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

COLORADO INTERSTATE GAS COMPANY, L.L.C. - FORM 10-K - February 27, 2012

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EXCEL - IDEA: XBRL DOCUMENT - COLORADO INTERSTATE GAS COMPANY, L.L.C.	Financial_Report.xls
EX-3.B - FIRST AMENDED AND RESTATED LIMITED LIABILITY COMPANY AGREEMENT - COLORADO INTERSTATE GAS COMPANY, L.L.C.	d271449dex3b.htm
EX-21 - SUBSIDIARIES OF COLORADO INTERSTATE GAS COMPANY - COLORADO INTERSTATE GAS COMPANY, L.L.C.	d271449dex21.htm
EX-3.A - CERTIFICATE OF CONVERSION OF COLORADO INTERSTATE GAS COMPANY, L.L.C. - COLORADO INTERSTATE GAS COMPANY, L.L.C.	d271449dex3a.htm
EX-31.A - CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER PURSUANT TO SECTION 302 - COLORADO INTERSTATE GAS COMPANY, L.L.C.	d271449dex31a.htm
EX-32.B - CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER PURSUANT TO SECTION 906 - COLORADO INTERSTATE GAS COMPANY, L.L.C.	d271449dex32b.htm
EX-31.B - CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER PURSUANT TO SECTION 302 - COLORADO INTERSTATE GAS COMPANY, L.L.C.	d271449dex31b.htm
EX-32.A - CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER PURSUANT TO SECTION 906 - COLORADO INTERSTATE GAS COMPANY, L.L.C.	d271449dex32a.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)

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

For the fiscal year ended December 31, 2011

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

For the transition period from to

Commission File Number 1-4874

Colorado Interstate Gas Company, L.L.C.

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

Telephone Number: (713) 420-2600

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


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 x

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 x

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 x 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 x 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. x

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

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

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, L.L.C.

TABLE OF CONTENTS


	Caption	Page

	PART I

Item 1.	Business		1
Item 1A.	Risk Factors		5
Item 1B.	Unresolved Staff Comments		13
Item 2.	Properties		13
Item 3.	Legal Proceedings		13
Item 4.	Mine Safety Disclosures		13

	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		14
Item 6.	Selected Financial Data		14
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		15
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		22
Item 8.	Financial Statements and Supplementary Data		23
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		43
Item 9A.	Controls and Procedures		43
Item 9B.	Other Information		43

	PART III
Item 10.	Directors, Executive Officers and Corporate Governance		44
Item 11.	Executive Compensation		46
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		46
Item 13.	Certain Relationships and Related Transactions, and Director Independence		48
Item 14.	Principal Accountant Fees and Services		50

	PART IV
Item 15.	Exhibits and Financial Statement Schedules		51
	Signatures		52

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


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

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

When we refer to “us,” “we,” “our,” “ours”, or “CIG,” we are describing Colorado Interstate Gas Company, L.L.C. and/or our subsidiaries.

PART I

ITEM 1. BUSINESS

Overview and Strategy

We are a Delaware limited liability company, originally formed in 1927 as a corporation. Effective August 31, 2011, we converted our legal structure to a limited liability company and changed our name to Colorado Interstate Gas Company, L.L.C. We are owned 86 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 Corporation (El Paso), and 14 percent indirectly through a wholly owned subsidiary 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). A description of these assets is discussed below.

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

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

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

•

focusing on customer service;

•

developing growth projects in our market and supply areas;

•

maintaining 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 4,592 MMcf/d. During 2011, 2010 and 2009, average throughput was 2,128 BBtu/d, 2,131 BBtu/d and 2,299 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 38 Bcf of underground working natural gas storage capacity, including 7 Bcf of storage capacity from the Totem storage facility which is owned by WYCO as further discussed below. In addition, we have a processing plant located in Wyoming.

WYCO. WYCO owns the Totem storage facility and the High Plains pipeline, both of which are located in Northeast Colorado. We operate the Totem storage facility and High Plains pipeline as permitted under our 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 storage facility services and interconnects with the High Plains pipeline. The Totem storage facility has 7 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 our affiliate, Wyoming Interstate Company, L.L.C. (WIC).

Markets and Competition

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

The natural gas industry has experienced a major shift from conventional supply sources to unconventional sources, such as shales. In addition, the increase in oil prices has led to increased production of natural gas found in association with the production of oil. This shift has impacted supply patterns, gas flows and rates that can be charged on pipeline systems. The impact will vary among pipelines according to the location and the number of competitors attached to these new supply sources.

Electric power generation has been the source of most of the demand growth for natural gas over the last 10 years, and this trend is expected to continue. The growth of natural gas in this sector is influenced by competition with coal and economic growth. Short-term market shifts have been driven by relative electric generation costs of coal-fired plants versus gas-fired plants. A long-term market shift in the use of coal in power generation could be driven by environmental regulations. The future demand for natural gas could be increased by regulations limiting or discouraging coal use. However, natural gas demand could potentially be adversely affected by laws mandating or encouraging renewable power sources. Industrial demand has also grown recently with the economic recovery and low natural gas price environment, and this sector offers an opportunity for continued growth.

Our system serves two major markets, an on-system market, consisting of utilities and other customers located along the front range of the Rocky Mountains in Colorado and Wyoming, and an off-system market, consisting of the transportation of 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.

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 that are directly connected to our supply sources, including WIC, our affiliate. We face 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

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

The following table details our customer and contract information related to our pipeline system as of December 31, 2011. Firm customers reserve capacity on our pipeline system and storage facilities and are obligated to pay a monthly reservation or demand charge, regardless of the amount of natural gas they transport or store, for the term of their contracts. Interruptible customers are customers without reserved capacity that pay usage charges based on the volume of natural gas they transport, store, inject or withdraw.


Customer Information		Contract Information
Approximately 100 firm and interruptible customers.		Approximately 160 firm transportation contracts. Weighted average remaining contract term of approximately eight years.

Major Customers:
PSCo and subsidiary (913 BBtu/d)		Expire in 2012 - 2019.
(874 BBtu/d)		Expire in 2025 – 2029.
(200 BBtu/d)		Expires in 2040.

Williams Gas Marketing, Inc.
(385 BBtu/d)		Expire in 2013 - 2014.

Colorado Springs Utilities
(331 BBtu/d)		Expire in 2012 - 2023.

Regulatory Environment

Our interstate natural gas transmission system and storage operations are regulated by the FERC under the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and the Energy Policy Act of 2005. We operate under a tariff approved by the FERC that establishes rates, cost recovery mechanisms and other terms and conditions of services to our customers. The rates established under our tariff are a function of our costs of providing services to our customers, including a reasonable return on our invested capital. Generally, the FERC’s authority also extends to:

•

rates and charges for natural gas transportation and storage;

•

certification and construction of new facilities;

•

extension or abandonment of services and facilities;

•

maintenance of accounts and records;

•

relationships between pipelines and certain affiliates;

•

terms and conditions of service;

•

depreciation and amortization policies;

•

acquisition and disposition of facilities; and

•

initiation and discontinuation of services.

Our interstate pipeline system is also subject to federal, state and local safety and environmental statutes and regulations of the U.S. Department of Transportation and the U.S. Department of the Interior. We have ongoing inspection programs designed to keep our facilities in compliance with pipeline safety and environmental requirements. For a further discussion of the potential impact of regulatory matters on us, see Item 1A. Risk Factors.

Environmental

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

Employees

We do not have employees. We are managed and operated by officers of El Paso and its affiliates. 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.

ITEM 1A. RISK FACTORS

CAUTIONARY STATEMENT FOR PURPOSES OF THE “SAFE HARBOR” PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

This report contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These forward-looking statements are based on assumptions or beliefs that we believe to be reasonable; however, assumed facts almost always vary from the actual results and such variances can be material. Where we express an expectation or belief as to future results, that expectation or belief is expressed in good faith and is believed to have a reasonable basis. We cannot assure you, however, that the stated expectation or belief will occur. The words “believe,” “expect,” “estimate,” “anticipate,” and similar expressions will generally identify forward-looking statements. All of our forward-looking statements, whether written or oral, are expressly qualified by these and other cautionary statements. We disclaim any obligation to update any forward-looking statements to reflect events or circumstances after the date provided. With this in mind, you should consider the risks discussed elsewhere in this report and other documents we file with the Securities and Exchange Commission (SEC) from time to time and the following important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. If any of the following risks were actually to occur, our business, results of operations, financial condition and growth could be materially adversely affected.

Risks Related to Our Business

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

•

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

•

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

•

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

•

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

•

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

•

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

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

We depend on certain key customers 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 revenues. For the year ended December 31, 2011, PSCo and its subsidiary, and Pioneer Natural Resources USA, Inc. accounted for approximately 41 percent and 11 percent, respectively of our operating revenues. The creditworthiness of our customers may be adversely impacted by negative effects in the economy, including low natural gas prices which can reduce liquidity and cash flows for some of our customers that produce natural gas. The loss of any material portion of the contracted volumes of these customers, 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 these customers, see Part II, Item 8. Financial Statements and Supplementary Data, Note 9.

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

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

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

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

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

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

reduction in our earnings once the project is placed into service. We periodically evaluate the applicability of accounting standards related to regulated operations, and consider factors such as regulatory changes and the impact of competition. If cost-based regulation ends or competition increases, we may have to evaluate our assets for impairment and write-off the associated regulatory assets, which could impact our future earnings.

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

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

•

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

•

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

•

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

•

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

•

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

•

increased prices of natural gas that could negatively impact demand;

•

increased costs to transport natural gas;

•

adoption of various energy efficiency and conservation measures; and

•

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

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

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

•

changes in regional and domestic supply and demand;

•

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

•

changes in the costs of transporting natural gas;

•

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

•

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

•

the amount of capacity available to transport natural gas.

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

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

•

Adverse weather conditions, natural disasters, and/or other climate related matters – including extreme cold or heat, lightning and flooding, fires, tornadoes and other natural disasters. 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 also have a negative impact upon our operations in the future.

•

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

•

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

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

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

Our operations are subject to a complex set of federal, state and local laws and regulations that tend to change from time to time and generally are becoming increasingly more stringent. In addition to the laws and regulations affecting our business, there are various laws and regulations that regulate various market practices in the industry, including antitrust laws and laws that prohibit fraud and manipulation in the markets in which we operate. The authority of the FTC and the FERC to impose penalties for violations of laws or regulations has generally increased over the last few years. In addition, our business is subject to laws and regulations that govern environmental, health and safety matters. These regulations include compliance obligations for air emissions, water quality, wastewater discharge and solid and hazardous waste disposal, as well as regulations designed for the protection of human health and safety and threatened or endangered species. Compliance obligations can result in significant costs to install and maintain pollution

controls, and to maintain measures to address personal and process safety and protection of the environment and animal habitat near our operations. We are often obligated to obtain permits or approvals in our operations from various federal, state and local authorities, which permits and approvals (including renewals thereof) can be denied or delayed. In addition, we are exposed to fines and penalties to the extent that we fail to comply with the applicable laws and regulations, as well as the potential for limitations to be imposed on our operations. These regulations often impose remediation obligations associated with the investigation or clean-up of contaminated properties, as well as damage claims arising out of the contamination of properties or impact on natural resources. Finally, many of our assets are located and operate on federal, state, or local lands and are typically regulated by one or more federal, state or local agencies. For example, we operate assets that are located on federal lands, which are regulated by the U.S. Department of the Interior, particularly by the Bureau of Land Management.

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

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

•

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

•

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

•

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

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

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

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

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

We have certain contingent liabilities that could exceed our estimates.

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

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

We are subject to interest rate risks.

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

Risks Related to Our Affiliation with El Paso and EPB

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

We are a majority owned subsidiary of EPB.

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

•

decisions on our financing and capital raising activities;

•

mergers or other business combinations;

•

our acquisitions or dispositions of assets; and

•

our participation in EPB’s cash management program.

EPB 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 EPB and EI Paso and their financial condition subjects us to potential risks that are beyond our control.

Due to our relationship with EPB and EI Paso, 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. There is a risk that El Paso’s, EPB’s or our 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, credit profile and potential transactions. Following the announcement of El Paso’s proposed merger with KMI, Moody’s and Fitch adjusted their view of El Paso to a negative outlook, and Moody’s adjusted their view of EPB and us to a negative outlook. 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, 2011:

Rating Agency

Moody’s Investor
Service

Standard &
Poor’s

Fitch
Ratings

Credit Ratings

CIG

Baa3

⁽¹⁾

⁽²⁾

BBB-

⁽¹⁾

EPB

Ba1

⁽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 to our owners as defined in our limited liability company agreement on a quarterly basis. 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 our affiliated transactions, 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.

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.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

PART II

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

Our member interests are held by El Paso and EPB and, accordingly, are not publicly traded.

We are required to make distributions to our owners as defined in our limited liability company agreement on a quarterly basis as approved by our Management Committee. We made cash distributions of approximately $155 million in 2011, $170 million in 2010 and $144 million in 2009 to our members/partners. Additionally, in January 2012, we made a cash distribution of approximately $37 million to our members.

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,
	2011		2010		2009		2008		2007
	(In millions)
Operating Results Data:
Operating revenues	$	415	$	410	$	383	$	323	$	317
Operating income		202		194		205		153		145
Net income		144		143		157		149		107

Financial Position Data:
Total assets	$	1,555	$	1,542	$	1,569	$	1,543	$	1,769
Long-term debt and other financing obligations, less current maturities		647		649		646		580		575
Members’ equity/partners’ capital		809		769		796		783		1,043

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

Overview

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

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

Our Business

Our primary business consists of the interstate transportation, storage and processing of natural gas. We face 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 2011 Revenues⁽¹⁾
Reservation	Reservation revenues are from customers (referred to as firm customers) that reserve capacity on our pipeline system and storage facilities. These firm customers are obligated to pay a monthly reservation or demand charge, regardless of the amount of natural gas they transport or store, for the term of their contracts.	93

Usage and Other	Usage revenues are from both firm customers and interruptible customers (those without reserved capacity) that pay usage charges based on the volume of gas actually transported, stored, injected or withdrawn. We also earn revenue from other miscellaneous sources.	7

(1)	Excludes liquids revenues 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. In addition, our future earnings may be impacted by both positive and negative fluctuations in gas prices related to the revaluation of system gas inventory. 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 volumetric impact of over or under collecting fuel and lost and unaccounted for gas from our operational gas costs.

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. Currently, we face recontracting risk in certain of our market areas due, in part, to competition with other pipelines which transport natural gas from the same supply basins that we do, and due to potential declines in production in certain other supply basins.

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


	Contracted Capacity		Percent of Total Contracted Capacity		Reservation Revenue		Percent of Total Reservation Revenue
	(BBtu/d)				(In millions)
2012		285		7	$	15		5
2013		492		12		13		4
2014		47		1		5		1
2015		86		2		8		2
2016		1,414		33		128		39
2017 and beyond		1,896		45		161		49

Total		4,220		100	$	330		100

Results of Operations

Our management uses segment earnings before interest expense and income taxes (Segment EBIT) as a measure to assess the operating results and effectiveness of our business, which consist of consolidated operations as well as an investment in an unconsolidated affiliate. We believe Segment EBIT is useful to investors to provide them with the same measure used by our management to evaluate our performance and so that investors may evaluate our operating results without regard to our financing methods. Segment EBIT is defined as net income adjusted for items such as interest and debt expense, and affiliated interest income. Segment EBIT may not be comparable to measures used by other companies. Additionally, Segment 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 Segment EBIT to net income, our throughput volumes and an analysis and discussion of our results in 2011 compared with 2010 and 2010 compared with 2009.

Operating Results:


	2011			2010			2009
	(In millions, except for volumes)
Operating revenues	$	415		$	410		$	383
Operating expenses		(213	)		(216	)		(178	)

Operating income		202			194			205
Other income, net		3			8			4

Segment EBIT		205			202			209
Interest and debt expense, net		(62	)		(60	)		(54	)
Affiliated interest income, net		1			1			2

Net income	$	144		$	143		$	157

Throughput volumes (BBtu/d)		2,128			2,131			2,299

Segment EBIT Analysis:


	2011 to 2010												2010 to 2009
	Operating Revenue			Operating Expense			Other			Total			Operating Revenue		Operating Expense			Other		Total
	Favorable/(Unfavorable)
	(In millions)
Expansions	$	21		$	(7	)	$	(5	)	$	9		$	16	$	(2	)	$	2	$	16
Reservation revenues and expenses		(9	)		—			—			(9	)		3		4			—		7
Operating and general and administrative expenses		—			(15	)		—			(15	)		—		(2	)		—		(2	)
Non-cash asset write down		—			21			—			21			—		(29	)		—		(29	)
Other⁽¹⁾		(7	)		4			—			(3	)		8		(9	)		2		1

Total impact on Segment EBIT	$	5		$	3		$	(5	)	$	3		$	27	$	(38	)	$	4	$	(7	)

____________

(1)	Consists of individually insignificant items.

Expansions. During 2011 and 2010, we benefited from increased reservation revenues due to expansion projects placed in service. These projects included Raton 2010 placed in service in December 2010 and the Totem storage facility placed in service in June 2009. Partially offsetting this increase during 2011 and 2010, was depreciation and other operating expenses on the new facilities. During 2011, we also had higher transportation expenses of approximately $4 million due to increased third party capacity commitments.

We have other projects that are in various phases of commercial development. Some of the potential projects involve expansion capacity to serve increased natural gas-fired generation loads and would have in-service dates in 2014 and beyond. If we are eventually successful in contracting for these new loads the capital requirements could be substantial. 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.

Reservation Revenues and Expenses. During the year ended December 31, 2011 compared to 2010, our reservation revenues were lower due to the nonrenewal of expiring contracts and increased competition in the Rockies region. During the year ended December 31, 2010, our reservation revenues and expenses contributed favorably to our Segment EBIT, when compared to 2009, primarily due to higher revenues generated from capacity released on off-system volumes, increased demand from off-system firm transportation, and a transportation contract buy-out expense of $4 million recorded in 2009.

Operating and General and Administrative Expenses. Our operating and general and administrative expenses were higher in 2011 compared to 2010 primarily due to higher benefits and payroll costs of approximately $5 million, higher allocated costs from El Paso of $2 million based on the estimated level of resources devoted to us and increased contractor costs of approximately $6 million due to field repairs on our pipeline system.

Non-cash Asset Write Down. During 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 this facility. In October 2010, we filed a request for rehearing and clarification of the FERC order and in October 2011, the FERC denied our request. For a further discussion of Natural Buttes, see Item 8. Financial Statements and Supplementary Data, Note 2.

Rates and Regulatory Matter

In August 2011, the FERC approved an uncontested pre-filing settlement of a rate case required under the terms of a previous settlement. The settlement generally provides for (i) our current tariff rates to continue until our next general rate case which will be effective no earlier than October 1, 2014 but no later than October 1, 2016, (ii) contract extensions to March 2016, (iii) a revenue sharing mechanism with certain of our customers for certain revenues above annual threshold amounts and (iv) a revenue surcharge mechanism with certain of our customers to charge for certain shortfalls of revenue less than an annual threshold amount.

Interest and Debt Expense, Net

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 the Totem storage facility. For a further discussion of this financing obligation, see Item 8. Financial Statements and Supplementary Data, Note 6.

Affiliated Interest Income, Net

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


	2011			2010			2009
	(In millions, except for rates)
Average advance to EPB	$	70		$	59		$	39
Average short-term interest rate on affiliate note receivable from EPB		1.5	%		0.8	%		0.7	%
Average advance to El Paso	$	—		$	58		$	119
Average short-term interest rate on affiliate note receivable from El Paso		—			1.5	%		1.7	%

Liquidity and Capital Resources

Liquidity Overview. Our primary sources of liquidity are cash flows from operating activities, amounts available to us under EPB’s cash management program and capital contributions from our members, while our primary uses of cash are for working capital, capital expenditures and required distributions. At December 31, 2011, we had a note receivable from EPB under its cash management program of approximately $67 million, of which $6 million was classified as current based on the net amount we anticipate using in the next twelve months considering available cash sources and needs. See Item 8. Financial Statements and Supplementary Data, Note 11 for a further discussion of EPB’s cash management program.

Cash Flow Activities. Our cash flows for the year ended December 31, 2011 are summarized as follows (in millions):


Cash Flow from Operations
Net income	$	144
Non-cash income adjustments		67
Change in assets and liabilities		(18	)

Total cash flow from operations		193

Other Cash Inflows
Investing activities
Other		1

Financing activities
Contributions from members/partners		42

Total other cash inflows		236

Cash Outflows
Investing activities
Capital expenditures		69
Net change in note receivable from affiliate		4
Other		3

Total other cash outflows		76

Financing activities
Distributions to members/partners		155
Payments to retire other financing obligations		4

		159

Total cash outflows		235

Net change in cash and cash equivalents	$	1

During 2011, we generated $193 million of operating cash flow. We primarily utilized these amounts to fund a portion of our maintenance and expansion capital expenditures, as well as pay distributions to our members/partners. During the year ended December 31, 2011, we paid cash distributions of approximately $155 million to our members/partners. In addition, in January

2012 we paid a cash distribution to our members of approximately $37 million. During 2011, we received cash contributions of approximately $42 million from our members/partners to fund our expansion projects. In January 2012, we received cash contributions from our members of approximately $10 million to fund our expansion projects.

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


	2011
	(In millions)
Maintenance	$	37
Expansion		32

Total	$	69

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

We believe we have adequate liquidity available to us to meet our capital requirements and our existing operating needs through cash flow from operating activities, amounts available under EPB’s cash management program and capital contributions from our members. While we do not anticipate a need to directly access the financial markets in 2012 for any of our operating activities or expansion capital needs based on liquidity available to us, market conditions may impact our, EPB’s or El Paso’s ability to act opportunistically. Our future plans could also be impacted by the completion of El Paso’s announced acquisition by KMI.

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

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 and 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, 2011, 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	$	252	$	652
Interest		59		116		84		510		769

Other contractual liabilities		4		3		1		2		10
Operating leases		2		4		1		—		7
Transportation and storage commitments		20		26		24		73		143

Total contractual obligations	$	90	$	159	$	495	$	837	$	1,581

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 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 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 long-term 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. For a further discussion of these obligations, see Item 8. Financial Statements and Supplementary Data, Note 7.

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 10 and 11, which are incorporated herein by reference.

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, revenues 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 under GAAP 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 periodically evaluate the applicability of accounting standards related to regulated operations, and consider factors such as regulatory changes and the impact of competition. If cost-based regulation ends or competition increases, we may have to 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 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.

As of December 31, 2011, we had no accruals for legal matters and approximately $10 million for environmental matters. Our environmental estimates range from approximately $10 million to approximately $34 million.

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, 2011, our postretirement benefit plan was over funded by $11 million. Our postretirement benefit obligation and net benefit costs are primarily based on actuarial calculations. We use various assumptions in performing these calculations, including those related to the return that we expect to earn on our plan assets, the estimated cost of health care when benefits are provided under our plan and other factors. A significant assumption we utilize is the discount rate used in calculating our benefit obligation. We select our discount rate by matching the timing and amount of our expected future benefit payments for our postretirement benefit obligation to the average yields of various high-quality bonds with corresponding maturities.

Actual results may differ from the assumptions included in these calculations, and as a result, our estimates associated with our postretirement benefits can be, and often are, revised in the future. The income statement impact of the changes in the assumptions on our related benefit obligation, along with changes to the plan and other items, are deferred and recorded in accumulated other comprehensive income, a component of members’equity. 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.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to the risk of changing interest rates. At December 31, 2011, we had an interest bearing note receivable from EPB of approximately $67 million, with a variable interest rate of 2.3% that is due upon demand. While we are exposed to changes in interest income based on changes to the variable interest rate, the fair value of this note receivable approximates the carrying value due to the note being due on demand and the market-based nature of the interest rate.

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


	December 31, 2011																						December 31, 2010
	Expected Fiscal Year of Maturity of Carrying Amounts																				Fair		Carrying		Fair
	2012			2013			2014			2015			2016			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		$	380		$	5		$	252		$652		$	702	$	654	$	703
Average interest rate		15.6	%		15.6	%		15.6	%		6.8	%		15.6	%		12.2	%

(1)	Our other financing obligations include amounts due to WYCO related to the construction of the High Plains pipeline and Totem storage facility. See additional information in Item 8. Financial Statements and Supplementary Data, Note 6.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

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

•

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

•

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

•

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

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

Report of Independent Registered Public Accounting Firm

To The Members of Colorado Interstate Gas Company, L.L.C.

We have audited the accompanying consolidated balance sheets of Colorado Interstate Gas Company, L.L.C. (the Company) as of December 31, 2011 and 2010, and the related consolidated statements of income and comprehensive income, members’ equity/partners’ capital, and cash flows for each of the three years in the period ended December 31, 2011. Our audits also included the financial statement schedule listed in the Index at Item 15(a) for each of the three years in the period ended December 31, 2011. These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

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

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Colorado Interstate Gas Company, L.L.C. at December 31, 2011 and 2010, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2011, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

/s/ Ernst & Young LLP

Houston, Texas

February 27, 2012

COLORADO INTERSTATE GAS COMPANY, L.L.C.

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(In millions)


	Year Ended December 31,
	2011			2010			2009
Operating revenues	$	415		$	410		$	383

Operating expenses
Operation and maintenance		144			154			121
Depreciation and amortization		46			42			38
Taxes, other than income taxes		23			20			19

		213			216			178

Operating income		202			194			205
Other income, net		3			8			4
Interest and debt expense, net		(62	)		(60	)		(54	)
Affiliated interest income, net		1			1			2

Net income		144			143			157
Other comprehensive income
Unrealized actuarial gains on postretirement benefit obligations		9			—			—

Comprehensive income	$	153		$	143		$	157

See accompanying notes.

COLORADO INTERSTATE GAS COMPANY, L.L.C.

CONSOLIDATED BALANCE SHEETS

(In millions)


	December 31,
	2011		2010
ASSETS
Current assets
Cash and cash equivalents	$	2	$	1
Accounts and note receivable
Customer, net of allowance		1		1
Affiliates		8		3
Other		14		16
Materials and supplies		8		8
Regulatory assets		3		3
Other		4		3

Total current assets		40		35

Property, plant and equipment, at cost		1,904		1,850
Less accumulated depreciation and amortization		496		455

Total property, plant and equipment, net		1,408		1,395

Other long-term assets
Note receivable from affiliate		61		63
Other		46		49

		107		112

Total assets	$	1,555	$	1,542

LIABILITIES AND MEMBERS’ EQUITY/PARTNERS’ CAPITAL
Current liabilities
Accounts payable
Trade	$	7	$	5
Affiliates		19		19
Other		7		17
Current maturities of other financing obligations		5		5
Taxes payable		17		15
Regulatory liabilities		9		8
Contractual deposits		8		11
Other		9		7

Total current liabilities		81		87

Long-term debt and other financing obligations, less current maturities		647		649

Other long-term liabilities		18		37

Commitments and contingencies (Note 7)
Members’ equity/partners’ capital		800		769
Accumulated other comprehensive income		9		—

Total members’ equity/partners’ capital		809		769

Total liabilities and members’ equity/partners’ capital	$	1,555	$	1,542

See accompanying notes.

COLORADO INTERSTATE GAS COMPANY, L.L.C.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)


	Year Ended December 31,
	2011			2010			2009
Cash flows from operating activities
Net income	$	144		$	143		$	157
Adjustments to reconcile net income to net cash from operating activities
Depreciation and amortization		46			42			38
Non-cash asset write down/(gain) on long-lived asset		—			21			(8	)
Other non-cash income items		21			7			16
Asset and liability changes
Accounts receivable		1			16			4
Change in deferred purchase price from accounts receivable sales		1			(15	)		—
Accounts payable		1			(6	)		4
Other asset changes		(5	)		(2	)		—
Other liability changes		(16	)		(22	)		(15	)

Net cash provided by operating activities		193			184			196

Cash flows from investing activities
Capital expenditures		(69	)		(84	)		(103	)
Net change in notes receivable from affiliates		(4	)		71			45
Proceeds from the sale of assets		1			1			10
Other		(3	)		1			2

Net cash used in investing activities		(75	)		(11	)		(46	)

Cash flows from financing activities
Payments to retire other financing obligations		(4	)		(4	)		(4	)
Distributions to members/partners		(155	)		(170	)		(144	)
Contributions from members/partners		42			—			—

Net cash used in financing activities		(117	)		(174	)		(148	)

Net change in cash and cash equivalents		1			(1	)		2
Cash and cash equivalents
Beginning of period		1			2			—

End of period	$	2		$	1		$	2

Supplemental cash flow information
Interest paid, net of amounts capitalized	$	59		$	57		$	52

See accompanying notes.

COLORADO INTERSTATE GAS COMPANY, L.L.C.

CONSOLIDATED STATEMENTS OF MEMBERS’ EQUITY/PARTNERS’ CAPITAL

(In millions)


January 1, 2009	$	783
Net income		157
Distributions		(144	)

December 31, 2009		796
Net income		143
Distributions		(170	)

December 31, 2010		769
Net income		144
Contributions		42
Distributions		(155	)
Accumulated other comprehensive income		9

December 31, 2011	$	809

See accompanying notes.

COLORADO INTERSTATE GAS COMPANY, L.L.C.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Basis of Presentation and Significant Accounting Policies

Basis of Presentation

We are a Delaware limited liability company, originally formed in 1927 as a corporation. Effective August 31, 2011, we converted our legal structure from a general partnership to a limited liability company and changed our name to Colorado Interstate Gas Company, L.L.C. We are owned 86 percent by EPPP CIG GP Holdings, L.L.C., an indirect subsidiary of El Paso Pipeline Partners, L.P. (EPB), a master limited partnership of El Paso Corporation (El Paso), and 14 percent by El Paso Noric Investments III, L.L.C., an indirect 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. Our financial statements for prior periods include reclassifications that were made to conform to the current year presentation, none of which impacted our reported net income, members’ equity/partners’ capital or cash flows from operating activities.

Principles of Consolidation

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

Use of Estimates

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

Regulated Operations

Our natural gas pipeline and storage operations are subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC) and follow the Financial Accounting Standards Board’s accounting standards for regulated operations. Under these standards, we record regulatory assets and liabilities that would not be recorded for non-regulated entities. Regulatory assets and liabilities represent probable future revenues or expenses associated with certain charges or credits that are expected to be recovered from or refunded to customers through the rate making process. Items to which we may record a regulatory asset or liability include certain postretirement employee benefit plan costs, loss on reacquired debt, taxes related to an equity return component on regulated capital projects in periods prior to 2007 when we changed our legal structure to a general partnership, and certain costs related to gas not used in operations and other costs included in, or expected to be included in, future rates. For further details of our regulatory assets and liabilities, see Note 4.

Cash and Cash Equivalents

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

Allowance for Doubtful Accounts

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

Materials and Supplies

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

Natural Gas Imbalances

Natural gas imbalances occur when the amount of natural gas delivered from or received by a pipeline system, 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.

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

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

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

Asset and Investment Divestitures/Impairments

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

Revenue Recognition

Our revenues are primarily generated from natural gas transportation, 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.

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

Postretirement Benefits

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

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

Income Taxes

We are a limited liability company and are not subject to either federal income taxes or generally to state income taxes. Our members 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 member’s tax attributes in us is not available to us.

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. In October 2010, we filed a request for rehearing and clarification of the FERC order and in October 2011, the FERC denied our request.

3. Financial Instruments

At December 31, 2011 and 2010, the carrying amounts of cash and cash equivalents and trade receivables and payables represent fair value because of the short-term nature of these instruments. At December 31, 2011 and 2010, we had an interest bearing note receivable from EPB of approximately $67 million and $63 million, with a variable interest rate of 2.3% and 0.8%. While we are exposed to changes in interest income based on changes to the variable interest rate, the fair value of this note approximates the carrying value due to the note being due on demand and the market-based nature of the interest rate.

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


	2011				2010
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)
Long-term debt and other financing obligations, including current maturities	$	652	$	702	$	654	$	703

4. Regulatory Assets and Liabilities

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


	2011		2010
	(In millions)
Current regulatory assets
Difference between gas retained and gas consumed in operations	$	—	$	1
Other		3		2

Total current regulatory assets		3		3

Non-current regulatory assets
Taxes on capitalized funds used during construction		10		10
Unamortized loss on reacquired debt		4		5
Other		1		2

Total non-current regulatory assets⁽¹⁾		15		17

Total regulatory assets	$	18	$	20

Current regulatory liabilities
Difference between gas retained and gas consumed in operations	$	8	$	7
Other		1		1

Total current regulatory liabilities		9		8

Non-current regulatory liabilities
Property and plant depreciation		9		18
Postretirement benefits		1		10

Total non-current regulatory liabilities⁽¹⁾		10		28

Total regulatory liabilities	$	19	$	36

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

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. Represents the regulatory asset balance established in periods prior to 2007 when we changed our legal structure to a general partnership, to offset the deferred tax for the equity component of AFUDC. Taxes on capitalized funds used during construction and the offsetting deferred income taxes are included in the rate base and are recovered over the depreciable lives of the long-lived asset to which they relate.

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

Postretirement Benefits. Represents the differences in postretirement benefit costs expensed and the amounts previously recovered in rates. Prior to our rate case settlement, these balances also included unrecognized gains and losses or changes in actuarial assumptions related to our postretirement benefit plan. As part of our rate case settlement, we no longer include these costs in our rates and during 2011, we reclassified these balances to accumulated other comprehensive income.

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 less than $1 million, $2 million and $1 million during the years ended December 31, 2011, 2010 and 2009. Equity amounts capitalized are included in other income on our income statements and were $1 million, $6 million and $4 million during the years ended December 31, 2011, 2010 and 2009.

Construction Work-In-Progress. At December 31, 2011 and 2010, we had $16 million and $17 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, sealing and possibly removing the facilities if they are abandoned. We also have obligations to remove hazardous materials associated with our natural gas transmission facilities if they are ever demolished or replaced. We 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 pipeline and storage system assets because these assets have indeterminate lives. Our asset retirement liabilities as of December 31, 2011 and 2010, 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:


	2011		2010
	(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
Other financing obligations		177		179

		652		654
Less: Current maturities		5		5

Total long-term debt and other financing obligations, less current maturities	$	647	$	649

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, 2011, we were in compliance with our debt-related covenants.

Other Financing Obligations. In conjunction with the construction of the Totem storage facility and the High Plains pipeline, our joint venture partner in WYCO Development L.L.C. (WYCO) funded 50 percent of the construction costs. We reflected these payments made by our joint venture partner as other long-term liabilities on our balance sheet during construction and upon project completion, these advances were converted into a financing obligation to WYCO. As of December 31, 2011, the principal amounts of our obligations related to the Totem storage facility and the High Plains pipeline were $77 million and $100 million, respectively, which will be paid in monthly installments through 2039, and extended for the term of related firm service agreements until 2060 and 2043, respectively. Interest payments on these obligations are based on 50 percent of the operating results of the facilities’ and are currently estimated at a 15.5 percent rate as of December 31, 2011.

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, 2011. 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, and these adjustments could be material.

Environmental Matters

We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require us to remove or remedy the effect of the disposal or release of specified substances at current and former operating sites. At December 31, 2011 and 2010, our accrual was approximately $10 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, 2011. Our accrual at December 31, 2011 includes $6 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 2012, we estimate that our total remediation expenditures will be approximately $4 million, most of which will be expended under government directed clean-up plans. In addition, we expect to make capital expenditures for environmental matters of approximately $2 million in the aggregate for 2012 through 2016, including capital expenditures associated with the impact of the EPA rule on emissions of hazardous air pollutants from reciprocating internal combustion engines which are subject to regulations with which we have to be in compliance by October 2013.

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

Rates and Regulatory Matter

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 $143 million at December 31, 2011, of which $93 million is related to storage capacity contracts with our affiliate, Young Gas Storage Company, Ltd. Our annual commitments under these agreements are $20 million in 2012, $14 million in 2013, $12 million in 2014, $12 million in 2015, $12 million in 2016, and $73 million in total thereafter.

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


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

Total	$	7

Rental expense on our lease obligations for the years ended December 31, 2011, 2010, and 2009 was $3 million, $2 million and $2 million.

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

8. Retirement Benefits

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

Postretirement Benefits Plan. We provide postretirement medical benefits for a closed group of retirees under the El Paso Corporation Retiree Benefits Plan. 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 were prefunded and were recoverable under prior rate case settlements. Currently, there is no cost recovery or related funding that is required as part of our current FERC approved rates, however , we can seek to recover any funding shortfall that may be required in the future. We do not expect to make any contributions to our postretirement benefit plan in 2012, and there were no contributions made in 2011, 2010 and 2009.

Accumulated Postretirement Benefit Obligation, Plan Assets and Funded Status. In accounting for our postretirement benefit plan we record an asset or liability based on the over funded or under funded status. Any deferred amounts related to unrecognized gains and losses or changes in actuarial assumptions are recorded in accumulated other comprehensive income, a component of members’ equity, until those gains and losses are recognized in the income statement. Prior to our rate case settlement in August 2011, we recorded a regulatory asset or liability for these unrecognized amounts as allowed by the FERC. During 2011, we reclassified $9 million from a net regulatory liability to accumulated other comprehensive income pursuant to our rate case settlement whereby these amounts are no longer included in the rates we charge our customers.

The table below provides information about our postretirement benefit plan.


	December 31,
	2011			2010
	(In millions)
Change in accumulated postretirement benefit obligation:
Accumulated postretirement benefit obligation — beginning of period	$	5		$	5
Participant contributions		—			1
Benefits paid⁽¹⁾		(1	)		(1	)

Accumulated postretirement benefit obligation — end of period	$	4		$	5

Change in plan assets:
Fair value of plan assets — beginning period	$	15		$	14
Actual return on plan assets		1			2
Benefits paid		(1	)		(1	)

Fair value of plan assets — end of period	$	15		$	15

Reconciliation of funded status:
Fair value of plan assets	$	15		$	15
Less: accumulated postretirement benefit obligation		4			5

Net asset at December 31	$	11		$	10

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

Components of Accumulated Other Comprehensive Income. The amount recognized in accumulated other comprehensive income at December 31, 2011 of $9 million is related to unrecognized gains. We anticipate that approximately $1 million of our accumulated other comprehensive income will be recognized as part of our net periodic benefit income in 2012.

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

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

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


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

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

(2)	Includes benefit payments of less than $1 million.

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


	2011		2010		2009
	(Percent)
Assumptions related to benefit obligations at December 31:
Discount rate		4.13		4.52		5.06
Assumptions related to benefit costs for the year ended December 31:
Discount rate		4.52		5.06		5.82
Expected return on plan assets⁽¹⁾		7.75		7.75		8.00

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

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

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


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

Net benefit income	$	(1	)	$	(1	)	$	—

9. Transactions with Major Customers

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


	2011		2010			2009
	(In millions)
PSCo and subsidiary	$	169	$	168		$	154
Pioneer Natural Resources USA, Inc.		46			*			*

*	Less than 10 percent of operating revenues

At December 31, 2011, we have transportation and storage agreements with PSCo for capacity on the High Plains pipeline through 2029 and Totem storage facility through 2040 with annual firm revenue of $41 million and $38 million, respectively.

10. Accounts Receivable Sales Program

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

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


	Year Ended December 31,
	2011		2010
	(In millions)
Accounts receivable sold to the third-party financial institution⁽¹⁾	$	415	$	436
Cash received for accounts receivable sold under the program		235		240
Deferred purchase price related to accounts receivable sold		180		196
Cash received related to the deferred purchase price		181		181
Amount paid in conjunction with terminated program⁽²⁾		—		20

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

(2)

In January 2010, we terminated our previous accounts receivable sales program and paid $20 million to acquire the related senior interests in certain receivables under that program. During 2009, we sold approximately $386 million of accounts receivable under that program and our fees and losses related to the program were not material.


	As of December 31,
	2011		2010
	(In millions)
Accounts receivable sold and held by third-party financial institution	$	36	$	37
Uncollected deferred purchase price related to accounts receivable sold ⁽¹⁾		14		15

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

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

11. Investment in Unconsolidated Affiliate and Transactions with Affiliates

Investment in Unconsolidated Affiliate

WYCO. 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 storage facility (both of which are FERC regulated), a state regulated intrastate pipeline, and a compressor station. We reflect the Totem storage facility and the High Plains pipeline as property, plant and equipment in our financial statements as of December 31, 2011 due to our continuing involvement with the projects through WYCO. At December 31, 2011 and 2010, our investment in WYCO was approximately $14 million and $15 million, which is included in other long-term assets on our balance sheets. Our equity earnings for the years ended December 31, 2011, 2010 and 2009 were $1 million, $2 million and $1 million. We reflect equity earnings in other income on our income statements. Additionally, for the year ended December 31, 2011, 2010 and 2009, we received cash distributions of $2 million, $1 million and $1 million.

Transactions with Affiliates

Other Financing Obligations. We have other financing obligations payable to WYCO related to the Totem storage facility and High Plains pipeline. At December 31, 2011 and 2010, these other financing obligations were $177 million and $179 million. For a further discussion of these obligations see Note 6.

EPB Acquisition. During 2011, EPB acquired an additional 28 percent ownership interest in us from El Paso. The acquisition increased EPB’s interest in us to 86 percent.

Distributions and Contributions. We are required to make distributions to our owners as defined in our limited liability company agreement on a quarterly basis. During 2011, 2010 and 2009, we paid cash distributions of approximately $155 million, $170 million and $144 million to our members/partners. In addition, in January 2012, we paid a cash distribution to our members of approximately $37 million. During 2011, we received cash contributions of approximately $42 million from our members/partners to fund our expansion projects. In January 2012, we received cash contributions from our members of approximately $10 million to fund our expansion projects.

Cash Management Program. We participate in EPB’s cash management program which matches our short-term cash surpluses and needs of participating affiliates, thus minimizing our total borrowings from outside sources. EPB uses the cash management program to settle intercompany transactions between participating affiliates. At December 31, 2011 and 2010, we had a note receivable from EPB of approximately $67 million and $63 million. We classified $6 million of this receivable as current on our balance sheet at December 31, 2011 based on the net amount we anticipate using in the next twelve months considering available cash sources and needs. The interest rate on this note is variable and was 2.3% and 0.8% at December 31, 2011 and 2010.

Other Affiliate Balances. At December 31, 2011 and 2010, we had contractual deposits from our affiliates of $7 million.

Affiliate Revenues and Expenses. We enter 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 and we are managed and operated by officers of El Paso and its affiliates. 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. L.L.C. (TGP), our affiliates, associated with our pipeline services. We also allocate costs to Wyoming Interstate Company, L.L.C. (WIC), Cheyenne Plains Gas Pipeline, Young Gas Storage Company, Ltd. and Ruby Pipeline Company, L.L.C., 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.

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


	2011		2010		2009
	(In millions)
Revenues	$	12	$	12	$	11
Operation and maintenance expenses		97		86		101
Reimbursements of operating expenses		9		11		26

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		Total
	(In millions)
2011
Operating revenues	$	116	$	100	$	92	$	107	$	415
Operating income		63		44		41		54		202
Net income		48		29		28		39		144
2010
Operating revenues	$	113	$	97	$	89	$	111	$	410
Operating income		65		47		23		59		194
Net income		54		34		10		45		143

(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).

SCHEDULE II

COLORADO INTERSTATE GAS COMPANY, L.L.C.

VALUATION AND QUALIFYING ACCOUNTS

Years Ended December 31, 2011, 2010 and 2009

(In millions)


Description	Balance at Beginning of Period		Charged to Costs and Expenses		Deductions⁽¹⁾			Charged to Other Accounts		Balance at End of Period
2011
Environmental reserves	$	10	$	2	$	(2	)	$	—	$	10
2010
Environmental reserves	$	11	$	—	$	(1	)	$	—	$	10
2009
Environmental reserves	$	13	$	1	$	(3	)	$	—	$	11

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

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

None.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As of December 31, 2011, we carried out an evaluation under the supervision and with the participation of our management, including our President and Chief Financial Officer (CFO), as to the effectiveness, design and operation of our disclosure controls and procedures. This evaluation considered the various processes carried out under the direction of our disclosure committee in an effort to ensure that information required to be disclosed in the U.S. Securities and Exchange Commission reports we file or submit under the Securities Exchange Act of 1934, as amended (Exchange Act) is accurate, complete and timely. Our management, including our President and CFO, does not expect that our disclosure controls and procedures or our internal controls will prevent and/or detect all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within our company have been detected. Our disclosure controls and procedures are designed to provide reasonable assurance of achieving their objectives and our President and 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, 2011. See Item 8. Financial Statements and Supplementary Data, under Management’s Annual Report on Internal Control Over Financial Reporting.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting during the fourth quarter of 2011 that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10. DIRECTORS, AND EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Management Committee Members and Executive Officers

We are a Delaware limited liability company with two members, the first of which is a wholly owned subsidiary of EPB (the “EPB Member”), and the second of which is a wholly owned subsidiary of El Paso (the “El Paso Member”). The EPB Member owns 86 percent of the ownership interest in us, and the El Paso Member owns the remaining 14 percent interest. Our limited liability company agreement provides that the business and affairs of the company shall be fully vested in, and managed by, a management committee. The management committee is composed of five representatives, with four representatives being designated by the EPB Member and one representative being designated by the El Paso Member. 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. 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 20, 2012. 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	57	President and Management Committee Member
John R. Sult	52	Executive Vice President, Chief Financial Officer and Management Committee Member
James C. Yardley	60	Management Committee Member
Daniel B. Martin	55	Senior Vice President and Management Committee Member
Thomas L. Price	56	Vice President and Management Committee Member

James J. Cleary. Mr. Cleary has been President of Colorado Interstate Gas Company, L.L.C. since January 2004 and is a member of its Management Committee. He has been a director and President of El Paso Natural Gas Company since January 2004. Mr. Cleary 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. He 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 also serves as a member of the Management Committee of Ruby Pipeline Holding Company, L.L.C.

Mr. Cleary’s day to day leadership as our President provides him with an intimate knowledge of our company, 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, L.L.C. since March 2010 and a member of its Management Committee since February 2012. He was 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 El Paso, and as Executive Vice President and Chief Financial Officer of our affiliates, El Paso Natural Gas Company, Southern Natural Gas Company, L.L.C. and Tennessee Gas Pipeline Company, L.L.C. 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.

Through his role as our Chief Financial Officer, as well as Chief Financial Officer of El Paso Corporation and El Paso Pipeline GP Company, L.L.C., Mr. Sult brings significant knowledge of our company, including its capital structure and financing requirements. Mr. Sult has an extensive knowledge of the energy industry, as well as financing and accounting skills, and brings significant operations and financial experience to the Management Committee.

James C. Yardley. Mr. Yardley is a member of the Management Committee of Colorado Interstate Gas Company, L.L.C. He has been Executive Vice President of El Paso Corporation with responsibility for the regulated pipeline business unit since August 2006. Mr. Yardley has been Chairman of the Board of El Paso Natural Gas Company since 2006. He previously served as President and Chairman of the Board of Tennessee Gas Pipeline Company, L.L.C. from February 2007 to August 2010, and served as Chairman of the Board from August 2010 until its conversion to a limited liability company in October 2011. Mr. Yardley served as President of Southern Natural Gas Company from May 1998 to August 2010 and currently serves on its Management Committee. 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. He serves on the board of Interstate Natural Gas Association of America and previously served as its Chairman.

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 Senior Vice President of Colorado Interstate Gas Company, L.L.C. since January 2001 and is a member of its Management Committee. Mr. Martin also serves on the Management Committee of our affiliate Southern Natural Gas Company, L.L.C. He served as a director of Tennessee Gas Pipeline Company from May 2005 until its conversion to a limited liability company in October 2011, and upon a change in management structure in February 2012 he was reappointed as a director. He has been Senior Vice President of Southern Natural Gas Company, L.L.C. and Tennessee Gas Pipeline Company, L.L.C. 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. He 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, L.L.C. since February 2012, Vice President of Marketing and Business Development since February 2007 and Vice President of Marketing since February 2002. He was a member of the Management Committee of Colorado Interstate Gas Company until its conversion to a limited liability company in August 2011, and upon a change in management structure in February 2012 he was reappointed as a member of that Management Committee. Mr. Price served as a director of our affiliate El Paso Natural Gas Company from November 2005 to November 2010, and was reappointed as a director in November 2011. He also served as Vice President of Marketing of El Paso Natural Gas Company 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, L.L.C., 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.

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.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

CIG is a Delaware limited liability company. CIG is owned 14 percent indirectly through a wholly owned subsidiary of El Paso, and is owned 86 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 10, 2012, the number of shares of common stock of El Paso owned by each of our executive officers individually and 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		40,694		125,747		166,441	*
John R. Sult		155,568		294,279		449,847	*
James C. Yardley		354,611		662,423		1,017,034	*
Daniel B. Martin		138,992		214,718		353,710	*
Thomas L. Price		18,300		65,856		84,156	*
All management committee members and executive officers as a group (5 persons)		708,165		1,363,023		2,071,188	*

^*	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 10, 2012. Shares subject to options cannot be voted.

⁽²⁾	Based on 772,743,059 shares outstanding as of February 10, 2012.

The following table sets forth, as of February 10, 2012, 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 205,698,750 units outstanding as of February 10, 2012.

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

El Paso Pipeline Partners, L.P.

We are a limited liability company presently owned 86 percent indirectly through a wholly owned subsidiary of EPB and 14 percent through a wholly owned subsidiary of the El Paso.

CIG Operating and Services Agreements

We entered into a Construction and Operating Agreement with Wyoming Interstate Company, L.LC. (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 marketing and administering the service agreements) using the same practices that we adopt in the operation and administration of our own facilities. On September 1, 2011, the Construction and Operating Agreement between us and WIC was superseded by a more generic CIG Pipeline Services Company, L.L.C. (CIG Pipeline Services) Master Services Agreement between us, CIG Pipeline Services and WIC. Under this agreement, CIG Pipeline Services employees provide services to us and WIC and we provide additional services to WIC. Direct and/or allocated costs can be billed either by us or CIG Pipeline Services

We entered into a Construction and Operating Agreement with Young Gas Storage Company, Ltd. (Young Gas) on June 30, 1992. This agreement was amended in 1994 and 1997. Under this agreement, we agreed to design and construct the Young Gas storage facilities and to operate the 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 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 Gas partnership agreement.

We entered into a Construction and Operating Agreement with Cheyenne Plains Gas Pipeline Company, L.L.C. (Cheyenne Plains) 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.

We entered into an Administrative Services Agreement with WYCO Development LLC (WYCO) on January 1, 2009. Under this agreement we perform the general and administrative functions of WYCO, including accounting, budgeting, tax and treasury functions. The contract has a one-year term and is renewed automatically in the absence of notice. We receive a fee of $2,000 per month for these services.

We are a party to a Master Services Agreement with El Paso, Tennessee Pipeline Services Company, L.L.C. (Tennessee Pipeline Services), El Paso Natural Gas Company (EPNG) and CIG Pipeline Services. Under these agreements we reimburse El Paso for supervisory, administrative and financial services in connection with their operations.

We reimburse Tennessee Pipeline Services for technical services such as control, metallurgical, pipeline integrity, rates, tariffs, certificates, engineering and rehabilitation, operational training, government affairs and measurement. Tennessee Pipeline Services provides these services to all El Paso pipeline operating companies. The specific allocations are based on the estimated level of effort devoted to their operations (time and motion studies).

We reimburse EPNG for supervisory, administrative, financial and technical services such as gas scheduling, gas control, market analysis, and executives. The specific allocation to us is based on the estimated level of effort devoted to their operations.

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, 2012 and the balance expiring thereafter.

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 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 term for this transportation service agreement extends through December 31, 2020.

We are party to a capacity release agreement with Public Service Company of Colorado (PSCo), whereby PSCo has released storage capacity from our affiliate, Young Gas, 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 its 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.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Audit Fees

The audit fees for the years ended December 31, 2011 and 2010 of $538,000 and $982,000, respectively, were primarily for professional services rendered by Ernst & Young LLP for the audits of the consolidated financial statements of Colorado Interstate Gas Company, L.L.C. as well as the review of documents filed with the SEC and a consent in 2010.

All Other Fees

No other audit-related, tax or other services were provided by our independent registered public accounting firm for the years ended December 31, 2011 and 2010.

Policy for Approval of Audit and Non-Audit Fees

We are a majority owned subsidiary of EPB and do not have a separate audit committee. EPB’s Audit Committee has adopted a pre-approval policy for audit and non-audit services. For a description of EPB’s pre-approval policy for audit and non-audit related services, see EPB’s Annual Report on Form 10-K for the year ended December 31, 2011.

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)	The following documents are filed as 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		24
Consolidated Statements of Income and Comprehensive Income		25
Consolidated Balance Sheets		26
Consolidated Statements of Cash Flows		27
Consolidated Statements of Members’ Equity/Partners’ Capital		28
Notes to Consolidated Financial Statements		29

2. Financial statement schedules

Schedule II — Valuation and Qualifying Accounts		42

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

3. Exhibits

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

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

•

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

•

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

•

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

•

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

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

Undertaking

We hereby undertake, pursuant to Regulation S-K, Item 601(b), paragraph (4)(iii), to furnish to the Securities and Exchange Commission upon request all constituent instruments defining the rights of holders of our long-term debt and 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.

SIGNATURES

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


COLORADO INTERSTATE GAS COMPANY, L.L.C

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, L.L.C. and in the capacities and on the dates indicated:


Signature	Title	Date
/s/ James J. Cleary	President and Management Committee Member	February 27, 2012
James J. Cleary	(Principal Executive Officer)

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

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

/s/ James C. Yardley	Management Committee Member	February 27, 2012
James C. Yardley

/s/ Daniel B. Martin	Management Committee Member	February 27, 2012
Daniel B. Martin

/s/ Thomas L. Price	Management Committee Member	February 27, 2012
Thomas L. Price

COLORADO INTERSTATE GAS COMPANY, L.L.C.

EXHIBIT INDEX

December 31, 2011

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


Exhibit Number		Description

*3.A		Certificate of Conversion of Colorado Interstate Gas Company, L.L.C., dated August 31, 2011.

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

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).

*21		Subsidiaries of Colorado Interstate Gas Company.

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

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

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


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

*101.INS		XBRL Instance Document.

*101.SCH		XBRL Schema Document.

*101.CAL		XBRL Calculation Linkbase Document.

*101.LAB		XBRL Labels Linkbase Document.

*101.PRE		XBRL Presentation Linkbase Document.

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