁾		—		—		—			68		68
2010
Legal reserves	$	7	$	—	$	(7	)	$	—	$	—
Environmental reserves		5		1		(2	)⁽¹⁾		—		4
2009
Legal reserves	$	—	$	7	$	—		$	—	$	7
Environmental reserves		6		—		(1	)⁽¹⁾		—		5

(1)	Primarily payments made for environmental remediation activities.

(2)	See Note 7 for a discussion of our rate case.

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, 2011, we carried out an evaluation under the supervision and with the participation of our management, including our President and Chief Financial Officer (CFO), as to the effectiveness, design and operation of our disclosure controls and procedures. This evaluation considered the various processes carried out under the direction of our disclosure committee in an effort to ensure that information required to be disclosed in the U.S. Securities and Exchange Commission reports we file or submit under the Securities Exchange Act of 1934, as amended (Exchange Act) is accurate, complete and timely. Our management, including our President and CFO, does not expect that our disclosure controls and procedures or our internal controls will prevent and/or detect all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within our company have been detected. Our disclosure controls and procedures are designed to provide reasonable assurance of achieving their objectives and our President and CFO concluded that our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) were effective as of December 31, 2011. 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 2011 that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

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, 2011 and 2010 of $1,593,000 and $982,000, respectively, were primarily for professional services rendered by Ernst & Young LLP for the audits of the consolidated financial statements of Tennessee Gas Pipeline Company, L.L.C. as well as the review of documents filed with the SEC and related consents.

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, 2011 and 2010.

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’s Annual Report on Form 10-K for the year ended December 31, 2011.

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
Report of Independent Registered Public Accounting Firm		23
Consolidated Statements of Income and Comprehensive Income		24
Consolidated Balance Sheets		25
Consolidated Statements of Cash Flows		26
Consolidated Statements of Member’s Equity/Stockholder’s Equity		27
Notes to Consolidated Financial Statements		28

2. Financial statement schedules


Schedule II — Valuation and Qualifying Accounts			45

All other schedules are omitted because they are not applicable, or the required information is disclosed in the financial statements or accompanying notes.

3. Exhibits

The Exhibit Index, which follows the signature page to this report and is hereby incorporated herein by reference, sets forth a list of those exhibits filed herewith, and includes and identifies contracts or arrangements required to be filed as exhibits to this Form 10-K by Item 601(b)(10)(iii) of Regulation S-K.

The agreements included as exhibits to this report are intended to provide information regarding their terms and not to provide any other factual or disclosure information about us or the other parties to the agreements. The agreements may contain representations and warranties by the parties to the agreements, including us, solely for the benefit of the other parties to the applicable agreement and:

•

should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties if those statements prove to be inaccurate;

•

may have been qualified by disclosures that were made to the other party in connection with the negotiation of the applicable agreement, which disclosures are not necessarily reflected in the agreement;

•

may apply standards of materiality in a way that is different from what may be viewed as material to certain investors; and

•

were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement and are subject to more recent developments.

Accordingly, these representations and warranties may not describe the actual state of affairs as of the date they were made or at any other time.

Undertaking

We hereby undertake, pursuant to Regulation S-K, Item 601(b), paragraph (4)(iii), to furnish to the Securities and Exchange Commission upon request all constituent instruments defining the rights of holders of our long-term debt and consolidated subsidiaries not filed herewith for the reason that the total amount of securities authorized under any of such instruments does not exceed 10 percent of our total consolidated assets.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Tennessee Gas Pipeline Company, L.L.C. has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on the 27^th day of February 2012.


TENNESSEE GAS PIPELINE COMPANY, L.L.C.

By:		/s/ Norman G. Holmes
		Norman G. Holmes
		President

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of Tennessee Gas Pipeline Company, L.L.C. and in the capacities and on the dates indicated:


Signature	Title	Date

/s/ Norman G. Holmes	President and Director	February 27, 2012
Norman G. Holmes	(Principal Executive Officer)

	Executive Vice President and
/s/ John R. Sult	Chief Financial Officer	February 27, 2012
John R. Sult	(Principal Financial Officer)

/s/ Rosa P. Jackson	Vice President and Controller	February 27, 2012
Rosa P. Jackson	(Principal Accounting Officer)

/s/ Daniel B. Martin Daniel B. Martin	Director	February 27, 2012

/s/ Bryan W. Neskora Bryan W. Neskora	Director	February 27, 2012

/s/ James C. Yardley James C. Yardley	Director	February 27, 2012

TENNESSEE GAS PIPELINE COMPANY, L.L.C.

EXHIBIT INDEX

December 31, 2011

Each exhibit identified below is filed as part of this Report. Exhibits filed with this Report are designated by “*”. All exhibits not so designated are incorporated herein by reference to a prior filing as indicated.


Exhibit Number		Description

*3.A		Certificate of Conversion of Tennessee Gas Pipeline Company, L.L.C., dated October 1, 2011.

*3.B		First Amended and Restated Limited Liability Company Agreement of Tennessee Gas Pipeline Company, L.L.C., dated February 14, 2012.

*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.

*4.A.1		First Supplemental Indenture dated as of March 13, 1997, between Tennessee Gas Pipeline Company and the Trustee.

*4.A.2		Second Supplemental Indenture dated as of March 13, 1997, between Tennessee Gas Pipeline Company and the Trustee.

*4.A.3		Third Supplemental Indenture dated as of March 13, 1997, between Tennessee Gas Pipeline Company and the Trustee.

*4.A.4		Fourth Supplemental Indenture dated as of October 9, 1998, between Tennessee Gas Pipeline Company and the Trustee.

4.A.5		Fifth Supplemental Indenture dated June 10, 2002, between Tennessee Gas Pipeline Company and the Trustee (incorporated by reference to Exhibit 4.A.5 to our Annual Report on Form 10-K for the year ended December 31, 2008, filed with the SEC on March 2, 2009).

4.A.6		Sixth Supplemental Indenture dated as of January 27, 2009 between Tennessee Gas Pipeline Company and the Trustee (incorporated by reference to Exhibit 4.A to our Current Report on Form 8-K filed with the SEC on January 29, 2009).

*4.A.7		Seventh Supplemental Indenture dated as of October 1, 2011 between Tennessee Gas Pipeline Company, Tennessee Gas Pipeline Issuing Corporation and the Trustee.

10.A		Fourth Amended and Restated Credit Agreement dated as of May 27, 2011, among El Paso Corporation, El Paso Natural Gas Company, Tennessee Gas Pipeline Company, as Borrowers, the Lenders party thereto and JPMorgan Chase Bank, N.A., as Administrative Agent and Collateral Agent for the Lenders (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the SEC on June 3, 2011).

10.B		Fourth Amended and Restated Security Agreement dated as of May 27, 2011, among El Paso Corporation, the persons referred to therein as Pipeline Company Borrowers, the persons referred to therein as Subsidiary Grantors, and JPMorgan Chase Bank, N.A., as Collateral Agent and Depository Bank (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K filed with the SEC on June 3, 2011).



21		Omitted pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.

*23		Consent of Independent Registered Public Accounting Firm Ernst & Young LLP.

*31.A		Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

*31.B		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

*32.A		Certification of Principal Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

*32.B		Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

*101.INS		XBRL Instance Document.

*101.SCH		XBRL Schema Document.

*101.CAL		XBRL Calculation Linkbase Document.

*101.DEF		XBRL Definition Linkbase Document.

*101.LAB		XBRL Labels Linkbase Document.

*101.PRE		XBRL Presentation Linkbase Document.

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