e10vk

Percent of Total Revenues

Description

in 2006

Reservation

Reservation revenues are from customers (referred to as firm customers) that reserve capacity on our pipeline systems 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.

Usage revenues are from both firm customers and interruptible customers (those without reserved capacity) who pay usage charges and provide fuel in-kind based on the volume of gas actually transported, stored, injected or withdrawn.

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, 2006


o		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 1-7320

ANR Pipeline Company

(Exact Name of Registrant as Specified in Its Charter)


Delaware		38-1281775
(State or Other Jurisdiction of Incorporation or Organization)		(I.R.S. Employer Identification No.)

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

Telephone Number: (713) 420-2600

Securities registered pursuant to Section 12(b) of the Act:


		Name of each exchange
Title of each class		on which registered
9.625% Debentures, due 2021
7.375% Debentures, due 2024		New York Stock Exchange
7% Debentures, due 2025

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

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

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o 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 o

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one).

Large accelerated filer o Accelerated filer o Non-accelerated filer þ

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

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

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date.

Common Stock, par value $1 per share. Shares outstanding on February 19, 2007: 1,000

ANR PIPELINE COMPANY MEETS THE CONDITIONS OF GENERAL INSTRUCTION I (1)(a) AND (b) TO FORM 10-K AND IS THEREFORE FILING THIS REPORT WITH A REDUCED DISCLOSURE FORMAT AS PERMITTED BY SUCH INSTRUCTION.

Documents Incorporated by Reference: None

ANR PIPELINE COMPANY

TABLE OF CONTENTS


	Caption	Page

PART I
Item 1.	Business		3
Item 1A.	Risk Factors		6
Item 1B.	Unresolved Staff Comments		9
Item 2.	Properties		9
Item 3.	Legal Proceedings		9
Item 4.	Submission of Matters to a Vote of Security Holders		*

PART II

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		9
Item 6.	Selected Financial Data		*
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		10
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		14
Item 8.	Financial Statements and Supplementary Data		15
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		34
Item 9A.	Controls and Procedures		34
Item 9B.	Other Information		34

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		34

PART IV

Item 15.	Exhibits and Financial Statement Schedules		35
	Signatures		45
Indenture
First Supplemental Indenture
Certification Pursuant to Section 302
Certification Pursuant to Section 302
Certification Pursuant to Section 906
Certification Pursuant to Section 906


*		We have not included a response to this item in this document since no response is required pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.

Below is a list of terms that are common to our industry and used throughout this document:


/d BBtu Bcf		= per day = billion British thermal units = billion cubic feet		LNG MMcf NGL		= liquefied natural gas = million cubic feet = natural gas liquids

When we refer to cubic feet measurements, all measurements are at a pressure of 14.73 pounds per square inch.

When we refer to “us”, “we”, “our”, “ours”, or “ANR”, we are describing ANR Pipeline Company and/or our subsidiaries.

PART I

ITEM 1. BUSINESS

Overview and Strategy

We are a Delaware corporation incorporated in 1945, and an indirect wholly owned subsidiary of El Paso Corporation (El Paso). Our primary business consists of the interstate transportation, storage and gathering of natural gas. We conduct our business activities through our natural gas pipeline system and our storage facilities as discussed below. In addition, until December 2006, we held a 50 percent interest in Great Lakes Gas Transmission Limited Partnership (Great Lakes L.P.). In December 2006, El Paso announced it would sell its 100 percent interest in us and its interest in Great Lakes L.P. to affiliates and subsidiaries of TransCanada Corporation. As an interim step to this announced sale, in December 2006, we sold El Paso Great Lakes Company L.L.C. (Great Lakes), which own the indirect 50 percent interest in Great Lakes L.P., to Seafarer US Pipeline System, Inc. (Seafarer), a direct wholly owned subsidiary of El Paso.

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

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

	•		Optimizing our contract portfolio;

	•		Managing market segmentation and differentiation;

	•		Focusing on efficiency initiatives;

	•		Expanding both ends of our pipeline system; and

	•		Seeking new business opportunities.

Below is a further discussion of our pipeline systems and storage facilities.

The ANR System. The ANR pipeline system consists of approximately 10,500 miles of pipeline with a design capacity of approximately 7,311 MMcf/d. During 2006, 2005 and 2004, average throughput was 3,954 BBtu/d, 4,100 BBtu/d and 4,067 BBtu/d. Our two interconnected, large-diameter, multiple pipeline systems transport natural gas from natural gas producing fields in Louisiana, Oklahoma, Texas and the Gulf of Mexico to markets in the midwestern regions of the U.S., including the metropolitan areas of Chicago, Detroit and Milwaukee. Our pipeline systems connect with multiple pipelines that provide our shippers with access to diverse sources of supply and various natural gas markets served by these pipelines, including pipelines owned by Alliance Pipeline L.P., Vector Pipeline L.P., Guardian Pipeline L.L.C., Viking Gas Transmission Company, Midwestern Gas Transmission, Natural Gas Pipeline Company of America, Northern Border Pipeline Company, Great Lakes L.P. and Northern Natural Gas Company.

The Great Lakes L.P. System. Until December 2006, we had a 50 percent ownership interest in Great Lakes L.P., which owns and operates a 2,115 mile interstate natural gas pipeline system with a design capacity of 2,600 MMcf/d that transports natural gas to customers in the midwestern and northeastern U.S. and eastern Canada. During 2006, 2005 and 2004, average throughput was 2,244 BBtu/d, 2,376 BBtu/d and 2,200 BBtu/d. For more information regarding our investment in Great Lakes L.P., see Part II, Item 8, Financial Statements and Supplementary Data, Note 10 as well as Great Lakes L.P.’s audited financial statements and related notes beginning on page 36 of this Annual Report on Form 10-K.

Storage Facilities. We own, or have contracted for, approximately 197 Bcf of underground natural gas storage capacity, which includes contracted rights for 77 Bcf of natural gas storage capacity from affiliates, of which 47 Bcf is provided by Blue Lake Gas Storage Company (Blue Lake) and 30 Bcf is provided by ANR Storage Company (ANR Storage). The maximum daily delivery capacity of our underground natural gas storage is approximately 3 Bcf/d.

In November 2006, the FERC granted certificate authorization for our storage enhancement project, which involves four natural gas storage fields in Michigan. The project will increase our salable working capacity by 17 Bcf, and our deliverability by 212 MMcf/d through reclassification of operational and base gas and physical enhancements. The estimated cost of the project is approximately $35 million, and we anticipate completing this project by the fourth quarter of 2007.

Markets and Competition

Our customers consist of natural gas distribution and industrial companies, electric generation companies, natural gas producers, other natural gas pipelines and natural gas marketing and trading companies. We provide transportation and storage services in both our natural gas supply and market areas. Our pipeline systems connect with multiple pipelines that provide our customers with access to diverse sources of supply and various natural gas markets.

Imported LNG is one of the fastest growing supply sectors of the natural gas market. LNG terminals and other regasification facilities can serve as important sources of supply for pipelines, enhancing their delivery capabilities and operational flexibility and complementing traditional supply transported into market areas. However, these LNG delivery systems also may compete with us for transportation of gas into market areas we serve.

Electric power generation is the fastest growing demand sector of the natural gas market. The growth of the electric power industry potentially benefits the natural gas industry by creating more demand for natural gas turbine generated electric power. This effect is offset, in varying degrees, by increased generation efficiency, the more effective use of surplus electric capacity, increased natural gas prices and the use and the availability of other fuel sources for power generation. In addition, in several regions of the country, new additions in electric generating capacity have exceeded load growth and electric transmission capabilities out of those regions. These developments may inhibit owners of new power generation facilities from signing firm contracts with us.

We have historically operated under long-term contracts. In response to changing market conditions, we have shifted from a traditional dependence solely on long-term contracts to an approach that balances short-term and long-term commitments. The shift is due to changes in market conditions and competition driven by state utility deregulation, local distribution company mergers, new pipeline competition, shifts in supply sources, volatility in natural gas prices, demand for short-term capacity and new power generation markets.

Our existing transportation and storage contracts mature at various times and in varying amounts of throughput capacity. Our ability to extend our existing contracts or remarket expiring capacity is dependent on competitive alternatives, the regulatory environment at the local, state and federal levels and market supply and demand factors at the relevant dates these contracts are extended or expire. The duration of new or renegotiated contracts will be affected by current prices, competitive conditions and judgments concerning future market trends and volatility. Subject to regulatory requirements, we attempt to recontract or remarket our capacity at the rates allowed under our tariffs. Currently, we have discounted a substantial portion of these rates to remain competitive.

The following table details our customers, contracts and competition on our ANR pipeline system as of December 31, 2006:


Customer Information	Contract Information	Competition
Approximately 290 firm and interruptible customers Major Customer: We Energies (799 BBtu/d)	Approximately 670 firm transportation contracts. Weighted average contract term between five and six years. Expire in 2007—2016.	In our market areas, we compete with other interstate and intrastate pipeline companies and local distribution companies to provide natural gas transportation and storage services in the midwest. We compete directly with other interstate pipelines, including Guardian Pipeline, which is constructing an expansion of its facilities, for markets in Wisconsin. We also compete directly with other interstate pipelines in the northeast market to serve electric generation and local distribution companies.


		In our supply areas, we compete directly with numerous pipelines and gathering systems for access to new supply sources. Our principal supply sources are the Rockies and mid-continent production accessed in Kansas and Oklahoma, western Canadian production delivered to Wisconsin and the Chicago area and Gulf of Mexico sources, including deepwater production and LNG imports.

Regulatory Environment

Our interstate natural gas transmission system and storage operations are regulated by the FERC under the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and the Energy Policy Act of 2005. We operate under tariffs approved by the FERC that establish rates, cost recovery mechanisms, terms and conditions of service to our customers. Generally, the FERC’s authority extends to:

	•		rates and charges for natural gas transportation, storage and related services;

	•		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 services;

	•		depreciation and amortization policies;

	•		acquisition and disposition of facilities; and

	•		initiation and discontinuation of services.

Our interstate pipeline systems are also subject to federal, state and local statutes and regulations regarding pipeline safety and environmental matters. We have ongoing inspection programs designed to keep all of our facilities in compliance with environmental and pipeline safety requirements and we believe that our systems are in material compliance with the applicable requirements.

We are subject to U.S. Department of Transportation regulations that establish safety requirements in the design, construction, operation and maintenance of our interstate natural gas transmission systems and storage facilities. Our operations on U.S. government land are regulated by the U.S. Department of the Interior.

Environmental

A description of our environmental activities is included in Part II, Item 8, Financial Statements and Supplementary Data, Note 6, and is incorporated herein by reference.

Employees

As of February 16, 2007, we had approximately 770 full-time employees, none of whom are subject to a collective bargaining agreement.

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. Such forward-looking statements are based on assumptions and beliefs that we believe to be reasonable; however, assumed facts almost always vary from actual results, and the differences between assumed facts and actual results can be material, depending upon the circumstances. Where we or our management express an expectation or belief as to future results, that expectation or belief is expressed in good faith and based on assumptions believed to have a reasonable basis. We cannot assure you, however, that the stated expectation or belief will occur or be achieved or accomplished. The words “believe,” “expect,” “estimate,” “anticipate,” and similar expressions will generally identify forward-looking statements. Our forward-looking statements, whether written or oral, are expressly qualified by these cautionary statements and any other cautionary statements that may accompany those statements. In addition, we disclaim any obligation to update any forward-looking statements to reflect events or circumstances after the date of this report.

With this in mind, you should consider the risks discussed elsewhere in this report and other documents we file with the Securities and Exchange Commission from time to time and the following important factors that could cause actual results to differ materially from those expressed in any forward-looking statement made by us or on our behalf.

Our success depends on factors beyond our control.

Our business is the transportation, storage and gathering of natural gas for third parties. Our results of operations are, to a large extent, driven by the volumes of natural gas we transport or store and the prices we are able to charge for doing so. The volumes of natural gas we are able to transport and store depends on the actions of those third parties and is beyond our control. Further, the following factors, most of which are beyond our control, may unfavorably impact our ability to maintain or increase current throughput, to renegotiate existing contracts as they expire or to remarket unsubscribed capacity:

	•		service area competition;

	•		expiration or turn back of significant contracts;

	•		changes in regulation and actions of regulatory bodies;

	•		weather conditions that impact throughput and storage levels;

	•		price competition;

	•		drilling activity and availability of natural gas;

	•		continued development of additional sources of gas supply that can be accessed;

	•		decreased natural gas demand due to various factors, including increases in prices and the increased availability or popularity of alternative energy sources such as coal and fuel oil;

	•		availability and increased cost of capital to fund ongoing maintenance and growth projects;

	•		opposition to energy infrastructure development, especially in environmentally sensitive areas;

	•		adverse general economic conditions; and

	•		unfavorable movements in natural gas prices in supply and demand areas.

The revenues of our pipeline business are generated under contracts that must be renegotiated periodically.

Our revenues are generated under transportation and storage contracts that expire periodically and must be renegotiated, extended or replaced. Although we actively pursue the renegotiation, extension or replacement of these contracts, we may not be able to extend or replace these contracts when they expire or may only be able to do so on terms that are not as favorable as existing contracts. If we are unable to renew, extend or replace these contracts or if we renew them on less favorable terms, we may suffer a material reduction

in our revenues and earnings. Currently, a substantial portion of our revenues are under contracts that are discounted at rates below the maximum rates allowed under our tariff.

We face competition that could adversely affect our operating results.

In our principal market areas of Wisconsin, Michigan, Illinois, Ohio and Indiana, we compete with other interstate and intrastate pipeline companies and local distribution companies for the transportation and storage of natural gas. In the northeastern markets, we compete with other interstate pipelines serving electric generation and local distribution companies. An affiliate of one of our significant customers, Michigan Consolidated Gas Company, holds a partial ownership interest in Vector Pipeline L.P. which competes directly with us. If we are unable to compete effectively with these and other energy enterprises, our future profitability may be negatively impacted. Even if we do compete effectively with these and other energy enterprises, we may discount our rates more than currently anticipated to retain committed service volumes or to recontract volumes as our existing contracts expire, which could adversely affect our revenues and results of operations.

Fluctuations in energy commodity prices could adversely affect our business.

Revenues generated by our transportation and storage contracts depend on volumes and rates, both of which can be affected by the price of natural gas. Increased natural gas prices could result in a reduction of the volumes transported by our customers, including power companies that may not dispatch natural gas-fired power plants if natural gas prices increase. Increased prices could also result in industrial plant shutdowns or load losses to competitive fuels as well as local distribution companies’ loss of customer base. The success of our transmission and storage operations is subject to continued development of additional gas supplies to offset the natural decline from existing wells connected to our system, which requires the development of additional oil and gas reserves and obtaining additional supplies from interconnecting pipelines, primarily in the Gulf of Mexico. A decline in energy prices could cause a decrease in these development activities and could cause a decrease in the volume of natural gas available for transmission and storage through our system. If natural gas prices in the supply basins connected to our pipeline system are higher than prices in other natural gas producing regions, our ability to compete with other transporters and our long term recontracting efforts may be negatively impacted. Furthermore, fluctuations in pricing between supply sources and market areas could negatively impact our transportation revenues. Fluctuations in energy prices are caused by a number of factors, including:

	•		regional, domestic and international supply and demand;

	•		availability and adequacy of transportation facilities;

	•		energy legislation;

	•		federal and state taxes, if any, on the transportation and storage of natural gas and NGL;

	•		abundance of supplies of alternative energy sources; and

	•		political unrest among oil producing countries.

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

Our business is regulated by the FERC, the U.S. Department of Transportation, the U.S. Department of the Interior and various state and local regulatory agencies. Regulatory actions taken by these agencies have the potential to adversely affect our profitability. In particular, the FERC regulates the rates we are permitted to charge our customers for our services. In setting authorized rates of return in recent FERC decisions, the FERC has utilized a proxy group of companies that includes local distribution companies that are not faced with as much competition or risks as interstate pipelines. The inclusion of these lower risk companies may create downward pressure on tariff rates when subjected to review by the FERC in future rate proceeding. Shippers on other pipelines have sought reductions from the FERC for the rates charged to their customers. If our tariff rates were reduced or redesigned in a future rate proceeding, our results of operations, financial position and cash flows could be materially adversely affected.

In addition, increased regulatory requirements relating to the integrity of our pipelines requires additional spending in order to maintain compliance with these requirements. Any additional requirements that are enacted could significantly increase the amount of these expenditures.

Further, state agencies that regulate our local distribution company customers could impose requirements that could impact demand for our services.

Environmental compliance and remediation costs and the costs of environmental liabilities could exceed our estimates.

Our operations are subject to various environmental laws and regulations that establish compliance and remediation obligations. Compliance obligations can result in significant costs to install and maintain pollution controls, fines and penalties resulting from any failure to comply and potential limitations on our operations. Remediation obligations can result in significant costs associated with the investigation and remediation of contaminated properties (some of which have been designated as Superfund sites by the United States Environmental Protection Agency under the Comprehensive Environmental Response, Compensation and Liability Act), as well as damage claims arising out of the contamination of properties or impact on natural resources. It is not possible for us to estimate exactly the amount and timing of all future expenditures related to environmental matters because of:

	•		The uncertainties in estimating pollution control and clean up costs, including sites where only preliminary site investigation or assessments have been completed;

	•		The discovery of new sites or additional information at existing sites;

	•		The uncertainty in quantifying liability under environmental laws that impose joint and several liability on all potentially responsible parties; and

	•		The nature of environmental laws and regulations, including the interpretation and enforcement thereof.

Currently, various legislative and regulatory measures to address greenhouse gas (GHG) emissions (including carbon dioxide and methane) are in various phases of discussion or implementation. These include the Kyoto Protocol (which is impacting proposed domestic legislation), proposed federal legislation and state actions to develop statewide or regional programs, each of which have imposed or would impose reductions in GHG emissions. These actions could result in increased costs to (i) operate and maintain our facilities, (ii) install new emission controls on our facilities and (iii) administer and manage any GHG emissions program. These actions could also impact the consumption of natural gas, thereby affecting our operations.

Although we believe we have established appropriate reserves for our environmental liabilities, we could be required to set aside additional amounts due to these uncertainties which could significantly impact our future results of operations, cash flows or financial position. For additional information concerning our environmental matters, see Part II, Item 8, Financial Statements and Supplementary Data, Note 6.

Our operations are subject to operational hazards and uninsured risks.

Our operations are subject to the inherent risks normally associated with pipeline operations, including pipeline ruptures, explosions, pollution, release of toxic substances, fires, adverse weather conditions and other hazards, each of which could result in damage to or destruction of our facilities or damages or injuries to persons. In addition, our operations and assets face possible risks associated with acts of aggression or terrorism. If any of these events were to occur, we could suffer substantial losses.

While we maintain insurance against many of these risks to the extent and in amounts we believe are reasonable, this insurance does not cover all risks. Many of our insurance coverages have material deductibles as well as limits on our maximum recovery. As a result, our results of operations, cash flows or financial condition could be adversely affected if a significant event occurs that is not fully covered by insurance.

One of our customers accounts for a significant portion of our firm transportation capacity.

In 2006, our contracts with We Energies represented approximately 10% of our firm transportation capacity. For additional information, see Item 1, Business — Markets and Competition and Part II, Item 8, Financial Statements and Supplementary Data, Note 8. The loss of this customer or a decline in its creditworthiness could adversely affect our results of operations, financial position and cash flows.

The expansion of our business by constructing new facilities subjects us to construction and other risks that may adversely affect our financial results.

We may expand the capacity of our existing pipeline or storage facilities by constructing additional facilities. Construction of these facilities is subject to various regulatory, development and operational risks, including:

	•		our ability to obtain necessary approvals and permits by regulatory agencies on a timely basis and on terms that are acceptable to us;

	•		the ability to obtain continued access to sufficient capital to fund expansion projects;

	•		potential changes in federal, state and local statutes and regulations, including environmental requirements, that prevent a

			project from proceeding or increase the anticipated cost of the project;

	•		impediments on our ability to acquire rights-of-way or land rights on a timely basis on terms that are acceptable to us;

	•		our ability to construct projects within anticipated costs, including the risk that we may incur cost overruns resulting from inflation or increased costs of equipment, materials or labor, or other factors beyond our control, that may be material;

	•		lack of anticipated future growth in natural gas supply; and

	•		lack of transportation, storage or throughput commitments.

Any of these risks could prevent a project from proceeding, delay its completion or increase its anticipated costs. As a result, new facilities may not achieve our expected investment return, which could adversely affect our results of operations, cash flows or financial position.

Our business requires the retention and recruitment of a skilled workforce and the loss of employees could result in the failure to implement our business plan.

Our business requires the retention and recruitment of a skilled workforce. If we are unable to retain and recruit employees such as engineers and other technical positions, our business could be negatively impacted.

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 businesses, 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 businesses. 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 legal proceedings is included in Part II, Item 8, Financial Statements and Supplementary Data, Note 6, and is incorporated herein by reference.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

Item 4, Submission of Matters to a Vote of Security Holders, has been omitted from this report pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.

PART II


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

At December 31, 2006, all of our common stock, par value $1 per share, is owned by an indirect subsidiary of El Paso and, accordingly, our stock is not publicly traded.

We pay dividends on our common stock from time to time from legally available funds that have been approved for payment by our Board of Directors. No common stock dividends were declared or paid in 2006 or 2005.

ITEM 6. SELECTED FINANCIAL DATA

Item 6, Selected Financial Data, 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

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. Factors that could cause actual results to differ include those risks and uncertainties that are discussed in Part I, Item 1A, Risk Factors.

In December 2006, El Paso announced it would sell its interest in us and its interest in Great Lakes to TransCanada and T.C. Pipelines. As an interim step to this announced sale, in December 2006, we sold all of our interest in Great Lakes to Seafarer.

Overview

Our business primarily consists of interstate natural gas transmission, storage, gathering and related services. Each of these businesses faces varying degrees of competition from other pipelines, as well as from alternative energy sources used to generate electricity, such as coal and fuel oil. Our revenues from transportation, storage and related services consist of two types.

Because of our regulated nature and the high percentage of our revenues attributable to reservation charges, our revenues have historically been relatively stable. However, our financial results can be subject to volatility due to factors such as changes in natural gas prices, market conditions, regulatory actions, competition, the creditworthiness of our customers and weather.

Historically, much of our business was conducted through long-term contracts with customers. However, many of our customers have shifted from a traditional dependence solely on long-term contracts to a portfolio approach which balances short-term opportunities with long-term commitments. This shift, which can increase the volatility of our revenues, is due to changes in market conditions and competition driven by state utility deregulation, local distribution company mergers, new supply sources, volatility in natural gas prices, demand for short-term capacity and new markets in electric generation.

In addition, our ability to extend existing customer contracts or remarket expiring contracted capacity is dependent on competitive alternatives, the regulatory environment at the federal, state and local levels and market supply and demand factors at the relevant dates these contracts are extended or expire. The duration of new or renegotiated contracts will be affected by current prices, competitive conditions and judgments concerning future market trends and volatility. Subject to regulatory requirements, we attempt to recontract or remarket our capacity at the rates allowed under our tariffs. Currently, we have discounted a substantial portion of these rates to remain competitive. Our existing contracts mature at various times and in varying amounts of throughput capacity. We continue to manage our recontracting process to mitigate the risk of significant impacts on our revenues. The weighted average term for active contracts is between five and six years as of December 31, 2006.

Below is the contract expiration portfolio for our firm transportation contracts as of December 31, 2006, including those whose terms begin in 2007 or later.


			Percent of Total
	BBtu/d		Contracted Capacity
2007		1,298		19
2008		1,268		18
2009		1,348		19
2010 and beyond		3,044		44

Total		6,958		100

Results of Operations

Our management uses earnings before interest expense and income taxes (EBIT) to assess the operating results and effectiveness of our business which consists of consolidated operations and, until late 2006, an investment in an unconsolidated affiliate. We believe EBIT is useful to our investors because it allows them to more effectively evaluate our operating performance using the same performance measure analyzed internally by our management. We define EBIT as net income adjusted for (i) items that do not impact our income from continuing operations, (ii) income taxes and (iii) interest and debt expense. We exclude interest and debt expense from this measure so that investors may evaluate our operating results independently from our financing methods. EBIT may not be comparable to measurements used by other companies. Additionally, EBIT should be considered in conjunction with net income and other performance measures such as operating income or operating cash flow. Below is a reconciliation of EBIT to net income for the years ended December 31:


	2006			2005
	(In millions,
	except volumes)
Operating revenues	$	540		$	548
Operating expenses		(306	)		(331	)

Operating income		234			217
Earnings from unconsolidated affiliate		58			59
Other income, net		3			2

EBIT		295			278
Interest and debt expense		(65	)		(67	)
Affiliated interest income, net		32			21
Income taxes		(110	)		(84	)

Income before cumulative effect of accounting change		152			148
Cumulative effect of accounting change, net of income taxes		—			(1	)

Net income	$	152		$	147

Throughput volumes (BBtu/d)⁽¹⁾		5,076			5,288


⁽¹⁾		Throughput volumes include billable transportation throughput volumes for storage withdrawal and volumes associated with our proportionate share of our 50 percent equity investment in Great Lakes L.P.

The following items contributed to our overall EBIT increase of $17 million for the year ended December 31, 2006 as compared to 2005:


										EBIT
	Revenue			Expense			Other			Impact
	Favorable (Unfavorable)
	(In millions)
Contract restructuring/settlements	$	(43	)	$	(2	)	$	(1	)	$	(46	)
Higher services revenues		35			—			—			35
Revaluations of imbalances		(1	)		10			—			9
Cashout adjustment		—			32			—			32
Higher maintenance and other costs		—			(6	)		—			(6	)
Impact of Hurricane Rita		—			(4	)		—			(4	)
Other⁽¹⁾		1			(5	)		1			(3	)

Total impact on EBIT	$	(8	)	$	25		$	—		$	17


⁽¹⁾		Consists of individually insignificant items.

The following discusses some of the significant items listed above as well as events that may affect our operations in the future.

Contract Restructuring/Settlements. During 2005, we received a settlement of two transportation agreements previously rejected in the bankruptcy of USGen New England, Inc. In addition, we completed the restructuring of our transportation contracts as well as a related gathering contract with one of our shippers. These two transactions increased our EBIT by approximately $44 million during the year ended December 31, 2005.

Higher Services Revenues. During the year ended December 31, 2006, our reservation revenues increased due to sales of additional capacity and higher realized rates primarily as a result of increased demand in our supply areas. In addition, our usage revenues increased overall, primarily due to increased activity under various interruptible services provided under our tariff as a result of stronger demand in our service areas.

Revaluations of Imbalances. We experienced lower operating expenses during 2006 due to a decrease in the index price used to value our imbalance positions with third parties. These imbalances are cashed out and the adjustment varies from period to period based on volumes and current index prices.

Cashout Adjustment. Our cashout adjustment represents the difference between the sales proceeds from cashout sales of gas and the actual or estimated cost to replace the system gas that is the source of those sales. This adjustment varies from period to period based on volumes and prices, and changes in the value of our cashout position are reflected as a change in our operating expenses. During the year ended December 31, 2006, our actual and estimated cost to replace system gas was lower primarily due to a decrease in natural gas prices and volumes.

Higher Maintenance and Other Costs. Operating costs were higher for the year ended December 31, 2006 as compared to 2005, primarily due to costs we expensed associated with our pipeline integrity program of approximately $3 million as a result of a FERC accounting release adopted in January 2006. We capitalized these costs in 2005.

Impact of Hurricane Rita. During 2006, we continued to repair the damage caused by Hurricane Rita. As a result, we incurred higher operation and maintenance expenses due to partial insurance recovery of our repair costs. For a further discussion of the impact of this hurricane and its effect on our capital expenditures, see our Liquidity and Capital Expenditures discussion below.

Expansion. In November 2006, the FERC granted certificate authorization for our storage enhancement project, which involves four natural gas storage fields in Michigan. The project will increase our salable working capacity by 17 Bcf, and our deliverability by 212 MMcf/d through reclassification of operational and base gas and physical enhancements. The estimated cost of the project is approximately $35 million and is estimated to increase our revenues by approximately $8 million in 2007, $11 million for each of the years from 2008 through 2011 and $10 million annually thereafter. We also expect approximately $60 million of sales of reclassified base gas associated with the project in 2007.

Affiliated Interest Income, Net

Affiliated interest income, net for the year ended December 31, 2006, was $11 million higher than in 2005 due to higher average advances to El Paso under its cash management program and higher average short-term interest rates. The average advances due from El Paso of $527 million in 2005 increased to $560 million in 2006. In addition, the average short-term interest rates increased from 4.2% in 2005 to 5.7% in 2006.

Income Taxes


	Year Ended
	December 31,
	2006			2005
	(In millions,
	except for rates)
Income taxes	$	110		$	84
Effective tax rate		42	%		36	%

In 2006, our effective tax rate was different than the statutory rate of 35 percent primarily due to state income taxes, additional taxes recorded based on El Paso’s announced sale of us, and taxes recorded on the undistributed earnings of Great Lakes as a result of its sale to Seafarer. Prior to the sale of Great Lakes, deferred taxes were recorded assuming the earnings qualified for a dividends received deduction. For a reconciliation of the statutory rate to the effective rates, see Item 8, Financial Statements and Supplementary Data, Note 3.

Liquidity and Capital Expenditures

Liquidity Overview

Our liquidity needs are provided by cash flows from operating activities. In addition, we participate in El Paso’s cash management program. Under El Paso’s cash management program, depending on whether we have short-term cash surpluses or requirements, we either provide cash to El Paso or El Paso provides cash to us in exchange for an affiliated note receivable or payable. We have historically provided cash advances to El Paso, and we reflect these advances as investing activities in our statement of cash flows. At December 31, 2006, we had notes receivable from El Paso and other affiliates of approximately $1.4 billion that are due upon demand. As part of El Paso’s announced sale of its interest in us, a portion of these receivables will be settled as a non-cash distribution prior to the closing of the sale.

During the third quarter of 2006, we entered into agreements to sell certain accounts receivable to a qualifying special purpose entity under Statement of Financial Accounting Standards No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities. As of December 31, 2006, we sold approximately $54 million of receivables, net of an allowance of approximately $1 million, received cash of approximately $35 million, received subordinated beneficial interests of approximately $18 million, and recognized a loss of approximately $1 million. The cash received from the sale was advanced to El Paso under the cash management program. We reflect accounts receivable sold under this program and the related redemption of the subordinated beneficial interests as operating cash flows in our statement of cash flows. In January 2007, we discontinued this program. For a further discussion of the sales of our accounts receivable, see Item 8, Financial Statements and Supplementary Data, Note 10.

We believe that cash flows from operating activities and, until the closing of El Paso’s sale of us, our note receivable from El Paso will be adequate to meet our short-term capital and debt service requirements for our existing operations and planned expansion opportunities.

Debt

In January 2007, we made a cash tender offer to purchase our $300 million, 8.875% notes due March 15, 2010. In February 2007, approximately $269 million of the notes were tendered. The cash was funded by recoveries of receivables from El Paso under its cash management program. As a result of this payment, some of our most restrictive covenants were removed from the indenture.

Capital Expenditures

Our capital expenditures for the years ended December 31 were as follows:


	2006		2005
	(In millions)
Maintenance	$	74	$	79
Expansion		53		44
Hurricanes⁽¹⁾		41		2

Total	$	168	$	125


⁽¹⁾		Amounts shown are net of insurance proceeds received of approximately $8 million and less than $1 million for 2006 and 2005, respectively.

Hurricanes

We continue to repair damages to our pipeline caused by Hurricane Rita in 2005. We currently estimate total repair costs of approximately $80 million. Our mutual insurance company has indicated that we will not receive insurance recoveries of some of the amounts due to exceeding aggregate loss limits per event. We expect most of the remaining repair costs to be incurred in 2007 and insurance reimbursements to be received in 2007 and into 2008. While we do not believe the unrecovered costs will materially impact our overall liquidity or financial results, the timing between expenditures and reimbursements may impact our liquidity from period to period. The table below provides further detail on what we have spent to date, our estimated remaining costs, and insurance recoveries.


	Recoverable			Unrecoverable
	Costs			Costs ⁽¹⁾		Total
	( In millions)
Cumulative costs through December 31, 2006	$	45		$	20	$	65
Estimated remaining		10			5		15

Total costs	$	55		$	25	$	80

Less: Reimbursements to date		10

Expected future reimbursements	$	45	⁽²⁾


⁽¹⁾		Approximately $15 million of these costs are capital costs.


⁽²⁾		Reimbursement will be retained by El Paso subsequent to the closing of our sale.

The mutual insurance company also notified us that effective June 1, 2006, the aggregate loss limits on future events would be reduced to $500 million from $1 billion, which will limit our recoveries on future hurricanes or other insurable events.

Commitments and Contingencies

For a discussion of our commitments and contingencies, see Item 8, Financial Statements and Supplementary Data, Note 6, which is incorporated herein by reference.

New Accounting Pronouncements Issued But Not Yet Adopted

See Item 8, Financial Statements and Supplementary Data, Note 1, under New Accounting Pronouncements Issued But Not Yet Adopted, which is incorporated herein by reference.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Our primary market risk is exposure to changing interest rates. The table below shows the carrying value and related weighted average effective interest rates of our interest bearing securities by expected maturity dates and the fair value of those securities. At December 31, 2006, the fair values of our fixed rate long-term debt securities have been estimated based on quoted market prices for the same or similar issues.


	December 31, 2006										December 31, 2005
	Expected Fiscal Year of Maturity of Carrying Amounts
									Fair		Carrying		Fair
	2010			Thereafter			Total		Value		Amount		Value
	(In millions, except for rates)
Liabilities:
Long-term debt — fixed rate	$	310	⁽¹⁾	$	431		$	741	$	875	$	740	$	844
Average effective interest rate		9.3	%		9.0	%


⁽¹⁾		In January 2007, we made a cash tender offer to purchase our $300 million, 8.875% notes due March 15, 2010. In February 2007, approximately $269 million of the notes were tendered.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholder of ANR Pipeline Company

We have audited the accompanying consolidated balance sheet of ANR Pipeline Company (the Company) as of December 31, 2006, and the related consolidated statements of income, stockholder’s equity, and cash flows for the year then ended. Our audit also included the financial statement schedule listed in the Index at Item 15(a). 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 audit. The consolidated financial statements of Great Lakes Gas Transmission Limited Partnership (a partnership in which the Company had a 50% interest), have been audited by other auditors whose report has been furnished to us, and our opinion on the consolidated financial statements, insofar as it relates to the amounts included for Great Lakes Gas Transmission Limited Partnership, is based solely on the report of the other auditors. In the consolidated financial statements, the Company’s earnings from unconsolidated affiliate, Great Lakes Gas Transmission Limited Partnership, is stated at $58 million for the year ended December 31, 2006.

We conducted our audit 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 audit 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 audit and the report of other auditors provide a reasonable basis for our opinion.

In our opinion, based on our audit and the report of other auditors, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of ANR Pipeline Company at December 31, 2006, and the consolidated results of its operations and its cash flows for the year then ended, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

As discussed in Note 1 to the consolidated financial statements, in 2006 the Company adopted the provisions of Statement of Financial Accounting Standards No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — An Amendment of FASB Statements No. 87, 88, 106, and 132(R).

/s/ Ernst & Young LLP

Houston, Texas
February 19, 2007

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholder of
ANR Pipeline Company:

In our opinion, the consolidated financial statements listed in the Index appearing under Item 15(a) (1), present fairly, in all material respects, the consolidated financial position of ANR Pipeline Company and its subsidiaries (the “Company”) at December 31, 2005, and the consolidated results of their operations and their cash flows for each of the two years in the period ended December 31, 2005 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule for each of the two years in the period ended December 31, 2005 listed in the Index appearing under Item 15 (a) (2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and the financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and the financial statement schedule based on our audits. We did not audit the consolidated financial statements of Great Lakes Gas Transmission Limited Partnership (the “Partnership”) as of December 31, 2005 and 2004 and for each of the two years in the period ended December 31, 2005. The Partnership is an equity investment of El Paso Great Lakes Inc., a wholly-owned subsidiary of the Company, that comprised assets of $234 million at December 31, 2005 and income of $38 million and $43 million for each of the two years in the period ended December 31, 2005. Those statements were audited by other auditors whose report thereon has been furnished to us, and our opinion expressed herein, insofar as it relates to the amounts included for the Partnership, is based solely on the report of the other auditors. We conducted our audits of these statements 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. An audit 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.

As discussed in Note 1, the Company adopted Financial Accounting Standards Board Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations, on December 31, 2005.

/s/ PricewaterhouseCoopers LLP

Houston, Texas
February 28, 2006

ANR PIPELINE COMPANY

CONSOLIDATED BALANCE SHEETS

(In millions, except share amounts)


	December 31,
	2006			2005
ASSETS
Current assets
Cash and cash equivalents	$	—		$	—
Accounts and notes receivable
Customer, net of allowance of $2 in 2005		17			85
Affiliates		830			8
Other		9			8
Materials and supplies		22			21
Deferred income taxes		—			12
Other		22			6

Total current assets		900			140

Property, plant and equipment, at cost		3,931			3,777
Less accumulated depreciation, depletion and amortization		2,128			2,146

Total property, plant and equipment, net		1,803			1,631

Other assets
Notes receivable from affiliates		—			527
Investment in unconsolidated affiliate		—			300
Other		46			19

		46			846

Total assets	$	2,749		$	2,617

LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities
Accounts payable
Trade	$	44		$	56
Affiliates		23			37
Other		14			21
Taxes payable		86			72
Other accrued liabilities		33			—
Accrued interest		16			16
Deferred taxes		280			—
Other		52			32

Total current liabilities		548			234

Long-term debt		741			740

Other liabilities
Deferred income taxes		306			370
Affiliate payable		163			172
Other		42			54

		511			596

Commitments and contingencies
Stockholder’s equity
Common stock, par value $1 per share; 1,000 shares authorized, issued and outstanding		—			—
Additional paid-in capital		931			597
Retained earnings		602			450
Accumulated other comprehensive income		10			—
Notes receivable from affiliates		(594	)		—

Total stockholder’s equity		949			1,047

Total liabilities and stockholder’s equity	$	2,749		$	2,617

See accompanying notes.

ANR PIPELINE COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)


	Year Ended December 31,
	2006			2005			2004
Cash flows from operating activities
Net income	$	152		$	147		$	117
Adjustments to reconcile net income to net cash from operating activities
Depreciation, depletion and amortization		37			40			37
Cumulative effect of accounting change		—			1			—
Deferred income taxes		34			22			33
Earnings from unconsolidated affiliates, adjusted for cash distributions		6			16			9
Other non-cash income items		2			1			2
Asset and liability changes
Accounts receivable		29			(33	)		7
Accounts payable		(50	)		25			22
Taxes payable		16			24			(5	)

Other		(9	)		10			(20	)

Net cash provided by operating activities		217			253			202


Cash flows from investing activities
Additions to property, plant and equipment		(168	)		(125	)		(143	)
Net proceeds from the sale of investment		815			—			42
Net change in affiliate advances		(863	)		(60	)		(100	)
Other		(1	)		—			(26	)

Net cash used in investing activities		(217	)		(185	)		(227	)


Cash flows from financing activities
Payments to retire long-term debt		—			(68	)		—

Net cash used in financing activities		—			(68	)		—


Net change in cash and cash equivalents		—			—			(25	)
Cash and cash equivalents
Beginning of period		—			—			25

End of period	$	—		$	—		$	—

See accompanying notes.

ANR PIPELINE COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Summary of Significant Accounting Policies

Basis of Presentation and Principles of Consolidation

We are a Delaware corporation incorporated in 1945, and an indirect wholly owned subsidiary of El Paso Corporation (El Paso). Our primary business consists of the interstate transportation, storage and gathering of natural gas. We conduct our business activities through our natural gas pipeline system and our storage facilities. In addition, until December 2006, we held an indirect 50 percent interest in Great Lakes Gas Transmission Limited Partnership (Great Lakes L.P.) through El Paso Great Lakes Company L.L.C. (Great Lakes). In December 2006, El Paso announced its sale of us and we sold our interest in Great Lakes to an affiliate. See Note 2 for a further discussion of our sale of Great Lakes.

Our consolidated financial statements are prepared in accordance with U.S. generally accepted accounting principles and we include the accounts of all majority owned and controlled subsidiaries after the elimination of all significant intercompany accounts and transactions. Our financial statements for prior periods include reclassifications that were made to conform to the current year presentation. Those reclassifications had no impact on reported net income or stockholder’s equity.

We consolidate entities when we either (i) have the ability to control the operating and financial decisions and policies of that entity or (ii) are allocated a majority of the entity’s losses and/or returns through our variable interests in that entity. The determination of our ability to control or exert significant influence over an entity and whether we are allocated a majority of the entity’s losses and/or returns involves the use of judgment. We apply the equity method of accounting where we can exert significant influence over, but do not control the policies and decisions of an entity and where we are not allocated a majority of the entity’s losses and/or returns. We use the cost method of accounting where we are unable to exert significant influence over the entity.

Use of Estimates

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

Regulated Operations

Our natural gas transmission systems and storage operations are subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC) under the Natural Gas Act of 1938, Natural Gas Policy Act of 1978 and the Energy Policy Act of 2005. In 1996, we discontinued the application of Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation.

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 receivable balance. We regularly review collectibility and establish or adjust our allowance as necessary using the specific identification method.

Material and Supplies

Our inventory consists of materials and supplies. Our materials and supplies are valued 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 actual amount of natural gas delivered from or received by a pipeline system or storage facility differs from the amount of natural gas delivered or received. We value these imbalances due to or from shippers and operators at current index prices. Imbalances are settled in cash or made up 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. In addition, we classify all imbalances as current as we expect to settle them within a year.

Property, Plant and Equipment

Our property, plant and equipment is recorded at its original cost of construction or, upon acquisition, at the fair value of the assets acquired. For assets we construct, we capitalize direct costs, such as labor and materials, and indirect costs, such as overhead and interest. We capitalize major units of property replacements or improvements and expense minor items. Prior to January 1, 2006, we capitalized certain costs incurred related to our pipeline integrity programs as part of our property, plant and equipment. Beginning January 1, 2006, we began expensing certain of these costs based on FERC guidance. The impact on prior years’ earnings was not material. During the year ended December 31, 2006, we expensed approximately $3 million as a result of this change.

We use the composite (group) method to depreciate property, plant and equipment. Under this method, assets with similar lives and characteristics are grouped and depreciated as one asset. We apply the depreciation rate to the total cost of the group until its net book value equals its salvage value. Currently, our depreciation rates vary from 1 percent to 33 percent per year. Using these rates, the remaining depreciable life of our pipeline and storage assets is approximately 70 years and the remaining depreciable lives of other assets range from 1 to 62 years.

When we retire 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 or retire an entire operating unit. We include gains or losses on dispositions of operating units in operating income.

At December 31, 2006 and 2005, we had approximately $51 million and $74 million of construction work in progress included in our property, plant and equipment.

We capitalize a carrying cost (an allowance for funds used during construction) on funds related to our construction of long-lived assets. The capitalized carrying costs are calculated based on our average cost of debt. Interest costs on debt amounts capitalized during each of the years ended December 31, 2006, 2005 and 2004, were $4 million. These amounts are included as a reduction to interest and debt expense in our income statement. Capitalized carrying costs are reflected as an increase in the cost of the asset on our balance sheet.

Asset and Investment Impairments

We evaluate assets and investments for impairment when events or circumstances indicate that their carrying values may not be recovered. These events include market declines that are believed to be other than temporary, changes in the manner in which we intend to use a long-lived asset, decisions to sell an asset or investment and adverse changes in the legal or business environment such as adverse actions by regulators. When an event occurs, we evaluate the recoverability of our long-lived assets’ carrying values based on either (i) our long-lived assets’ ability to generate future cash flows on an undiscounted basis or (ii) the fair value of our investment in our 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 these assets downward, if necessary, to their estimated fair value. Our fair value estimates are generally based on market data obtained through the sales process or an analysis of expected discounted cash flows. The magnitude of any impairment is impacted by a number of factors, including the nature of the assets being sold and our established time frame for completing the sales, among other factors.

Revenue Recognition

Our revenues are primarily generated from 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 regardless of the amount of natural gas that is transported or stored. For interruptible or volumetric-based services, as well as revenues on operational sales of natural gas and related products, we record revenues when physical deliveries of natural gas and other commodities are made at the agreed upon delivery point or when gas is injected or withdrawn from the storage facility. Gas not used in operations is based on the volumes of natural gas we are allowed to retain for fuel/lost and unaccounted for relative to the amounts we use for operating purposes. During 2005, we adopted a fuel tracker for gas not used in operations that contains a true-up mechanism for amounts over or under retained. Prior to the adoption of the tracker, we recognized revenue on gas not used in operations when the volumes were sold. 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 environmental liabilities at their undiscounted amounts in our balance sheet in 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 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 expense when clean-up efforts do not benefit future periods.

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

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

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 account for our asset retirement obligations in accordance with SFAS No. 143, Accounting for Asset Retirement Obligations and Financial Accounting Standards Board (FASB) Interpretation (FIN) No. 47, Accounting for Conditional Asset Retirement Obligations. We record a liability for legal obligations associated with the replacement, removal and retirement of our long-lived assets. Our asset retirement liabilities are recorded at their estimated fair value with a corresponding increase to property, plant and equipment. This increase in property, plant and equipment is then depreciated over the useful life of the long-lived asset to which that liability relates. An ongoing expense is also recognized for changes in the value of the liability as a result of the passage of time, which we record as depreciation, depletion and amortization expense in our income statement. We adopted FIN No. 47 in the fourth quarter of 2005 and recorded a charge as a cumulative effect of accounting change, net of income taxes, of approximately $1 million.

We have legal obligations associated with our natural gas pipelines and related 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 relate primarily to purging and sealing the pipelines if they are abandoned. We also have obligations to remove hazardous materials associated with our natural gas transmission facilities if they are replaced. We accrue a liability for legal obligations based on an estimate of the timing and amount of their settlement.

We are required to operate and maintain our natural gas pipeline and storage systems, and intend to do so as long as supply and demand for natural gas exists, which we expect for the foreseeable future. Therefore, we believe that the substantial majority of our natural gas pipeline and storage system assets have indeterminate lives. Accordingly, our asset retirement liabilities as of December 31, 2006 and 2005 were not material to our financial statements. We continue to evaluate our asset retirement obligations and future developments could impact the amounts we record.

Pension and Other Postretirement Benefits

In December 2006, we adopted the provisions of SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — An Amendment of FASB Statements No. 87, 88, 106, and 132(R). Under SFAS No. 158, we record an asset or liability for our pension and other postretirement benefit plans based on their funded or unfunded status. We also record any deferred amounts related to unrealized gains and losses or changes in actuarial assumptions in accumulated other comprehensive income, a component of stockholder’s equity, until those gains and losses are recognized in the income statement. For a further discussion of our adoption of SFAS No. 158, see Note 7.

Evaluation of Prior Period Misstatements in Current Financial Statements

In December 2006, we adopted the provisions of Staff Accounting Bulletin (SAB) No. 108. Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in Current Year Financial Statements. SAB No. 108 provides guidance on how to evaluate the impact of financial statement misstatements from prior periods that have been identified in the current year. The adoption of these provisions did not have a material impact on our financial statements.

New Accounting Pronouncements Issued But Not Yet Adopted

As of December 31, 2006, the following accounting standards and interpretations had not yet been adopted by us.

Accounting for Uncertainty in Income Taxes. In July 2006, the FASB issued FIN No. 48, Accounting for Uncertainty in Income Taxes. FIN No. 48 clarifies SFAS No. 109, Accounting for Income Taxes, and requires us to evaluate our tax positions for all jurisdictions and all years where the statute of limitations has not expired. FIN No. 48 requires companies to meet a more likely than not threshold (i.e. greater than a 50 percent likelihood of a tax position being sustained under examination) prior to recording a benefit for their tax positions. Additionally, for tax positions meeting this more likely than not threshold, the amount of benefit is limited to the largest benefit that has a greater than 50 percent probability of being realized upon ultimate settlement. The cumulative effect of applying this interpretation will be recorded as an adjustment to the beginning balance of retained earnings, or other components of stockholder’s equity as appropriate, in the period of adoption. This interpretation is effective for fiscal years beginning after December 15, 2006, and we do not anticipate that it will have a material impact on our financial statements.

Fair Value Measurements. In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements, which provides guidance on measuring the fair value of assets and liabilities in the financial statements. We will be required to adopt the provisions of this standard no later than in 2008, and are currently evaluating the impact, if any, that it will have on our financial statements.

Measurement Date of Other Postretirement Benefits. In December 2006, we adopted the recognition provisions of SFAS No. 158. This standard will also require us to change the measurement date of our other postretirement benefit plans from September 30, the date we currently use, to December 31 beginning in 2008.

2. Divestitures

In December 2006, we sold our interest in Great Lakes to Seafarer US Pipeline System, Inc. (Seafarer), a direct wholly owned subsidiary of El Paso, for $815 million. The difference between the amount recorded and the historical carrying value of our investment in Great Lakes, which was approximately $334 million, net of related taxes of approximately $188 million, was accounted for as a capital contribution.

3. Income Taxes

Components of Income Taxes. The following table reflects the components of income taxes included in income before cumulative effect of accounting change for each of the three years ended December 31:


	2006			2005		2004
	(In millions)
Current
Federal	$	65		$	59	$	33
State		11			3		3

		76			62		36


Deferred
Federal		37			20		30
State		(3	)		2		3

		34			22		33

Total income taxes	$	110		$	84	$	69

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


	2006			2005			2004
	(In millions, except
	for rates)
Income taxes at the statutory federal rate of 35%	$	92		$	81		$	65
State income taxes, net of federal income tax effect		5			3			3
Deferred taxes recorded on sales⁽¹⁾		14			—			—
Other		(1	)		—			1

Income taxes	$	110		$	84		$	69

Effective tax rate		42	%		36	%		37	%


⁽¹⁾		Relates to our sale of Great Lakes and El Paso’s announced sale of us.

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


	2006		2005
	(In millions)
Deferred tax liabilities
Property, plant and equipment	$	364	$	342
Investment in unconsolidated affiliate		307		103
Other assets		29		23

Total deferred tax liability		700		468


Deferred tax assets
Lease liability		66		69
Other liabilities		48		41

Total deferred tax asset		114		110

Net deferred tax liability	$	586	$	358

As part of recording the sale of Great Lakes to Seafarer, we recorded deferred taxes of $188 million. These taxes represent the tax impact of the difference between the proceeds from the sale and the underlying book value of Great Lakes, and are included in deferred tax liabilities on investment in unconsolidated affiliate. See Note 2 for an additional discussion of the sale.

4. Financial Instruments

The carrying amounts and estimated fair values of our financial instruments are as follows at December 31:

2006

2005

Carrying

Fair

Carrying

Fair

Amount

Value

Amount

Value

(In millions)

Balance sheet financial instruments:

Long-term debt ⁽¹⁾

741

875

740

844


⁽¹⁾		We estimated the fair value of our debt with fixed interest rates based on quoted market prices for the same or similar issues.

At December 31, 2006 and 2005, the carrying amounts of trade receivables and payables are representative of their fair value because of the short-term maturity of these instruments.

5. Debt and Other Credit Facilities

Debt

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


	2006		2005
	(In millions)
8.875% Notes due March 2010	$	300	$	300
13.75% Notes due March 2010		12		12
9.625% Debentures due November 2021		300		300
7.375% Debentures due February 2024		125		125
7.00% Debentures due June 2025		7		7

Less:		744		744
Unamortized discount		3		4

Total long-term debt	$	741	$	740

Currently, we have the ability to call $300 million of our 8.875% notes due March 15, 2010, and an additional $12 million of our 13.75% notes due March 2010. If we were to exercise our option to call these notes, we would be obligated to pay principal, accrued interest and a make-whole premium to redeem the debt. In January 2007, we made a cash tender offer to purchase our $300 million, 8.875% notes due March 15, 2010. In February 2007, approximately $269 million of the notes were tendered. The cash was funded by recoveries of receivables from El Paso under its cash management program. As a result of this payment, some of our most restrictive covenants included in our indenture were removed.

Credit Facilities

In July 2006, El Paso entered into a new $1.75 billion credit agreement. We are not a borrower under the credit agreement and our common stock is no longer pledged as collateral.

Under 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 Consolidated Debt to EBITDA (as defined in the indenture), the most restrictive of which shall not exceed 6 to 1; (ii) limitations on sale leaseback transactions; (iii) limitations, in some cases, on transactions with our affiliates; (iv) limitations on the incurrence of liens; (v) potential limitations on our ability to declare and pay dividends; and (vi) limitations on participation in El Paso’s cash management program. For the year ended December 31, 2006, we were in compliance with our debt-related covenants.

Our long-term debt contains cross-acceleration provisions, the most restrictive of which is a $5 million cross-acceleration clause. If triggered, repayment of the long-term debt could be accelerated.

6. Commitments and Contingencies

Legal Proceedings

Gas Measurement Cases. We and a number of our affiliates were named defendants in actions that generally allege mismeasurement of natural gas volumes and/or heating content resulting in the underpayment of royalties. The first set of cases was filed in 1997 by an individual under the False Claims Act, which has been consolidated for pretrial purposes (In re: Natural Gas Royalties Qui Tam Litigation, U.S. District Court for the District of Wyoming). These complaints allege an industry-wide conspiracy to underreport the heating value as well as the volumes of the natural gas produced from federal and Native American lands. In May 2005, a representative appointed by the court issued a recommendation to dismiss most of the actions. In October 2006, the U.S. District Judge issued an order dismissing all measurement claims against all defendants. An appeal has been filed.

Similar allegations were filed in a second set of actions initiated in 1999 in Will Price, et al. v. Gas Pipelines and Their Predecessors, et al., in the District Court of Stevens County, Kansas. The plaintiffs currently seek certification of a class of royalty owners in wells on non-federal and non-Native American lands in Kansas, Wyoming and Colorado. Motions for class certification have been briefed and argued in the proceedings and the parties are awaiting the court’s ruling. The plaintiffs seek an unspecified amount of monetary damages in the form of additional royalty payments (along with interest, expenses and punitive damages) and injunctive relief with regard to future gas measurement practices. Our costs and legal exposure related to this lawsuit and claim are not currently determinable.

In addition to the above matters, we and our subsidiaries and affiliates are also named defendants in numerous lawsuits and governmental proceedings that arise in the ordinary course of our business.

For each of our outstanding legal matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies and the likelihood of an unfavorable outcome. If we determine that an unfavorable outcome is probable and can be estimated, we establish the necessary accruals. As further information becomes available, or other relevant developments occur, we may accrue amounts accordingly. While there are still uncertainties related to the ultimate costs we may incur, based upon our evaluation and experience to date, we had no accruals for our outstanding legal matters at December 31, 2006.

Environmental Matters

We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require us to remove or remedy the effect on the environment of the disposal or release of specified substances at current and former operating sites. At December 31, 2006, we had accrued approximately $25 million for expected remediation costs and associated onsite, offsite and groundwater technical studies and for related environmental legal costs. Our accrual represents a combination of two estimation methodologies. First, where the most likely outcome can be reasonably estimated, that cost has been accrued. Second, where the most likely outcome cannot be estimated, a range of costs is established and if no amount in that range is more likely than any other, the lower end of the expected range has been accrued. Our environmental remediation projects are in various stages of completion. The liabilities we have recorded reflect our current estimates of amounts we will expend to remediate

Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) Matters. We have received notice that we could be designated, or have been asked for information to determine whether we could be designated, as a Potentially Responsible Party (PRP) with respect to one active site under the CERCLA or state equivalents. We have sought to resolve our liability as a PRP at this site through indemnification by third parties and settlements which provide for payment of our allocable share of remediation costs. As of December 31, 2006, we have estimated our share of the remediation costs at this site to be between $1 million and $2 million. Because the clean-up costs are estimates and are subject to revision as more information becomes available about the extent of remediation required, and in some cases we have asserted a defense to any liability, our estimates could change. Moreover, liability under the federal CERCLA statute is joint and several, meaning that we could be required to pay in excess of our pro rata share of remediation costs. Our understanding of the financial strength of other PRPs has been considered, where appropriate, in estimating our liabilities. Accruals for these matters are included in the environmental reserve discussed above.

7. Retirement Benefits

Pension and Retirement Benefits. El Paso maintains a pension plan to provide benefits as determined under a cash balance formula covering substantially all of its U.S. employees, including our employees. El Paso also maintains a defined contribution plan covering its U.S. employees, including our employees. El Paso matches 75 percent of participant basic contributions up to 6 percent of eligible compensation and can make additional discretionary matching contributions. El Paso is responsible for benefits accrued under its plans and allocates the related costs to its affiliates.

Postretirement Benefits. We provide medical and life insurance benefits for a closed group of retirees who were at least age 50 with 10 years of service on December 31, 2000, and who retired on or before June 30, 2001. 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. El Paso reserves the right to change these benefits. Employees who retire after June 30, 2001, will continue to receive limited postretirement life insurance benefits. Our postretirement benefit plan costs are prefunded to the extent these costs are recoverable through rates. Under the terms of the settlement of our last rate case, once this postretirement benefit plan has ended, we will be required to make refunds to our customers of those costs collected in rates that have not been used to pay benefits to our employees. We expect to contribute approximately $9 million to our postretirement benefit plan in 2007.

On December 31, 2006, we adopted the provisions of SFAS No. 158, and upon adoption reflected the assets related to our postretirement benefit plan based on its funded status. The adoption of this standard increased our other non-current assets by approximately $16 million, our non-current deferred tax liabilities by approximately $6 million, and our accumulated other comprehensive income by approximately $10 million. We anticipate that less than $1 million of our accumulated other comprehensive income will be recognized as a part of our net periodic benefit cost in 2007.

Change in Accumulated Postretirement Benefit Obligation, Plan Assets and Funded Status. Our benefits are presented and computed as of and for the twelve months ended September 30:


	2006			2005
	(In millions)
Change in Accumulated Postretirement benefit obligation:
Accumulated Postretirement benefit obligation at beginning of period	$	49		$	53
Interest cost		3			3
Participant contributions		2			2
Actuarial gain		—			(3	)
Benefits paid		(6	)		(6	)
Other		3			—

Accumulated Postretirement benefit obligation at end of period	$	51		$	49


Change in plan assets:
Fair value of plan assets at beginning of period	$	67		$	57
Actual return on plan assets		5			5
Employer contributions		9			9
Participant contributions		2			2
Benefits paid		(6	)		(6	)

Fair value of plan assets at end of period	$	77		$	67


Reconciliation of funded status:
Fair value of plan assets at September 30	$	77		$	67
Less: Accumulated postretirement benefit obligation, end of period		51			49

Funded status at September 30		26			18
Fourth quarter contributions and income		2			2
Unrecognized actuarial gains⁽¹⁾		—			(15	)

Net asset at December 31	$	28		$	5


⁽¹⁾		Amounts were reclassified to accumulated other comprehensive income upon the adoption of SFAS No. 158 in 2006.

Expected Payment of Future Benefits. As of December 31, 2006, we expect the following payments under our plans (in millions):


Year Ending
December 31,
2007	$	5
2008		5
2009		5
2010		5
2011		5
2012-2016		20

Total	$	45

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


	2006			2005			2004
	(In millions)
Interest cost	$	3		$	3		$	3
Expected return on plan assets		(4	)		(3	)		(2	)

Net postretirement benefit cost	$	(1	)	$	—		$	1

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 for 2006, 2005 and 2004:


	2006		2005		2004
	(Percent)
Assumptions related to benefit obligations at September 30:
Discount rate		5.50		5.25
Assumptions related to benefit costs at December 31:
Discount rate		5.25		5.75		6.00
Expected return on plan assets⁽¹⁾		8.00		7.50		7.50


⁽¹⁾		The expected return on plan assets is a pre-tax rate (before a tax rate of 35 percent on postretirement benefits) that is primarily based on an expected risk-free investment return, adjusted for historical risk premiums and specific risk adjustments associated with the debt and equity securities. These expected returns were then weighted based on the target asset allocations of our investment portfolio.

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 10.3 percent in 2006, gradually decreasing to 5 percent by the year 2015. Assumed health care cost trends have a significant effect on the amounts reported for our postretirement benefit plan. A one-percentage point change would not have had a significant effect on interest costs in 2006 or 2005. A one-percentage point change in these trends would have the following increase (decrease) on our accumulated postretirement benefit obligation as of September 30:


	2006			2005
	(In millions)
One percentage point increase:
Accumulated postretirement benefit obligation	$	2		$	2
One percentage point decrease:
Accumulated postretirement benefit obligation	$	(2	)	$	(2	)

Plan Assets. The following table provides the actual asset allocations in our postretirement plan as of September 30:


	Actual		Actual
Asset Category	2006		2005
	(Percent)
Equity securities		61		61
Debt securities		33		31
Other		6		8

Total		100		100

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 support the benefit obligation to participants, retirees and beneficiaries. In meeting this objective, the plan seeks to achieve a high level of investment return consistent with a prudent level of portfolio risk. Investment objectives are long-term in nature covering typical market cycles of three to five years. Any shortfall in investment performance compared to investment objectives is the result of general economic and capital market conditions.

The target allocation for the invested assets is 65 percent equity and 35 percent fixed income. Other assets are held in cash for payment of benefits upon presentment. Any El Paso stock held by the plan is held indirectly through investments in mutual funds.

8. Transactions with Major Customer

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


	2006		2005		2004
	(In millions)
We Energies	$	54	$	56	$	59

9. Supplemental Cash Flow Information

The following table contains supplemental cash flow information for each of the three years ended December 31:


	2006		2005		2004
	(In millions)
Interest paid, net of capitalized interest	$	65	$	70	$	68
Income tax payments		61		38		41

10. Investment in Unconsolidated Affiliate and Transactions with Affiliates

Investment in Unconsolidated Affiliate

Until December 2006, we owned all of the common stock of Great Lakes, which owns an indirect 50 percent interest in Great Lakes L.P. In December 2006, we sold our interest in Great Lakes to Seafarer.

Summarized financial information of our proportionate share of our unconsolidated affiliate as of and for the years ended December 31 is presented as follows:


	2006		2005		2004
	(In millions)
Operating results data:
Operating revenues	$	123	$	131	$	133
Operating expenses		55		60		56
Income from continuing operations and net income⁽¹⁾		38		38		43


	2005
	(In millions)
Financial position data:
Current assets	$	56
Non-current assets		581
Short-term debt		5
Other current liabilities		34
Long-term debt		210
Other non-current liabilities		154
Equity in net assets⁽¹⁾		234


⁽¹⁾		Our proportionate share of Great Lakes’ net income and equity in net assets includes our share of taxes recorded by Great Lakes. Our earnings from unconsolidated affiliate recognized in our income statements are presented before these taxes.

For the year ended December 31, 2006 and 2005, we received approximately $64 million and $75 million in dividends from Great Lakes.

Transactions with Affiliates

Cash Management Program. 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. We have historically provided cash to El Paso in exchange for an affiliated note receivable that is due upon demand. At December 31, 2006, we had notes receivable from El Paso and other affiliates of approximately $1.4 billion. The interest rate at December 31, 2006 was 5.3%. As a result of El Paso’s announced sale of its interest in us, a portion of these receivables will be settled as a non-cash distribution prior to the closing of the sale. Accordingly, at December 31, 2006, we have reclassified an estimate of the amount that will be settled in this manner as a reduction of stockholder’s equity.

Accounts Receivable Sales Program. During the third quarter of 2006, we entered into agreements to sell certain accounts receivable to a qualifying special purpose entity (QSPE) under SFAS No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities. As of December 31, 2006, we sold approximately $54 million of receivables, net of an

allowance of approximately $1 million, received cash of approximately $35 million, received subordinated beneficial interests of approximately $18 million, and recognized a loss of approximately $1 million. In conjunction with the sale, the QSPE also issued senior beneficial interests on the receivables sold to a third party financial institution, which totaled $36 million on the closing date. Prior to its redemption, we reflect the subordinated beneficial interest in receivables sold as accounts and notes receivable — affiliates on our balance sheet. We reflect accounts receivable sold under this program and the related redemption of the subordinated beneficial interests as operating cash flows in our statement of cash flows. Under the agreements, we earned a fee for servicing the accounts receivable and performing all administrative duties for the QSPE, which is reflected as a reduction of operation and maintenance expense in our income statement. The fair value of these servicing and administrative agreements as well as the fees earned were not material to our financial statements for the year ended December 31, 2006. In January 2007, we discontinued this program.

Taxes. El Paso files consolidated U.S. federal and certain state tax returns which include our taxable income. In certain states, we file and pay taxes directly to the state taxing authorities. We had income taxes payable of $76 million and $60 million at December 31, 2006 and 2005. The majority of these balances will become payable to El Paso. See Note 1 for a discussion of our tax accrual policy.

Other. At December 31, 2006 and 2005, we had payables to an affiliate of $171 million and $180 million, for obligations related to the relocation of our headquarters from Detroit, Michigan to Houston, Texas and the transfer of this lease to our affiliate from a third party. At December 31, 2006 and 2005, $8 million of these payables was classified as other current liabilities. The payments under this obligation are due semi-annually.

During 2004, we sold a storage field and its related base gas to Mid Michigan Gas Storage Company, our affiliate, at its net book value of $42 million. We did not recognize a gain or loss on this sale. We also acquired assets from our affiliates during 2004 with a net book value of $26 million.

Other Affiliate Balances. The following table shows other balances with our affiliates arising in the ordinary course of business at December 31:


	2006		2005
	(In millions)
Accounts and notes receivable — other	$	—	$	4
Contractual deposits		1		1

Affiliate Revenues and Expenses. We provide natural gas transportation and storage services to our affiliates in the normal course of our business.

El Paso bills us directly for certain general and administrative costs and allocates a portion of its general and administrative costs to us. In addition to allocations from El Paso, we are allocated costs from Tennessee Gas Pipeline Company (TGP) associated with our pipeline services. The allocations from El Paso and TGP are based on the estimated level of effort devoted to our operations and the relative size of our EBIT, gross property and payroll.

We provide administrative services to related parties, Eaton Rapids Gas Storage and Blue Lake Gas Storage (Blue Lake). We record the amounts received for these services as a reduction of operating expenses and as reimbursement costs.

Great Lakes L.P. provides us capacity under contracts, the longest of which extends through 2016. We also have natural gas storage contracts with our affiliates, Blue Lake and ANR Storage. Our contract with Blue Lake extends to 2013 and covers capacity of 47 Bcf of natural gas storage. Our contract with ANR Storage extends to 2007 and covers storage capacity of 30 Bcf. Transportation and storage costs are recorded as operating expenses. The terms of service provided to and by our affiliates are the same as those terms as non-affiliated parties.

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


	2006		2005		2004
	(In millions)
Revenues from affiliates	$	2	$	4	$	10
Operation and maintenance expense from affiliates		112		117		113
Reimbursement of operating expenses charged to affiliates		3		6		4

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

As previously reported in our Current Report on Form 8-K dated April 18, 2006, as amended on May 8, 2006, we appointed Ernst & Young LLP as our independent registered public accounting firm for the fiscal year ending December 31, 2006 and dismissed PricewaterhouseCoopers LLP. During the fiscal years ended December 31, 2006 and 2005, there were no disagreements with our former accountant or reportable events as defined in Item 304(a)(1)(iv) and Item 304(a)(1)(v) of Regulation S-K.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As of December 31, 2006, we carried out an evaluation under the supervision and with the participation of our management, including our President and Chief Financial Officer, as to the effectiveness, design and operation of our disclosure controls and procedures, as defined by the Securities Exchange Act of 1934, as amended. This evaluation considered the various processes carried out under the direction of our disclosure committee in an effort to ensure that information required to be disclosed in the SEC reports we file or submit under the Exchange Act is accurate, complete and timely. Our management, including our President and Chief Financial Officer, does not expect that our disclosure controls and procedures or our internal controls will prevent and/or detect all error 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. Based on the results of this evaluation, our President and Chief Financial Officer concluded that our disclosure controls and procedures are effective at December 31, 2006.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting that have materially affected or are reasonably likely to materially affect our internal control over financial reporting during the fourth quarter of 2006.

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, 2006 and 2005, of $678,000 and $810,000 were for professional services rendered by Ernst & Young LLP and PricewaterhouseCoopers LLP, respectively, for the audits of the consolidated financial statements of ANR Pipeline Company.

All Other Fees

No other audit-related, tax or other services were provided by our independent registered public accounting firms for the years ended December 31, 2006 and 2005.

Policy for Approval of Audit and Non-Audit Fees

We are a wholly owned subsidiary of El Paso and do not have a separate audit committee. El Paso’s Audit Committee has adopted a pre-approval policy for audit and non-audit services. For a description of El Paso’s pre-approval policies for audit and non-audit related services, see El Paso Corporation’s proxy statement for its 2007 Annual Meeting of Stockholders.

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) The following documents are filed as part of this report:

1. Financial statements.

The following consolidated financial statements are included in Part II, Item 8 of this report:


	Page
ANR Pipeline Company
Reports of Independent Registered Public Accounting Firms		15
Consolidated Statements of Income		17
Consolidated Balance Sheets		18
Consolidated Statements of Cash Flows		19
Consolidated Statements of Stockholder’s Equity		20
Notes to Consolidated Financial Statements		21

The following financial statements of our equity investments are included on the following pages of this report:


	Page
Great Lakes Gas Transmission Limited Partnership
Report of Independent Registered Public Accounting Firm		36
Consolidated Statements of Income and Partners’ Capital		37
Consolidated Balance Sheets		38
Consolidated Statements of Cash Flows		39
Notes to Consolidated Financial Statements		40

2. Financial statement schedules.

Schedule II — Valuation and Qualifying Accounts		33

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

3. Exhibits

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

Undertaking

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

Report of Independent Registered Public Accounting Firm

The Partners and Management Committee
Great Lakes Gas Transmission Limited Partnership:

We have audited the accompanying consolidated balance sheets of Great Lakes Gas Transmission Limited Partnership and subsidiary (Partnership) as of December 31, 2006 and 2005, and the related consolidated statements of income and partners’ capital and cash flows for each of the years in the three-year period ended December 31, 2006. These consolidated financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these consolidated financial statements 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. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Partnership as of December 31, 2006 and 2005, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2006, in conformity with U.S. generally accepted accounting principles.

Detroit, Michigan
January 23, 2007

Consolidated Statements of Income and Partners’ Capital

Years Ended December 31
(Thousands of Dollars)


	2006			2005			2004
Transportation Revenues
Affiliated Revenues	$	161,605			173,796			185,391
Non Affiliated Revenues		110,652			106,947			98,936

		272,257			280,743			284,327

Operating Expenses

Operation and Maintenance		34,083			41,312			34,723
Depreciation		57,612			57,693			57,756
Income Taxes Payable by Partners		44,076			43,253			47,058
Property and Other Taxes		25,965			26,756			23,265

		161,736			169,014			162,802


Operating Income		110,521			111,729			121,525

Other Income (Expense)
Interest on Long Term Debt		(35,970	)		(36,844	)		(37,718	)
Other, Net		3,723			1,917			1,373

		(32,247	)		(34,927	)		(36,345	)


Net Income	$	78,274			76,802			85,180


Partners’ Capital
Balance at Beginning of Year	$	376,713			420,501			452,007
Contributions by General Partners		—			30,976			29,398
Net Income		78,274			76,802			85,180
Current Income Taxes Payable by Partners Charged to Earnings		39,259			33,237			31,536
Distributions to Partners		(132,099	)		(184,803	)		(177,620	)


Balance at End of Year	$	362,147			376,713			420,501

The accompanying notes are an integral part of these statements.

Consolidated Balance Sheets

As of December 31
(Thousands of Dollars)


			2006				2005


ASSETS

Current Assets
Cash and Cash Equivalents	$	78,368	59,280
Accounts Receivable (net of allowance of $1,000 in 2006 and $1,200 in 2005)		16,327	33,804
Receivable from Affiliates		18,954	16,721
Materials and Supplies, at Average Cost		10,908	9,664
Prepayments		4,286	2,746
Other		310	361

		129,153	122,576

Gas Utility Plant
Property, Plant and Equipment		2,038,123	2,025,196
Less Accumulated Depreciation		1,030,059	970,737

		1,008,064	1,054,459


	$	1,137,217	1,177,035


LIABILITIES & PARTNERS’ CAPITAL

Current Liabilities
Current Maturities of Long Term Debt	$	10,000	10,000
Accounts Payable		16,306	30,671
Payable to Affiliates		2,362	4,755
Property Taxes		17,793	19,149
Other Non Income Taxes		3,939	5,299
Accrued Interest		9,289	9,435
Other		4,136	3,976

		63,825	83,285

Long Term Debt		440,000	450,000

Other Liabilities
Amounts Equivalent to Deferred Income Taxes		270,515	266,192
Other		730	845

		271,245	267,037


Partners’ Capital		362,147	376,713

	$	1,137,217	1,177,035

The accompanying notes are an integral part of these statements.

Consolidated Statements of Cash Flows

Years Ended December 31
(Thousands of Dollars)


	2006			2005			2004
Cash Flow Increase (Decrease) from:

Operating Activities
Net Income	$	78,274			76,802			85,180
Adjustments to Reconcile Net Income to Operating Cash Flows:
Depreciation		57,612			57,693			57,756
Amounts Equivalent to Deferred Income Taxes		4,323			9,233			15,678
Allowance for Funds Used During Construction		(386	)		(135	)		(157	)
Changes in Current Assets and Liabilities:
Accounts Receivable		17,477			(2,516	)		(15,848	)
Receivable from Affiliates		(2,233	)		(3,872	)		6,458
Accounts Payable		(14,365	)		5,675			11,957
Payable to Affiliates		(2,393	)		1,767			1,177
Property and Other Non Income Taxes		(2,716	)		341			(970	)
Other		(2,834	)		1,950			(3,076	)

		132,759			146,938			158,155

Investing Activities
Investment in Utility Plant		(18,953	)		(16,102	)		(15,136	)
Insurance Proceeds		8,122			—			2,545

		(10,831	)		(16,102	)		(12,591	)

Financing Activities
Repayment of Long Term Debt		(10,000	)		(10,000	)		(10,000	)
Contributions by General Partners		—			30,976			29,398
Current Income Taxes Payable by Partners Charged to Earnings		39,259			33,237			31,536
Distribution to Partners		(132,099	)		(184,803	)		(177,620	)

		(102,840	)		(130,590	)		(126,686	)

Change in Cash and Cash Equivalents		19,088			246			18,878

Cash and Cash Equivalents:

Beginning of Year		59,280			59,034			40,156


End of Year	$	78,368			59,280			59,034

Supplemental Disclosure of Cash Flow Information Cash Paid During the Year for Interest
(Net of Amounts Capitalized of $153, $47 and $48, Respectively)	$	36,132			37,018			37,903

The accompanying notes are an integral part of these statements.

Notes to Consolidated Financial Statements

1 Organization and Management

Great Lakes Gas Transmission Limited Partnership (Partnership) is a Delaware limited partnership that owns and operates an interstate natural gas pipeline system. The Partnership transports natural gas for delivery to wholesale customers in the midwestern and northeastern United States and eastern Canada. The partners, their parent companies, and partnership ownership percentages at December 31 are as follows:


	Ownership %
Partner (Parent Company)	2006		2005
General Partners:
El Paso Great Lakes Company, LLC (El Paso Corporation)		46.45		46.60
TransCanada GL, Inc. (TransCanada PipeLines Ltd.)		46.45		46.60

Limited Partner:
Great Lakes Gas Transmission Company (TransCanada		7.10		6.80
PipeLines Ltd. and El Paso Corporation)

The day-to-day operation of Partnership activities is the responsibility of Great Lakes Gas Transmission Company (Company), which is reimbursed for its employee salaries, benefits and other expenses, pursuant to the Partnership’s Operating Agreement with the Company.

On December 22, 2006, TC PipeLines, LP and TransCanada Corporation announced the purchase of El Paso’s 46.45% ownership interest in the Partnership and 50% interest in the Company, respectively. The acquisition is subject to regulatory approvals and is expected to close in the first quarter of 2007. The impact, if any, of this transaction on the Partnership’s consolidated financial statements has not been determined.

2 Summary of Significant Accounting Policies

Principles of Consolidation and Basis of Presentation

The consolidated financial statements include the accounts of the Partnership and GLGT Aviation Company, a wholly owned subsidiary. GLGT Aviation Company owns a fractional interest in a transport aircraft used principally for pipeline operations. Intercompany amounts have been eliminated.

For purposes of reporting cash flows, the Partnership considers all liquid investments with original maturities of three months or less to be cash equivalents.

The fair value of long term debt is discussed in footnote 4. All other financial instruments approximate fair value due to the short maturity of these instruments.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires the use of estimates and assumptions that affect the amounts reported as assets, liabilities, revenues and expenses and the disclosures in these financial statements. Actual results can, and often do, differ from those estimates.

Regulation

The Partnership is subject to the rules, regulations and accounting procedures of the Federal Energy Regulatory Commission (FERC). The Partnership’s accounting policies follow regulatory accounting principles prescribed under Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation. Regulatory assets and liabilities have been established and represent probable future revenue or expense which will be recovered from or refunded to customers.

Revenue and Accounts Receivable

The Partnership recognizes transportation revenues in the period the service is provided based on transportation service contracts under a tariff regulated by the FERC. The tariff specifies maximum transportation rates and the contracts’ general terms and conditions of service.

Accounts receivable are reported at the invoiced amount. The Partnership establishes an allowance for losses on accounts receivable if it is determined that all or a portion of the outstanding balance will not be collected. The Partnership also considers historical industry data and customer credit trends. Account balances are charged against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote.

Notes to Consolidated Financial Statements

2 Summary of Significant Accounting Policies, Continued

Natural Gas Imbalances

Natural gas imbalances occur when the actual amount of natural gas delivered or received differs from the scheduled amount of natural gas delivered or received. The Partnership values these imbalances due to or from customers and interconnecting pipelines at current index prices. Imbalances are made up in kind, in accordance with the terms of the tariff.

Imbalances due from others are reported on the consolidated balance sheet as either accounts receivable or receivable from Partners and their affiliated companies. Imbalances owed to others are reported on the consolidated balance sheet as either accounts payable or payable to Partners and their affiliated companies. Imbalances are expected to settle within a year.

Gas Utility Plant and Depreciation

Gas utility plant is stated at cost and includes certain administrative and general expenses, plus an allowance for funds used during construction. The Partnership capitalizes major units of property replacements or improvements and expenses minor items. The cost of plant retired is charged to accumulated depreciation. Depreciation of gas utility plant is computed using the straight-line method. The Partnership’s principal operating assets are depreciated at an annual rate of 2.75%.

The allowance for funds used during construction represents the debt and equity costs of capital funds applicable to utility plant under construction, calculated in accordance with a uniform formula prescribed by the FERC. The rates used were 10.37%, 10.50% and 10.49% for years 2006, 2005, and 2004, respectively.

Asset Retirement Obligations

In the fourth quarter of 2005, the Partnership adopted Financial Accounting Standards Board Interpretation (FIN) No. 47, Accounting for Conditional Asset Retirement Obligations. FIN No. 47 requires companies to record a liability for those asset retirement obligations in which the timing or amount of settlement of the obligations are uncertain. These conditional obligations were not addressed by SFAS No 143, Accounting for Asset Retirement Obligations, which the Partnership adopted on January 1, 2003. FIN No. 47 requires accrual of a liability when a range of scenarios indicates that the potential timing or settlement amounts of conditional asset retirement obligations can be determined. The Partnership has asset retirement obligations if it were to permanently retire all or part of the pipeline system; however, the amount of asset retirement obligations cannot be reasonably estimated because the end of the pipeline system life is not determinable with the degree of accuracy necessary to currently establish a liability for the obligation.

Accounting for Pipeline Integrity Costs

Prior to January 1, 2006, the Partnership capitalized certain costs incurred related to its pipeline integrity assessment programs as part of Property, Plant and Equipment. In June 2005, the FERC issued an order on Accounting for Pipeline Assessment Costs which generally requires pipeline inspections and assessments incurred after January 1, 2006 to be expensed. The Partnership expensed $2,400,000 of pipeline integrity costs in 2006.

Uncertain Income Tax Positions

In July 2006, the Financial Accounting Standards Board (FASB) issued FIN 48, “Accounting for Uncertainty in Income Taxes.” FIN 48 prescribes a comprehensive model for how a company should recognize, measure, present, and disclose in its financial statements uncertain income tax positions taken or expected to be taken on a tax return. FIN 48 also requires significant new annual disclosures. FIN 48 is effective beginning January 1, 2007. The Partnership is currently determining the effect of FIN 48 on the consolidated financial statements but does not expect it to have a material impact.

Notes to Consolidated Financial Statements

2 Summary of Significant Accounting Policies, Continued

Fair Value Measurements

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements”, which provides guidance on measuring the fair value of assets and liabilities in the financial statements. This standard is effective in 2008. The Partnership is currently evaluating the impact of SFAS No. 157, if any, on the consolidated financial statements.

Income Taxes

The Partnership’s tariff includes an allowance for income taxes, which the FERC requires the Partnership to record as if it were a corporation. Income taxes are deducted in the Consolidated Statements of Income and the current portion of income taxes is returned to partners’ capital. Recorded current income taxes are distributed to partners based on their ownership percentages.

Amounts equivalent to deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases at currently enacted income tax rates.

3 Affiliated Company Transactions

Affiliated company amounts included in the Partnership’s consolidated financial statements, not otherwise disclosed, are as follows:


	(In Thousands)
	2006		2005		2004
Transportation revenues:
TransCanada PipeLines Limited and affiliates	$	150,067		156,561		164,810
El Paso Corporation and affiliates		11,538		17,235		20,581

Affiliated transportation revenues are primarily provided under fixed priced contracts with remaining terms ranging from 1 to 10 years.

The Partnership reimburses the Company for salaries, benefits and other incurred expenses. Benefits include pension, savings plan, and other post-retirement benefits. Operating expenses charged by the Company in 2006, 2005 and 2004 were $16,056,000, $18,636,000 and $17,388,000, respectively.

The Company makes contributions for eligible employees of the Company to a voluntary defined contribution plan sponsored by El Paso Corporation. The Company’s contributions, which are based on matching employee contributions, amounted to $592,000, $1,008,000, and $475,000 in 2006, 2005 and 2004, respectively.

Notes to Consolidated Financial Statements

3 Affiliated Company Transactions, Continued

The Company participates in a cash balance pension plan sponsored by El Paso Corporation and a post-retirement plan. The Company accounts for pension and post-retirement benefits on an accrual basis. The net expense (income) for each of the plans is as follows:


	(In Thousands)
	2006			2005			2004
Pension	$	(2,186	)		(297	)		(743	)
Post-Retirement		151			179			202

4 Debt


	(In Thousands)
	2006		2005
Senior Notes, unsecured, interest due semiannually, principal due as follows:
8.74% series, due 2007 to 2011	$	50,000		60,000
9.09% series, due 2012 to 2021		100,000		100,000
6.73% series, due 2009 to 2018		90,000		90,000
6.95% series, due 2019 to 2028		110,000		110,000
8.08% series, due 2021 to 2030		100,000		100,000


		450,000		460,000
Less current maturities		10,000		10,000


Total long term debt less current maturities	$	440,000		450,000

The aggregate estimated fair value of long term debt was $516,698,000 and $547,433,000 for 2006 and 2005, respectively. The fair value is determined using discounted cash flows based on the Partnership’s estimated current interest rates for similar debt.

The aggregate annual required repayments of Senior Notes are $10,000,000 in 2007 and 2008 and $19,000,000 for each year 2009 through 2011.

Under the most restrictive covenants in the Senior Note Agreements, approximately $242,000,000 of partners’ capital is restricted as to distributions as of December 31, 2006.

Notes to Consolidated Financial Statements

5 Income Taxes Payable by Partners

Income taxes payable by partners for the years ended December 31, 2006, 2005 and 2004 consists of:


	(In Thousands)
	2006		2005		2004
Current
Federal	$	37,579		31,815		30,187
State		1,680		1,422		1,349

		39,259		33,237		31,536

Deferred
Federal		4,611		9,588		14,833
State		206		428		689

		4,817		10,016		15,522

	$	44,076		43,253		47,058

Income taxes payable by partners differs from the statutory rate of 35% due to the amortization of excess deferred taxes along with the effects of state and local taxes. The Partnership was required by FERC to amortize excess deferred taxes which had previously been accumulated at tax rates in excess of current statutory rates. Such amortization reduced income taxes payable by partners by $575,000 in 2004. These excess deferred taxes were fully amortized at December 31, 2004.

The deferred tax assets and deferred tax liabilities as of December 31, 2006 and 2005 are as follows:


	(In Thousands)
	2006			2005
Deferred tax assets — other	$	4,924			4,674
Deferred tax liabilities — utility plant		(258,537	)		(254,752	)
Deferred tax liabilities — other		(16,902	)		(16,114	)

Net deferred tax liability	$	(270,515	)		(266,192	)

As of December 31, 2006 and 2005, no valuation allowance is required.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, ANR Pipeline Company has duly caused this report to be signed on its behalf by the undersigned thereunto, duly authorized on the 21^st day of February 2007.

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


Signature	Title	Date

/S/ STEPHEN C. BEASLEY Stephen C. Beasley	President and Director (Principal Executive Officer)	February 21, 2007

/S/ JOHN R. SULT John R. Sult	Senior Vice President, Chief Financial Officer and Controller (Principal Accounting and Financial Officer)	February 21, 2007

/S/ JAMES C. YARDLEY	Chairman of the Board	February 21, 2007
James C. Yardley

/S/ DANIEL B. MARTIN	Senior Vice President and Director	February 21, 2007
Daniel B. Martin

/S/ GARY C. CHARETTE	Vice President and Director	February 21, 2007
Gary C. Charette

ANR PIPELINE COMPANY

EXHIBIT INDEX
December 31, 2006

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


Exhibit
Number		Description
3.A		Amended and Restated Certificate of Incorporation dated March 7, 2002 (Exhibit 3.A to our 2001 Form 10-K).

3.B		By-laws dated June 24, 2002 (Exhibit 3.B to our 2002 Form 10-K).

*4.A		Indenture dated as of May 13, 1991 between ANR Pipeline Company and The Bank of New York Trust Company, N.A., successor to Manufacturers Bank, N.A., as Trustee.

*4.A.1		First supplemental indenture dated as of November 4, 1991 between ANR Pipeline Company and The Bank of New York Trust Company, N.A., successor to Manufacturers Bank, N.A., as Trustee.

4.B		Indenture dated as of February 15, 1994 and First Supplemental Indenture dated as of February 15, 1994 (Exhibit 4.A to our 2004 Form 10-K).

4.C		Indenture dated as of March 5, 2003 between ANR Pipeline Company and The Bank of New York Trust Company, N.A., successor to The Bank of New York, as Trustee (Exhibit 4.1 to our Form 8-K filed March 5, 2003).

4.D		First Supplemental Indenture dated as of January 29, 2007, by and between ANR Pipeline Company and The Bank of New York Trust Company, N.A., as Trustee to indenture dated as of March 5, 2003 (Exhibit 10.A to our Form 8-K filed February 21, 2007).

10.A		First Tier Receivables Sale Agreement dated August 31, 2006 between ANR Pipeline Company, and ANR Finance Company, L.L.C. (Exhibit 10.A to our Form 8-K filed September 8, 2006).

10.B		Second Tier Receivables Sale Agreement dated August 31, 2006 between ANR Finance Company, L.L.C. and ANR Funding Company, L.L.C. (Exhibit 10.B to our Form 8-K filed September 8, 2006).

10.C		Receivables Purchase Agreement dated August 31, 2006 among ANR Funding Company, L.L.C., as Seller, ANR Pipeline Company, as Servicer, Starbird Funding Corporation, as the initial Conduit Investor and Committed Investor, the other investors from time to time parties thereto, BNP Paribas, New York Branch, as the initial Managing Agent, the other Managing Agents from time to time parties thereto, and BNP Paribas, New York Branch, as Program Agent (Exhibit 10.C to our Form 8-K filed September 8, 2006).

10.D		Purchase and Sale Agreement dated December 21, 2006, by and between ANR Capital Corporation and Seafarer U.S. Pipeline System, Inc. (Exhibit 10.A to our Form 8-K filed December 28, 2006).

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

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

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

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

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


Balance at January 1, 2006	$	27
Additions/adjustments for remediation activities		5
Payments for remediation activities		(7	)

Balance at December 31, 2006	$	25


									Accumulated		Notes
					Additional				other		receivable			Total
	Common stock				paid-in		Retained		comprehensive		from			stockholder’s
	Shares		Amount		capital		earnings		income		affiliates			equity
January 1, 2004		1,000	$	—	$	597	$	186	$	—	$	—		$	783
Net income								117							117

December 31, 2004		1,000		—		597		303		—		—			900
Net income								147							147

December 31, 2005		1,000		—		597		450		—		—			1,047
Capital contribution						334									334
Net income								152							152
Adoption of SFAS No. 158, net of taxes of $6										10					10
Notes receivable from affiliates												(594	)		(594	)

December 31, 2006		1,000	$	—	$	931	$	602	$	10	$	(594	)	$	949


	Quarters Ended
	March 31		June 30		September 30		December 31			Total
	(In millions)
2006
Operating revenues	$	180	$	114	$	111	$	135		$	540
Operating income		107		33		34		60			234
Net income		72		25		26		29			152

2005
Operating revenues	$	184	$	119	$	112	$	133		$	548
Operating income		102		47		33		35			217
Income before cumulative effect of accounting change		66		32		23		27			148
Cumulative effect of accounting change, net of income taxes		—		—		—		(1	)		(1	)
Net income		66		32		23		26			147


	Balance at		Charged to					Charged to			Balance
	Beginning		Costs and					Other			at End
Description	of Period		Expenses		Deductions			Accounts			of Period
2006
Allowance for doubtful accounts	$	2	$	—	$	(1	)	$	(1	)⁽¹⁾	$	—
Environmental reserves		27		5		(7	)⁽²⁾		—			25

2005
Allowance for doubtful accounts	$	3	$	—	$	—		$	(1	)	$	2
Environmental reserves		27		4		(4	)⁽²⁾		—			27

2004
Allowance for doubtful accounts	$	3	$	—	$	—		$	—		$	3
Environmental reserves		29		2		(4	)⁽²⁾		—			27


⁽¹⁾		Due to the accounts receivable sales program.

⁽²⁾		Primarily payments made for environmental remediation activities.