COLORADO INTERSTATE GAS COMPANY, L.L.C. - FORM 10-K

Attached files

file	filename
EX-21 - EXHIBIT 21 - SUBSIDIARIES OF COLORADO INTERSTATE GAS COMPANY - COLORADO INTERSTATE GAS COMPANY, L.L.C.	exhibit_21.htm
EX-31.B - EXHIBIT 31.B - CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 - COLORADO INTERSTATE GAS COMPANY, L.L.C.	exhibit_31b.htm
EX-31.A - EXHIBIT 31.A - CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 - COLORADO INTERSTATE GAS COMPANY, L.L.C.	exhibit_31a.htm
EX-32.A - EXHIBIT 32.A - CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 - COLORADO INTERSTATE GAS COMPANY, L.L.C.	exhibit_32a.htm
EX-23 - EXHIBIT 23 - CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM ERNST & YOUNG LLP - COLORADO INTERSTATE GAS COMPANY, L.L.C.	exhibit_23.htm
EX-32.B - EXHIBIT 32.B - CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 - COLORADO INTERSTATE GAS COMPANY, L.L.C.	exhibit_32b.htm

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

________________

Form 10-K

(Mark One)

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

	For the fiscal year ended December 31, 2010

	OR

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

	For the transition period from to

Commission File Number 1-4874

Colorado Interstate Gas Company

(Exact Name of Registrant as Specified in Its Charter)

Delaware	84-0173305
(State or Other Jurisdiction of Incorporation or Organization)	(I.R.S. Employer 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 £ No R

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes £ No R

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes R No £

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer £	Accelerated filer £	Non-accelerated filer R	Smaller reporting company £
	(Do not check if a smaller reporting company)

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

State the aggregate market value of the voting equity 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	4
Item 1B.	Unresolved Staff Comments	12
Item 2.	Properties	12
Item 3.	Legal Proceedings	12
Item 4.	(Removed and Reserved)	12

	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	13
Item 6.	Selected Financial Data	13
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	14
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	23
Item 8.	Financial Statements and Supplementary Data	24
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	44
Item 9A.	Controls and Procedures	44
Item 9B.	Other Information	44

	PART III
Item 10.	Directors, Executive Officers and Corporate Governance	45
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	49
Item 14.	Principal Accountant Fees and Services	51

	PART IV
Item 15.	Exhibits and Financial Statement Schedules	52
	Signatures	53

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	LNG	=	liquefied natural gas
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”, "the Company" 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 42 percent indirectly through a wholly owned subsidiary of El Paso Corporation (El Paso) and 58 percent by EPPP CIG GP Holdings, L.L.C., a subsidiary of El Paso Pipeline Partners, L.P. (EPB), a master limited partnership of 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, a processing plant and our 50 percent ownership interest in WYCO Development LLC (WYCO) which is a joint venture with an affiliate of Public Service Company of Colorado (PSCo).

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

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

•

providing outstanding customer service;

•

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

•

developing new growth projects in our market and supply areas;

•

maintaining the integrity and ensuring the safety of our pipeline system and other assets;

•

successfully recontracting expiring contracts for transportation capacity; and

•

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

Pipeline System. Our pipeline system consists of approximately 4,300 miles of pipeline with a design capacity of approximately 4,592 MMcf/d. During 2010, 2009, and 2008, average throughput was 2,131 BBtu/d, 2,299 BBtu/d, and 2,225 BBtu/d. This system extends from production areas in the U.S. Rocky Mountains and the Anadarko Basin directly to customers in Colorado and Wyoming and indirectly to the midwest, southwest, California and the Pacific northwest.

Storage and Processing Facilities. Along our pipeline system, we own interests in five storage fields in Colorado and Kansas with approximately 37 Bcf of underground working natural gas storage capacity, including 6 Bcf of storage capacity from Totem Gas Storage owned by WYCO which is further discussed below. In addition, we have a processing plant located in Wyoming.

WYCO. We own a 50 percent interest in WYCO, a joint venture with an affiliate of PSCo. WYCO owns Totem Gas Storage and the 164 mile High Plains pipeline, both of which are located in Northeast Colorado. Totem Gas Storage and the High Plains pipeline were placed in service in June 2009 and November 2008, respectively and are operated by us under CIG’s certificate with the FERC. The High Plains pipeline extends 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 primarily contracted with PSCo pursuant to a firm contract through 2029. The Totem Gas Storage facility consists of a natural gas storage field that services and interconnects with the High Plains pipeline. The Totem Gas Storage field has 6 Bcf of working natural gas storage capacity with a maximum withdrawal rate of 200 MMcf/d and a maximum injection rate of 100 MMcf/d. 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 in Wyoming operated by an affiliate.

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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, including supply from unconventional sources, and various natural gas markets.

The natural gas industry is undergoing a major shift in supply sources. Production from conventional sources is declining while production from unconventional sources, such as shales, is rapidly increasing. This shift will affect the supply patterns, the flows and the rates that can be charged on pipeline systems. The impact will vary among pipelines according to the location and the number of competitors attached to these new supply sources.

Electric power generation has been the source of most of the growth in demand for natural gas over the last 10 years, and this trend is expected to continue in the future. The growth of natural gas in this sector is influenced by competition with coal and increased consumption of electricity as a result of recent economic growth. Short-term market shifts have been driven by relative costs of coal-fired generation versus gas-fired generation. A long-term market shift in the use of coal in power generation could be driven by environmental regulations. The future demand for natural gas could be increased by regulations limiting or discouraging coal use. However, natural gas demand could potentially be adversely affected by laws mandating or encouraging renewable power sources.

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. In late 2010, the Colorado Public Utility Commission approved a proposal for Public Service of Colorado to convert approximately 900 megawatts of older coal generation to natural gas fired generation by 2017. This approval remains under review and is being protested by the coal industry.

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 Wyoming Interstate Company, LLC (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.

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

Customers and Contracts

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

The following table details our customer and contract information related to our pipeline system as of December 31, 2010. Firm customers reserve capacity on our pipeline system and storage facilities and are obligated to pay a monthly reservation or demand charge, regardless of the amount of natural gas they transport or store, for the term of their contracts. Interruptible customers are customers without reserved capacity that pay usage charges based on the volume of gas they transport, store, inject or withdraw.

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Customer Information		Contract Information
Approximately 110 firm and interruptible customers.		Approximately 160 firm transportation contracts. Weighted average remaining contract term of approximately seven years.

Major Customers: PSCo (905 BBtu/d)		Expire in 2012 – 2029.
(874 BBtu/d)		Expire in 2025 – 2029.
(200 BBtu/d)		Expires in 2040.

Williams Gas Marketing, Inc.
(395 BBtu/d)		Expire in 2011 – 2014.

Pioneer Natural Resources USA, Inc.
(109 BBtu/d)		Expire in 2014 – 2015.
(202 BBtu/d)		Expire in 2020 – 2022.

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. The rates established under our tariffs are a function of our costs of providing services to our customers, including a reasonable return on our invested capital. Generally, the FERC’s authority extends to:

•

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

•

certification and construction of new facilities;

•

extension or abandonment of services and facilities;

•

maintenance of accounts and records;

•

relationships between pipelines and certain affiliates;

•

terms and conditions of 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 (DOT) and the U.S. Department of the Interior. We have ongoing inspection programs designed to keep our facilities in compliance with pipeline safety and environmental requirements and we believe that our system is in material compliance with the applicable regulations. For a further discussion of the potential impact of regulatory matters on us, see Item 1A, Risk Factors.

Environmental

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

Employees

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

Risks Related to Our Business

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

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

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

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

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

Our pipeline business is extensively regulated by the FERC, the DOT, the Department of Interior, the U.S. Department of Homeland Security and various state and local regulatory agencies whose actions have the potential to adversely affect our profitability. The FERC regulates most aspects of our business, including the terms and conditions of services offered, our relationships with affiliates, construction and abandonment of facilities and the rates charged by our pipeline (including establishing authorized rates of return). We periodically file to adjust the rates charged to our customers. We are working with our customers to pre-settle a rate case that will establish new rates effective October 2011. We may not be successful in this effort which would then require that we file and potentially litigate a full rate case the outcome of which we cannot control. There is a risk that the FERC may establish rates that are not acceptable to us and have a negative impact on us. In addition, our profitability is influenced by fluctuations in costs and our ability to recover any increases in our costs in the rates charged to our shippers. Our operating results can be negatively impacted to the extent that such costs increase in an amount greater than what we are permitted to recover in our rates or to the extent that there is a lag before we can file and obtain rate increases.

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Our existing rates may also be challenged by complaint. The FERC commenced several proceedings in 2009 and 2010 against unaffiliated pipeline systems to reduce the rates they were charging their customers. There is a risk that the FERC or our customers could file similar complaints on us and that a successful complaint against our rates could have an adverse impact on us.

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

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

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

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

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

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

●	our ability to obtain necessary approvals and permits from the FERC and other regulatory agencies on a timely basis that are on terms that are acceptable to us, including the potential negative impact of delays and increased costs caused by general opposition to energy infrastructure development, especially in environmentally, culturally sensitive and more heavily populated areas;
●	the ability to access sufficient capital at reasonable rates to fund expansion projects, especially in periods of prolonged economic decline when we may be unable to access the capital markets;
●	the availability of skilled labor, equipment, and materials to complete expansion projects;
●	potential changes in federal, state and local statutes, regulations, and orders;
●	impediments on our ability to acquire rights-of-way or land rights on terms that are acceptable to us;
●	our ability to construct projects within anticipated costs, including the risk that we may incur cost overruns resulting from weather conditions, geologic conditions, inflation or increased costs of equipment, materials (such as steel and nickel), labor, contractor productivity, delays in construction due to various factors including delays in obtaining regulatory approvals or other factors beyond our control. These cost overruns could be material and we may not be able to recover such excess costs from our customers which could negatively impact the return on our investments or could result in financial impairments;
●	our ability to construct projects within anticipated time frames that would likely delay our collection of transportation charges under our contracts;
●	the failure of suppliers and contractors to meet their performance and warranty obligations; and
●	the lack of transportation, storage or throughput commitments.

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

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We depend on certain key customers and producers for a significant portion of our revenues and the loss of any of these key customers could result in a decline in our revenues.

We rely on a limited number of customers for a significant portion of our system revenues. For the year ended December 31, 2010, PSCo accounted for approximately 41 percent of our operating revenues. The loss of any material portion of the contracted volumes of this customer, as a result of competition, creditworthiness, inability to negotiate extensions, or replacements of contracts or otherwise, could have a material adverse effect on us. For additional information on our revenues from this customer, see Part II, Item 8, Financial Statements and Supplementary Data, Note 9.

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

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

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

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

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

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

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

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

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●	adverse changes in global economic conditions, including changes that negatively impact general demand for power generation and industrial loads for natural gas;
●	adverse changes in geopolitical factors and unexpected wars, terrorist activities and others acts of aggression;
●	technological advancements that may drive further increases in production from natural gas shales;
●	competition from imported LNG and alternate fuels;
●	increased prices of natural gas that could negatively impact demand for these products;
●	increased costs to transport natural gas;
●	adoption of various energy efficiency and conservation measures; and
●	perceptions of customers on the availability and price volatility of natural gas prices over the longer-term.

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

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

●	changes in regional and domestic supply and demand;
●	changes in basis differentials among different supply basins that can negatively impact our ability to compete with supplies from other basins, including our ability to maintain transportation revenues and renew transportation contracts in supply basins that are not as competitive as other alternatives;
●	changes in the costs of transporting natural gas;
●	increased in federal and state taxes, if any, on the transportation of natural gas;
●	the price and availability of supplies of alternative energy sources; and
●	the amount of capacity available to transport natural gas.

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

The natural gas business is highly competitive. We compete with other interstate and intrastate pipeline companies as well as gatherers and storage companies in the transportation and storage of natural gas. We also compete with suppliers of alternate sources of energy, including electricity, coal and fuel oil. We frequently have one or more competitors in the supply basins and markets that we are connected to. This includes the Rockies Express Pipeline and other third-party competitors in the U.S. Rocky Mountain region.

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

Our operations are subject to a number of inherent risks including fires, earthquakes, adverse weather conditions (such as extreme cold or heat, tornadoes, lightning and flooding) and other natural disasters; terrorist activity or acts of aggression; the collision of equipment of third parties on our infrastructure (such as damage caused to our underground pipelines by third party excavation or construction); explosions, pipeline failures, mechanical and process safety failures, events causing our facilities to operate below expected levels of capacity or efficiency; uncontrollable flows of natural gas, release of pollution or contaminants into the environment (including discharges of toxic gases or substances) and other environmental hazards. Each of these risks could result in (a) damage or destruction of our facilities, (b) damages and injuries to persons and property or (c) business interruptions while damaged energy infrastructure is repaired or replaced, each of which could cause us to suffer substantial losses. In addition, although the potential effects of climate change on our operations (such as flooding, etc.) are uncertain at this time, changes in climate patterns as a result of global emissions of greenhouse gas (GHG) could have a negative impact upon our operations in the future.

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While we maintain insurance against some of these risks in amounts that we believe are reasonable, our insurance coverages have material deductibles, self-insurance levels, limits on our maximum recovery and do not cover all risks. For example, we do not carry or are unable to obtain insurance coverage on terms that we find acceptable for certain exposures including, but not limited to certain environmental exposures (including potential environmental fines and penalties), business interruption, named windstorm/hurricane exposures and in limited circumstances certain political risk exposures. The premiums and deductibles we pay for certain insurance policies are also subject to the risk of substantial increases over time that could negatively impact our financial results. In addition, we may not be able to renew existing insurance policies or procure desirable insurance on commercially reasonable terms. There is also a risk that our insurers may default on their coverage obligations. As a result, we could be adversely affected if a significant event occurs that is not fully covered by insurance.

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

Our operations are subject to a complex set of federal, state and local laws and regulations that tend to change from time to time and generally are becoming increasingly more stringent. In addition to laws and regulations affecting our business, there are various laws and regulations that regulate various market practices in the industry, including antitrust laws and laws that prohibit fraud and manipulation in the markets in which we operate. The authority of the Federal Trading Commission and the FERC to impose penalties for violations of laws or regulations has generally increased over the last few years. In addition, our business is subject to laws and regulations that govern environmental, health and safety matters. These regulations include compliance obligations for air emissions, water quality, wastewater discharge and solid and hazardous waste disposal, as well as regulations designed for the protection of human health and safety and threatened or endangered species. Compliance obligations can result in significant costs to install and maintain pollution controls, and to maintain measures to address personal and process safety and protection of the environment and animal habitat near our operations. We are often obligated to obtain permits or approvals in our operations from various federal, state and local authorities, which permits and approvals can be denied or delayed. In addition, we are exposed to fines and penalties to the extent that we fail to comply with the applicable laws and regulations, as well as the potential for limitations to be imposed on our operations. These regulations often impose remediation obligations associated with the investigation or clean-up of contaminated properties, as well as damage claims arising out of the contamination of properties or impact on natural resources. Finally, many of our assets are located and operate on federal, state, or local lands and are typically regulated by one or more federal, state or local agencies. For example, we operate assets that are located on federal lands, which are regulated by the Department of the Interior.

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

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

●

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

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●

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

●

Pipeline Safety. There Various legislative and regulatory reforms associated with pipeline safety and integrity issues have been recently proposed, including reforms that would require increased periodic inspections, installation of additional valves and other equipment on our pipelines and subjecting additional pipelines (including gathering and intrastate pipeline facilities) to more stringent regulation. It is uncertain what reforms, if any, will be adopted and what impact they might ultimately have on our operations or financial results.

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

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

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

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

We have certain contingent liabilities that could exceed our estimates.

We have certain contingent liabilities associated with litigation, regulatory and environmental matters. In this regard, although we have greatly reduced our litigation, regulatory and environmental exposures over the last several years, we continue to have contingent liabilities (see Part II, Item 8, Financial Statements and Supplementary Data, Note 7). Although we believe that we have established appropriate reserves for our litigation and environmental matters, we could be required to accrue additional amounts in the future and these amounts could be material.

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We have also sold assets and either retained certain liabilities or indemnified certain purchasers against future liabilities related to assets sold, including liabilities associated with environmental and other representations that we have provided. Although we believe that we have established appropriate reserves for these liabilities, we could be required to accrue additional amounts in the future and these amounts could be material. We have experienced substantial reductions and turnover in the workforce that previously supported the ownership and operation of such assets which could result in difficulties in managing these retained liabilities, including a reduction in historical knowledge of the assets and business that is required to effectively manage these liabilities or defend any associated litigation or regulatory proceedings.

We are subject to interest rate risks.

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

Risks Related to Our Affiliation with El Paso and EPB

El Paso and EPB 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 EPB and El Paso.

As a majority owned subsidiary of EPB and El Paso, subject to limitations in our indentures, EPB and El Paso have 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 EPB’s cash management program.

EPB and El Paso may exercise such control in their 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.

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

Due to our relationship with El Paso and EPB, adverse developments or announcements concerning them or their other subsidiaries could adversely affect our financial condition, even if we have not suffered any similar development. El Paso, EPB and their subsidiaries, including us, are on a stable outlook with Moody’s Investor Service, Fitch Ratings and Standard & Poor’s rating agencies. There is a risk that these credit ratings may be adversely affected in the future as the credit rating agencies continue to review our, EPB’s, and El Paso’s leverage, liquidity and credit profile. Any reduction in our, El Paso’s, or EPB’s credit ratings could impact our ability to access the capital markets, as well as our cost of capital. Below are the ratings assigned to our, El Paso’s and EPB’s senior unsecured indebtedness at December 31, 2010:

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		Rating Agency
		Moody’s Investor Service	Standard & Poor’s	Fitch Ratings
		Credit Ratings
CIG		Baa3 (1)	BB (2)	BBB- (1)
EPB		Ba1 (2)	BB (2)	BBB- (1)
El Paso		Ba3 (2)	BB- (2)	BB+ (2)
____________
(1)	Investment Grade
(2)	Non-Investment Grade

EPB provides cash management services and El Paso provides 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 EPB, 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 EPB subjects us to potential conflicts of interest and they may favor their interests to the detriment of us.

Although EPB has majority control of most decisions affecting our business, there are certain decisions that require the approval of both El Paso and EPB, 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 EPB with regard to such matters requiring unanimous approval, which could negatively impact our future operations.

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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.

ITEM 3. LEGAL PROCEEDINGS

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

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 executed a Consent Decree with the DOJ and have paid a total of $1.02 million to settle all of these Title V and PSD issues at the Natural Buttes Compressor Station. In addition, as required by the Consent Decree, ambient air monitoring at the Uintah Basin commenced on January 1, 2010 for a period of two years. In November 2009, we sold our Natural Buttes Compressor Station and gas processing plant to a third party for $9 million. Pursuant to the 2009 FERC order approving the sale of the compressor station and gas processing plant, we filed proposed accounting entries associated with the sale with the FERC for its approval which utilized a technical obsolescence valuation methodology for determining the portion of the composite accumulated depreciation attributable to the plant which resulted in us recording a gain on the sale in the fourth quarter of 2009. In September 2010, the FERC issued an order that utilized a different depreciation allocation methodology to estimate the net book value of the facilities. Based on the order, we recorded a non-cash adjustment as an increase of operation and maintenance expense of approximately $21 million in September, 2010 to write down net property, plant and equipment associated with the sale of the Natural Buttes facilities since it is no longer probable of recovery. We have filed a request for rehearing and clarification of the order.

ITEM 4. (REMOVED AND RESERVED)

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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 EPB 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 $170 million in 2010, $144 million in 2009 and approximately $109 million in 2008. Additionally, in January 2011, we made a cash distribution of approximately $44 million to our partners.

ITEM 6. SELECTED FINANCIAL DATA

The following selected historical financial data is derived from our audited consolidated financial statements and is not necessarily indicative of results to be expected in the future. The selected 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 Report on Form 10-K.

	As of or for the Year Ended December 31,
	2010		2009		2008		2007		2006
	(In millions)
Operating Results Data:
Operating revenues	$	410	$	383	$	323	$	317	$	305
Operating income		194		205		153		145		143
Net income		143		157		149		107		87
Financial Position Data:
Total assets	$	1,542	$	1,569	$	1,543	$	1,769	$	2,292
Long-term debt and other financing obligations, less current maturities		649		646		580		575		600
Partners’ capital		769		796		783		1,043		1,149

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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 estimates that may affect us as we operate in the future.

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 2010 (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.	92

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.	8

____________

(1)	Excludes liquids transportation revenue, fuel sales and in the case of CIG, liquids revenue associated 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. During 2008, we recorded cost and revenue tracker adjustments associated with the implementation of fuel and related gas cost recovery mechanisms, which the FERC approved subject to the outcome of technical conferences. The implementation of these mechanisms was protested by a limited number of shippers. On July 31, 2009, the FERC issued an order to us directing us to remove the cost and revenue components from our fuel recovery mechanism. Due to this order, our future earnings may be impacted by both positive and negative fluctuations in gas prices related to fuel imbalance revaluations and other gas balance related items. We continue to explore options to minimize the price volatility associated with these operational pipeline activities. Our tariff continues to provide that the difference between the quantity of fuel retained and fuel used in operations and lost and unaccounted for will be flowed-through or charged to shippers. These fuel trackers remove the impact of over or under collecting fuel and lost and unaccounted for gas from our operational gas costs.

CIG Rate Case. Under the terms of the 2006 rate case settlement, we must file a new general rate case to be effective no later than October 1, 2011. In February 2011, FERC approved an amendment of the 2006 settlement, which was unopposed by all of our shippers, to provide for a modification allowing the effective date of the required new rate case to be moved to December 1, 2011. The purpose of the delay in filing date is to allow us and our shippers the opportunity to reach a settlement of the rate proceeding before it is formally filed at FERC. At this time, the outcome of the pre-filing settlement negotiations and the outcome of the upcoming general rate case, in the event pre-filing settlement cannot be reached, cannot be known with certainty.

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

Our existing contracts expire at various times and in varying amounts of throughput capacity. The weighted average remaining contract term for our active contracts is approximately seven years as of December 31, 2010. Below are the contract expiration portfolio and the associated revenue expirations for our firm transportation contracts as of December 31, 2010, including those with terms beginning in 2011 or later.

	Contracted Capacity		Percent of Total Contracted Capacity		Reservation Revenue		Percent of Total Reservation Revenue
	(BBtu/d)				(In millions)
2011		204		5	$	11		3
2012		574		14		45		14
2013		1,254		30		84		27
2014		261		6		27		9
2015		133		3		12		4
2016 and beyond		1,725		42		136		43
Total		4,151		100	$	315		100

Projects Placed In Service. In December 2010, the Raton 2010 expansion project was placed into service, with a total project cost of approximately $95 million, well below the original budget. This expansion consists of approximately 118 miles of pipeline from the Raton Basin Wet Canyon Lateral to the south end of the Valley Line and provides additional capacity of approximately 130 MMcf/d from the Raton Basin in southern Colorado to the Cheyenne Hub in northern Colorado.

In June 2009, the Totem Gas Storage project was placed in service under our certificate with the FERC. We operate this storage facility, which is also owned by WYCO. This project consists of a natural gas storage field that services and interconnects with the High Plains pipeline. The Totem Gas Storage field has 6 Bcf of working natural gas storage capacity with a maximum withdrawal rate of 200 MMcf/d and a maximum injection rate of 100 MMcf/d. All of the storage capacity of this new storage field is fully contracted with PSCo pursuant to a firm contract through 2040.

In November 2008, the High Plains pipeline was placed in service under our certificate with the FERC. We operate this pipeline, which is owned by WYCO, a joint venture with an affiliate of PSCo in which we have a 50 percent ownership interest. For a further discussion of the accounting related to this asset, see Item 8, Financial Statements and Supplementary Data, Note 6. 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 interconnection with PSCo’s system. The system added approximately 900 MMcf/d of overall transportation capacity to our system. The increased capacity is primarily contracted with PSCo pursuant to a firm contract through 2029.

Growth Projects. We expect to spend approximately $24 million on organic growth projects through 2012. In addition to our organic growth projects, which are primarily contracted, we have other projects that are in various phases of commercial development. Many of the potential projects involve expansion capacity to serve increased natural gas-fired generation loads. For example, along the Front Range of our system, utilities have various projects under development that involve constructing new natural gas-fired generation in part to provide backup capacity required when renewable generation is not available during certain daily or seasonal periods. Most of these potential expansion projects would have in-service dates for 2014 and beyond. If we are successful in contracting for these new loads the capital requirements of such projects could be substantial and would be incremental to our contracted organic growth projects. Although we pursue the development of these potential projects from time to time, there can be no assurance that we will be successful in negotiating the definitive binding contracts necessary for such projects to be included in our contracted organic growth projects.

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We believe that cash flows from operating activities, combined with amounts available to us under EPB’s cash management program and capital 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 consist of consolidated operations as well as an investment in an unconsolidated affiliate. We believe EBIT is useful to investors to provide them with the same measure used by El Paso to evaluate our performance and so that investors may evaluate our operating results without regard to our financing methods. We define EBIT as net income adjusted for items such as interest and debt expense and affiliated interest income. EBIT may not be comparable to measures 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 2010 compared with 2009 and 2009 compared with 2008.

Operating Results:	2010			2009			2008
	(In millions, except for volumes)
Operating revenues	$	410		$	383		$	323
Operating expenses		(216	)		(178	)		(170	)
Operating income		194			205			153
Other income, net		8			4			11
EBIT		202			209			164
Interest and debt expense		(60	)		(54	)		(38	)
Affiliated interest income, net		1			2			23
Net income	$	143		$	157		$	149

Throughput volumes (BBtu/d)		2,131			2,299			2,225

EBIT Analysis:

	2010 to 2009										2009 to 2008
	Operating Revenue		Operating Expense			Other		Total			Operating Revenue			Operating Expense			Other			Total
	Favorable/(Unfavorable)
	(In millions)
Expansions	$	16	$	(2	)	$	2	$	16		$	67		$	(18	)	$	(3	)	$	46
Transportation revenues and expenses		3		4			—		7			(5	)		(4	)		—			(9	)
Operational gas, revaluations and processing revenues		8		(7	)		—		1			(2	)		3			—			1
Non-cash asset write down/Gain on long lived assets		—		(29	)		—		(29	)		—			8			—			8
Other(1)		—		(4	)		2		(2	)		—			3			(4	)		(1	)
Total impact on EBIT	$	27	$	(38	)	$	4	$	(7	)	$	60		$	(8	)	$	(7	)	$	45

____________

(1)	Consists of individually insignificant items.

Expansions. Our EBIT increased during the years ended December 31, 2010 and 2009 due to expansion projects placed into service, as follows:

	2010 to 2009		2009 to 2008
	(In millions)
High Plains pipeline	$	—	$	28
Totem gas storage		10		14
Raton 2010(1)		6		1
Other		—		3
Total impact on EBIT	$	16	$	46

____________

(1)	Placed in-service December 2010.

Transportation Revenues and Expenses. During the year ended December 31, 2010, our EBIT was favorably impacted, when compared to 2009, primarily due to $3 million higher revenue generated from capacity released on off-system volumes, increased demand from off-system firm transportation, and a transportation contract buy-out cost of $4 million recorded in 2009. During the year ended December 31, 2009 when compared to 2008, our transportation revenue decreased primarily due to $5 million lower usage revenues and a $4 million transportation contract buy-out cost.

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Operational Gas, Revaluations and Processing Revenues. Our EBIT increased during the year ended December 31, 2010 compared with 2009, primarily due to $8 million increased processing revenues from favorable liquid price changes and increased demand for natural gas liquids. This favorable impact, however, was largely offset by unfavorable prices for gas consumed in processing these liquids of $7 million when compared with 2009.

During 2009, we used a gas cost and revenue tracker to recover from shippers all cost impacts, or flow through to shippers any revenue impacts, of all gas balance items including fuel, gas imbalance and operational gas. On July 31, 2009, the FERC issued orders which retroactively unwound the non-volumetric provisions of the gas cost and revenue tracker, which exposes us to both positive and negative fluctuations in gas prices related to gas balance items. During 2009, we recorded a $7 million favorable adjustment to reflect the impact of retroactively unwinding the non-volumetric provision of the tracker. During 2010, we experienced $7 million favorable gas balance revaluations due to increases in gas prices. This price volatility impacts our earnings through the monthly non-cash revaluation of our gas balances and their eventual settlement. We continue to explore options to minimize the price volatility associated with these operational pipeline activities. For a further discussion of our fuel recovery mechanism, see Item 8, Financial Statements and Supplementary Data, Note 7.

Non-cash Asset Write Down/ Gain on Sale of Long-Lived Asset. During the third quarter of 2010, we recorded a $21 million non-cash asset write down as an increase of operations and maintenance expense based on a FERC order related to the sale of the Natural Buttes facilities in 2009. In the fourth quarter of 2009, we recorded a gain of $8 million related to the sale of the Natural Buttes facilities. For a further discussion of Natural Buttes, see Item 8, Financial Statements and Supplementary Data, Note 2.

Interest and Debt Expense

Interest and debt expense for the year ended December 31, 2010 was $6 million higher than in 2009 primarily related to the financing obligation to WYCO upon completion of Totem Gas Storage (see Item 8, Financial Statements and Supplementary Data, Note 6). Interest and debt expense for the year ended December 31, 2009 was $16 million higher than in 2008 primarily related to the financing obligations to WYCO upon completion of High Plains Pipeline and Totem Gas Storage (see Item 8, Financial Statements and Supplementary Data, Note 6), partially offset by a lower average outstanding long-term debt balance resulting from the repurchase of $100 million of our senior notes in 2008.

Affiliated Interest Income, Net

Affiliated interest income, net for the year ended December 31, 2010 was $1 million lower than in 2009 and $21 million lower for the year ended December 31, 2009 as compared with 2008 due to lower average advances due from El Paso under its cash management program and lower short-term interest rates. The following table shows the average advances and the average short-term interest rates for the years ended December 31:

	2010			2009			2008
	(In millions, except for rates)
Average advance to El Paso	$	58		$	119		$	534
Average advance to EPB		59			39			—
Average short-term interest rate on affiliate note receivable from El Paso		1.5	%		1.7	%		4.4	%
Average short-term interest rate on affiliate note receivable from EPB		0.8	%		0.7	%		—

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Liquidity and Capital Resources

Liquidity Overview. Our primary sources of liquidity are cash flows from operating activities, amounts available under EPB’s cash management program and capital contributions from our partners. In conjunction with EPB’s acquisition of an additional interest in us during July 2009, we terminated our participation in El Paso’s cash management program and began to participate in EPB’s cash management program. As a result, we converted our note receivable with El Paso under its cash management program into a demand note receivable. In December 2010, El Paso repaid the balance of the demand note, which approximated $19 million in principal and interest. In addition, at December 31, 2010, we had a note receivable from EPB under its cash management program of approximately $63 million. See Item 8, Financial Statements and Supplemental Data, Note 11 for a further discussion of EPB’s and El Paso’s cash management programs. Our primary uses of cash are for working capital, capital expenditures and for required distributions to our partners.

Although financial conditions have improved, continued volatility in the financial markets could impact our longer-term access to capital for future growth projects as well as the cost of such capital. Additionally, although the impacts are difficult to quantify at this point, a prolonged recovery of the global economy could have adverse impacts on natural gas consumption and demand. However, we believe our exposure to changes in natural gas consumption and demand is largely mitigated by a revenue base that is significantly comprised of long-term contracts that are based on firm demand charges and are less affected by a potential reduction in the actual usage or consumption of natural gas.

We believe we have adequate liquidity available to us to meet our capital requirements and our existing operating needs through cash flow from operating activities, amounts available under EPB’s cash management program and capital contributions from our partners. As of December 31, 2010, EPB had approximately $450 million of capacity available to it under its $750 million revolving credit facility and $69 million of cash. While we do not anticipate a need to directly access the financial markets in 2011 for any of our operating activities or expansion capital needs based on liquidity available to us, market conditions could impact our, EPB’s or El Paso’s ability to act opportunistically.

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

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2010 Cash Flow Activities. Our cash flows for the year ended December 31, 2010 are summarized as follows (In millions):



Cash Flow from Operations
Net income	$	143
Non-cash asset write down		21
Non-cash income adjustments		49
Change in other assets and liabilities		(29	)
Total cash flow from operations		184

Other Cash Inflows
Investing activities
Net change in notes receivable from affiliates		71
Other		2
Total other cash inflows		73

Cash Outflows
Investing activities
Capital expenditures		84
Financing activities
Distributions to partners		170
Other financing obligations		4
		174

Total cash outflows		258
Net change in cash and cash equivalents	$	(1	)

During 2010, we generated $184 million of operating cash flow. We primarily utilized these amounts along with net collections of our note receivables from affiliates to fund maintenance and expansion capital expenditures, as well as pay distributions to our partners. During the year ended December 31, 2010, we paid cash distributions of approximately $170 million to our partners. In addition, in January 2011 we paid a cash distribution to our partners of approximately $44 million. Our cash capital expenditures for the years ended December 31, 2010 and those planned for 2011 are listed below:

	2010		Expected 2011
	(In millions)
Maintenance	$	25	$	40
Expansion		59		21
Total	$	84	$	61

Our maintenance capital expenditures primarily relate to maintaining and improving the integrity of our pipeline complying with regulations and ensuring the safe and reliable delivery of natural gas to our customers. While we expect to fund maintenance capital expenditures through internally generated funds, we intend to fund our expansion capital expenditures through capital contributions from our partners and amounts available under EPB’s cash management program. Our expected 2011 expansion capital expenditures primarily relate to the installation of new air blending and related facilities in Douglas County, Colorado.

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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 and storage commitments, are not reflected on our balance sheet. The following table and discussion summarizes our contractual cash obligations as of December 31, 2010, 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	$	5	$	10	$	385	$	254	$	654
Interest		59		117		113		536		825

Other contractual liabilities		2		4		1		2		9
Operating leases		2		4		4		—		10
Transportation and storage commitments		20		29		24		84		157
Total contractual obligations	$	88	$	164	$	527	$	876	$	1,655

Long-Term Financing Obligations (Principal and Interest). Long-term financing obligations included in the table above represent stated maturities. Interest payments are shown through the stated maturity date of the related fixed rate obligations based on the contractual interest rate. Included in these amounts are payments related to the financing obligations for the construction of WYCO’s High Plains Pipeline and Totem Gas Storage facility. We make monthly interest payments on these obligations that are based on 50 percent of the operating results of the High Plains Pipeline and Totem Gas Storage facility. 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.

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

Transportation and Storage Commitments. Included in these amounts are commitments for demand charges for firm access to natural gas transportation and storage capacity.

Commitments and Contingencies

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

Off-Balance Sheet Arrangements

We have no off-balance sheet financing entities or structures with third parties other than our equity investment in WYCO and our accounts receivable sales program. For a discussion of our off-balance sheet arrangements, see Item 8, Financial Statements and Supplementary Data, Notes 7, 10, and 11 which are incorporated herein by reference.

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Critical Accounting Estimates

Our significant accounting policies are described in Note 1 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K. The preparation of financial statements in conformity with GAAP requires management to select appropriate accounting estimates and to make estimates and assumptions that affect the reported amount of assets, liabilities, revenue and expenses and the disclosures of contingent assets and liabilities. We consider our critical accounting estimates to be those that require difficult, complex, or subjective judgment necessary in accounting for inherently uncertain matters and those that could significantly influence our financial results based on changes in those judgments. Changes in facts and circumstances may result in revised estimates and actual results may differ materially from those estimates.

Cost-Based Regulation. We account for our regulated operations in accordance with current Financial Accounting Standards Board’s accounting standards for rate-regulated operations. 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 for non-regulated entities. Management regularly assesses whether regulatory assets are probable of future recovery or if regulatory liabilities are probable of being refunded to our customers 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 evaluate the applicability of accounting standards related to regulated operations, and consider factors such as regulatory changes and the impact of competition. If cost-based regulation ends or competition increases, we may have to reduce certain of our asset balances to reflect a market basis lower than cost and write-off the associated regulatory assets.

Accounting for Environmental and Legal Reserves. We accrue environmental and legal reserves when our assessments indicate that it is probable that a liability has been incurred or an asset will not be recovered and an amount can be reasonably estimated. Estimates of our liabilities are based on an evaluation of potential outcomes, currently available facts, and in the case of environmental reserves, 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.

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, 2010, our postretirement benefit plan was over funded by $10 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 rates 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-percentage point change in the primary assumptions would not have had a significant effect on the funded status or net postretirement benefit cost.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to the risk of changing interest rates. At December 31, 2010, we had a note receivable from EPB of approximately $63 million with a variable interest rate of 0.8%. In addition, at December 31, 2009, we had a note receivable from El Paso of approximately $73 million with a variable interest rate of 1.5%. While we are exposed to changes in interest income based on changes to the variable interest rate, the fair value of this note receivable approximates the carrying value due to the note being due on demand and the market-based nature of the interest rate.

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

	December 31, 2010																						December 31, 2009
	Expected Fiscal Year of Maturity of Carrying Amounts																				Fair		Carrying		Fair
	2011			2012			2013			2014			2015			Thereafter			Total		Value		Amounts		Value
	(In millions, except for rates)
Long-term debt and other financing obligations(1), including current portion — fixed rate.	$	5		$	5		$	5		$	5		$	380		$	254		$	654	$	703	$	650	$	695
Average interest rate		15.6	%		15.6	%		15.6	%		15.6	%		6.8	%		12.2	%

____________

(1) Our other financing obligations include amounts due to WYCO related to High Plains pipeline and Totem Gas Storage. 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 the Securities and Exchange Commission (SEC) rules adopted under the Securities Exchange Act of 1934, as amended. Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. It consists of policies and procedures that:

•

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

•

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

•

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

Under the supervision and with the participation of management, including the President and Chief Financial Officer, we made an assessment of the effectiveness of our internal control over financial reporting as of December 31, 2010. In making this assessment, we used the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation, we concluded that our internal control over financial reporting was effective as of December 31, 2010.

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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, 2010 and 2009, and the related consolidated statements of income, partners’ capital, and cash flows for each of the three years in the period ended December 31, 2010. Our audits also included the financial statement schedule listed in the Index at Item 15(a) for each of the three years in the period ended December 31, 2010. These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

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

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Colorado Interstate Gas Company at December 31, 2010 and 2009, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2010, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

/s/ Ernst & Young LLP

Houston, Texas

February 28, 2011

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COLORADO INTERSTATE GAS COMPANY

CONSOLIDATED STATEMENTS OF INCOME

(In millions)

	Year Ended December 31,
	2010			2009			2008
Operating revenues	$	410		$	383		$	323
Operating expenses
Operation and maintenance		154			121			120
Depreciation and amortization		42			38			33
Taxes, other than income taxes		20			19			17
		216			178			170
Operating income		194			205			153
Other income, net		8			4			11
Interest and debt expense		(60	)		(54	)		(38	)
Affiliated interest income, net		1			2			23
Net income	$	143		$	157		$	149

See accompanying notes.

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COLORADO INTERSTATE GAS COMPANY

CONSOLIDATED BALANCE SHEETS

(In millions)

	December 31,
	2010		2009
ASSETS
Current assets
Cash and cash equivalents	$	1	$	2
Accounts and notes receivable
Customer		1		—
Affiliates		3		121
Other		16		1
Materials and supplies		8		9
Regulatory assets		3		1
Other		3		4
Total current assets		35		138
Property, plant and equipment, at cost		1,850		1,753
Less accumulated depreciation and amortization		455		404
Total property, plant and equipment, net		1,395		1,349
Other assets
Notes receivable from affiliates		63		33
Other		49		49
		112		82
Total assets	$	1,542	$	1,569

LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities
Accounts payable
Trade	$	5	$	5
Affiliates		19		23
Other		17		10
Short-term financing obligations, including current maturities		5		4
Taxes payable		15		14
Regulatory liabilities		8		13
Accrued interest		4		4
Contractual deposits		11		7
Other		3		8
Total current liabilities		87		88
Long-term debt and other financing obligations, less current maturities		649		646
Other liabilities		37		39
Commitments and contingencies (Note 7)
Partners’ capital		769		796
Total liabilities and partners’ capital	$	1,542	$	1,569

See accompanying notes.

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COLORADO INTERSTATE GAS COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

	Year Ended December 31,
	2010			2009			2008
Cash flows from operating activities
Net income	$	143		$	157		$	149
Adjustments to reconcile net income to net cash from operating activities
Depreciation and amortization		42			38			33
Non-cash asset write down/(gain) on long-lived asset		21			(8	)		—
Other non-cash income items		7			16			3
Asset and liability changes
Accounts receivable		16			4			(3	)
Change in deferred purchase price from accounts receivable sales		(15	)		—			—
Accounts payable		(6	)		4			1
Current assets		1			(5	)		(2	)
Current liabilities		(20	)		(14	)		(9	)
Non-current assets		(3	)		5			(14	)
Non-current liabilities		(2	)		(1	)		2
Net cash provided by operating activities		184			196			160
Cash flows from investing activities
Capital expenditures		(84	)		(103	)		(134	)
Net change in notes receivable from affiliates		71			45			183
Proceeds from sale of assets		1			10			—
Other		1			2			3
Net cash provided by (used in) investing activities		(11	)		(46	)		52
Cash flows from financing activities
Payments to retire long-term debt and other financing obligations		(4	)		(4	)		(103	)
Distributions to partners		(170	)		(144	)		(109	)
Net cash used in financing activities		(174	)		(148	)		(212	)
Net change in cash and cash equivalents		(1	)		2			—
Cash and cash equivalents
Beginning of period		2			—			—
End of period	$	1		$	2		$	—


Supplemental cash flow information
Interest paid, net of amounts capitalized	$	57		$	52		$	37

See accompanying notes.

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COLORADO INTERSTATE GAS COMPANY

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

(In millions)



January 1, 2008	$	1,043
Net income		149
Distributions		(409	)
December 31, 2008		783
Net income		157
Distributions		(144	)
December 31, 2009		796
Net income		143
Distributions		(170	)
December 31, 2010	$	769

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 58 percent by EPPP CIG GP Holdings, L.L.C., a subsidiary of the El Paso Pipeline Partners, L.P. (EPB) which is majority owned by El Paso Corporation (El Paso) and 42 percent by El Paso Noric Investments III, L.L.C., a wholly owned subsidiary of El Paso. For a further discussion of these and other related transactions, see Note 11.

Our consolidated financial statements are prepared in accordance with U.S. generally accepted accounting principles (GAAP) and include the accounts of all consolidated subsidiaries after the elimination of intercompany accounts and transactions.

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

Use of Estimates

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

Regulated Operations

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

Cash and Cash Equivalents

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

Allowance for Doubtful Accounts

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

Materials and Supplies

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

Natural Gas Imbalances

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

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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 useful lives and other characteristics are grouped and depreciated as one asset. We apply the depreciation rate approved in our rate settlements to the total cost of the group until its net book value equals its salvage value. We re-evaluate depreciation rates each time we file with the FERC for an increase or decrease in our transportation and storage rates. Currently, our depreciation rates vary from approximately two percent to 25 percent per year.

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, as defined by the FERC. We include gains or losses on dispositions of operating units in operation and maintenance expense in our income statements.

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

Asset and Investment Divestitures/Impairments

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

Revenue Recognition

Our revenues are primarily generated from natural gas transportation, 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 ratably over the contract period. For interruptible or volumetric-based services, we record revenues when physical deliveries of natural gas are made at the agreed upon delivery point or when gas is injected or withdrawn from the storage facility. For contracts with step-up or step-down rate provisions, that are not related to changes in levels of service, we recognize reservation revenues ratably over the contract life. 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.

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Environmental Costs and Other Contingencies

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

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

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

Accounting for Asset Retirement Obligations

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

Postretirement Benefits

We maintain a postretirement benefit plan covering certain of our former employees. This plan requires us to make contributions to fund the benefits to be paid under the plan. These contributions are invested until the benefits are paid to plan participants. 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 factors such as the level of benefits provided under the plan, actuarial assumptions and the passage of time), expected returns on plan assets and amortization of certain deferred gains and losses. For a further discussion of our policies with respect to our postretirement benefit plan, see Note 8.

In accounting for our postretirement benefit plan, we record an asset or liability based on the over funded or under funded status of the plan. Any deferred amounts related to unrecognized gains and losses or changes in actuarial assumptions are recorded as either a regulatory asset or liability.

Income Taxes

We are a partnership for income tax purposes and are not subject to either federal income taxes or generally to state income taxes. Our partners are responsible for income taxes on their allocated share of taxable income which may differ from income for financial statement purposes due to differences in the tax basis and financial reporting basis of assets and liabilities. We are unable to readily determine the net difference in the bases of our assets and liabilities for financial and tax reporting purposes because information regarding each partner’s tax attributes in us is not available to us.

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2. Divestitures

In November 2009, we sold our Natural Buttes compressor station and gas processing plant to a third party for $9 million and recorded a gain of approximately $8 million related to the sale, which was included in our income statement as a reduction of operation and maintenance expense. Pursuant to the 2009 FERC order approving the sale of the compressor station and gas processing plant we filed for FERC approval of the proposed accounting entries associated with the sale which utilized a technical obsolescence valuation methodology for determining the portion of the composite accumulated depreciation attributable to the plant which resulted in us recording a gain on the sale in the fourth quarter of 2009. In September 2010, the FERC issued an order that utilized a different depreciation allocation methodology to estimate the net book value of the facilities. Based on the order, we recorded a non-cash adjustment as an increase of operation and maintenance expense of approximately $21 million to write down net property, plant and equipment associated with the sale of the Natural Buttes facilities since it is no longer probable of recovery. We have filed a request for rehearing and clarification of the order.

3. Fair Value of Financial Instruments

At December 31, 2010 and 2009, the carrying amounts of cash and cash equivalents and trade receivables and payables are representative of their fair value because of the short-term nature of these instruments. At December 31, 2010, we had a note receivable from EPB of approximately $63 million with a variable interest rate of 0.8%. In December 2010, El Paso repaid the balance of the demand note, which approximated $19 million in principal and interest. In addition, at December 31, 2009, we had a note receivable from El Paso of approximately $73 million, with a variable interest rate of 1.5%. While we are exposed to changes in interest income based on changes to the variable interest rates, the fair value of these note receivables approximates the carrying value due to the notes being due on demand and the market-based nature of the interest rates.

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

	2010				2009
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)
Long-term debt and other financing obligations, including current maturities	$	654	$	703	$	650	$	695

4. Regulatory Assets and Liabilities

Our non-current regulatory assets and liabilities are included in other non-current assets and liabilities on our balance sheets. Our regulatory asset and liability balances are recoverable or reimbursable over various periods. Below are the details of our regulatory assets and liabilities at December 31:

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	2010		2009
	(In millions)
Current regulatory assets
Difference between gas retained and gas consumed in operations	$	1	$	—
Other		2		1
Total current regulatory assets		3		1
Non-current regulatory assets
Taxes on capitalized funds used during construction		10		11
Unamortized loss on reacquired debt		5		6
Postretirement benefits		1		1
Other		1		1
Total non-current regulatory assets		17		19
Total regulatory assets	$	20	$	20

Current regulatory liabilities
Difference between gas retained and gas consumed in operations	$	7	$	13
Other		1		—
Total current regulatory liabilities		8		13
Non-current regulatory liabilities
Property and plant depreciation		18		18
Postretirement benefits		10		10
Total non-current regulatory liabilities		28		28
Total regulatory liabilities	$	36	$	41

The significant regulatory assets and liabilities include:

Difference Between Gas Retained and Gas Consumed in Operations. These amounts reflect the value of the volumetric difference between the gas retained and consumed in our operations. These amounts are not included in the rate base, but given our tariffs, are expected to be recovered from our customers or returned to our customers in subsequent fuel filing periods.

Taxes on Capitalized Funds Used During Construction. Regulatory asset balance established to offset the deferred tax for the equity component of the allowance for funds used during the construction of long-lived assets. Taxes on capitalized funds used during construction and the offsetting deferred income taxes are included in the rate base and are recovered over the depreciable lives of the long-lived asset to which they relate. The balance was established prior to our conversion to a non-taxable entity.

Unamortized Loss on Reacquired Debt. Amount represents the deferred and unamortized portion of losses on reacquired debt which are recovered over the original life of the debt issue through the cost of service.

Postretirement Benefits. Represents unrecognized gains and losses or changes in actuarial assumptions related to our postretirement benefit plan and differences in the postretirement benefit related amounts expensed and the amounts recovered in rates. Postretirement benefit amounts have been included in the rate base computations and are recoverable in such periods as benefits are funded.

Property and Plant Depreciation. Amounts represent the deferral of customer-funded amounts for costs of future asset retirements.

5. Property, Plant and Equipment

Capitalized costs during construction. Interest costs capitalized are included as a reduction to interest and debt expense on our income statements and were $2 million, $1 million, and $2 million during the years ended December 31, 2010, 2009 and 2008. The equity portion is calculated using the most recent FERC approved equity rate of return. Equity amounts capitalized are included in other income on our income statement and were $6 million, $4 million, and $8 million during the years ended December 31, 2010, 2009, and 2008. These amounts are recovered over the depreciable lives of the long-lived assets to which they relate.

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Construction work-in-progress. At December 31, 2010 and 2009, we had $17 million and $69 million of construction work-in-progress included in our property, plant and equipment.

Asset Retirement Obligations. We have legal obligations associated with the retirement of our natural gas pipelines, transmission facilities and storage wells. We have obligations to plug storage wells when we no longer plan to use them and when we abandon them. Our legal obligations associated with our natural gas transmission facilities primarily involve purging and sealing the pipeline if it is abandoned. We also have obligations to remove hazardous materials associated with our natural gas transmission facilities if they are ever demolished or replaced. We 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 pipelines 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 we cannot reasonably estimate the asset retirement obligation for the substantial majority of our natural gas pipelines and storage system assets because these assets have indeterminate lives. Our asset retirement liabilities as of December 31, 2010 and 2009, were not material to our financial statements. We continue to evaluate our asset retirement obligations and future developments could impact the amounts we record.

6. Long-Term Debt and Other Financing Obligations

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

	2010		2009
	(In millions)
5.95% Senior Notes due March 2015	$	35	$	35
6.80% Senior Notes due November 2015		340		340
6.85% Senior Debentures due June 2037		100		100
Total long-term debt		475		475
Other financing obligations		179		175
Total long-term debt and other financing obligations		654		650
Less: Current maturities		5		4
Total long-term debt and other financing obligations, less current maturities	$	649	$	646

In March 2009, we, Colorado Interstate Issuing Corporation (CIIC), El Paso and certain other El Paso subsidiaries filed a registration statement on Form S-3 under which we and CIIC may co-issue debt securities in the future. CIIC is a wholly owned finance subsidiary of us and is the co-issuer of our outstanding debt securities. CIIC has no material assets, operations, revenues or cash flows other than those related to its service as a co-issuer of our debt securities. Accordingly, it has no ability to service obligations on our debt securities.

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. For the year ended December 31, 2010, we were in compliance with our debt-related covenants.

Other Financing Obligations. In June 2009 and November 2008, the Totem Gas Storage project and the High Plains pipeline were placed in service. Upon placing these projects in service, we transferred our title in the projects to WYCO Development LLC (WYCO) (a joint venture with an affiliate of Public Service Company of Colorado (PSCo) in which we have a 50 percent ownership interest). Although we transferred the title in these projects to WYCO, we continue to reflect the Totem Gas Storage facility and the High Plains pipeline as property, plant and equipment in our financial statements as of December 31, 2010 due to our continuing involvement with the projects through WYCO.

We constructed the Totem Gas Storage project and the High Plains pipeline and our joint venture partner in WYCO funded 50 percent of the construction costs, which we reflected as other non-current liabilities in our balance sheet during the construction period. Upon completion of the construction, our obligations to the affiliate of PSCo for these construction advances were converted into financing obligations to WYCO and accordingly, we reclassified the amounts from other non-current liabilities to debt and other financing obligations.

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The Totem Gas Storage obligation has a principal amount of $75 million as of December 31, 2010 and has monthly principal payments totaling approximately $2 million each year through 2039 and extended for the term of related firm service agreements until 2060. We also make monthly interest payments on this obligation that are based on 50 percent of the operating results of the Totem Gas Storage facility, which is currently at a 15.5% rate as of December 31, 2010.

The High Plains pipeline obligation has a principal amount of $104 million as of December 31, 2010, and has monthly principal payments totaling $3 million each year through 2039 and extended for the term of related firm service agreements until 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 at a 15.5% rate as of December 31, 2010.

7. Commitments and Contingencies

Legal Proceedings

We and our affiliates are named defendants in numerous legal proceedings and claims that arise in the ordinary course of our business. For each of these matters, we evaluate the merits of the case or claim, our exposure to the matter, possible legal or settlement strategies and the likelihood of an unfavorable outcome. If we determine that an unfavorable outcome is probable and can be estimated, we establish the necessary accruals. While the outcome of these matters cannot be predicted with certainty, and there are still uncertainties related to the costs we may incur, based upon our evaluation and experience to date, we had no accruals for our outstanding legal proceedings at December 31, 2010. It is possible, however, that new information or future developments could require us to reassess our potential exposure related to these matters and establish accruals accordingly.

Environmental Matters

We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require us to remove or remedy the effect of the disposal or release of specified substances at current and former operating sites. At December 31, 2010 and 2009, we had accrued approximately $10 million and $11 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 $34 million at December 31, 2010. Our accrual at December 31, 2010 includes $7 million for environmental contingencies related to properties we previously owned.

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

For 2011, we estimate that our total remediation expenditures will be approximately $2 million, most of which will be expended under government directed clean-up plans. In addition, we expect to make capital expenditures for environmental matters of $5 million in the aggregate for 2011 through 2015. Included in this amount is $4 million associated with the impact of the EPA rule related to emissions of hazardous air pollutants from reciprocating internal combustion engines subject to regulations with which we have to be in compliance by October 2013.

It is possible that new information or future developments could require us to reassess our potential exposure related to environmental matters. We may incur significant costs and liabilities in order to comply with existing environmental laws and regulations. It is also possible that other developments, such as increasingly strict environmental laws, regulations and orders of regulatory agencies, as well as claims for damages to property and the environment or injuries to 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 Matter

Fuel Recovery Mechanism. During 2008, we recorded cost and revenue tracker adjustments associated with the implementation of fuel and related gas cost recovery mechanisms, which the FERC approved subject to the outcome of technical conferences. The implementation of these mechanisms was protested by a limited number of shippers. On July 31, 2009, the FERC issued an order to us directing us to remove the cost and revenue components from our fuel recovery mechanism. Due to this order, our future earnings may be impacted by both positive and negative fluctuations in gas prices related to fuel imbalance revaluations, our settlement, and other gas balance related items. We continue to explore options to minimize the price volatility associated with these operational pipeline activities. Our tariff continues to provide that the difference between the quantity of fuel retained and fuel used in operations and lost and unaccounted for will be flowed-through or charged to shippers. These fuel trackers remove the impact of over or under collecting fuel and lost and unaccounted for from our operational gas costs.

Other Commitments

Capital Commitments. We have planned capital and investment projects that are discretionary in nature, with no substantial contractual capital commitments made in advance of the actual expenditures.

Transportation and Storage Commitments. We have entered into transportation commitments and storage capacity contracts totaling approximately $157 million at December 31, 2010, of which $100 million is related to storage capacity contracts with our affiliate, Young Gas Storage Company, Ltd (Young). Our annual commitments under these agreements are $20 million in 2011, $17 million in 2012, $12 million in 2013, $12 million in 2014, $12 million in 2015, and $84 million in total thereafter.

Operating Leases. We lease property, facilities and equipment under various operating leases. Future minimum annual rental commitments under our operating leases at December 31, 2010, were as follows:

Year Ending December 31,	(In millions)
2011	$	2
2012		2
2013		2
2014		3
2015		1
Total	$	10

Rental expense on our lease obligations for the years ended December 31, 2010, 2009, and 2008 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. During 2009, our financial guarantee with a maximum exposure of approximately $2 million was terminated.

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8. Retirement Benefits

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

Postretirement Benefits Plan. 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 2011.

Accumulated Postretirement Benefit Obligation, Plan Assets and Funded Status. In accounting for our postretirement benefit plan we record an asset or liability based on the over funded or under funded status. Any deferred amounts related to unrecognized gains and losses or changes in actuarial assumptions are recorded either as a regulatory asset or liability as allowed by the FERC. These amounts would otherwise be recorded in accumulated other comprehensive income for non-regulated entities. The table below provides information about our postretirement benefit plan.

	December 31
	2010			2009
	(In millions)
Change in accumulated postretirement benefit obligation:
Accumulated postretirement benefit obligation – beginning of period	$	5		$	7
Participant contributions		1			1
Actuarial gain		—			(2	)
Benefits paid(1)		(1	)		(1	)
Accumulated postretirement benefit obligation ––end of period	$	5		$	5
Change in plan assets:
Fair value of plan assets – beginning period	$	14		$	12
Actual return on plan assets		2			2
Participant contributions		—			1
Benefits paid		(1	)		(1	)
Fair value of plan assets – end of period	$	15		$	14
Reconciliation of funded status:
Fair value of plan assets	$	15		$	14
Less: accumulated postretirement benefit obligation		5			5
Net asset at December 31	$	10		$	9

____________

(1)	Amounts shown net of a subsidy of less than $1 million for each of the years ended December 31, 2010 and 2009 related to the Medicare Prescription Drug, Improvement, and Modernization Act of 2003.

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

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We use various methods to determine the fair values of the assets in our other postretirement benefit plan, which is impacted by a number of factors, including the availability of observable market data over the contractual term of the underlying assets. We separate these assets into three levels (Level 1, 2 and 3) based on our assessment of the availability of this market data and the significance of non-observable data used to determine the fair value of these assets. As of December 31, 2010, assets were comprised of an exchange-traded mutual fund with a fair value of $1 million and common collective trust funds with a fair value of $14 million. As of December 31, 2009, assets were comprised of an exchange-traded mutual fund with a fair value of $1 million and common collective trust funds with a fair value of $13 million. Our exchange-traded mutual fund invests primarily in dollar-denominated securities, and its fair value (which is considered a Level 1 measurement) is determined based on the price quoted for the fund in actively traded markets. Our common collective trust funds are invested in approximately 65 percent equity and 35 percent fixed income securities, and their fair values (which are considered Level 2 measurements) are determined primarily based on the net asset value reported by the issuer, which is based on similar assets in active markets. Certain restrictions on withdrawal exist for these common collective trust funds where the issuer reserves the right to temporarily delay withdrawal in certain situations such as market conditions or at the issuer's discretion. We do not have any assets that are considered Level 3 measurements. The methods described above may produce a fair value that may not be indicative of net realizable value or reflective of future fair values, and there have been no changes in the methodologies used at December 31, 2010 and 2009.

Expected Payment of Future Benefits. As of December 31, 2010, we expect the following benefit payments under our plan:

Year Ending December 31,	Expected Payments(1)
	(In millions)
2011	$	1
2012		1
2013		1
2014		1
2015		1
2016 - 2020		2

____________

(1)	Includes a reduction of less than $1 million in each of the years 2011 – 2015 and approximately $1 million in aggregate for 2016 – 2020 for an expected subsidy related to the Medicare Prescription Drug, Improvement, and Modernization Act of 2003.

Actuarial Assumptions and Sensitivity Analysis. Accumulated postretirement benefit obligations and net benefit costs are based on actuarial estimates and assumptions. The following table details the weighted average actuarial assumptions used in determining our postretirement plan obligations and net benefit costs for 2010, 2009 and 2008:

	2010		2009		2008
	(Percent)
Assumptions related to benefit obligations at December 31:
Discount rate		4.52		5.06		5.82
Assumptions related to benefit costs for the year ended December 31:
Discount rate		5.06		5.82		6.05
Expected return on plan assets(1)		7.75		8.00		8.00

____________

(1)

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

Actuarial estimates for our postretirement benefits plan assumed a weighted average annual rate of increase in the per capita costs of covered health care benefits of 7.4 percent, gradually decreasing to 5.0 percent by the year 2016. A one-percentage point change would not have had a significant effect on the accumulated postretirement benefit obligation or interest cost as of and for the years ended December 31, 2010 and 2009.

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

	2010			2009			2008
	(In millions)
Interest cost	$	—		$	1		$	1
Expected return on plan assets		(1	)		(1	)		(1	)
Amortization of net actuarial gain		—			—			(1	)
Net benefit income	$	(1	)	$	—		$	(1	)

9. Transactions with Major Customer

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

	2010		2009		2008
	(In millions)
PSCo	$	168	$	154	$	90

At December 31, 2010, we have transportation and storage agreements with PSCo for capacity on the High Plains pipeline through 2029 and Totem Storage Gas facility through 2040 with annual firm revenue of $44 million and $34 million, respectively.

10. Accounts Receivable Sales Program

During 2009, we had agreements to sell senior interests in certain of our accounts receivable (which are short-term assets that generally settle within 60 days) to a third party financial institution (through wholly-owned special purpose entities), and we retained subordinated interests in those receivables. The sale of these senior interests qualified for sale accounting and was conducted to accelerate cash from these receivables, the proceeds from which were used to increase liquidity and lower our overall cost of capital. During the year ended December 31, 2009 and 2008, we received $207 million and $153 million of cash related to the sale of the senior interests, collected $179 million and $181 million from the subordinated interests we retained in the receivables, and recognized a loss of approximately less than $1 million in both periods on these transactions. At December 31, 2009, the third party financial institution held $20 million of senior interests and we held $17 million of subordinated interests. Our subordinated interests were reflected in accounts receivable on our balance sheet. In January 2010, we terminated these accounts receivable sales programs and paid $20 million to acquire the senior interests. We reflected the cash flows related to the accounts receivable sold under this program, changes in our retained subordinated interests, and cash paid to terminate the programs, as operating cash flows on our statement of cash flows.

In the first quarter of 2010, we entered into a new accounts receivable sales program to continue to sell accounts receivable to a third party financial institution that qualifies for sale accounting under the updated accounting standards related to financial asset transfers. Under these programs, we sell receivables in their entirety to the third-party financial institution (through a wholly-owned special purpose entity). At December 31, 2010, the third-party financial institution held $37 million of the accounts receivable we sold under the program. In connection with our accounts receivable sales, we receive a portion of the sales proceeds up front and receive an additional amount upon the collection of the underlying receivables (which we refer to as a deferred purchase price). Our ability to recover the deferred purchase price is based solely on the collection of the underlying receivables. During the year ended December 31, 2010, we sold approximately $436 million of accounts receivable to the third-party financial institution, for which we received approximately $240 million of cash up front and had a deferred purchase price of approximately $196 million. We received approximately $181 million of cash related to the deferred purchase price when the underlying receivables were collected during 2010. As of December 31, 2010, we had not collected approximately $15 million of deferred purchase price related to our accounts receivable sales, which is reflected as other accounts receivable on our balance sheet (and was initially recorded at an amount which approximates its fair value as a Level 2 measurement). We recognized a loss of approximately less than $1 million on our accounts receivable sales during the year ended December 31, 2010. Because the cash received up front and the deferred purchase price relate to the sale or ultimate collection of the underlying receivables, and are not subject to significant other risks given their short term nature, we reflect all cash flows under the new accounts receivable sales programs as operating cash flows on our statement of cash flows.

Under both the prior and current accounts receivable sales programs, we serviced the underlying receivables for a fee. The fair value of these servicing agreements as well as the fees earned were not material to our financial statements for the periods ended December 31, 2010, 2009, and 2008.

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The third party financial institution involved in both of these accounts receivable sales programs acquires interests in various financial assets and issues commercial paper to fund those acquisitions. We do not consolidate the third party financial institution because we do not have the power to control, direct, or exert significant influence over its overall activities since our receivables do not comprise a significant portion of its operations.

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 and the Totem Gas storage facility (both of which are FERC regulated), a state regulated intrastate pipeline, and a compressor station. At December 31, 2010 and 2009, our investment in WYCO was approximately $15 million and $14 million, which is included in other non-current assets in our balance sheets. We have other financing obligations payable to WYCO totaling $179 million and $175 million as of December 31, 2010 and 2009, which are further described in Note 6.

Transactions with Affiliates

EPB Acquisition. In July 2009, EPB acquired an additional 18 percent ownership interest in us from El Paso. The acquisition increased EPB’s interest in us to 58 percent.

Distributions. On September 30, 2008, prior to EPB’s 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. We are required to make distributions of available cash as defined in our partnership agreement on a quarterly basis to our partners. During 2010, 2009 and 2008, we paid cash distributions of approximately $170 million, $144 million and $109 million to our partners.

Cash Management Programs. In conjunction with EPB’s acquisition of an additional interest in us as described above, during the third quarter of 2009 we began to participate in EPB’s cash management program which matches our short-term cash surpluses and needs, thus minimizing our total borrowings from outside sources. EPB uses the cash management program to settle intercompany transactions with us. At December 31, 2010 and December 31, 2009, we had a note receivable from EPB of approximately $63 million and $61 million. The interest rate on this variable rate note was 0.8% and 0.7% at December 31, 2010 and December 31, 2009.

In conjunction with EPB’s acquisition of the additional interest in us as described above, we terminated our participation in El Paso’s cash management program. We converted our note receivable with El Paso under its cash management program into a demand note receivable from El Paso. In December 2010, El Paso repaid the balance of the demand note, which approximated $19 million in principal and interest. At December 31, 2009, we had a $73 million note receivable from El Paso. The interest rate on this variable rate note was 1.5% at December 31, 2009.

Other Affiliate Balances. At December 31, 2010 and 2009, we had contractual deposits from our affiliates of $11 million and $7 million included in other current liabilities on our balance sheet.

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. We are managed and operated by officers of El Paso, our general partner and we are provided services through an affiliated service company owned by El Paso. 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 (TGP), our affiliates, associated with our pipeline services. We also allocate costs to Wyoming Interstate Company, LLC (WIC) and Cheyenne Plains Gas Pipeline, our affiliates, for their share of our pipeline services. The allocations from TGP and El Paso are based on the estimated level of effort devoted to our operations and the relative size of our earnings before interest expense and income taxes, 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:

	2010		2009		2008
	(In millions)
Revenues from affiliates	$	12	$	11	$	17
Operation and maintenance expenses from affiliates		86		101		86
Reimbursements of operating expenses charged to affiliates		11		26		26

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(1)		December 31(2)		Total
	(In millions)
2010
Operating revenues	$	113	$	97	$	89	$	111	$	410
Operating income		65		47		23		59		194
Net income		54		34		10		45		143
2009
Operating revenues	$	97	$	85	$	91	$	110	$	383
Operating income		51		42		47		65		205
Net income		41		33		33		50		157

____________

(1)	The quarter ended September 30, 2010 includes a $21 million non-cash asset write down related to the sale of the Natural Buttes facilities in 2009 (see Note 2).

(2)	The quarter ended December 31, 2009 includes a gain of $8 million related to the sale of the Natural Buttes facilities (see Note 2).

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SCHEDULE II

COLORADO INTERSTATE GAS COMPANY

VALUATION AND QUALIFYING ACCOUNTS

Years Ended December 31, 2010, 2009 and 2008

(In millions)

Description	Balance at Beginning of Period		Charged to Costs and Expenses		Deductions(1)			Charged to Other Accounts		Balance at End of Period
2010
Environmental reserves	$	11	$	—	$	(1	)	$	—	$	10

2009
Environmental reserves	$	13	$	1	$	(3	)	$	—	$	11

2008
Environmental reserves	$	15	$	1	$	(3	)	$	—	$	13

____________

(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, 2010, we carried out an evaluation under the supervision and with the participation of our management, including our President and Chief Financial Officer (CFO), as to the effectiveness, design and operation of our disclosure controls and procedures. This evaluation considered the various processes carried out under the direction of our disclosure committee in an effort to ensure that information required to be disclosed in the U.S. Securities and Exchange Commission reports we file or submit under the Securities Exchange Act of 1934, as amended (Exchange Act) is accurate, complete and timely. Our management, including our President and CFO, does not expect that our disclosure controls and procedures or our internal controls will prevent and/or detect all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within our company have been detected. Our disclosure controls and procedures are designed to provide reasonable assurance of achieving their objective and our President and our CFO concluded that our disclosure controls and procedures (as defined in Exchange Act Rules 13a – 15(e) and 15d – 15(e)) were effective as of December 31, 2010. See Item 8, Financial Statements and Supplementary Data, under Management’s Annual Report on Internal Control Over Financial Reporting.

Changes in Internal Control Over Financial Reporting

During the fourth quarter of 2010, we implemented a new gas accounting system which includes customer imbalance management, gas cost accounting, gas balance, customer invoicing and revenue accounting functionalities. The system implementation efforts were carefully planned and executed. Training sessions were administered to individuals who are impacted by the new system. The system controls and functionality were reviewed and successfully tested prior and subsequent to implementation. Following evaluation, management believes that the new system has been successfully implemented. There were no other changes in our internal control over financial reporting during the fourth quarter of 2010 that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

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PART III

ITEM 10. DIRECTORS, AND EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Management Committee and Executive Officers

We are a Delaware general partnership with two partners, the first of which is a wholly owned subsidiary of EPB (the “EPB Partner”), and the second of which is a wholly owned subsidiary of El Paso (the “El Paso Partner”). The EPB Partner owns a 58 percent interest in our partnership, and the El Paso Partner owns our remaining 42 percent interest. A general partnership agreement governs our ownership and management. Although our management is vested in our 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 EPB Partner and one representative being designated by the El Paso 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 management committee members, including the experience, qualifications, attributes or skills of such individuals, as well as information regarding our executive officers, as of February 25, 2011. 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	56	President and Management Committee Member
John R. Sult	51	Executive Vice President and Chief Financial Officer
James C. Yardley	59	Management Committee Member
Daniel B. Martin	54	Senior Vice President and Management Committee Member
Thomas L. Price	55	Vice President and Management Committee Member

James J. Cleary. Mr. Cleary has been President of Colorado Interstate Gas Company since January 2004 and a member of its Management Committee since November 2007. 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. Mr. Cleary also serves as Senior Vice President of El Paso Pipeline GP Company, L.L.C., the general partner of El Paso Pipeline Partners, L.P.

Mr. Cleary’s day to day leadership as our President provides him with an intimate knowledge of our partnership, including its strategies, operations and markets. In addition, his experience as President of El Paso Corporation’s Western Pipeline Group and as an attorney provides the Management Committee with an important skill set and perspective.

John R. Sult. Mr. Sult has been Executive Vice President and Chief Financial Officer of Colorado Interstate Gas Company since March 2010, Senior Vice President and Chief Financial Officer from November 2009 to March 2010 and Senior Vice President, Chief Financial Officer and Controller from November 2005 to November 2009. Mr. Sult also serves as Executive Vice President and Chief Financial Officer of our parent El Paso and as Executive Vice President and Chief Financial Officer of our affiliates El Paso Natural Gas Company, Southern Natural Gas Company and Tennessee Gas Pipeline Company. Mr. Sult previously served as Senior Vice President and Controller of El Paso from November 2005 to November 2009. Mr. Sult held the position of Vice President and Controller at Halliburton Energy Services Company from August 2004 until joining El Paso in October 2005. Mr. Sult also serves as Director, Executive Vice President and Chief Financial Officer of El Paso Pipeline GP Company, L.L.C., the general partner of El Paso Pipeline Partners, L.P.

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 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 served as President from May 1998 to August 2010. Mr. Yardley has served as Chairman of the Board of Tennessee Gas Pipeline Company since February 2007 and served as its President from August 2006 to August 2010. Mr. Yardley serves on the Board of Interstate Natural Gas Association of America and previously served as its Chairman. Mr. Yardley also 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.

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As Executive Vice President of El Paso Corporation’s Pipeline Group, Mr. Yardley brings a wealth of operating experience to our Management Committee as well as an extensive understanding of the pipeline industry overall. In addition, Mr. Yardley’s experience as President and Chief Executive Officer of El Paso Pipeline Partners, L.P. further augments his knowledge and experience.

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. Mr. Martin also serves as Senior Vice President of El Paso Pipeline GP Company, L.L.C., the general partner of El Paso Pipeline Partners, L.P. Mr. Martin is currently a member of the board of directors of Citrus Corp., a joint venture between El Paso Citrus Holdings, Inc. and CrossCountry Citrus, LLC.

With his years of experience with El Paso’s pipeline subsidiaries, Mr. Martin brings comprehensive knowledge and understanding of the pipeline industry. In particular, Mr. Martin provides the Management Committee with valuable leadership and experience in pipeline safety, compliance and emergency response.

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. Additionally, Mr. Price previously served as a Director of our affiliate El Paso Natural Gas Company from November 2005 to November 2010, and Vice President of Marketing from June 2002 to November 2010.

Mr. Price brings extensive experience in marketing and business development, and in his current role oversees, the marketing, business development and facility planning activities for Colorado Interstate Gas Company, Wyoming Interstate Company, L.L.C., Cheyenne Plains Gas Pipeline Company, L.L.C., Young Gas Storage Company, Ltd. and Ruby Pipeline, L.L.C., which collectively serve much of the Rockies and the Western United States.

Audit Committee, Compensation Committee and Code of Ethics

As a majority owned subsidiary of EPB, we rely on EPB 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 Conduct”. The Code of 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 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 Conduct. A copy of the Code of Conduct is available for your review at El Paso’s website, www.elpaso.com.

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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 AND RELATED STOCKHOLDER MATTERS

CIG is a Delaware general partnership. CIG is owned 42 percent indirectly through a wholly owned subsidiary of El Paso, and is owned 58 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 17, 2011, 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	66,952	256,477	323,429	*
John R. Sult	116,131	209,897	326,028	*
James C. Yardley	306,991	559,203	866,194	*
Daniel B. Martin	162,099	227,670	389,769	*
Thomas L. Price	62,326	101,797	164,123	*
All management committee members and executive officers as a group (5 persons)	714,499	1,355,044	2,069,543	*

___________________

*	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 17, 2011. Shares subject to options cannot be voted.

(2)	Based on 704,734,612 shares outstanding as of February 17, 2011.

The following table sets forth, as of February 17, 2011, the number of common units of EPB 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	Total Common Units Beneficially Owned	Percentage of Total Common Units Beneficially Owned(1)
James J. Cleary	2,000	*
John R. Sult	10,000	*
James C. Yardley	10,000	*
Daniel B. Martin	—	—
Thomas L. Price	—	—
All management committee members and executive officers as a group (5 persons)	22,000	*

___________________

*	Less than 1%.

(1)	Based on 177,167,863 units outstanding as of February 17, 2011.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

El Paso Pipeline Partners, L.P.

We are a general partnership presently owned 58 percent indirectly through a wholly owned subsidiary of EPB and 42 percent through a wholly owned subsidiary of the El Paso.

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.

We entered into a Construction and Operating Agreement with Young 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 57,950 Dth/d expiring on December 31, 2011, 89,021 Dth/d expiring on July 31, 2012 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.

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We are party to a capacity release agreement with PSCo, whereby PSCo has released storage capacity in our affiliate, Young Gas Storage Company, Ltd., to us for a term expiring on April 30, 2025. PSCo simultaneously contracted for a corresponding quantity of transportation and storage balancing service (which utilizes the storage capacity acquired through the capacity release).

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. In addition, CIG is a party to interconnection and operational balancing agreements with Ruby Pipeline, L.L.C. 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.

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).

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 revised and updated 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.

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ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Audit Fees

The audit fees for the years ended December 31, 2010 and 2009 of $982,000 and $792,000, 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 as well as the review of documents filed with the SEC and related consent.

All Other Fees

No other audit-related, tax or other services were provided by our independent registered public accounting firm for the years ended December 31, 2010 and 2009.

Policy for Approval of Audit and Non-Audit Fees

We are a majority owned subsidiary of both El Paso and EPB and do not have a separate audit committee. El Paso’s and EPB’s Audit Committees have adopted pre-approval policies for audit and non-audit services. For a description of El Paso’s pre-approval policies for audit and non-audit related services, see El Paso Corporation’s proxy statement for its 2011 Annual Meeting of Stockholders. For a description of EPB’s pre-approval for audit and non-audit related services, see EPB’s Annual Report on Form 10-K for the year ended December 31, 2010.

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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

Report of Independent Registered Public Accounting Firm	25
Consolidated Statements of Income	26
Consolidated Balance Sheets	27
Consolidated Statements of Cash Flows	28
Consolidated Statements of Partners’ Capital	29
Notes to Consolidated Financial Statements	30

2. Financial statement schedules

Schedule II — Valuation and Qualifying Accounts	43

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

3. Exhibits

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

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

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

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

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

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

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

Undertaking

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

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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 28th day of February 2011.

	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	February 28, 2011
James J. Cleary	(Principal Executive Officer)

/s/ John R. Sult	Executive Vice President and	February 28, 2011
John R. Sult	Chief Financial Officer (Principal Financial Officer)

/s/ Rosa P. Jackson	Vice President and Controller	February 28, 2011
Rosa P. Jackson	(Principal Accounting Officer)

/s/ James C. Yardley	Management Committee Member	February 28, 2011
James C. Yardley

/s/ Daniel B. Martin	Management Committee Member	February 28, 2011
Daniel B. Martin

/s/ Thomas L. Price	Management Committee Member	February 28, 2011
Thomas L. Price

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COLORADO INTERSTATE GAS COMPANY

EXHIBIT INDEX

December 31, 2010

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

Exhibit Number		Description
3.A		Certificate of Conversion (incorporated by reference to Exhibit 3.A to our Current Report on Form 8-K filed with the SEC on November 7, 2007).

3.B		Statement of Partnership Existence (incorporated by reference to Exhibit 3.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 (incorporated by reference to Exhibit 3.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 (incorporated by reference to Exhibit 3.A to our Current Report on Form 8-K filed with the SEC on October 6, 2008).

3.E		Second Amendment to the General Partnership Agreement of Colorado Interstate Gas Company, dated July 24, 2009 (incorporated by reference to Exhibit 3 to our Current Report on Form 8-K filed with the SEC on July 30, 2009).

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 (incorporated by reference to Exhibit 4.A to our Annual Report on Form 10-K for the year ended December 31, 2009, filed with the SEC on February 26, 2010); First Supplemental Indenture dated as of June 27, 1997, between Colorado Interstate Gas Company and The Bank of New York Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.A.1 to our Annual Report on Form 10-K for the year ended December 31, 2009, filed with the SEC on February 26, 2010); 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. (incorporated by reference to Exhibit 4.A.2 to our Annual Report on Form 10-K for the year ended December 31, 2009, filed with the SEC on February 26, 2010); 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 (incorporated by reference to Exhibit 4.A.3 to our Annual Report on Form 10-K for the year ended December 31, 2009, filed with the SEC on February 26, 2010); Fourth Supplemental Indenture dated October 15, 2007 by and between Colorado Interstate Gas Company and The Bank of New York Trust Company, N.A., as trustee (incorporated by reference to 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 Colorado Interstate Gas Company, Colorado Interstate Issuing Corporation, and The Bank of New York Trust Company, N.A., as trustee (incorporated by reference to 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 (incorporated by reference to Exhibit 10.A to our Annual Report on Form 10-K for the year ended December 31, 2009, filed with the SEC on February 26, 2010).

10.B		Lease Agreement dated December 17, 2008, and effective on November 1, 2008, by and between WYCO Development LLC and Colorado Interstate Gas Company (incorporated by reference to Exhibit 10.C to our Annual Report on Form 10-K for the year ended December 31, 2009, filed with the SEC on February 26, 2010).

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*21		Subsidiaries of Colorado Interstate Gas Company.

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

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

*31.B		Certification of 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.

Attached files

COLORADO INTERSTATE GAS COMPANY, L.L.C. Reports

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