UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

____________________

Form 10-K

(Mark One)

R	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the fiscal year ended December 31, 2008
	OR
£	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number 1-4874

Colorado Interstate Gas Company

(Exact Name of Registrant as Specified in Its Charter)

Delaware	84-0173305
(State or Other Jurisdiction of	(I.R.S. Employer
Incorporation or Organization)	Identification No.)
El Paso Building	77002
1001 Louisiana Street	(Zip Code)
Houston, Texas
(Address of Principal Executive Offices)

Telephone Number: (713) 420-2600

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

Title of each class	Name of each exchange on which registered
6.85% Senior Debentures, due 2037	New York Stock Exchange

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes 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, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o Accelerated filer o Non-accelerated filer þ (Do not check if a smaller reporting company) Smaller Reporting Company o

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

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

Documents Incorporated by Reference: None

COLORADO INTERSTATE GAS COMPANY

TABLE OF CONTENTS

			Caption	Page
PART I
Item 1.		Business		1
Item 1A.		Risk Factors		5
Item 1B.		Unresolved Staff Comments		12
Item 2.		Properties		12
Item 3.		Legal Proceedings		13
Item 4.		Submission of Matters to a Vote of Security Holders		13
PART II
Item 5.		Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		14
Item 6.		Selected Financial Data		14
Item 7.		Management’s Discussion and Analysis of Financial Condition and Results of Operations		15
Item 7A.		Quantitative and Qualitative Disclosures About Market Risk		22
Item 8.		Financial Statements and Supplementary Data		23
Item 9.		Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		45
Item 9A.		Controls and Procedures		45
Item 9A(T).		Controls and Procedures		45
Item 9B.		Other Information		45
PART III
Item 10.	Directors, Executive Officers and Corporate Governance			46
Item 11.	Executive Compensation			47
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			48
Item 13.	Certain Relationships and Related Transactions, and Director Independence			48
Item 14.	Principal Accountant Fees and Services			50
PART IV
Item 15.		Exhibits and Financial Statement Schedules		51
		Signatures		52

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

/d	=	per day	MDth	=	thousand dekatherms
BBtu	=	billion British  thermal units	MMcf	=	million cubic feet
Bcf	=	billion cubic feet	NGL	=	natural gas liquid
Dth	=	dekatherm

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 “CIG”, we are describing Colorado Interstate Gas Company and/or our subsidiaries.

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PART I

ITEM 1. BUSINESS

Overview and Strategy

We are a Delaware general partnership, originally formed in 1927 as a corporation. We are owned 60 percent indirectly through a wholly owned subsidiary of El Paso Corporation (El Paso) and 40 percent by EPPP CIG GP Holdings, L.L.C., a subsidiary of El Paso Pipeline Partners, L.P., El Paso’s master limited partnership (MLP). El Paso’s MLP was formed in November 2007 at which time El Paso contributed 10 percent of its interest in us to the MLP. In September 2008, El Paso’s MLP acquired an additional 30 percent ownership interest in us from El Paso. Our primary business consists of the interstate transportation, storage and processing of natural gas. We conduct our business activities through our natural gas pipeline system, storage facilities, processing plants and our 50 percent ownership interest in WYCO Development LLC (WYCO).

In November 2007, in conjunction with the formation of El Paso’s MLP, we distributed 100 percent of Wyoming Interstate Company, Ltd. (WIC) to the MLP and certain other assets to El Paso. We have reflected these operations as discontinued operations in our financial statements for periods prior to their distribution. For a further discussion of these discontinued operations, see Part II, Item 8, Financial Statements and Supplementary Data, Note 2. In addition, effective November 1, 2007, we converted our legal structure into a general partnership, and are no longer subject to income taxes. Accordingly, we settled our then existing current and deferred tax balances through El Paso’s cash management program pursuant to our tax sharing agreement with El Paso.

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

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

• Developing new growth projects in our market and supply areas;

• Successfully executing on our backlog of committed expansion projects;

• Focusing on efficiency and synergies across our system;

• Ensuring the safety of our pipeline system and assets;

• Successfully recontracting expiring transportation capacity; and

• Providing outstanding customer service.

Pipeline System. Our pipeline system consists of approximately 4,100 miles of pipeline with a design capacity of approximately 3,920 MMcf/d. During 2008, 2007 and 2006, average throughput was 2,225 BBtu/d, 2,339 BBtu/d and 2,008 BBtu/d. This system extends from production areas in the U.S. Rocky Mountains and the Anadarko Basin directly to customers in Colorado, Wyoming and indirectly to the midwest, southwest, California and the Pacific northwest.

Storage and Processing Facilities. Along our pipeline system, we have four storage fields in Colorado and Kansas with approximately 29 Bcf of underground working natural gas storage capacity. In addition, we have two processing plants located in Wyoming and Utah.

WYCO. We own a 50 percent interest in WYCO, a joint venture with an affiliate of Public Service Company of Colorado (PSCo). In November 2008, the High Plains pipeline was placed in service, which is owned by WYCO and operated by us. The High Plains pipeline consists of a 164-mile interstate gas pipeline extending from the Cheyenne Hub in northeast Colorado to PSCo’s Fort St. Vrain electric generation plant and other points of interconnections with PSCo’s system. The system added approximately 900 MMcf/d of overall transportation capacity to our system. The increased capacity is fully contracted with PSCo and Coral Energy Resources pursuant to firm contracts through 2029 and 2019. WYCO also owns a state regulated intrastate gas pipeline that extends from the Cheyenne Hub in northeast Colorado to PSCo’s Fort St. Vrain’s electric generation plant, which we do not operate and a compressor station operated by an affiliate.

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FERC Approved Storage Expansion Project. As of December 31, 2008, we had the following FERC-approved expansion project. For a further discussion of our other expansion projects, see Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Project	Capacity	Description	Anticipated Completion or In-Service Date
Totem Gas Storage(1)	7 Bcf(2)	To develop a natural gas storage field that services and interconnects with the High Plains pipeline having 10.7 Bcf of natural gas storage capacity, of which 7 Bcf will be working gas capacity, with a maximum withdrawal rate of 200MMcf/d and a maximum injection rate of 100 MMcf/d.	July 2009

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(1) This joint project between us and an affiliate of PSCo will be operated by us and owned by WYCO.

(2) All of the working storage capacity is fully contracted with PSCo to cover the cost of service (including a return on investment) pursuant to a firm contract through 2040.

Markets and Competition

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

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

Our system serves two major markets, an on-system market, consisting of utilities and other customers located along the Front Range of the U.S. Rocky Mountains in Colorado and Wyoming, and an off-system market, consisting of the transportation of U.S. Rocky Mountain natural gas production from multiple supply basins to users accessed through interconnecting pipelines in the midwest, southwest, California and the Pacific northwest. Recent growth in the on-system market from both the space heating segment and electric generation segment has provided us with incremental demand for transportation services.

We expect growth of the natural gas market will be adversely affected by the current economic recession in the U. S. and global economies. The decline in economic activity will reduce industrial demand for natural gas and electricity, which will cause lower natural gas demand both directly in end-use markets and indirectly through lower power generation demand for natural gas. The demand for natural gas and electricity in the residential and commercial segments of the market will likely be less affected by the economy. The lower demand and the credit restrictions on investments in the current environment may also slow development of supply projects. While our pipeline could experience some level of reduced throughput and revenues, or slower development of expansion projects as a result of these factors, we generate a significant (greater than 80 percent) portion of our revenues through fixed monthly reservation or demand charges on long-term contracts at rates stipulated under our tariff. Additionally, we do not expect production in the U.S. Rocky Mountain region to significantly decrease from current levels due to the need to replace diminishing exports from Canada and declining production from traditional domestic sources.

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

Competition for our on-system market consists of an intrastate pipeline, an interstate pipeline, local production from the Denver-Julesburg basin, and long-haul shippers who elect to sell into this market rather than the off-system market. Competition for our off-system market consists of other interstate pipelines, including WIC, that are directly connected to our supply sources. CIG faces competition from other existing pipelines and alternative energy sources that are used to generate electricity such as hydroelectric power, wind, solar, coal and fuel oil.

Our most direct competitor in the U.S. Rocky Mountain region is the Rockies Express Pipeline. The Rockies Express Pipeline is being constructed in three phases with a planned terminus in Clarington, Ohio. The first two phases have been placed in service. The Rockies Express Pipeline could result in significant downward pressure on natural gas transportation prices in the U.S. Rocky Mountain region and in additional discounting on our system.

The following table details our customer and contract information related to our pipeline system as of December 31, 2008. Firm customers reserve capacity on our pipeline system and storage facilities and are obligated to pay a monthly reservation or demand charge, regardless of the amount of natural gas they transport or store, for the term of their contracts. Interruptible customers are customers without reserved capacity that pay usage charges based on the volume of gas they transport, store, inject or withdraw.

Customer Information	Contract Information
Approximately 120 firm and interruptible customers.	Approximately 170 firm transportation contracts. Weighted average remaining contract term of approximately eight years.
Major Customers: PSCo (5 BBtu/d) (1,764 BBtu/d)	Expires in 2009. Expires in 2012 — 2029.
Williams Gas Marketing, Inc.
(37 BBtu/d)	Expires in 2009.
(113 BBtu/d)	Expires in 2010.
(175 BBtu/d)	Expires in 2011.
(175 BBtu/d)	Expires in 2013.
Anadarko Petroleum Corporation
(11 BBtu/d)	Expires in 2009.
(80 BBtu/d)	Expires in 2010.
(24 BBtu/d)	Expires in 2011.
(164 BBtu/d)	Expires in 2012— 2015.

Regulatory Environment

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

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

• certification and construction of new facilities;

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• extension or abandonment of services and facilities;

• maintenance of accounts and records;

• relationships between pipelines and certain affiliates;

• terms and conditions of service;

• depreciation and amortization policies;

• acquisition and disposition of facilities; and

• initiation and discontinuation of services.

Our interstate pipeline system is also subject to federal, state and local safety and environmental statutes and regulations of the U.S. Department of Transportation and the U.S. Department of the Interior. We have ongoing inspection programs designed to keep our facilities in compliance with pipeline safety and environmental requirements and we believe that our system is in material compliance with the applicable regulations.

Environmental

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

Employees

We do not have employees. Following our reorganization, our former employees continue to provide services to us through an affiliated service company owned by our general partner, El Paso. We are managed and operated by officers of El Paso, our general partner. We have an omnibus agreement with El Paso and its affiliates under which we reimburse El Paso for the provision of various general and administrative services for our benefit and for direct expenses incurred by El Paso on our behalf.

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ITEM 1A. RISK FACTORS

CAUTIONARY STATEMENT FOR PURPOSES OF THE “SAFE HARBOR” PROVISIONS OF

THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

This report contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These forward-looking statements are based on assumptions or beliefs that we believe to be reasonable; however, assumed facts almost always vary from actual results, and differences between assumed facts and actual results can be material, depending upon the circumstances. Where, based on assumptions, we or our management express an expectation or belief as to future results, that expectation or belief is expressed in good faith and is believed to have a reasonable basis. We cannot assure you, however, that the stated expectation or belief will occur, be achieved or accomplished. The words “believe,” “expect,” “estimate,” “anticipate,” and similar expressions will generally identify forward-looking statements. All of our forward-looking statements, whether written or oral, are expressly qualified by these cautionary statements and any other cautionary statements that may accompany such forward-looking statements. In addition, we disclaim any obligation to update any forward-looking statements to reflect events or circumstances after the date of this report.

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

Risks Related to Our Business

Our success depends on factors beyond our control.

The financial results of our transportation and storage operations are impacted by the volumes of natural gas we transport or store and the prices we are able to charge for doing so. The volume of natural gas and NGL we are able to transport and store depends on the actions of third parties, including our customers, and is beyond our control. Further, the following factors, most of which are also beyond our control, may unfavorably impact our ability to maintain or increase current throughput, or to remarket unsubscribed capacity on our pipeline system:

• service area competition;

• price competition;

• expiration or turn back of significant contracts;

• changes in regulation and actions of regulatory bodies;

• weather conditions that impact natural gas throughput and storage levels;

• weather fluctuations or warming or cooling trends that may impact demand in the markets in which we do business, including trends potentially attributed to climate change;

• drilling activity and decreased availability of conventional gas supply sources and the availability and timing of other natural gas supply sources;

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

• decreased natural gas demand due to various factors, including economic recession (as further discussed below) and increases in prices;

• legislative, regulatory or judicial actions, such as mandatory greenhouse gas regulations and/or legislation, that could result in (i) changes in the demand for natural gas and oil, (ii) changes in the availability of or demand for alternative energy sources such as hydroelectric and nuclear power, wind and solar and/or (iii) changes in the demand for less carbon intensive energy sources;

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• availability and cost to fund ongoing maintenance and growth projects, especially in periods of prolonged economic decline;

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

• adverse general economic conditions including prolonged recessionary periods that might negatively impact natural gas demand and the capital markets; and

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

A substantial portion of our revenues are generated from firm transportation contracts that must be renegotiated periodically.

Our revenues are generated under transportation and storage contracts which expire periodically and must be renegotiated, extended or replaced. If we are unable to extend or replace these contracts when they expire or renegotiate contract terms as favorable as the existing contracts, we could suffer a material reduction in our revenues, earnings and cash flows. For additional information on the expiration of our contract portfolio, see Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations. In particular, our ability to extend and replace contracts could be adversely affected by factors we cannot control, including:

• competition by other pipelines, including the change in rates or upstream supply of existing pipeline competitors, as well as the proposed construction by other companies of additional pipeline capacity in markets served by our interstate pipeline;

• changes in state regulation of local distribution companies, which may cause them to negotiate short-term contracts or turn back their capacity when their contracts expire;

• reduced demand and market conditions in the areas we serve;

• the availability of alternative energy sources or natural gas supply points; and

• legislative and/or regulatory actions.

For 2008, our revenues with PSCo represented approximately 28 percent of our operating revenues. For additional information on our revenues from PSCo, see Part II, Item 8, Financial Statements and Supplementary Data, Note 9. The loss of this customer or a decline in its creditworthiness could adversely affect our results of operations, financial position and cash flows.

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

We are subject to the risk of delays in payment as well as losses resulting from nonpayment and/or nonperformance by our customers, including default risk associated with adverse economic conditions. Our credit procedures and policies may not be adequate to fully eliminate customer credit risk. If we fail to adequately assess the creditworthiness of our existing or future customers, and they fail to pay and/or perform due to an unanticipated deterioration intheir creditworthiness and we are unable to remarket the capacity, our business, the results of our operations and our financial condition could be adversely affected. We may not be able to effectively remarket capacity during and after insolvency proceedings involving a shipper.

Fluctuations in energy commodity prices could adversely affect our business.

Revenues generated by our transportation and storage contracts depend on volumes and rates, both of which can be affected by the price of natural gas. Increased prices could result in a reduction of the volumes transported by our customers, including power companies that may not dispatch natural gas-fired power plants if natural gas prices increase. Increased prices could also result in industrial plant shutdowns or load losses to competitive fuels as well as local distribution companies’ loss of customer base. The success of our transmission and storage operations is subject to continued development of additional gas supplies to offset the natural decline from existing wells connected to our system, which requires the development of additional oil and natural gas reserves and obtaining additional supplies from interconnecting pipelines, primarily in the U.S. Rocky Mountain region. A decline in energy prices could cause a decrease in these development activities and could cause a decrease in the volume of reserves available for transmission and storage through our system.

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Pricing volatility may, in some cases, impact the value of under or over recoveries of retained natural gas, as well as imbalances, cashouts and system encroachments. We obtain in-kind fuel reimbursements from shippers in accordance with each individual tariff or applicable contract terms. We revalue our natural gas imbalances and other gas owed to shippers (such as excess fuel retention) to an index price and periodically settle these obligations in cash or in-kind pursuant to each individual tariff or balancing contract. Currently, our tariff provides that the volumetric difference between fuel retained and fuel burned will be flowed-through or charged to shippers and provides for collection or payback of the income impact of the timing of financial results of such fuel and related imbalances. We are currently litigating a protested filing of such timing value collection. Our tariff provides that all liquid revenue proceeds, including those proceeds associated with our processing plants, are used to reimburse shrinkage or other system fuel and lost-or-unaccounted-for costs and variations in liquid revenues and variations in shrinkage volumes are included in the reconciliation of retained fuel and burned fuel. We must purchase gas volumes from time to time due, in part, to such shrinkage associated with liquid production and such expenses vary with both price and quantity.

If natural gas prices in the supply basins connected to our pipeline system are higher than prices in other natural gas producing regions, our ability to compete with other transporters may be negatively impacted on a short-term basis, as well as with respect to our long-term recontracting activities. Furthermore, fluctuations in pricing between supply sources and market areas could negatively impact our transportation revenues. As a result, significant prolonged changes in natural gas prices could have a material adverse effect on our financial condition, results of operations and liquidity. Fluctuations in energy prices are caused by a number of factors, including:

• regional, domestic and international supply and demand;

• availability and adequacy of transportation facilities;

• energy legislation and regulation;

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

• abundance of supplies of alternative energy sources; and

• political unrest among countries producing oil.

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

Our business is regulated by the FERC, the U.S. Department of Transportation, the U.S. Department of the Interior and various state and local regulatory agencies whose actions have the potential to adversely affect our profitability. In particular, the FERC regulates the rates we are permitted to charge our customers for our services and sets authorized rates of return.

In April 2008, the FERC adopted a new policy that will allow master limited partnerships to be included in rate of return proxy groups for determining rates for services provided by interstate natural gas and oil pipelines. The FERC uses a discounted cash flow model that incorporates the use of proxy groups to develop a range of reasonable returns earned on equity interests in companies with corresponding risks. The FERC then assigns a rate of return on equity within that range to reflect specific risks of that pipeline when compared to the proxy group companies. The FERC’s policy statement concludes among other items that (i) there should be no cap on the level of distributions included in the current discounted cash flow methodology and (ii) there should be a downward adjustment to the long-term growth rate used for the equity cost of capital of natural gas pipeline master limited partnerships. Pursuant to the FERC’s jurisdiction over rates, existing rates may be challenged by complaint, and proposed rate increases may be challenged by protest. A successful complaint or protest against our rates could have an adverse impact on our revenues.

In a January 15, 2009 decision that discussed an individual pipeline’s rate of return, the FERC analyzed the operations of each company proposed for inclusion in that pipeline’s proxy group to determine whether each company to be included had commensurate risks to the pipeline whose rates were being determined. The FERC included in that proxy group two primarily gas pipeline master limited partnerships (with the adjusted gross domestic product) and a diversified company that had higher risk exploration, production and trading operations in addition to pipeline operations. Companies whose distribution, electric or natural gas liquids operations exceeded pipeline operations were excluded. In light of this, it is expected that pipeline returns on equity will be driven largely by fact-based proxy group determinations in each case.

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The FERC currently allows partnerships and other pass through entities to include in their cost-of-service an income tax allowance. Any changes to the FERC’s treatment of income tax allowances in cost-of-service and to potential adjustment in a future rate case of our equity rate of return may cause our rates to be set at a level that is different from those currently in place and in some instances lower than the level otherwise in effect.

Also, increased regulatory requirements relating to the integrity of our pipeline requires additional spending in order to maintain compliance with these requirements. Any additional requirements that are enacted could significantly increase the amount of these expenditures. Further, state agencies that regulate our local distribution company customers could impose requirements that could impact demand for our services.

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

Our operations are subject to various environmental laws and regulations regarding compliance and remediation obligations. Compliance obligations can result in significant costs to install and maintain pollution controls, fines and penalties resulting from any failure to comply and potential limitations on our operations. Remediation obligations can result in significant costs associated with the investigation or clean up of contaminated properties (some of which have been designated as Superfund sites by the U. S. Environmental Protection Agency (EPA) under the Comprehensive Environmental Response, Compensation and Liability Act), as well as damage claims arising out of the contamination of properties or impact on natural resources. Although we believe we have established appropriate reserves for our environmental liabilities, it is not possible for us to estimate the exact amount and timing of all future expenditures related to environmental matters and we could be required to set aside additional amounts which could significantly impact our future consolidated results of operations, financial position, or cash flows. See Item 3, Legal Proceedings and Part II, Item 8, Financial Statements and Supplementary Data, Note 7.

In estimating our environmental liabilities, we face uncertainties that include:

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

• discovering new sites or additional information at existing sites;

• receiving regulatory approval for remediation programs;

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

• evaluating and understanding environmental laws and regulations, including their interpretation and enforcement; and

• changing environmental laws and regulations that may increase our costs.

In addition to potentially increasing the cost of our environmental liabilities, changing environmental laws and regulations may increase our future compliance costs, such as the costs of complying with ozone standards and potential mandatory greenhouse gas reporting and emission reductions. Future environmental compliance costs relating to greenhouse gases (GHGs) associated with our operations are not yet clear. Legislative and regulatory measures to address GHG emissions are in various phases of discussions or implementation at the international, national, regional and state levels. Various federal and state legislative proposals have been made over the last several years and it is possible that legislation may be enacted in the future that could negatively impact our operations and financial results. The level of such impact will likely depend upon whether any of our facilities will be directly responsible for compliance with GHG regulations and legislation; whether federal legislation will preempt any potentially conflicting state/ regional GHG programs; whether cost containment measures will be available; the ability to recover compliance costs from our customers; and the manner in which allowances are provided. At the federal regulatory level, the EPA has requested public comments on the potential regulation of GHGs under the Clean Air Act. Some of the regulatory alternatives identified by the EPA in its request for comments, if eventually promulgated as final rules, would likely impact our operations and financial results. It is uncertain whether the EPA will proceed with adopting final rules or whether the regulation of GHGs will be addressed in federal and state legislation.

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Legislation and regulation are also in various stages of discussion or implementation in many of the states and regions in which we operate, including the Western Climate Initiative (WCI) regarding a cap-and-trade program and target emission reductions. There is uncertainty regarding whether and to what extent each member state will adopt the WCI recommendations, and the details of the programs as eventually adopted may differ significantly among the member states. Therefore, it is not yet possible to determine whether the regulations implementing the WCI recommendations will be material to our operations or our financial results.

Finally, several lawsuits have been filed seeking to force the federal government to regulate GHG emissions and individual companies to reduce the GHG emissions from their operations. These and other lawsuits may also result in decisions by federal and state courts and agencies that impact our operations and ability to obtain certifications and permits to construct future projects.

Although it is uncertain what impact these legislative, regulatory, and judicial actions might have on us until further definition is provided in those forums, there is a risk that such future measures could result in changes to our operations and to the consumption and demand for natural gas. Changes to our operations could include increased costs to (i) operate and maintain our facilities, (ii) install new emission controls on our facilities, (iii) construct new facilities, (iv) acquire allowances to authorize our GHG emissions, (v) pay any taxes related to our GHG emissions and (vi) administer and manage a GHG emissions program. While we may be able to include some or all of the costs associated with our environmental liabilities and environmental and GHG compliance in the rates charged by our pipeline and in the prices at which we sell natural gas, our ability to recover such costs is uncertain and may depend on events beyond our control including the outcome of future rate proceedings before the FERC and the provisions of any final regulations and legislation.

Our operations are subject to operational hazards and uninsured risks.

Our operations are subject to the inherent risks normally associated with pipeline operations, including pipeline ruptures, explosions, pollution, release of toxic substances, fires, adverse weather conditions (such as flooding), terrorist activity or acts of aggression, and other hazards. Each of these risks could result in damage to or destruction of our facilities or damages or injuries to persons and property causing us to suffer substantial losses. Analyses performed by various governmental and private organizations indicate potential physical risks associated with climate change events (such as flooding, etc). Some of the studies indicate that potential impacts on energy infrastructure are highly uncertain and not well understood, including both the timing and potential magnitude of such impacts. As the science is better understood and analyzed, we will review the operational and uninsured risks to our facilities attributed to climate change.

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

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

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

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

• the ability to access sufficient capital at reasonable rates to fund expansion projects, especially in periods of prolonged economic decline when we may be unable to access the capital markets;

• the availability of skilled labor, equipment, and materials to complete expansion projects;

• potential changes in federal, state and local statutes, regulations and orders, including environmental requirements that prevent a project from proceeding or increase the anticipated cost of the project;

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

• our ability to construct projects within anticipated costs, including the risk that we may incur cost overruns resulting from inflation or increased costs of equipment, materials, labor, contractor productivity or other factors beyond our control, that we may not be able to recover from our customers which may be material;

• the lack of future growth in natural gas supply and/or demand; and

• the lack of transportation, storage or throughput commitments.

Any of these risks could prevent a project from proceeding, delay its completion or increase its anticipated costs. There is also the risk that the downturn in the economy and its negative impact upon natural gas demand may result in either slower development in our expansion projects or adjustments in the contractual commitments supporting such projects. As a result, new facilities may be delayed or may not achieve our expected investment return, which could adversely affect our results of operations, cash flows or financial position.

Competition from pipelines that may be able to provide our shippers with capacity at a lower price could cause us to reduce our rates or otherwise reduce our revenues.

We face competition from other pipelines that may be able to provide our shippers with capacity on a more competitive basis or access to consuming markets that would pay a higher price for the shippers’ gas. The Rockies Express Pipeline could result in significant downward pressure on natural gas transportation prices in the U.S. Rocky Mountain region.

An increase in competition in our key markets could arise from new ventures or expanded operations from existing competitors. As a result, significant competition from the Rockies Express Pipeline, other third-party competitors and WIC could have a material adverse effect on our financial condition, results of operations and ability to make distributions to our partners.

Adverse general domestic economic conditions could negatively affect our operating results, financial condition or liquidity.

We, El Paso, and its subsidiaries are subject to the risks arising from adverse changes in general domestic economic conditions including recession or economic slowdown. Recently, the U.S. economy has experienced recession and the financial markets have experienced extreme volatility and instability. In response to the volatility in the financial markets, El Paso has announced certain actions that are designed to reduce its need to access such financial markets, including reductions in the capital programs of certain of its operating subsidiaries and the sale of several non-core assets.

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 If we or El Paso experience prolonged periods of recession or slowed economic growth in the United States, demand growth from consumers for natural gas transported by us may continue to decrease, which could impact the development of our future expansion projects. Additionally, our or El Paso’s access to capital could continue to be impeded and the cost of capital we obtain could be higher. Finally, we are subject to the risks arising from changes in legislation and regulation associated with any such recession or prolonged economic slowdown, including creating preference for renewables, as part of a legislative package to stimulate the economy. Any of these events, which are beyond our control, could negatively impact our business, results of operations, financial condition, and liquidity.

We are subject to financing and interest rate risk.

Our future success, financial condition and liquidity could be adversely affected based on our ability to access capital markets and obtain financing at cost effective rates. This is dependent on a number of factors in addition to general economic conditions discussed above, many of which we cannot control, including changes in:

• our credit ratings;

• the structured and commercial financial markets;

• market perceptions of us or the natural gas and energy industry; and

• market prices for hydrocarbon products.

Risks Related to Our Affiliation with El Paso and the MLP

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

We are a majority owned subsidiary of El Paso.

As a majority owned subsidiary of El Paso, subject to limitations in our indentures, El Paso has substantial control over:

• decisions on our financing and capital raising activities;

• mergers or other business combinations;

• our acquisitions or dispositions of assets; and

• our participation in El Paso’s cash management program.

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

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

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

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

Due to our relationship with El Paso, adverse developments or announcements concerning El Paso or its other subsidiaries could adversely affect our financial condition, even if we have not suffered any similar development. The ratings assigned to El Paso’s senior unsecured indebtedness are below investment grade, currently rated Ba3 by Moody’s Investor Service, BB- by Standard & Poor’s and BB+ by Fitch Ratings. The ratings assigned to our senior unsecured indebtedness are currently investment grade, with a Baa3 rating by Moody’s Investor Service and a BBB- rating by Fitch Ratings. Standard & Poor’s has assigned a below investment grade rating of BB to our senior unsecured indebtedness. El Paso and its subsidiaries, including us, are (i) on a stable outlook with Moody’s Investor Service and Fitch Ratings and (ii) on a negative outlook with Standard & Poor’s. There is a risk that these credit ratings may be adversely affected in the future as the credit rating agencies continue to review our and El Paso’s leverage, liquidity and credit profile. Any reduction in our or El Paso’s credit ratings could impact our ability to access the capital markets, as well as our cost of capital.

El Paso provides cash management and other corporate services for us. We are currently required to make distributions of available cash as defined in our partnership agreement on a quarterly basis to our partners. In addition, we conduct commercial transactions with some of our affiliates. If El Paso or such affiliates are unable to meet their respective liquidity needs, we may not be able to access cash under the cash management program, or our affiliates may not be able to pay their obligations to us. However, we might still be required to satisfy any affiliated payables we have established. Our inability to recover any affiliated receivables owed to us could adversely affect our financial position and cash flows. For a further discussion of these matters, see Part II, Item 8, Financial Statements and Supplementary Data, Note 11.

Our relationship with El Paso and the MLP subjects us to potential conflicts of interest and they may favor their interests to the detriment of us.

Although El Paso has majority control of most decisions affecting our business, there are certain decisions that require the approval of both El Paso and the MLP, including material regulatory filings, any significant sale of our assets, mergers and certain changes in affiliated service agreements. Conflicts of interest or disagreements could arise between El Paso and the MLP with regard to such matters requiring unanimous approval, which could negatively impact our future operations.

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 business. We believe that our properties are adequate and suitable for the conduct of our business in the future.

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ITEM 3. LEGAL PROCEEDINGS

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

Natural Buttes. In May 2004, the EPA issued a Compliance Order to us related to alleged violations of a Title V air permit in effect at our Natural Buttes Compressor Station. In September 2005, the matter was referred to the U.S. Department of Justice (DOJ). We entered into a tolling agreement with the United States and conducted settlement discussions with the DOJ and the EPA. While conducting some testing at the facility, we discovered that three generators installed in 1992 may have been emitting oxides of nitrogen at levels which suggested the facility should have obtained a Prevention of Significant Deterioration (PSD) permit when the generators were first installed, and we promptly reported those test data to the EPA. We have reached an agreement with the DOJ under which we will pay a total of $1.02 million to settle all of these Title V and PSD issues at the Natural Buttes Compressor Station and, in addition, we will conduct ambient air monitoring in the Uintah Basin for a period of two years. We are working with the DOJ to draft and finalize a definitive settlement agreement. In January 2009, we filed an application with the FERC to abandon the facilities by sale.

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

None.

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PART II

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

All of our partnership interests are held by El Paso and the MLP and, accordingly, are not publicly traded. Prior to converting into a general partnership effective November 1, 2007, all of our common stock was held by El Paso.

We are required to make distributions to our partners of available cash as defined in our partnership agreement on a quarterly basis from legally available funds that have been approved for payment by our Management Committee. We made cash distributions to our partners of approximately $109 million in 2008. Additionally, in January 2009, we made a cash distribution of approximately $43 million to our partners. No dividends or cash distributions were declared or paid in 2007 or 2006.

ITEM 6. SELECTED FINANCIAL DATA

The following selected historical financial data should be read together with Item 7, Management’s Discussion and Analysis and Financial Condition and Results of Operations and Item 8, Financial Statements and Supplementary Data included in this Form 10-K. This information reflects our wholly owned subsidiary, WIC and certain other assets as discontinued operations for periods prior to their distribution. The information as of and for each of the years ended December 31, 2005, 2006, 2007 and 2008 was derived from our audited consolidated financial statements. The information as of and for the year ended December 31, 2004 was derived from unaudited financial statements. These selected historical results are not necessarily indicative of results to be expected in the future.

	As of or for the Year Ended December 31,
	2008		2007		2006		2005		2004
	(In million)
Operating Results Data:
Operating revenues	$	323	$	317	$	305	$	302	$	284
Operating income		153		145		143		109		120
Income from continuing operations		149		107		87		68		69
Financial Position Data:
Total assets	$	1,543	$	1,769	$	2,292	$	2,121	$	1,792
Total long-term debt and other financing obligations, less current maturities		580		575		600		700		100
Partners’ capital/stockholder’s equity		783		1,043		1,149		1,009		1,127

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

Our Management’s Discussion and Analysis (MD&A) should be read in conjunction with our consolidated financial statements and the accompanying footnotes. MD&A includes forward-looking statements that are subject to risks and uncertainties that may result in actual results differing from the statements we make. These risks and uncertainties are discussed further in Part I, Item 1A, Risk Factors. We have included a discussion in this MD&A of our business, growth projects, results of operations, liquidity, contractual obligations and critical accounting policies and estimates that may affect us as we operate in the future.

In November 2007, in conjunction with the formation of El Paso’s master limited partnership (MLP), we distributed 100 percent of Wyoming Interstate Company (WIC) to the MLP and certain other assets to El Paso. We have reflected these operations as discontinued operations in our financial statements for periods prior to their distribution. For a further discussion of these discontinued operations, see Item 8, Financial Statements and Supplementary Data, Note 2. In addition, effective November 1, 2007, we converted our legal structure into a general partnership, and are no longer subject to income taxes. Accordingly, we settled our then existing current and deferred tax balances through El Paso’s cash management program pursuant to our tax sharing agreement with El Paso.

Overview

Business. Our primary business consists of the interstate transportation, storage and processing of natural gas. Each of these businesses faces varying degrees of competition from other existing and proposed pipelines, as well as from alternative energy sources used to generate electricity, such as hydroelectric power, wind, solar, coal and fuel oil. Our revenues from transportation, storage and processing services consist of the following types.

Type	Description	Percent of Total Revenues in 2008(1)
Reservation	Reservation revenues are from customers (referred to as firm customers) that reserve capacity on our pipeline system and storage facilities. These firm customers are obligated to pay a monthly reservation or demand charge, regardless of the amount of natural gas they transport or store, for the term of their contracts.	81
Usage and Other	Usage revenues are from both firm customers and interruptible customers (those without reserved capacity) that pay usage charges based on the volume of gas actually transported, stored, injected or withdrawn. We also earn revenue from the processing and sale of natural gas liquids and other miscellaneous sources.	19

____________

(1) Total revenues include both tariff-based revenues as well as other revenues.  Our tariff-based revenues are 90 percent reservation and 10 percent usage and other. Other non-tariff based revenues include liquids revenue associates with our processing plants.

The FERC regulates the rates we can charge our customers. These rates are generally a function of the cost of providing services to our customers, including a reasonable return on our invested capital. Because of our regulated nature 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, changes in supply and demand, regulatory actions, competition, declines in the creditworthiness of our customers and weather. Effective March 1, 2008, we implemented a FERC-approved fuel and related gas cost recovery mechanism which is designed to recover all cost impacts, or flow through to shippers any revenue impacts, of all fuel imbalance revaluations and related gas balance items. In September 2008, the FERC issued an order accepting certain tariff changes effective October 1, 2008, subject to refund and the outcome of a technical conference. We are required to file a new general rate case with the FERC to be effective no later than October 2011.

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We continue to manage our recontracting process to mitigate the risk of significant impacts on our revenues from expiring contracts. Our ability to extend our existing customer contracts or remarket expiring contracted capacity is dependent on competitive alternatives, the regulatory environment at the federal, state and local levels and the market supply and demand factors at the relevant dates these contracts are extended or expire. The duration of new or renegotiated contracts will be affected by current prices, competitive conditions and judgments concerning future market trends and volatility. Subject to regulatory requirements, we attempt to recontract or remarket our capacity at the maximum rates allowed under our tariffs, although at times, we enter into firm transportation contracts at amounts that are less than these maximum allowable rates to remain competitive. Our existing contracts mature at various times and in varying amounts of throughput capacity. The weighted average remaining contract term for our active contracts is approximately eight years as of December 31, 2008. Below are the contract expiration portfolio and the associated revenue expirations for our firm transportation contracts as of December 31, 2008, including those with terms beginning in 2009 or later.

	BBtu/d		Percent of Total Contracted Capacity		Reservation Revenue		Percent of Total Reservation Revenue
					(In millions)
2009		95		2	$	8		3
2010		329		8		13		4
2011		317		8		19		6
2012		491		12		45		15
2013		1,082		26		81		27
2014 and beyond		1,827		44		133		45
Total		4,141		100	$	299		100

Projects Placed In Service. In November 2008, the High Plains pipeline was placed in service. We operate this pipeline, which is owned by WYCO, a joint venture with an affiliate of Public Service Company of Colorado (PSCo) in which we have a 50 percent ownership interest. The High Plains pipeline consists of a 164-mile 24” and 30” interstate gas pipeline system extending from the Cheyenne Hub in northeast Colorado to PSCo’s Fort St. Vrain electric generation plant and other points of interconnection with PSCo’s system. The system added approximately 900 MMcf/d of overall transportation capacity to our system. The increased capacity is fully contracted with PSCo and Coral Energy Resources pursuant to firm contracts through 2029 and 2019.

Growth Projects. We expect to spend approximately $204 million on contracted organic growth projects through 2013. Of this amount, approximately $109 million will be spent in 2009. Included in this amount are the Totem Gas Storage expansion project, which is a joint investment project with an affiliate of PSCo through our 50 percent ownership in WYCO, to develop storage facilities in Colorado, and the Raton 2010 expansion project. The information below provides further details of our growth projects.

• Totem Gas Storage. The Totem Gas Storage expansion project consists of the development of the Totem Gas Storage field, a natural gas storage field that services and interconnects with the High Plains pipeline. The Totem Gas Storage field will have 10.7 Bcf of natural gas storage capacity, of which 7 Bcf will be working gas capacity and 3.7 Bcf will be base gas capacity. The Totem Gas Storage expansion project has a 200 MMcf/d maximum withdrawal rate and 100 MMcf/d maximum injection rate. All of the storage capacity of this new storage field is fully contracted with PSCo pursuant to a firm contract through 2040. The FERC approved this project in April 2008 and construction began in June 2008. We will operate this storage facility when it is placed in service (estimated to be in July 2009) and it will be owned by WYCO. The estimated total cost of this project is $154 million, with $77 million to be paid by us.

• Raton 2010. The Raton 2010 expansion project will consist of approximately 118 miles of pipeline from the Raton Basin Wet Canyon Lateral to the south end of the Valley Line. This project will provide additional capacity of approximately 130 MMcf/d from the Raton Basin in southern Colorado to the Cheyenne Hub in northern Colorado. The estimated total cost of the project is $146 million. The estimated in-service date is June 2010. The tentative FERC filing date for this project is March 2009.

We believe that cash flows from operating activities combined with amounts available to us under El Paso’s cash management program or contributions from our partners, will be adequate to meet our capital requirements and our existing operating needs.

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Results of Operations

Our management uses earnings before interest expense and income taxes (EBIT) as a measure to assess the operating results and effectiveness of our business, which consists of consolidated operations as well as an investment in an unconsolidated affiliate. We believe EBIT is useful to investors because it allows them to evaluate more effectively our operating performance using the same performance measure analyzed internally by our management. We define EBIT as net income adjusted for (i) items that do not impact our income from continuing operations, such as discontinued operations, (ii) income taxes (prior to conversion to a partnership), (iii) interest and debt expense and (iv) affiliated interest income. We exclude interest and debt expense from this measure so that investors may evaluate our operating results without regard to our financing methods. EBIT may not be comparable to measurements used by other companies. Additionally, EBIT should be considered in conjunction with net income and other performance measures such as operating income or operating cash flows. Below is a reconciliation of our EBIT to net income, our throughput volumes and an analysis and discussion of our results in 2008 compared with 2007 and 2007 compared with 2006.

Operating Results:	2008			2007			2006
	(In millions, except for volumes)
Operating revenues	$	323		$	317		$	305
Operating expenses		(170	)		(172	)		(162	)
Operating income		153			145			143
Other income, net		11			5			2
EBIT		164			150			145
Interest and debt expense		(38	)		(49	)		(47	)
Affiliated interest income, net		23			50			41
Income taxes		—			(44	)		(52	)
Income from continuing operations		149			107			87
Discontinued operations, net of income taxes		—			42			48
Net income	$	149		$	149		$	135
Throughput volumes (BBtu/d)		2,225			2,339			2,008

EBIT Analysis:

	2008 to 2007												2007 to 2006
	Revenue			Expense			Other			EBIT Impact			Revenue			Expense			Other		EBIT Impact
	Favorable/(Unfavorable)
	(In millions)
Expansions	$	5		$	(1	)	$	7		$	11		$	—		$	—		$	—	$	—
Reservation revenues		2			—			—			2			21			—			—		21
Operational gas, revaluations and processing revenues		(2	)		6			—			4			(9	)		(3	)		—		(12	)
Operating and general and administrative expenses		—			(4	)		—			(4	)		—			(4	)		—		(4	)
Other(1)		1			1			(1	)		1			—			(3	)		3		—
Total impact on EBIT	$	6		$	2		$	6		$	14		$	12		$	(10	)	$	3	$	5

____________

(1) Consists of individually insignificant items.

Expansions. During the fourth quarter of 2008, we completed the construction of the High Plains pipeline and placed it in service. Although we transferred our title in the pipeline to WYCO (a joint venture with an affiliate of PSCo in which we have a 50 percent ownership interest) in 2008, we continue to reflect the High Plains pipeline as property, plant and equipment in our financial statements due to our continuing involvement with the pipeline through WYCO. Accordingly, we recognize all of the operating revenues and expenses of the High Plains pipeline in our operating results. For a further description of the transactions surrounding the High Plains pipeline and WYCO, see Item 8, Financial Statements, Note 6.

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Reservation Revenues. During the year ended December 31, 2008, increased demand for our off-system capacity resulted in higher reservation revenues as compared to 2007. During the year ended December 31, 2007, our transportation, reservation and usage revenues were higher than the same period in 2006 due to increased throughput resulting from colder weather in the first part of 2007, increased demand for our off-system capacity and increased rates that went into effect in October 2006 as a result of our most recent rate case.

Operational Gas, Revaluations and Processing Revenues. Effective March 1, 2008, we implemented a FERC-approved fuel and related gas cost recovery mechanism which is designed to recover all cost impacts, or flow through to shippers any revenue impacts, of all fuel imbalance revaluations and related gas balance items. We recorded a favorable fuel cost and revenue tracker estimated adjustment to reflect the effect of the order on our current fuel recovery filing period. This favorable adjustment was partially offset by an unfavorable adjustment as a result of a FERC order received in September 2008, which accepted certain tariff changes effective October 1, 2008, subject to refund and the outcome of a technical conference.

Natural gas prices were higher for the year ended December 31, 2007, which unfavorably impacted the revaluation of imbalances and other amounts owed to shippers compared with 2006.

Operating and General and Administrative Expenses. During the year ended December 31, 2008, our operating and general and administrative expenses increased primarily due to higher allocated costs from El Paso Natural Gas Company and Tennessee Gas Pipeline Company, our affiliates, associated with our shared pipeline services. During the year ended December 31, 2007, our operating and general and administrative expenses increased primarily due to higher repair and maintenance costs.

Interest and Debt Expense

Interest and debt expense for the year ended December 31, 2008 was $11 million lower than in 2007 primarily due to a lower average outstanding debt balance. Interest and debt expense for the year ended December 31, 2007 was $2 million higher than in 2006 primarily due to consent fees paid to bondholders to amend our indentures in conjunction with our conversion to a partnership.

Affiliated Interest Income, Net

Affiliated interest income, net for the year ended December 31, 2008 was $27 million lower than in 2007 primarily due to lower average advances due from El Paso under its cash management program and lower short-term interest rates. Affiliated interest income, net for the year ended December 31, 2007 was $9 million higher than in 2006 primarily due to higher average advances due from El Paso under its cash management program and higher short-term interest rates. The following table shows the average advances due from El Paso and the average short-term interest rates for the years ended December 31:

	2008			2007			2006
	(In millions, except for rates)
Average advance due from El Paso	$	534		$	819		$	737
Average short-term interest rate		4.4	%		6.2	%		5.7	%

Income Taxes

Effective November 1, 2007, we no longer pay income taxes as a result of our conversion into a partnership. Our effective tax rate of 29 percent for the year ended December 31, 2007 was lower than the statutory rate of 35 percent due to income not subject to income taxes as a result of our conversion to a partnership, offset by the effect of state income taxes. Our effective tax rate of 37 percent for the year ended December 31, 2006 was higher than the statutory rate of 35 percent due to the effect of state income taxes. For a reconciliation of the statutory rate to the effective tax rates, see Item 8, Financial Statements and Supplementary Data, Note 3.

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Liquidity and Capital Resources

Liquidity Overview. Our primary sources of liquidity are cash flows from operating activities, El Paso’s cash management program and capital contributions from our partners. Our primary uses of cash are for working capital, capital expenditures, and for required distributions to our partners. We are required to make distributions of available cash as defined in our partnership agreement on a quarterly basis to our partners. We have historically advanced cash to El Paso under its cash management program, which we reflect in investing activities in our statement of cash flows. On September 30, 2008, prior to El Paso’s MLP acquiring an additional 30 percent ownership interest in us, we made a non-cash distribution to our partners of $300 million of our note receivable under El Paso’s cash management program. At December 31, 2008, we had a note receivable from El Paso of approximately $179 million of which approximately $103 million was classified as current based on the net amount we anticipate using in the next twelve months considering available cash sources and needs. See Item 8, Financial Statements and Supplementary Data, Note 11, for a further discussion of El Paso’s cash management program and our other affiliate note receivable. We believe that cash flows from operating activities combined with amounts available to us under El Paso’s cash management program or contributions from our partners, will be adequate to meet our capital requirements and our existing operating needs.

Extreme volatility in the financial markets, the energy industry and the global economy will likely continue through 2009. The global financial markets remain extremely volatile and it is uncertain whether recent U.S. and foreign government actions will successfully restore confidence and liquidity in the global financial markets. This could impact our longer-term access to capital for future growth projects as well as the cost of such capital. Based on the liquidity available to us through our operating activities, El Paso’s cash management program and capital contributions from our partners, we do not anticipate having a need to directly access the financial markets in 2009 for any of our operating activities or expansion capital needs. Additionally, although the impacts are difficult to quantify at this point, a downward trend in the global economy could have adverse impacts on natural gas consumption and demand. However, we believe our exposure to changes in natural gas consumption and demand is largely mitigated by a revenue base that is significantly comprised of long term contracts that are based on firm demand charges and are less affected by a potential reduction in the actual usage or consumption of natural gas.

As of December 31, 2008, El Paso had approximately $1.0 billion of cash and approximately $1.2 billion of capacity available to it under various committed credit facilities. In light of the current economic climate and in response to the financial market volatility, El Paso, since November 2008, has generated approximately $1.2 billion of additional liquidity through three separate note offerings and has obtained additional revolving credit facility capacity and letter of credit capacity. Although we do not anticipate to directly access the financial markets in 2009, the volatility in the financial markets could impact our or El Paso’s ability to access these markets at reasonable rates in the future.

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

2008 Cash Flow Activities. Our cash flows for the years ended December 31 were as follows:

	2008			2007
	(In millions)
Cash flows from continuing operating activities	$	160		$	(86	)
Cash flows from continuing investing activities		52			163
Cash flows from continuing financing activities		(212	)		(77	)

·   Operating Activities. For the year ended December 31, 2008 as compared to the same period in 2007, cash flow from operating activities was higher primarily due to tax settlements during 2007. During 2007, we settled our then existing current and deferred tax balances of approximately $216 million through the cash management program upon converting our legal structure into a general partnership, and we also settled $9 million through the cash management program with El Paso for certain tax attributes previously reflected as deferred income taxes in our financial statements.

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·   Investing Activities. Most of the change in investing activities in 2008 can be attributed to activity under El Paso’s cash management program and capital expenditures.  In September 2008, we also made a non-cash distribution to our partners of $300 million of our note receivable under El Paso's cash management program in conjunction with El Paso’s MLP acquiring an additional 30 percent ownership interest in us. Our capital expenditures for the years ended December 31 were as follows:

	2008		2007
	(In millions)
Maintenance	$	26	$	36
Expansion(1)		108		72
Total	$	134	$	108

____________

(1) Amount includes our share of costs related to our 50 percent joint investment in WYCO.

Under our current plan for 2009, we have budgeted to spend (i) approximately $37 million for capital expenditures to maintain the integrity of our pipeline, to comply with clean air regulations and to ensure the safe and reliable delivery of natural gas to our customers and (ii) approximately $103 million to expand the capacity of our system.

·   Financing Activities. In June 2008, we paid $103 million, including premiums, to repurchase approximately $100 million of our senior notes as part of our previously announced debt repurchases. We repurchased these notes with recoveries of our notes receivable from El Paso under its cash management program. Additionally, we are required to make distributions to our partners of available cash as defined in our partnership agreement on a quarterly basis. We made cash distributions to our partners of approximately $109 million in 2008. In addition, in January 2009, we made a cash distribution of approximately $43 million to our partners.

Contractual Obligations

We are party to various contractual obligations. A portion of these obligations are reflected in our financial statements, such as long-term debt, other long-term financing obligations and other accrued liabilities, while other obligations, such as operating leases, demand charges under transportation commitments and capital commitments, are not reflected on our balance sheet. The following table and discussion summarizes our contractual cash obligations as of December 31, 2008, for each of the periods presented (all amounts are undiscounted):

	Due in less than 1 Year		Due in 1 to 3 Years		Due in 3 to 5 Years		Thereafter		Total
	(In millions)
Long-term financing obligations:
Principal	$	3	$	6	$	6	$	568	$	583
Interest		49		96		92		374		611
Other contractual liabilities		6		3		1		3		13
Operating leases		2		1		—		—		3
Other contractual commitments and purchase obligations:
Transportation commitments		6		12		2		2		22
Other commitments		36		—		—		—		36
Total contractual obligations	$	102	$	118	$	101	$	947	$	1,268

Long-Term Financing Obligations (Principal and Interest). Long-term financing obligations represent stated maturities. Interest payments are shown through the stated maturity date of the related fixed rate obligations based on the contractual interest rate. For a further discussion of our long-term financing obligations, see Item 8, Financial Statements and Supplementary Data, Note 6.

Other Contractual Liabilities. Included in this amount are, environmental liabilities related to sites that we own or have a contractual or legal obligation with a regulatory agency or property owner upon which we perform remediation activities. These liabilities are included in other current and non-current liabilities in our balance sheet.

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Operating Leases. For a further discussion of these obligations, see Item 8, Financial Statements and Supplementary Data, Note 7.

Other Contractual Commitments and Purchase Obligations. Other contractual commitments and purchase obligations are defined as legally enforceable agreements to purchase goods or services that have fixed or minimum quantities and fixed or minimum variable price provisions, and that detail approximate timing of the underlying obligations. Included are the following:

• Transportation Commitments. Included in these amounts are commitments for demand charges for firm access to natural gas transportation.

• Other Commitments. Included in these amounts are commitments for construction contracts and purchase obligations. We have excluded asset retirement obligations and reserves for litigation and environmental remediation as these liabilities are not contractually fixed as to timing and amount.

Commitments and Contingencies

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

Off-Balance Sheet Arrangements

For a discussion of our off-balance sheet arrangements, see Item 8, Financial Statements and Supplementary Data, Notes 7 and 11, which are incorporated herein by reference.

Critical Accounting Policies and Estimates

The accounting policies discussed below are considered by management to be critical to an understanding of our financial statements as their application places the most significant demands on management’s judgment. Due to the inherent uncertainties involved with this type of judgment, actual results could differ significantly from estimates and may have a material impact on our results of operations. For additional information concerning our other accounting policies, please read the notes to the financial statements included in Item 8, Financial Statements and Supplementary Data, Note 1.

Cost-Based Regulation. We account for our regulated operations under the provisions of Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation. The economic effects of regulation can result in a regulated company recording assets for costs that have been or are expected to be approved for recovery from customers or recording liabilities for amounts that are expected to be returned to customers in the rate-setting process in a period different from the period in which the amounts would be recorded by an unregulated enterprise. Accordingly, we record assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for non-regulated entities. Management regularly assesses whether regulatory assets are probable of future recovery by considering factors such as applicable regulatory changes and recent rate orders applicable to other regulated entities. Based on this continual assessment, management believes the existing regulatory assets are probable of recovery. We periodically evaluate the applicability of SFAS No. 71, and consider factors such as regulatory changes and the impact of competition. If cost-based regulation ends or competition increases, we may have to reduce certain of our asset balances to reflect a market basis lower than cost and write-off the associated regulatory assets.

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Accounting for Environmental Reserves. We accrue environmental reserves when our assessments indicate that it is probable that a liability has been incurred and an amount can be reasonably estimated. Estimates of our liabilities are based on an evaluation of potential outcomes, currently available facts, existing technology and presently enacted laws and regulations taking into consideration the likely effects of societal and economic factors, estimates of associated onsite, offsite and groundwater technical studies and legal costs. Actual results may differ from our estimates, and our estimates can be, and often are, revised in the future, either negatively or positively, depending upon actual outcomes or changes in expectations based on the facts surrounding each matter.

As of December 31, 2008, we had accrued approximately $13 million for environmental matters. Our environmental estimates range from approximately $13 million to approximately $41 million, and the amounts we have accrued represent a combination of two estimation methodologies. First, where the most likely outcome can be reasonably estimated, that cost has been accrued ($4 million). Second, where the most likely outcome cannot be estimated, a range of costs is established ($9 million to $37 million) and the lower end of the expected range has been accrued.

Accounting for Other Postretirement Benefits. We reflect an asset or liability for our postretirement benefit plan based on its over funded or under funded status. As of December 31, 2008, our postretirement benefit plan was over funded by $5 million. Our postretirement benefit obligation and net benefit costs are primarily based on actuarial calculations. We use various assumptions in performing these calculations, including those related to the return that we expect to earn on our plan assets, the estimated cost of health care when benefits are provided under our plan and other factors. A significant assumption we utilize is the discount rate used in calculating our benefit obligation. We select our discount rate by matching the timing and amount of our expected future benefit payments for our postretirement benefit obligation to the average yields of various high-quality bonds with corresponding maturities.

Actual results may differ from the assumptions included in these calculations, and as a result, our estimates associated with our postretirement benefits can be, and often are, revised in the future. The income statement impact of the changes in the assumptions on our related benefit obligation, along with changes to the plan and other items, are deferred and recorded as either a regulatory asset or liability. A one percent change in our primary assumptions would not have a material impact on our funded status or net postretirement benefit cost.

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

We are exposed to the risk of changing interest rates. At December 31, 2008, we had a note receivable from El Paso of approximately $179 million, with a variable interest rate of 3.2% that is due upon demand. While we are exposed to changes in interest income based on changes to the variable interest rate, the fair value of this note receivable approximates its carrying value due to the market-based nature of its interest rate and the fact that it is a demand note.

The table below shows the carrying value and related weighted-average effective interest rates on our long-term interest bearing financing obligations estimated based on quoted market prices for the same or similar issues.

	December 31, 2008
	Expected Fiscal Year of Maturity of Carrying Amounts																						December 31, 2007
	2009			2010			2011			2012			2013			Thereafter			Total		Fair Value		Carrying Amount		Fair Value
	(In millions, except for rates)
Long-term debt and other financing obligations(1), including current portion — fixed rate.	$	3		$	3		$	3		$	3		$	3		$	568		$	583	$	502	$	575	$	598
Average interest rate		15.5	%		15.4	%		15.0	%		14.6	%		14.2	%		7.3	%

(1) Our other financing obligations include amounts due to WYCO related to High Plains pipeline. See additional information in Note 6.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

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

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

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

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

Under the supervision and with the participation of management, including the President and Chief Financial Officer, we made an assessment of the effectiveness of our internal control over financial reporting as of December 31, 2008. In making this assessment, we used the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on our evaluation, we concluded that our internal control over financial reporting was effective as of December 31, 2008.

23

Report of Independent Registered Public Accounting Firm

To The Partners of Colorado Interstate Gas Company

We have audited the accompanying consolidated balance sheets of Colorado Interstate Gas Company (the Company) as of December 31, 2008 and 2007, and the related consolidated statements of income, partners’ capital/stockholder’s equity, and cash flows for each of the three years in the period ended December 31, 2008. Our audits also included the financial statement schedule listed in the Index at Item 15(a) for each of the three years in the period ended December 31, 2008. These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Colorado Interstate Gas Company at December 31, 2008 and 2007, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2008, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

As discussed in Note 1 to the consolidated financial statements, effective December 31, 2006 and January 1, 2008, the Company adopted the recognition and measurement date provisions, respectively, of Statement of Financial Accounting Standards No. 158, Employer’s Accounting for Defined Benefit Pension and Other Postretirement Plans — An Amendment of FASB Statements No. 87, 88, 106, and 132 (R).

                                                                                                                                                     /s/ Ernst & Young LLP

Houston, Texas

February 26, 2009

24

COLORADO INTERSTATE GAS COMPANY

CONSOLIDATED STATEMENTS OF INCOME

(In millions)

	Year Ended December 31,
	2008			2007			2006
Operating revenues	$	323		$	317		$	305
Operating expenses
Operation and maintenance		120			126			120
Depreciation and amortization		33			31			30
Taxes, other than income taxes		17			15			12
		170			172			162
Operating income		153			145			143
Other income, net		11			5			2
Interest and debt expense		(38	)		(49	)		(47	)
Affiliated interest income, net		23			50			41
Income before income taxes		149			151			139
Income taxes		—			44			52
Income from continuing operations		149			107			87
Discontinued operations, net of income taxes		—			42			48
Net income	$	149		$	149		$	135

See accompanying notes.

25

COLORADO INTERSTATE GAS COMPANY

CONSOLIDATED BALANCE SHEETS

(In millions)

	December 31,
	2008		2007
ASSETS
Current assets
Cash and cash equivalents	$	—	$	—
Accounts and notes receivable
Customer		8		—
Affiliates		119		181
Other		1		1
Materials and supplies		7		5
Regulatory assets		18		—
Other		2		1
Total current assets		155		188
Property, plant and equipment, at cost		1,675		1,413
Less accumulated depreciation and amortization		413		392
Total property, plant and equipment, net		1,262		1,021
Other assets
Notes receivable from affiliates		76		503
Other		50		57
		126		560
Total assets	$	1,543	$	1,769
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities
Accounts payable
Trade	$	11	$	14
Affiliates		10		8
Other		30		15
Taxes payable		10		10
Regulatory liabilities		29		12
Accrued interest		7		5
Contractual deposits		8		7
Other		9		8
Total current liabilities		114		79
Long-term debt and other financing obligations, less current maturities		580		575
Other liabilities		66		72
Commitments and contingencies (Note 7)
Partners’ capital		783		1,043
Total liabilities and partners’ capital	$	1,543	$	1,769

See accompanying notes.

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COLORADO INTERSTATE GAS COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

	Year Ended December 31,
	2008			2007			2006
Cash flows from operating activities
Net income	$	149		$	149		$	135
Less income from discontinued operations, net of income taxes		—			42			48
Income from continuing operations		149			107			87
Adjustments to reconcile net income to net cash from operating activities
Depreciation and amortization		33			31			30
Deferred income taxes		—			8			4
Other non-cash income items		3			8			28
Asset and liability changes
Accounts receivable		(3	)		3			41
Accounts payable		1			6			(9	)
Taxes payable		—			(56	)		14
Current assets		(2	)		6			8
Current liabilities		(9	)		—			(8	)
Non-current assets		(14	)		(4	)		(16	)
Non-current liabilities		2			(195	)		1
Cash provided by (used in) continuing activities		160			(86	)		180
Cash provided by discontinued activities		—			54			51
Net cash provided by (used in) operating activities		160			(32	)		231
Cash flows from investing activities
Additions to property, plant and equipment		(134	)		(108	)		(56	)
Net change in notes receivable from affiliates		183			271			(89	)
Cash paid for acquisitions of affiliates		—			—			(37	)
Other		3			—			2
Cash provided by (used in) continuing activities		52			163			(180	)
Cash used in discontinued activities		—			(83	)		(51	)
Net cash provided by (used in) investing activities		52			80			(231	)
Cash flows from financing activities
Payments to retire long-term debt		(103	)		(128	)		—
Distributions to partners		(109	)		—			—
Contribution from parent		—			7			—
Distribution from discontinued operations		—			44			—
Cash used in continuing activities		(212	)		(77	)		—
Cash provided by discontinued activities		—			29			—
Net cash used in financing activities		(212	)		(48	)		—
Net change in cash and cash equivalents		—			—			—
Cash and cash equivalents
Beginning of period		—			—			—
End of period	$	—		$	—		$	—

See accompanying notes.

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COLORADO INTERSTATE GAS COMPANY

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL/STOCKHOLDER’S EQUITY

(In millions, except share amounts)

						Additional						Accumulated Other			Total			Total
	Common stock					Paid-in			Retained			Comprehensive			Stockholder’s			Partners’
	Shares			Amount		Capital			Earnings			Income (Loss)			Equity			Capital
January 1, 2006		1,000		$	—	$	47		$	962		$	—		$	1,009		$	—
Net income										135						135
Adoption of SFAS No. 158, net of income taxes of $3													5			5			—
December 31, 2006		1,000			—		47			1,097			5			1,149			—
Net income										111						111
Reclassification to regulatory liability (Note 8)							—						(5	)		(5	)		—
October 31, 2007		1,000			—		47			1,208			—			1,255			—
Conversion to general partnership November 1, 2007)		(1,000	)				(47	)		(1,208	)					(1,255	)		1,255
Contributions																			82
Distributions																			(332	)
Net income																			38
December 31, 2007		—			—		—			—			—			—			1,043
Net income																			149
Distributions																			(409	)
December 31, 2008		—		$	—	$	—		$	—		$	—		$	—		$	783

See accompanying notes.

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COLORADO INTERSTATE GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Summary of Significant Accounting Policies

Basis of Presentation and Principles of Consolidation

We are a Delaware general partnership, originally formed in 1927 as a corporation. We are owned 60 percent by El Paso Noric Investments III, L.L.C., a wholly owned subsidiary of El Paso Corporation (El Paso) and 40 percent by EPPP CIG GP Holdings, L.L.C., a subsidiary of the El Paso Pipeline Partners, L.P. (MLP) which is majority owned by El Paso. In conjunction with the formation of El Paso’s MLP in November 2007, we distributed 100 percent of Wyoming Interstate Company, Ltd. (WIC) to the MLP and certain other assets to El Paso. We have reflected these operations as discontinued operations in our financial statements for periods prior to their distribution. Additionally, effective November 1, 2007, we converted our legal structure into a general partnership, and are no longer subject to income taxes and settled our then existing current and deferred tax balances through El Paso’s cash management program. For a further discussion of these and other related transactions, see Notes 2, 3 and 11.

Our consolidated financial statements are prepared in accordance with U.S. generally accepted accounting principles (GAAP) and include the accounts of all majority owned and controlled subsidiaries after the elimination of intercompany accounts and transactions. Our financial statements for prior periods include reclassifications that were made to conform to the current period presentation. Those reclassifications did not impact our reported net income or partners’ capital.

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

Use of Estimates

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

Regulated Operations

Our natural gas pipeline and storage operations are subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC) under the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and the Energy Policy Act of 2005. We follow the regulatory accounting principles prescribed under Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation. Under SFAS No. 71, we record regulatory assets and liabilities that would not be recorded under GAAP for non-regulated entities. Regulatory assets and liabilities represent probable future revenues or expenses associated with certain charges or credits that will be recovered from or refunded to customers through the rate making process. Items to which we apply regulatory accounting requirements include certain postretirement employee benefit plan costs, an equity return component on regulated capital projects, fuel recovery mechanism and related gas cost and other costs included in, or expected to be included in, future rates.

Cash and Cash Equivalents

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

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Allowance for Doubtful Accounts

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

Materials and Supplies

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

Natural Gas Imbalances

Natural gas imbalances occur when the actual amount of natural gas delivered from or received by a pipeline system, processing plant or storage facility differs from the contractual amount delivered or received. We value these imbalances due to or from shippers and operators utilizing current index prices. Imbalances are settled in cash or in-kind, subject to the terms of our tariff.

Imbalances due from others are reported in our balance sheet as either accounts receivable from customers or accounts receivable from affiliates. Imbalances owed to others are reported on the balance sheet as either trade accounts payable or accounts payable to affiliates. We classify all imbalances as current as we expect to settle them within a year.

Property, Plant and Equipment

Our property, plant and equipment is recorded at its original cost of construction or, upon acquisition, at either the fair value of the assets acquired or the cost to the entity that first placed the asset in service. For assets we construct, we capitalize direct costs, such as labor and materials, and indirect costs, such as overhead, interest and an equity return component, as allowed by the FERC. We capitalize major units of property replacements or improvements and expense minor items.

We use the composite (group) method to depreciate property, plant and equipment. Under this method, assets with similar lives and characteristics are grouped and depreciated as one asset. We apply the FERC-accepted depreciation rate to the total cost of the group until its net book value equals its salvage value. For certain general plant, we depreciate the asset to zero. Currently, our depreciation rates vary from approximately two percent to 25 percent per year. Using these rates, the remaining depreciable lives of these assets range from four to 50 years. We re-evaluate depreciation rates each time we file with the FERC for a change in our transportation and storage rates.

When we retire 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, 2008 and 2007, we had $106 million and $109 million of construction work in progress included in our property, plant and equipment.

We capitalize a carrying cost (an allowance for funds used during construction) on debt and equity funds related to our construction of long-lived assets. This carrying cost consists of a return on the investment financed by debt and a return on the investment financed by equity. The debt portion is calculated based on our average cost of debt. Interest costs on debt amounts capitalized during the years ended December 31, 2008, 2007 and 2006, were $2 million, $1 million and less than $1 million. These debt amounts are included as a reduction to interest and debt expense on our income statement. The equity portion of capitalized costs is calculated using the most recent FERC-approved equity rate of return. The equity amounts capitalized (exclusive of taxes) during the years ended December 31, 2008, 2007 and 2006, were $8 million $2 million, and $1 million. These equity amounts are included as other non-operating income on our income statement.

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Asset and Investment Impairments

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

We reclassify the assets (or groups of assets) to be sold as either held-for-sale or as discontinued operations, depending on, among other criteria, whether we will have significant long-term continuing involvement with those assets after they are sold. We cease depreciating assets in the period that they are reclassified as either held for sale or as discontinued operations.

Revenue Recognition

Our revenues are primarily generated from natural gas transportation, storage and processing services. Revenues for all services are based on the thermal quantity of gas delivered or subscribed at a price specified in the contract. For our transportation and storage services, we recognize reservation revenues on firm contracted capacity over the contract period regardless of the amount of natural gas that is transported or stored. For interruptible or volumetric-based services, we record revenues when physical deliveries of natural gas are made at the agreed upon delivery point or when gas is injected or withdrawn from the storage facility. Gas not used in operations is based on the volumes of natural gas we are allowed to retain relative to the amounts we use for operating purposes. Prior to July 1, 2006, we recognized revenue on gas not used in operations on our system when the volumes were retained from our shippers under our tariff. Effective July 1, 2006, we adopted a fuel tracker on our system that contains a true-up for volumetric amounts over or under retained. In addition, effective March 1, 2008, we implemented a FERC-approved fuel and related gas cost recovery mechanism which is designed to recover all cost impacts, or flow through to shippers any revenue impacts, of all fuel imbalance revaluations and related gas balance items. We are subject to FERC regulations and, as a result, revenues we collect may be subject to refund in a rate proceeding. We establish reserves for these potential refunds.

Environmental Costs and Other Contingencies

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

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

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

31

Income Taxes

Effective November 1, 2007, we converted into a general partnership in conjunction with the formation of El Paso’s MLP and accordingly, we are no longer subject to income taxes. As a result of our conversion into a general partnership, we settled our existing current and deferred tax balances with recoveries of note receivables from El Paso under its cash management program pursuant to our tax sharing agreement with El Paso (see Notes 3 and 11). Prior to that date, we recorded current income taxes based on our taxable income and provided for deferred income taxes to reflect estimated future tax payments and receipts. Deferred taxes represented the income tax impacts of differences between the financial statement and tax bases of assets and liabilities and carryovers at each year end. We accounted for tax credits under the flow-through method, which reduced the provision for income taxes in the year the tax credits first became available. We reduced deferred tax assets by a valuation allowance when, based on our estimates, it was more likely than not that a portion of those assets would not be realized in a future period.

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

We have legal obligations associated with our natural gas pipeline 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 pipeline if it is 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 system, 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, 2008 and 2007 were not material to our financial statements. We continue to evaluate our asset retirement obligations and future developments could impact the amounts we record.

Postretirement Benefits

We maintain a postretirement benefit plan covering certain of our former employees. This plan requires us to make contributions to fund the benefits to be paid out under the plan. These contributions are invested until the benefits are paid out to plan participants. We record the net benefit cost related to this plan in our income statement. This net benefit cost is a function of many factors including benefits earned during the year by plan participants (which is a function of the level of benefits provided under the plan, actuarial assumptions and the passage of time), expected returns on plan assets and amortization of certain deferred gains and losses. For a further discussion of our policies with respect to our postretirement plan, see Note 8.

Effective December 31, 2006, we began accounting for our postretirement benefit plan under the recognition provisions of SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an Amendment of FASB Statements No. 87, 88, 106, and 132(R) and recorded a $5 million increase, net of income taxes of $3 million, to accumulated other comprehensive income related to the adoption of this standard. Under SFAS No. 158, we record an asset or liability for our postretirement benefit plan based on its over funded or under funded status. In March 2007, the FERC issued guidance requiring regulated pipeline companies to record a regulatory asset or liability for any deferred amounts related to unrecognized gains and losses or changes in actuarial assumptions that would otherwise be recorded in accumulated other comprehensive income for non-regulated entities. Upon adoption of this FERC guidance, we reclassified $5 million from accumulated other comprehensive income to a regulatory liability.

32

Effective January 1, 2008, we adopted the measurement date provisions of SFAS No. 158 and changed the measurement date of our postretirement benefit plan from September 30 to December 31. The adoption of the measurement date provisions of this standard did not have a material impact on our financial statements. For a further discussion of our application of SFAS No. 158, see Note 8.

New Accounting Pronouncements Issued But Not Yet Adopted

As of December 31, 2008, the following accounting standards had not yet been adopted by us.

Fair Value Measurements. We have adopted the provisions of SFAS No. 157, Fair Value Measurements in measuring the fair value of financial assets and liabilities in the financial statements. We have elected to defer the adoption of SFAS No. 157 for certain of our non-financial assets and liabilities until January 1, 2009, the adoption of which will not have a material impact on our financial statements.

Business Combinations. In December 2007, the FASB issued SFAS No. 141(R), Business Combinations, which provides revised guidance on the accounting for acquisitions of businesses. This standard changes the current guidance to require that all acquired assets, liabilities, minority interest and certain contingencies be measured at fair value, and certain other acquisition-related costs be expensed rather than capitalized. SFAS No. 141(R) will apply to acquisitions that are effective after December 31, 2008, and application of the standard to acquisitions prior to that date is not permitted.

Noncontrolling Interests. In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements, which provides guidance on the presentation of minority interest, subsequently renamed “noncontrolling interest”, in the financial statements. This standard requires that noncontrolling interest be presented as a separate component of equity rather than as a “mezzanine” item between liabilities and equity, and also requires that noncontrolling interest be presented as a separate caption in the income statement. This standard also requires all transactions with noncontrolling interest holders, including the issuance and repurchase of noncontrolling interests, be accounted for as equity transactions unless a change in control of the subsidiary occurs. We will adopt the provisions of this standard effective January 1, 2009. The adoption of this standard will not have a material impact on our financial statements.

2. Acquisitions and Divestitures

Acquisitions. Effective October 1, 2006, we acquired CIG Resources Company, L.L.C. and a 50 percent equity interest in WYCO Development LLC (WYCO) from our affiliates at El Paso’s historical cost on the date of acquisition of approximately $37 million. We accounted for these transactions prospectively beginning with the date of acquisition and our investment in WYCO is accounted for using the equity method of accounting.

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Divestitures. In November 2007, in conjunction with the formation of El Paso’s MLP, we distributed 100 percent of WIC to the MLP and certain other assets to El Paso. We have reflected these operations as discontinued operations in our financial statements for periods prior to their distribution. The table below summarizes the operating results of our discontinued operations for each of the two years ended December 31, 2007 and 2006.

	2007			2006
	(In millions)
Revenues	$	97		$	98
Operating expenses		(41	)		(30	)
Other income, net		5			3
Interest and debt expense		1			1
Affiliated interest income, net		1			2
Income before income taxes		63			74
Income taxes		21			26
Income from discontinued operations, net of income taxes	$	42		$	48

3. Income Taxes

In conjunction with the formation of El Paso’s MLP, we converted our legal structure into a general partnership effective November 1, 2007 and settled our current and deferred tax balances pursuant to our tax sharing agreement with El Paso with recoveries of note receivables from El Paso under its cash management program. The tables below reflect that these balances have been settled and that we no longer pay income taxes effective November 1, 2007.

Components of Income Taxes. The following table reflects the components of income taxes included in income from continuing operations for each of the two years ended December 31, 2007 and 2006:

	2007		2006
	(In millions)
Current
Federal	$	33	$	43
State		3		5
		36		48
Deferred
Federal		7		4
State		1		—
		8		4
Total income taxes	$	44	$	52

Effective Tax Rate Reconciliation. Our income taxes, included in income from continuing operations, differ from the amount computed by applying the statutory federal income tax rate of 35 percent for the following reasons for each of the two years ended December 31, 2007 and 2006:

	2007			2006
	(In millions, except for rates)
Income taxes at the statutory federal rate of 35%	$	53		$	49
Increase (decrease)
Pretax income not subject to income taxes after conversion to partnership		(12	)		—
State income taxes, net of federal income tax benefit		3			3
Income taxes	$	44		$	52
Effective tax rate		29	%		37	%

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4. Financial Instruments

At December 31, 2008 and 2007, the carrying amounts of cash and cash equivalents and trade receivables and payables are representative of their fair value because of the short-term maturity of these instruments. At December 31, 2008 and 2007, we had an interest bearing note receivable from El Paso of approximately $179 million and $655 million due upon demand, with a variable interest rate of 3.2% and 6.5%. While we are exposed to changes in interest income based on changes to the variable interest rate, the fair value of this note receivable approximates its carrying value due to the market-based nature of its interest rate and the fact that it is a demand note.

In addition, the carrying amounts and estimated fair values of our long-term financing obligations are based on quoted market prices for the same or similar issues and are as follows at December 31:

	2008				2007
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)
Long-term financing obligations, including current maturities	$	583	$	502	$	575	$	598

5. Regulatory Assets and Liabilities

Below are the details of our regulatory assets and liabilities at December 31:

	2008		2007
	(In millions)
Current regulatory assets
Deferred fuel loss and unaccounted for gas	$	17	$	—
Other		1		—
Total current regulatory assets		18		—
Non-current regulatory assets
Taxes on capitalized funds used during construction		11		12
Unamortized loss on reacquired debt		7		3
Postretirement benefits		2		3
Under-collected income taxes		1		1
Total non-current regulatory assets		21		19
Total regulatory assets	$	39	$	19
Current regulatory liabilities
Over-collected fuel variance	$	29	$	12
Non-current regulatory liabilities
Property and plant depreciation		19		20
Postretirement benefits		6		13
Excess recovery of income taxes		—		1
Total non-current regulatory liabilities		25		34
Total regulatory liabilities	$	54	$	46

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6. Long-Term Financing Obligations

Our long-term financing obligations consisted of the following at December 31:

	2008		2007
	(In millions)
5.95% Senior Notes due March 2015	$	35	$	75
6.80% Senior Notes due November 2015		340		400
6.85% Senior Debentures due June 2037		100		100
Total long-term debt		475		575
Other financing obligations		108		—
Total long-term debt and other financing obligations		583		575
Less: Current maturities		3		—
Total long-term debt and other financing obligations, less current maturities	$	580	$	575

Debt. In June 2008, we paid $103 million, including premiums, to repurchase approximately $40 million of our 5.95% senior notes and $60 million of our 6.80% senior notes as part of our previously announced debt repurchases. Additionally, in December 2007, we repurchased approximately $125 million of our 5.95% senior notes. We repurchased these notes with recoveries of our notes receivable from El Paso under its cash management program.

For the year ended December 31, 2008, we were in compliance with our debt-related covenants. Under our various financing documents we are subject to a number of restrictions and covenants. The most restrictive of these include limitations on the incurrence of liens and limitations on sale-leaseback transactions.

Other Financing Obligations. In November 2008, the High Plains pipeline was placed in service. Upon placing this pipeline in service, we transferred our title in the pipeline to WYCO (a joint venture with an affiliate of PSCo in which we have a 50 percent ownership interest). Although we transferred the title in this pipeline to WYCO, we continue to reflect the High Plains Pipeline as property, plant and equipment in our financial statements as of December 31, 2008 due to our continuing involvement with the pipeline through WYCO.

We constructed the High Plains pipeline and our joint venture partner in WYCO funded 50 percent of the pipeline construction costs, which we reflected as an other non-current liability in our balance sheet during the construction period. Upon completion of the construction, our obligation to the affiliate of PSCo for these construction advances was converted into a financing obligation to WYCO and accordingly, we reclassified the amounts from other non-current liabilities to debt and other financing obligations during the fourth quarter of 2008.  This obligation has a principal amount of $108 million as of December 31, 2008, and has monthly principal payments totaling $3 million each year through 2043.  We also make monthly interest payments on this obligation that are based on 50 percent of the operating results of the High Plains pipeline, which is currently estimated at a 15.5% rate as of December 31, 2008.

7. Commitments and Contingencies

Legal Proceedings

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

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

In addition to the above proceedings, we and our subsidiaries and affiliates are named defendants in numerous lawsuits and governmental proceedings that arise in the ordinary course of our business. For each of these matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies and the likelihood of an unfavorable outcome. If we determine that an unfavorable outcome is probable and can be estimated, we establish the necessary accruals. While the outcome of these matters, including those discussed above, cannot be predicted with certainty, and there are still uncertainties related to the costs we may incur, based upon our evaluation and experience to date, we had no accruals for our outstanding legal matters at December 31, 2008. It is possible, however, that new information or future developments could require us to reassess our potential exposure related to these matters and establish accruals accordingly.

Environmental Matters

We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require us to remove or remedy the effect on the environment of the disposal or release of specified substances at current and former operating sites. At December 31, 2008, we had accrued approximately $13 million for expected remediation costs and associated onsite, offsite and groundwater technical studies and for related environmental legal costs; however, we estimate that our exposure could be as high as $41 million. Our accrual includes $9 million for environmental contingencies related to properties we previously owned.

Our accrual represents a combination of two estimation methodologies. First, where the most likely outcome can be reasonably estimated, that cost has been accrued. Second, where the most likely outcome cannot be estimated, a range of costs is established and if no one amount in that range is more likely than any other, the lower end of the expected range has been accrued. Our environmental remediation projects are in various stages of completion. Our recorded liabilities reflect our current estimates of amounts we will expend to remediate these sites. However, depending on the stage of completion or assessment, the ultimate extent of contamination or remediation required may not be known. As additional assessments occur or remediation efforts continue, we may incur additional liabilities.

Below is a reconciliation of our accrued liability from January 1, 2008 to December 31, 2008 (in millions):

Balance at January 1, 2008	$	15
Additions/adjustments for remediation activities		1
Payments for remediation activities		(3	)
Balance at December 31, 2008	$	13

For 2009, we estimate that our total remediation expenditures will be approximately $4 million, which will be expended under government directed clean-up plans.

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

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Regulatory Matters

Fuel Recovery Mechanisms. Effective March 1, 2008, we implemented a FERC-approved fuel and related gas cost recovery mechanism which is designed to recover all cost impacts, or flow through to shippers any revenue impacts, of all fuel imbalance revaluations and related gas balance items. We recorded a favorable fuel cost and revenue tracker estimated adjustment to reflect the effect of the order on our current fuel recovery filing period. In September 2008, the FERC issued an order accepting certain tariff changes effective October 1, 2008, subject to refund and the outcome of a technical conference.

Greenhouse Gas (GHG) Emissions.  Legislative and regulatory measures to address GHG emissions are in various phases of discussions or implementation at the international, national, regional and state levels. In the United States, it is likely that federal legislation requiring GHG controls will be enacted in the next few years. In addition, the EPA is considering initiating a rulemaking to regulate GHGs under the Clean Air Act. Legislation and regulation are also in various stages of discussions or implementation in many of the states in which we operate. These measures include recommendations released by the Western Climate Initiative regarding a cap-and-trade program and targeted emission reductions in several states in which we operate in the western United States. Additionally, lawsuits have been filed seeking to force the federal government to regulate GHG emissions and individual companies to reduce GHG emissions from their operations. These and other lawsuits may result in decisions by state and federal courts and agencies that could impact our operations and ability to obtain certifications and permits to construct future projects. Our costs and legal exposure related to GHG regulations are not currently determinable.

Purchase Obligations, Commitments and Other Matters

Transportation Commitments and Purchase Obligations. We have entered into transportation commitments totaling approximately $22 million at December 31, 2008. Our annual commitments under these agreements are $6 million each in 2009, 2010 and 2011, $2 million in 2012 and $2 million in total thereafter. We have entered into unconditional purchase obligations for pipe and construction services totaling approximately $36 million at December 31, 2008, all of which is expected to be paid in 2009. In addition, we have other planned capital and investment projects that are discretionary in nature, with no substantial contractual capital commitments made in advance of the actual expenditures.

Operating Leases. We lease property, facilities and equipment under various operating leases. Minimum future annual rental commitments on operating leases as of December 31, 2008, were as follows:

Year Ending December 31,	(In millions)
2009	$	2
2010		1
Total	$	3

Rental expense on our operating leases for each of the three years ended December 31, 2008, 2007 and 2006 was $2 million. These amounts include our share of rent allocated to us from El Paso.

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

Guarantees. We are or have been involved in various ownership and other contractual arrangements that sometimes require us to provide additional financial support that results in the issuance of financial and performance guarantees that are not recorded in our financial statements. In a financial guarantee, we are obligated to make payments if the guaranteed party failed to make payments under, or violated the terms of, the financial arrangement. As of December 31, 2008, we have a financial guarantee with a maximum exposure of approximately $2 million. In a performance guarantee, we provide assurance that the guaranteed party will execute on the terms of the contract. If they do not, we are required to perform on their behalf. In May 2008, our performance guarantee expired related to the purchase of natural gas and liquids by WIC.

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8. Retirement Benefits

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

Postretirement Benefits. We provide postretirement medical benefits for a closed group of retirees. These benefits may be subject to deductibles, co-payment provisions, and other limitations and dollar caps on the amount of employer costs and El Paso reserves the right to change these benefits. In addition, certain former employees continue to receive limited postretirement life insurance benefits. Our postretirement benefit plan costs are prefunded to the extent these costs are recoverable through our rates. To the extent actual costs differ from the amounts recovered in rates, a regulatory asset or liability is recorded. We do not expect to make any contributions to our postretirement benefit plan in 2009.

Effective December 31, 2006, we began accounting for our postretirement benefit plan under the recognition provisions of SFAS No. 158. Under SFAS No. 158, we record an asset or liability for our postretirement benefit plan based on its over funded or under funded status. In March 2007, the FERC issued guidance requiring regulated pipeline companies to record a regulatory asset or liability for any deferred amounts related to unrecognized gains and losses or changes in actuarial assumptions that would otherwise be recorded in accumulated other comprehensive income for non-regulated entities. Upon adoption of this FERC guidance, we reclassified $5 million from accumulated other comprehensive income to a regulatory liability.

Effective January 1, 2008, we adopted the measurement date provisions of SFAS No. 158 and changed the measurement date of our postretirement benefit plan from September 30 to December 31. The adoption of the measurement date provisions of this standard did not have a material impact on our financial statements.

 Accumulated Postretirement Benefit Obligation, Plan Assets and Funded Status. The table below provides information about our postretirement benefit plan. In 2008, we adopted the measurement date provisions of SFAS No. 158 and the information below for 2008 is presented and computed as of and for the fifteen months ended December 31, 2008. For 2007, the information is presented and computed as of and for the twelve months ended September 30, 2007.

	December 31, 2008			September 30, 2007
	(In millions)
Change in accumulated postretirement benefit obligation:
Accumulated postretirement benefit obligation — beginning of period	$	7		$	11
Interest cost		1			1
Actuarial (gain) loss		1			(4	)
Benefits paid(1)		(2	)		(1	)
Accumulated postretirement benefit obligation — end of period	$	7		$	7
Change in plan assets:
Fair value of plan assets — beginning of period	$	18		$	17
Actual return on plan assets		(4	)		2
Benefits paid		(2	)		(1	)
Fair value of plan assets — end of period	$	12		$	18
Reconciliation of funded status:
Fair value of plan assets	$	12		$	18
Less: accumulated postretirement benefit obligation		7			7
Fourth quarter contributions					—
Net asset at December 31	$	5		$	11

____________

(1)Amounts shown are net of a subsidy related to the Medicare Prescription Drug, Improvement, and Modernization Act of 2003.

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Plan Assets. The primary investment objective of our plan is to ensure that, over the long-term life of the plan, an adequate pool of sufficiently liquid assets exists to meet the benefit obligations to retirees and beneficiaries. Investment objectives are long-term in nature covering typical market cycles. Any shortfall of investment performance compared to investment objectives is the result of general economic and capital market conditions. As a result of the general decline in the markets for debt and equity securities, the fair value of our plan’s assets and the funded status of our postretirement benefit plan declined during 2008, which resulted in a decrease in our plan assets and regulatory liability when our plan’s assets and obligation were remeasured at December 31, 2008. The following table provides the target and actual asset allocations in our postretirement benefit plan as of December 31, 2008 and September 30, 2007:

Asset Category	Target		Actual 2008		Actual 2007
	(Percent)
Equity securities		65		61		63
Debt securities		35		32		33
Cash and cash equivalents		—		7		4
Total		100		100		100

Expected Payment of Future Benefits. As of December 31, 2008, we expect the following payments (net of participant contributions and an expected subsidy related to the Medicare Prescription Drug, Improvement, and Modernization Act of 2003) under our plan (in millions):

Year Ending December 31,
2009	$	1
2010		1
2011		1
2012		1
2013		1
2014 - 2018		3

 Actuarial Assumptions and Sensitivity Analysis. Accumulated postretirement benefit obligations and net benefit costs are based on actuarial estimates and assumptions. The following table details the weighted average actuarial assumptions used in determining our postretirement plan obligations and net benefit costs for 2008, 2007 and 2006:

	2008		2007		2006
	(Percent)
Assumptions related to benefit obligations at December 31, 2008 and September 30, 2007 and 2006 measurement dates:
Discount rate		5.82		6.05		5.50
Assumptions related to benefit costs at December 31:
Discount rate		6.05		5.50		5.25
Expected return on plan assets(1)		8.00		8.00		8.00

____________

(1) The expected return on plan assets is a pre-tax rate of return based on our targeted portfolio of investments. Our postretirement benefit plan’s investment earnings are subject to unrelated business income taxes at a rate of 35%. The expected return on plan assets for our postretirement benefit plan is calculated using the after-tax rate of return

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Actuarial estimates for our postretirement benefits plan assumed a weighted average annual rate of increase in the per capita costs of covered health care benefits of 8.6 percent in 2008, gradually decreasing to 5.0 percent by the year 2015. Changes in the assumed health care cost trends do not have a material impact on the amounts reported for our interest costs or our accumulated postretirement benefit obligations.

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

	2008			2007			2006
	(In millions)
Interest cost	$	1		$	1		$	—
Expected return on plan assets		(1	)		(1	)		(1	)
Other		(1	)		(1	)		3
Net postretirement benefit cost (income)	$	(1	)	$	(1	)	$	2

9. Transactions with Major Customer

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

	2008		2007		2006
	(In millions)
PSCo	$	90	$	91	$	95

10. Supplemental Cash Flow Information

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

	2008		2007			2006
	(In millions)
Interest paid, net of capitalized interest	$	37	$	52		$	48
Income tax payments		—		277	(1)		34

____________

(1) Includes amounts related to the settlement of current and deferred tax balances due to the conversion to a partnership in November 2007 (see Notes 3 and 11).

11. Investment in Unconsolidated Affiliate and Transactions with Affiliates

Investment in Unconsolidated Affiliate

We have a 50 percent investment in WYCO which we account for using the equity method of accounting. WYCO owns the High Plains pipeline (a FERC-regulated pipeline), a state regulated intrastate pipeline and a compressor station. At December 31, 2008 and 2007, our investment in WYCO was approximately $17 million and $18 million. We have an other financing obligation payable to WYCO totaling $108 million as of December 31, 2008, which is described further in Note 6.

Transactions with Affiliates

MLP Acquisition. On September 30, 2008, El Paso’s MLP acquired an additional 30 percent ownership interest in us.

Contributions/Distributions. On November 21, 2007, in conjunction with the formation of the MLP, we made a distribution of WIC and certain other assets (described in Note 1) with a book value of approximately $332 million to El Paso and El Paso made a capital contribution of approximately $82 million to us. On September 30, 2008, prior to El Paso’s MLP acquiring an additional 30 percent ownership interest in us, we made a $300 million non-cash distribution to our partners as discussed in the Cash Management Program section below. Additionally, we are required to make distributions of available cash as defined in our partnership agreement on a quarterly basis to our partners. During 2008, we paid cash distributions of approximately $109 million to our partners. In addition, in January 2009 we paid a cash distribution to our partners of approximately $43 million. We did not make any distributions to our partners during 2007.

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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. El Paso uses the cash management program to settle intercompany transactions between participating affiliates. We have historically advanced cash to El Paso in exchange for an affiliated note receivable that is due upon demand. During 2008, we made a non-cash distribution to our partners of $300 million of our note receivable under this program. At December 31, 2008 and 2007, we had a note receivable from El Paso of $179 million and $655 million. We classified $103 million and $159 million of this receivable as current on our balance sheets at December 31, 2008 and 2007, based on the net amount we anticipate using in the next twelve months considering available cash sources and needs. The interest rate on our note at December 31, 2008 and 2007 was 3.2% and 6.5%.

Income Taxes. Effective November 1, 2007, we converted into a general partnership as discussed in Note 1 and settled our existing current and deferred tax balances of approximately $216 million pursuant to our tax sharing agreement with El Paso with recoveries of note receivables from El Paso under its cash management program. During 2007, we also settled $9 million with El Paso through its cash management program for certain tax attributes previously reflected as deferred income taxes in our financial statements. These settlements are reflected as operating activities in our statement of cash flows.

Accounts Receivable Sales Program. We sell certain accounts receivable to a qualifying special purpose entity (QSPE) under SFAS No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities, whose purpose is solely to invest in our receivables. As of December 31, 2008 and 2007, we sold approximately $29 million and $34 million of receivables, received cash of approximately $20 million and $17 million and received subordinated beneficial interests of approximately $8 million and $16 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 $21 million and $17 million as of December 31, 2008 and 2007. We reflect the subordinated interest in receivables sold at their fair value on the date they are issued. These amounts (adjusted for subsequent collections) are recorded as accounts receivable from affiliate in our balance sheets. Our ability to recover our carrying value of our subordinated beneficial interests is based on the collectibility of the underlying receivables sold to the QSPE. We reflect accounts receivable sold under this program and changes in the subordinated beneficial interests as operating cash flows in our statement of cash flows. Under the agreements, we earn a fee for servicing the receivables and performing all administrative duties for the QSPE which is reflected as a reduction of operation and maintenance expense in our income statement. The fair value of these servicing and administrative agreements as well as the fees earned were not material to our financial statements for the years ended December 31, 2008 and 2007.

Other Affiliate Balances. At December 31, 2008 and 2007, we had contractual deposits from our affiliates of $6 million included in other current liabilities on our balance sheet. At December 31, 2007, we also had a non-current note receivable of $7 million, which we settled during 2008.

Affiliate Revenues and Expenses. We entered into transactions with our affiliates within the ordinary course of business and the services are based on the same terms as non-affiliates, including natural gas transportation services to and from affiliates under long-term contracts and various operating agreements. We also contract with an affiliate to process natural gas and sell extracted natural gas liquids.

We do not have employees. Following our reorganization in November 2007, our former employees continue to provide services to us through an affiliated service company owned by our general partner, El Paso. We are managed and operated by officers of El Paso, our general partner. We have an omnibus agreement with El Paso and its affiliates under which we reimburse El Paso for the provision of various general and administrative services for our benefit and for direct expenses incurred by El Paso on our behalf. El Paso bills us directly for certain general and administrative costs and allocates a portion of its general and administrative costs to us. In addition to allocations from El Paso, we are allocated costs from El Paso Natural Gas Company and Tennessee Gas Pipeline Company, our affiliates, associated with our pipeline services. We also allocate costs to WIC and Cheyenne Plains Gas Pipeline, our affiliates, for their share of 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.

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

	2008		2007		2006
	(In millions)
Revenues from affiliates	$	17	$	20	$	22
Operation and maintenance expenses from affiliates		86		60		53
Reimbursements of operating expenses charged to affiliates		26		22		18

12. Supplemental Selected Quarterly Financial Information (Unaudited)

Our financial information by quarter is summarized below. Due to the seasonal nature of our business, information for interim periods may not be indicative of our results of operations for the entire year.

	Quarters Ended
	March 31		June 30		September 30		December 31		Total
	(In millions)
2008
Operating revenues	$	90	$	73	$	71	$	89	$	323
Operating income		50		26		26		51		153
Net income		50		26		25		48		149
2007
Operating revenues	$	84	$	75	$	67	$	91	$	317
Operating income		40		32		28		45		145
Income from continuing operations		25		21		20		41		107
Discontinued operations, net of income taxes		8		14		12		8		42
Net income		33		35		32		49		149

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SCHEDULE II

COLORADO INTERSTATE GAS COMPANY

VALUATION AND QUALIFYING ACCOUNTS

Years Ended December 31, 2008, 2007 and 2006

(In millions)

Description	Balance at Beginning of Period		Charged to Costs and Expenses		Deductions(1)			Charged to Other Accounts			Balance at End of Period
2008
Environmental reserves	$	15	$	1	$	(3	)	$	—		$	13
2007
Legal reserves	$	—	$	3	$	(3	)	$	—		$	—
Environmental reserves		17		1		(3	)		—			15
2006
Allowance for doubtful accounts	$	1	$	—	$	—		$	(1	)	$	—
Environmental reserves		23		2		(8	)		—			17

____________

 (1) Primarily relates to payments for environmental remediation activities.

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

None.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As of December 31, 2008, we carried out an evaluation under the supervision and with the participation of our management, including our President and Chief Financial Officer, as to the effectiveness, design and operation of our disclosure controls and procedures. This evaluation considered the various processes carried out under the direction of our disclosure committee in an effort to ensure that information required to be disclosed in the SEC reports we file or submit under the Exchange Act is accurate, complete and timely. Our management, including our President and Chief Financial Officer, does not expect that our disclosure controls and procedures or our internal controls will prevent and/or detect all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within our company have been detected. Our disclosure controls and procedures are designed to provide reasonable assurance of achieving their objectives and our President and Chief Financial Officer have concluded that our disclosure controls and procedures are effective at a reasonable level of assurance at December 31, 2008. See Item 8, Financial Statements and Supplementary Data under Management’s Annual Report on Internal Control Over Financial Reporting.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting during the fourth quarter of 2008 that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

ITEM 9A(T). CONTROLS AND PROCEDURES

This annual report does not include an attestation report of our independent registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by our independent registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit us to provide only management’s report in this annual report. See Item 8, Financial Statements and Supplementary Data, under Management’s Annual Report on Internal Control Over Financial Reporting.

ITEM 9B. OTHER INFORMATION

None.

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PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

Management Committee and Executive Officers

 We are a Delaware general partnership with two partners, the first of which is a wholly owned subsidiary of El Paso (the “El Paso Partner”), and the second of which is a wholly owned subsidiary of the MLP (the “MLP Partner”). The El Paso Partner owns a 60 percent interest in our partnership, and the MLP Partner owns our remaining 40 percent interest. A general partnership agreement governs our ownership and management. Although our management is vested in its partners, the partners have agreed to delegate our management to a management committee. Decisions of or actions taken by the management committee are binding on us. The management committee is composed of four representatives, with three representatives being designated by the El Paso Partner and one representative being designated by the MLP Partner. Each member of the management committee has full authority to act on behalf of the partner that designated such member with respect to matters pertaining to us. Each member of the management committee is entitled to one vote on each matter submitted for a vote of the management committee, and the vote of a majority of the members of the management committee constitutes action of the management committee, except for certain actions specified in the general partnership agreement that require unanimous approval of the management committee. Our officers are appointed by the management committee.

The following provides biographical information for each of our executive officers and management committee members as of March 2, 2009.

There are no family relationships among any of our executive officers or management committee members, and, unless described herein, no arrangement or understanding exists between any executive officer and any other person pursuant to which he was or is to be selected as an officer.

Name	Age		Position
James J. Cleary	54	President and Management Committee Member
John R. Sult	49	Senior Vice President, Chief Financial Officer and Controller
James C. Yardley	57	Management Committee Member
Daniel B. Martin	52	Senior Vice President and Management Committee Member
Thomas L. Price	53	Vice President and Management Committee Member

James J. Cleary. Mr. Cleary has been a member of the Management Committee of Colorado Interstate Gas Company since November 2007 and President since January 2004. He previously served as Chairman of the Board of both Colorado Interstate Gas Company and El Paso Natural Gas Company from May 2005 to August 2006. From January 2001 to December 2003, he served as President of ANR Pipeline Company. Prior to that time, Mr. Cleary served as Executive Vice President of Southern Natural Gas Company from May 1998 to January 2001. He also worked for Southern Natural Gas Company and its affiliates in various capacities beginning in 1979. Mr. Cleary serves as Senior Vice President of El Paso Pipeline GP Company, L.L.C., the general partner of El Paso Pipeline Partners, L.P.

John R. Sult. Mr. Sult has been Senior Vice President, Chief Financial Officer and Controller of Colorado Interstate Gas Company since November 2005. He has been Senior Vice President and Controller of our parent El Paso and Senior Vice President, Chief Financial Officer and Controller of our affiliates El Paso Natural Gas Company, Southern Natural Gas Company and Tennessee Gas Pipeline Company. He served as Vice President and Controller for Halliburton Energy Services Company from August 2004 until joining El Paso in October 2005. From December 2002 to July 2004, Mr. Sult provided finance and accounting advisory services to energy companies as an independent consultant. He served as an audit partner for Arthur Andersen LLP from September 1994 to December 2002. From 1981 to 1994, Mr. Sult worked in various audit positions with Arthur Andersen. Mr. Sult serves as Senior Vice President, Chief Financial Officer and Controller of El Paso Pipeline GP Company, L.L.C., the general partner of El Paso Pipeline Partners, L.P.

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James C. Yardley. Mr. Yardley has been a member of the Management Committee of Colorado Interstate Gas Company since November 2007. Mr. Yardley also serves as Executive Vice President of our parent El Paso with responsibility for oversight of the regulated pipeline business unit since August 2006. He has been a member of the Management Committee of Southern Natural Gas Company since November 2007 and President since May 1998. Mr. Yardley has been President and Chairman of the Board of Tennessee Gas Pipeline since August 2006. He served as Vice President, Marketing and Business Development for Southern Natural Gas Company from April 1994 to April 1998. Prior to that time, Mr. Yardley worked in various capacities with Southern Natural Gas Company and Sonat Inc. beginning in 1978. Mr. Yardley is currently a member of the board of directors of Scorpion Offshore Ltd. He also serves as Chairman of the Board of Interstate Natural Gas Association of America. Mr. Yardley serves as Director, President and Chief Executive Officer of El Paso Pipeline GP Company, L.L.C., the general partner of El Paso Pipeline Partners, L.P.

Daniel B. Martin. Mr. Martin has been a member of the Management Committee of Colorado Interstate Gas Company since November 2007 and Senior Vice President since January 2001. Mr. Martin has been a member of the Management Committee of our affiliate Southern Natural Gas Company since November 2007. He previously served as a director of Colorado Interstate Gas Company and Southern Natural Gas Company from May 2005 to November 2007. Mr. Martin has been a director of our affiliates El Paso Natural Gas Company and Tennessee Gas Pipeline Company since May 2005. Mr. Martin has been Senior Vice President of Southern Natural Gas Company and Tennessee Gas Pipeline Company since June 2000 and Senior Vice President of El Paso Natural Gas Company since February 2000. He served as a director of ANR Pipeline Company from May 2005 through February 2007 and Senior Vice President of ANR Pipeline Company from January 2001 to February 2007. Prior to that time, Mr. Martin worked in various capacities with Tennessee Gas Pipeline Company beginning in 1978. Mr. Martin serves as Senior Vice President of El Paso Pipeline GP Company, L.L.C., the general partner of El Paso Pipeline Partners, L.P.

 Thomas L. Price. Mr. Price has been a member of the Management Committee of Colorado Interstate Gas Company since November 2007, Vice President of Marketing and Business Development since February 2007 and Vice President of Marketing since February 2002. He previously served as a director of Colorado Interstate Gas Company from May 2005 to November 2007. Mr. Price has been a director of our affiliate El Paso Natural Gas Company since November 2005 and Vice President of Marketing since June 2002. Prior to that time, Mr. Price worked in various capacities with Colorado Interstate Gas Company including Vice President of Customer Services from 1998 to 2001.

Audit Committee, Compensation Committee and Code of Ethics

As a majority owned subsidiary of El Paso, we rely on El Paso for certain support services. As a result, we do not have a separate corporate audit committee or audit committee financial expert, or a separate compensation committee. Also, we have not adopted a separate code of ethics. However, our executives are subject to El Paso’s code of ethics, referred to as the “Code of Business Conduct”. The Code of Business Conduct is a value-based code that is built on five core values: stewardship, integrity, safety, accountability and excellence. In addition to other matters, the Code of Business Conduct establishes policies to deter wrongdoing and to promote honest and ethical conduct, including ethical handling of actual or apparent conflicts of interest, compliance with applicable laws, rules and regulations, full, fair, accurate, timely and understandable disclosure in public communications and prompt internal reporting of violations of the Code of Business Conduct. A copy of the Code of Business Conduct is available for your review at El Paso’s website,www.elpaso.com. Copies will also be provided to any person upon request. Such requests should be in writing, addressed to El Paso Corporation, c/o Ms. Marguerite Woung-Chapman, Corporate Secretary, P.O. Box 2511, Houston, TX 77252.

ITEM 11. EXECUTIVE COMPENSATION

All of our executive officers are officers or employees of El Paso or one of its non-CIG subsidiaries and devote a substantial portion of their time to El Paso or such other subsidiaries. None of these executive officers receives any compensation from CIG or its subsidiaries. The compensation of our executive officers is set by El Paso, and we have no control over the compensation determination process. Our executive officers and former employees participate in employee benefit plans and arrangements sponsored by El Paso. We have not established separate employee benefit plans and we have not entered into employment agreements with any of our executive officers.

The members of our management committee are also officers or employees of El Paso or one of its non-CIG subsidiaries and do not receive additional compensation for their service as a member of our management committee.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

CIG is a Delaware general partnership. CIG is owned 60 percent indirectly through a wholly owned subsidiary of El Paso, and is owned 40 percent by EPPP CIG GP Holdings, L.L.C., a subsidiary of El Paso Pipeline Partners, L.P., El Paso’s master limited partnership. The address of each of El Paso and El Paso Pipeline Partners, L.P. is 1001 Louisiana Street, Houston, Texas 77002.

The following table sets forth, as of February 23, 2009, the number of shares of common stock of El Paso owned by each of our executive officers and management committee members and all of our management committee members and executive officers as a group.

Name of Beneficial Owner	Shares of Common Stock Owned Directly or Indirectly		Shares Underlying Options Exercisable Within 60 Days(1)		Total Shares of Common Stock Beneficially Owned		Percentage of Total Shares of Common Stock Beneficially Owned(2)
James J. Cleary		49,860		269,508		319,368		*
John R. Sult		64,945		94,607		159,552		*
James C. Yardley		205,448		404,245		609,693		*
Daniel B. Martin		132,437		263,701		396,138		*
Thomas L. Price		49,878		80,713		130,591		*
All management committee members and executive officers as a group (5 persons)		502,568		1,112,774		1,615,342		*

____________

* Less than 1%.

(1) The shares indicated represent stock options granted under El Paso’s current or previous stock option plans, which are currently exercisable or which will become exercisable within 60 days of February 23, 2009. Shares subject to options cannot be voted.

(2) Based on 698,613,542 shares outstanding as of February 23, 2009.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

El Paso Master Limited Partnership (MLP)

We are a general partnership presently owned 60 percent indirectly through a wholly owned subsidiary of El Paso and 40 percent through a wholly owned subsidiary of the MLP.

Guarantee of WYCO Purchases of Natural Gas from Anadarko Energy Services

CIG entered into a commitment with Anadarko Energy Services Company (AES) to unconditionally guarantee the obligations of WYCO to pay when due, fifty percent of the obligation owed to AES for the purchase, sale and/or exchange of natural gas from AES, pursuant to a Base Contract for Sale and Purchase of natural gas. CIG further agreed to pay reasonable attorney’s fees and expenses incurred by AES in conjunction with the collection of any debts pursuant to this guaranty. The maximum aggregate liability of CIG pursuant to the guaranty amount is $1.6 million. This commitment became effective on December 17, 2008 and will terminate on August 31, 2009.

CIG Operating Agreements

We entered into a Construction and Operating Agreement with WIC, on March 12, 1982. This agreement was amended in 1984 and 1988. Under this agreement, we agreed to design and construct the WIC system and to operate WIC (including conducting WIC’s marketing and administering WIC’s service agreements) using the same practices that we adopt in the operation and administration of our own facilities. Under this agreement, we are entitled to be reimbursed by WIC for all costs incurred in the performance of the services, including both direct costs and allocations of general and administrative costs based on direct field labor charges. Included in our allocated expenses are a portion of El Paso’s general and administrative expenses and El Paso Natural Gas and Tennessee Gas Pipeline Company allocated payroll and other expenses. We are the operator of the WIC facilities, and are reimbursed by WIC for operation, maintenance and general and administrative costs allocated from us, in each case under the Construction and Operating Agreement referred to above.

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We entered into a Construction and Operating Agreement with Young Gas Storage Company, Ltd. on June 30, 1992. This agreement was amended in 1994 and 1997. Under this agreement, we agreed to design and construct the Young storage facilities and to operate the facilities (including conducting Young’s marketing and administering Young’s service agreements) using the same practices that we adopt in the operation and administration of our own facilities. We are entitled to reimbursement of all costs incurred in the performance of the services, including both direct costs and allocations of general and administrative costs based on direct field labor charges (including any costs charged or allocated to us from other affiliates). The agreement is subject to termination only in the event of our dissolution or bankruptcy, or a material default by us that is not cured within certain permissible time periods. Otherwise the agreement continues until the termination of the Young partnership agreement.

We entered into a Construction and Operating Agreement with Cheyenne Plains Gas Pipeline Company, L.L.C. on November 14, 2003. Under this agreement, we agreed to design and construct the facilities and to operate the Cheyenne Plains facilities (including conducting marketing and administering the service agreements) using the same practices that we adopt in the operation and administration of our own facilities. We are entitled to reimbursement by Cheyenne Plains for all costs incurred in the performance of the services, including both direct field labor charges and allocations of general and administrative costs (including any costs charged or allocated to us from other affiliates) using a modified Massachusetts allocation methodology, a time and motion analysis or other appropriate allocation methodology. The agreement is subject to termination by Cheyenne Plains on 12 months’ prior notice and is subject to termination by us on 12 months’ prior notice given no earlier than 48 months following the commencement of service by Cheyenne Plains in December 2004.

Transportation Agreements

We are a party to four transportation service agreements with WIC for transportation on the WIC system at maximum recourse rates. The total volume subject to these contracts is 176,971 Dth/d. These contracts extend for various terms with 16,260 Dth/d expiring on December 31, 2009; 57,950 Dth/d expiring on December 31, 2011; and the balance expiring thereafter. In response to a solicitation of offers to turn back capacity in a WIC open season, we relinquished 70,000 Dth/d of capacity effective January 1, 2008.

We are also a party to a transportation service agreement with WIC pursuant to which we will acquire 75,600 Dth/day of firm transportation capacity on WIC from a Primary Point of Receipt at the Cheyenne Hub to a Primary Point of Delivery into El Paso’s Ruby Pipeline at Opal, Wyoming.  The rate that we will pay for this service is WIC’s maximum recourse rates plus the cost of any off-system capacity on a third party pipeline that is acquired by WIC to provide this service. The service will commence on the in-service date of El Paso’s Ruby Pipeline and will continue until the later of July 1, 2021 or ten years from the commencement date.

In order to provide “jumper” compression service between our system and the Cheyenne Plains pipeline system, we added compression at our existing compressor station in Weld County, Colorado. Cheyenne Plains entered into a 25-year contract that expires in 2030 for the full capacity of the additional compression pursuant to which our full cost of service is covered. The contract is for 119,500 Dth/d.

Interconnection and Operational Balancing Agreements and Other Inter-Affiliate Agreements

We are party to an operating balancing agreement with WIC and to an operating balancing agreement with Cheyenne Plains. These agreements require the interconnecting parties to use their respective reasonable efforts to cause the quantities of gas that are tendered/accepted at each point of interconnection to equal the quantities scheduled at those points. The agreements provide for the treatment and resolution of imbalances. The agreements are terminable by either party on 30 days’ advance notice.

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We and WIC are parties to a capacity lease agreement dated November 1, 1997. In 1998, WIC installed a compressor unit at WIC’s Laramie compressor station. The installation of this compressor unit allowed the interconnection of our Powder River lateral and WIC’s mainline transmission system and resulted in an increase of approximately 49 MDth/d of capacity on our Powder River lateral (the original capacity on the Powder River lateral was approximately 46 MDth/d). In connection with the installation of the compression by WIC, we leased the additional 49 MDth/d of capacity in the Powder River lateral to WIC. WIC, in turn, leased to us 46 MDth/d of capacity through the new WIC compressor unit. The initial term of the lease of the Powder River lateral capacity from CIG to WIC was 10 years from the November 15, 1998 in-service date of the additional compression. In November 2008, the term of the lease was extended for 10 years. The term of the lease of the compression unit capacity from WIC to us continues for as long as we have shipper agreements for service using the compressor unit capacity. The parties to this agreement have agreed that the reciprocal leases provide adequate compensation to each other so there is no rental fee for either lease other than an agreement by WIC to reimburse us for any increase in operating expense incurred by us (including increased taxes, insurance or other expenses).

We are party to a facilities lease agreement with WYCO.  Under this agreement, we lease the High Plains pipeline facilities from WYCO for a term of 34 years, including extension (expiring in 2043) at a rate based on the cost-of-service on the pipeline facilities.  The lease rate is designed to have the same rate impacts on our customers as if we had direct ownership of the pipeline facilities.

We are party to a development agreement for the Totem Storage project with Xcel Energy WYCO, Inc. and Public Service Company of Colorado.  This agreement sets forth the agreement of the parties to the development and operation of the Totem Storage facilities.  An affiliate of PSCo is a 50 percent joint venture partner in WYCO.

We are party to a management agreement with WYCO.  Effective January 1, 2009, under this agreement we will perform the administrative duties of managing WYCO’s day-to-day operations.

Other Agreements and Transactions

In addition, we currently have and will have in the future other routine agreements with El Paso or one of its subsidiaries that arise in the ordinary course of business, including agreements for services and other transportation and exchange agreements and interconnection and balancing agreements with other El Paso pipelines.

For a description of certain additional affiliate transactions, see Part II, Item 8, Financial Statements and Supplementary Data, Note 11.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Audit Fees

The audit fees for the years ended December 31, 2008 and 2007 of $751,000 and $770,000, respectively, were primarily for professional services rendered by Ernst & Young LLP for the audits of the consolidated financial statements of Colorado Interstate Gas Company and its subsidiaries.

All Other Fees

No other audit-related, tax or other services were provided by our independent registered public accounting firm for the years ended December 31, 2008 and 2007.

Policy for Approval of Audit and Non-Audit Fees

We are substantially owned indirectly by El Paso and its subsidiaries and do not have a separate audit committee. El Paso’s Audit Committee has adopted a pre-approval policy for audit and non-audit services. For a description of El Paso’s pre-approval policies for audit and non-audit related services, see El Paso Corporation’s proxy statement for its 2009 Annual Meeting of Stockholders.

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PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

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

1. Financial statements

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

	Page
Reports of Independent Registered Public Accounting Firms	24
Consolidated Statements of Income	25
Consolidated Balance Sheets	26
Consolidated Statements of Cash Flows	27
Consolidated Statements of Partners’ Capital/Stockholder's Equity	28
Notes to Consolidated Financial Statements	29
2. Financial statement schedules
Schedule II — Valuation and Qualifying Accounts	44

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

3. Exhibits

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

Undertaking

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

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Colorado Interstate Gas Company has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on the 2nd day of March 2009.

COLORADO INTERSTATE GAS COMPANY
By:	/s/ James J. Cleary
	James J. Cleary
	President

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

Signature	Title	Date
/s/ James J. Cleary	President and Management Committee Member	March 2, 2009
James J. Cleary	(Principal Executive Officer)
/s/ John R. Sult	Senior Vice President, Chief Financial	March 2, 2009
John R. Sult	Officer and Controller (Principal Accounting and Financial Officer)
/s/ James C. Yardley	Management Committee Member	March 2, 2009
James. C. Yardley
/s/ Daniel B. Martin	Senior Vice President and Management Committee Member	March 2, 2009
Daniel B. Martin
/s/ Thomas L. Price	Vice President and Management Committee Member	March 2, 2009
Thomas L. Price

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COLORADO INTERSTATE GAS COMPANY

EXHIBIT INDEX

December 31, 2008

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

Exhibit Number		Description
3.A	Certificate of Conversion (Exhibit 4.A to our Current Report on Form 8-K filed with the SEC on November 7, 2007).
3.B	Statement of Partnership Existence (Exhibit 4.B to our Current Report on Form 8-K filed with the SEC on November 7, 2007).
3.C	General Partnership Agreement dated November 1, 2007 (Exhibit 4.C to our Current Report on Form 8-K filed with the SEC on November 7, 2007).
3.D	First Amendment to the General Partnership Agreement of Colorado Interstate Gas Company, dated September 30, 2008 (Exhibit 3.A to our Current Report on Form 8-K filed with the SEC on October 6, 2008).
4.A	Indenture dated as of June 27, 1997, between Colorado Interstate Gas Company and The Bank of New York Trust Company, N.A. (successor to Harris Trust and Savings Bank), as Trustee (Exhibit 4.A to our Annual Report on Form 10-K for the year ended December 31, 2004, filed with the SEC on March 29, 2005); First Supplemental Indenture dated as of June 27, 1997, between Colorado Interstate Gas Company and The Bank of New York Trust Company, N.A. (successor to Harris Trust and Savings Bank), as Trustee (Exhibit 4.A.1 to our Annual Report on Form 10-K for the year ended December 31, 2004, filed with the SEC on March 29, 2005); Second Supplemental Indenture dated as of March 9, 2005 between Colorado Interstate Gas Company and The Bank of New York Trust Company, N.A., as Trustee (Exhibit 4.A to our Current Report on Form 8-K filed with the SEC on March 14, 2005); Third Supplemental Indenture dated as of November 1, 2005 between Colorado Interstate Gas Company and The Bank of New York Trust Company, N.A., as trustee (Exhibit 4.A to our Current Report on Form 8-K filed with the SEC on November 2, 2005); Fourth Supplemental Indenture dated October 15, 2007 by and between CIG and The Bank of New York Trust Company, N.A., as trustee (Exhibit 4.A to our Current Report on Form 8-K filed with the SEC on October 16, 2007); Fifth Supplemental Indenture dated November 1, 2007 by and among CIG, Colorado Interstate Issuing Corporation, and The Bank of New York Trust Company, N.A., as trustee (Exhibit 4.A to our Current Report on Form 8-K filed with the SEC on November 7, 2007).
10.A	No-Notice Storage and Transportation Delivery Service Agreement Rate Schedule NNT-1, dated October 1, 2001, between Colorado Interstate Gas Company and Public Service Company of Colorado (Exhibit 10.G to our Quarterly Report on Form 10-K for the period ended March 31, 2005, filed with the SEC on May 11, 2005).
10.B	Purchase and Sale Agreement, By and Among CIG Gas Supply Company, Wyoming Gas Supply Inc., WIC Holdings Inc., El Paso Wyoming Gas Supply Company and Wyoming Interstate Company, Ltd., dated November 1, 2005 (Exhibit 10.B to our Current Report on Form 8-K filed with the SEC on November 2, 2005).
10.C	First Tier Receivables Sale Agreement dated November 3, 2006 between Colorado Interstate Gas Company and CIG Finance Company L.L.C. (Exhibit 10.A to our Current Report on Form 8-K filed with the SEC on November 9, 2006).
10.D	Second Tier Receivables Sale Agreement dated November 3, 2006 between CIG Finance Company L.L.C. and CIG Funding Company L.L.C. (Exhibit 10.B to our Current Report on Form 8-K filed with the SEC on November 9, 2006).
10.E	Receivables Purchase Agreement dated November 3, 2006 among CIG Funding Company L.L.C., as Seller, Colorado Interstate Gas Company, as Servicer, Starbird Funding Corporation, as the initial Conduit Investor and Committed Investor, the other investors from time to time parties thereto, BNP Paribas, New York Branch, as the initial Managing Agent, the other Managing Agents from time to time parties thereto, and BNP Paribas, New York Branch, as Program Agent (Exhibit 10.C to our Current Report on Form 8-K filed with the SEC on November 9, 2006).

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10.F	Amendment No. 1 dated as of November 2, 2007 to the Receivables Purchase Agreement dated as of November 3, 2006, among CIG Funding Company, L.L.C., a Delaware limited liability company, Colorado Interstate Gas Company, a Delaware corporation, as initial Servicer, Starbird Funding Corporation and the other funding entities from time to time party hereto as Investors, BNP Paribas, New York Branch, and the other financial institutions from time to time party hereto as Managing Agents, and BNP Paribas, New York Branch, as Program Agent (Exhibit 10.H.1 to our Annual Report on Form 10-K for the year ended December 31, 2007, filed with the SEC on March 5, 2008).
*10.G	Amendment No. 2, dated as of October 31, 2008, to the Receivables Purchase Agreement dated as of October 6, 2006 among CIG Funding Company, L.L.C., Colorado Interstate Gas Company, as initial Servicer, Starbird Funding Corporation and other funding entities from time to time party hereto as Investors, BNP Paribas, New York Branch, and the other financial institutions from time to time party hereto as Managing Agents, and BNP Paribas, New York Branch, as Program Agent.
10.H	Lease Agreement dated December 17, 2008, and effective on November 1, 2008, by and between WYCO Development LLC, a Colorado limited liability company, and Colorado Interstate Gas Company, a Delaware corporation (Exhibit 10.A to our Current Report on Form 8-K filed with the SEC on December 22, 2008).
*21	Subsidiaries of Colorado Interstate Gas Company.
*31.A	Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*31.B	Certification of Principal 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 Principal Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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