Filing Compare · COLORADO INTERSTATE GAS COMPANY, L.L.C.

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

~~____________________________________________________~~_____________

Form 10-K

~~(Mark~~[X] ~~One~~ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

þFor ~~ANNUAL~~the ~~REPORT~~fiscal ~~PURSUANT~~year TOended ~~SECTION~~December 1331, OR2013 ~~15(d) OF THE SECURITIES EXCHANGE ACT OF 1934~~

~~For the fiscal year ended December 31, 2012~~ or

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

¨For ~~TRANSITION~~the ~~REPORT~~transition ~~PURSUANT~~period ~~TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934~~from____________to____________.

For the transition period from to

Commission File Number 1-4874

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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.)

1001 Louisiana Street, Suite 1000, Houston, Texas 77002
(Address of Principal Executive Offices)(Zip Code)

Registrant's telephone number, including area code: (713) 369-9000

_____________

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

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Title of Each Class		Name of Each Exchange on which Registered
6.85% Senior Debentures, due 2037		New York Stock Exchange

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. of 1933. Yes ¨ No ýþ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. of 1934. Yes ¨ No ýþ

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 ýþ 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 ýþ 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. ý

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Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ

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

Large accelerated filer ¨ Accelerated filer ¨ Non-accelerated filer xþ ~~(Do not check if a smaller reporting company)~~ Smaller reporting company ¨

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

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

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

____________________________________________________

Documents Incorporated by Reference: None

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COLORADO INTERSTATE GAS COMPANY, L.L.C.

TABLE OF CONTENTS

	Caption	Page Number
	Information Regarding Forward-Looking Statements	1
	PART I
Item 1 and 2.	Business and Properties	13
Item 1A.	Risk Factors	57
Item 1B.	Unresolved Staff Comments	14
Item 3.	Legal Proceedings	14
Item 4.	Mine Safety Disclosures	14
	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	15
Item 6.	Selected Financial Data	15
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	16
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	1920
Item 8.	Financial Statements and Supplementary Data	2021
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	2021
Item 9A.	Controls and Procedures	2021
Item 9B.	Other Information	2021
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance	2122
Item 11.	Executive Compensation	2122
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	2122
Item 13.	Certain Relationships and Related Transactions, and Director Independence	2122
Item 14.	Principal Accounting Fees and Services	2122
	PART IV
Item 15.	Exhibits and Financial Statement Schedules	2223
	Index to Financial Statements	2324
Signatures		4746

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



/d	=	per day	GAAP	=	Generally Accepted Accounting Principles in the United States of America
BBtu	=	billion British thermal units	FERC	=	Federal Energy Regulatory Commission
Bcf	=	billion cubic feet	MMcf	=	million cubic feet

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

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Information Regarding Forward-Looking Statements

This report includes forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. They use words such as "anticipate," "believe," "intend," "plan," "projection," "forecast," "strategy," "position," "continue," "estimate," "expect," "may," or the negative of those terms or other variations of them or comparable terminology. In particular, expressed or implied statements, concerning future actions, conditions or events, future operating results or the ability to generate sales, income or cash flow or to make distributions are forward-looking statements. Forward-looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions. Future actions, conditions or events and future results of operations may differ materially from those expressed in these forward-looking statements. Many of the factors that will determine these results are beyond our ability to control or predict. Specific factors which could cause actual results to differ from those in the forward-looking statements include:


•	price trends and overall demand for natural gas in the U.S.;


•	economic activity, weather, alternative energy sources, conservation and technological advances that may affect price trends and demand;


•	changes in our tariff rates required by the FERC;


•	our ability to acquire new businesses and assets and integrate those operations into our existing operations, as well as our ability to expand our facilities;


•	our ability to safely operate and maintain our existing assets and to access or construct new pipeline and gross processing capacity;


•	our ability to attract and retain key management and operations personnel;


•	changes in natural gas production from exploration and production areas that we serve;


•	changes in laws or regulations, third-party relations and approvals, and decisions of courts, regulators and governmental bodies that may adversely affect our business or our ability to compete;


•	our ability to obtain permits required for new construction projects and permit renewals for current operations in a timely manner;


•	changes in accounting standards that impact the measurement of our results of operations, the timing of when such measurements are to be made and recorded and the disclosures surrounding these activities;


•	our indebtedness, which could make us vulnerable to general adverse economic and industry conditions, limit our ability to borrow additional funds, place us at a competitive disadvantage compared to our competitors that have less debt, or have other adverse consequences;


•	interruptions of electric power supply to our facilities due to natural disasters, power shortages, strikes, riots, terrorism (including cyber attacks), war or other causes;


•	our ability to obtain insurance coverage without significant levels of self-retention of risk;


•	acts of nature, accidents, sabotage, cyber attacks, terrorism or other similar acts causing damage to our properties greater than our insurance coverage limits;


•	capital and credit markets conditions, inflation and fluctuation in interest rates;


•	global political and economic stability;


•	national, international, regional and local economic, competitive and regulatory conditions and developments;


•	our ability to achieve cost savings and revenue growth;


•	the timing and extent of changes in natural gas commodity prices;

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•	the ability to complete expansion projects on time and on budget;


•	the timing and success of our business development efforts including our ability to renew long-term customer contracts; and


•	unfavorable results of litigation and the outcome of contingencies referred to in Note 7 to our consolidated financial statements.

The foregoing list should not be construed to be exhaustive. We believe the forward-looking statements in this report are reasonable. However, there is no assurance that any of the actions, events or results of the forward-looking statements will occur, or if any of them do, what impact they will have on our results of operations, financial condition or cash flows. Because of these uncertainties, you should not put undue reliance on any forward-looking statements.

See Item 1A "Risk Factors" for a more detailed description of these and other factors that may affect the forward-looking statements. When considering forward-looking statements, one should keep in mind the risk factors described in Item 1A "Risk Factors." The risk factors could cause our actual results to differ materially from those contained in any forward-looking statement. We disclaim any obligation, other than as required by applicable law, to update the above list or to announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments.

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PART I

Item 1 and 2. Business and Properties

Overview

We are a Delaware limited liability company, originally formed in 1927 as a corporation. When we refer to "us," "we," "our," "ours," "the Company," or "CIG" we are describing Colorado Interstate Gas Company, L.L.C. and its consolidated subsidiaries. We are wholly owned by El Paso Pipeline Partners Operating Company, L.L.C. (EPPOC), a wholly owned subsidiary of El Paso Pipeline Partners, L.P. (EPB), a master limited partnership ofindirectly Elcontrolled ~~Paso~~by ~~LLC~~Kinder ~~(formerly~~Morgan, ElInc. ~~Paso Corporation~~ (~~El Paso~~KMI)). ~~El Paso indirectly owns EPB's general partner, El Paso Pipeline GP Company, L.L.C.~~ 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% 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 May 24, 2012, EPB acquired the remaining 14% interest in us from a wholly owned subsidiary of El Paso. El Paso became a wholly owned subsidiary of Kinder Morgan, Inc. (KMI) when KMI's acquisition of El Paso became effective on May 25, 2012.

Our pipeline system and storage facilities 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 fees or rates established under our tariff are a function of our cost of providing services to our customers, including a reasonable return on our invested capital.

Financial Information

See Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations" and Item 15 "Exhibits and Financial Statement Schedules" for financial information related to our operating results and financial condition. For financial information related to significant customers, see Note 1110 to our consolidated financial statements ~~included elsewhere in this report~~.

Business Strategy

Our business strategy is to:


•	Focus on stable, fee-based energy transportation and storage assets that are central to the energy infrastructure of growing markets within North America; and


•	Increase utilization of our existing assets while controlling costs, operating safely and employing environmentally sound operating practices.

It is our intention to carry out the above business strategy, modified as necessary to reflect changing economic conditions and other circumstances. However, as discussed under Item 1A "Risk Factors," there are factors that could affect our ability to carry out our strategy or affect its level of success even if carried out.

Our Assets

Pipeline System

Our pipeline system consists of approximately 4,300 miles of pipeline with a design capacity of 4,~~611~~635 MMcf/d. During ~~2012~~2013, ~~2011~~2012 and ~~2010~~2011, average throughput was 2,~~159~~200 BBtu/d, 2,~~128~~159 BBtu/d and 2,~~131~~128 BBtu/d, respectively. We deliver natural gas from production areas in the 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 facilities in Colorado and Kansas with 37 Bcf of underground working natural gas storage capacity, ~~including~~which includes 7 Bcf of storage capacity from the Totem storage facility (Totem) which is owned by WYCO as further discussed below. In addition, we have a natural gas processing plant located in Wyoming.

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WYCO

WYCO owns Totem and the High Plains pipeline (High Plains), both of which are located in northeast Colorado. Under a long-term agreement with WYCO, we operate Totem and High Plains as permitted under our certificate with the FERC. High Plains 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. Totem services and interconnects with High Plains. Totem has 7 Bcf of working natural gas storage capacity with a maximum withdrawal rate of 200 MMcf/d and a maximum injection rate of 150 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 U.S. natural gas industry has experienced a ~~major~~significant ~~shift~~increase ~~from~~in ~~conventional~~production ~~supply~~since ~~sources~~the tomiddle ~~unconventional~~of ~~sources,~~the ~~such~~previous decade as ~~shale~~well ~~plays~~as ~~with~~ a ~~focus~~major onshift ~~tight~~in ~~oil~~the geographic location of supply sources. ~~This~~ These ischanges ~~primarily~~have ~~due~~resulted toprimarily from the industry's success in commercializing horizontal drilling and hydraulic fracturing techniques, ~~which~~for ~~has~~the ~~led~~production toof angas ~~overall~~from ~~increase~~shale informations. ~~production~~Domestic ~~from~~oil ~~natural~~production ~~gas,~~has ~~but~~ also ~~because~~increased ofsubstantially, ~~the~~resulting ~~divergence~~in ofincreased ~~oil~~production ~~prices~~of ~~above~~"associated gas" (natural gas ~~prices~~produced weas ~~have~~a ~~seen~~byproduct ~~increases~~from informations ~~associated~~that ~~gas~~produce orprimarily ~~natural~~oil ~~gas~~or ~~found in association with oil~~liquids). These new supply sources ~~will~~continue to affect ~~the~~gas supply and flow patterns throughout North America, ~~gas~~as ~~flows~~well ~~and~~as the rates that ~~can~~pipeline besystems ~~charged~~can oncharge ~~pipeline~~for ~~systems~~their services. The impacts ~~will~~ vary among ~~pipelines~~pipeline ~~according~~systems toand ~~the~~over ~~location~~time, ~~and~~as ~~the~~production ~~number~~from ofthese ~~competitors~~new ~~attached~~sources toincreases ~~these~~and ~~new~~pipelines ~~supply~~compete ~~sources. While~~to ~~many~~provide ofmarket ~~our~~access ~~supply~~for ~~basins~~these tosupplies, ~~which~~often wedisplace ~~are~~traditional ~~connected~~supply sources. We are ~~primarily~~connected ~~producing~~to ~~natural~~multiple ~~gas~~supply basins, ~~our~~but ~~natural~~primarily ~~gas~~serve ~~pipelines serving~~ the Rocky Mountain area and are directly connected to the Niobrara Shale formation along the Front Range of the Rockies in Colorado and Wyoming.

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 in demand for natural gas in this sector is influenced by competition with coal and economic growth. Short-term market shifts have been driven by relative electricity generation costs of coal-fired plants versus gas-fired plants. 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 the low natural gas price environment, and this sector offers an opportunity for continued growth. All of the aforementioned factors have led to increased demand for domestic supplies and related transportation services over the last several years.

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.

We also compete with other interstate and intrastate pipelines for deliveries to multiple-connection customers who can take deliveries at alternative points. Some of our largest customers could obtain a significant portion of their natural gas requirements through transportation from other pipelines.

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

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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 fees or rates established under our tariff are a function of providing services to our customers, including a reasonable return on our invested capital. The FERC’s authority also extends to:


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


•	certification and construction of new facilities;


•	extension or abandonment of services and facilities;


•	maintenance of accounts and records;


•	relationships between pipelines and certain affiliates;


•	terms and conditions of service;


•	depreciation and amortization policies;


•	acquisition and disposition of facilities; and


•	initiation and discontinuation of services.

Safety Regulation

We are subject to safety regulations imposed by the ~~United~~U.S. ~~States~~ Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA), including those requiring us to develop and maintain integrity management programs to comprehensively evaluate certain areas along our pipelines and take additional measures to protect pipeline segments located in what are referred to as high consequence areas (HCA), where a leak or rupture could potentially do the most harm.

The ultimate costs of compliance with the integrity management rules are difficult to predict. Changes such as advances of in-line inspection tools, identification of additional threats to a pipeline's integrity and changes to the amount of pipe determined to be located in HCAs can have a significant impact on the costs to perform integrity testing and repairs. We plan to continue our pipeline integrity testing programs to assess and maintain the integrity of our existing and future pipelines as required by the ~~United~~U.S. ~~States~~ Department of Transportation rules. The results of these tests could cause us to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines.

The President signed into law new pipeline safety legislation in January 2012, The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, which increased penalties for violations of safety laws and rules, among other matters, and may result in the imposition of more stringent regulations in the next few years. PHMSA is also currently considering changes to its regulations. PHMSA ~~recently~~ issued an Advisory Bulletin which, among other things, advises pipeline operators that if they are relying on design, construction, inspection, testing, or other data to determine the pressures at which their pipelines should operate, the records of that data must be traceable, verifiable and complete. Locating such records and, in the absence of any such records, verifying maximum pressures through physical testing or modifying or replacing facilities to meet the demands of such pressures, could significantly increase our costs. Additionally, failure to locate such records or verify maximum pressures could result in reductions of allowable operating pressures, which would reduce available capacity on our pipelines. There can be no assurance as to the amount or timing of future expenditures for pipeline integrity regulation, and actual future expenditures may be different from the amounts we currently anticipate. Regulations, changes to regulations or an increase in public expectations for pipeline safety may require additional reporting, the replacement of some of our pipeline segments, the addition of monitoring equipment and more frequent inspection or testing of our pipeline facilities. Any repair, remediation, preventative or mitigating actions may require significant capital and operating expenditures.

From time to time, our pipelines may experience leaks and ruptures. These leaks and ruptures may cause explosions, fire, damage to the environment, damage to property and/or personal injury or death. In connection with these incidents, we may be sued for damages caused by an alleged failure to properly mark the locations of our pipelines and/or to properly maintain our pipelines. Depending upon the facts and circumstances of a particular incident, state and federal regulatory authorities may seek civil and/or criminal fines and penalties.

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We are also subject to the requirements of the Federal Occupational Safety and Health Administration (OSHA) and other comparable federal and state agencies that address employee health and safety. In general, we believe current expenditures are addressing the OSHA requirements and protection of the health and safety of our employees. Based on new regulatory developments, we may increase expenditures in the future to comply with higher industry and regulatory safety standards; however, such increases in our expenditures cannot be accurately estimated at this time.

Other Regulation

Our interstate pipeline system is also subject to federal, state and local safety and environmental statutes and regulations of the ~~United~~U.S. ~~States~~ Department of Transportation and the ~~United~~U.S. ~~States~~ 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" and Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations."

Environmental Matters

A description of our environmental remediation activities is included in Note 87 to our consolidated financial statements ~~included elsewhere in this report~~.

Other

Employees

Properties

We believe that we have satisfactory title to the properties owned and used in our businesses, subject to liens for taxes not yet payable, liens incident to minor encumbrances, liens for credit arrangements and easements and restrictions that do not materially detract from the value of these properties, our interests in these properties or the use of these properties in our business. We believe that our properties are adequate and suitable for the conduct of our business in the future.

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~~ITEM~~Item 1A. Risk Factors

You should carefully consider the risks described below, in addition to the other information contained in this document. Realization of any of the following risks could have a material adverse effect on our business, financial position, results of operations or cash flows.

Information Regarding Forward-Looking Statements

This report includes forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. They use words such as "anticipate," "believe," "intend," "plan," "projection," "forecast," "strategy," "position," "continue," "estimate," "expect," "may," or the negative of those terms or other variations of them or comparable terminology. In particular, statements, express or implied, concerning future actions, conditions or events, future operating results or the ability to generate sales, income or cash flow or to make distributions are forward-looking statements. Forward-looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions. Future actions, conditions or events and future results of operations may differ materially from those expressed in these forward-looking statements. Many of the factors that will determine these results are beyond our ability to control or predict. Specific factors which could cause actual results to differ from those in the forward-looking statements include:

• price trends and overall demand for natural gas in the United States;

• economic activity, weather, alternative energy sources, conservation and technological advances that may affect price trends and demand;

• changes in our tariff rates implemented by the FERC;

• our ability to acquire new businesses and assets and integrate those operations into our existing operations, as well as our ability to expand our facilities;

• shut-downs or cutbacks at major refineries, petrochemical or chemical plants, ports, utilities, military bases or other businesses that could use our services or provide services or products to us;

• changes in natural gas production from exploration and production areas that we serve;

• changes in laws or regulations, third-party relations and approvals, and decisions of courts, regulators and governmental bodies that may adversely affect our business or our ability to compete;

• changes in accounting standards that impact the measurement of our results of operations, the timing of when such measurements are to be made and recorded and the disclosures surrounding these activities;

• our indebtedness, which could make us vulnerable to general adverse economic and industry conditions, limit our ability to borrow additional funds and/or place us at competitive disadvantages compared to our competitors that have less debt or have other adverse consequences;

• interruptions of electric power supply to our facilities due to natural disasters, power shortages, strikes, riots, terrorism (including cyber attacks), war or other causes;

• our ability to obtain insurance coverage without significant levels of self-retention of risk;

• acts of nature, accidents, sabotage, cyber attacks, terrorism or other similar acts causing damage greater than our insurance coverage limits;

• capital and credit markets conditions, inflation and interest rates;

• global political and economic stability;

• national, international, regional and local economic, competitive and regulatory conditions and developments;

• our ability to achieve cost savings and revenue growth;

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• the timing and extent of changes in natural gas commodity prices;

• the ability to complete expansion projects on time and on budget;

• the timing and success of our business development efforts; and

• unfavorable results of litigation and the fruition of contingencies referred to in Note 8 to our consolidated financial statements included elsewhere in this report.

Risks Related to Our Business

New regulations, rulemaking and oversight, as well as changes in regulations, by regulatory agencies having jurisdiction over our operations could adversely impact our income and operations.

Our pipeline and storage facilities are subject to regulation and oversight by federal, state and local regulatory authorities. Regulatory actions taken by these agencies have the potential to adversely affect our profitability. Regulation affects almost every part of our business and extends to such matters as (i) rates (which include reservation, commodity, surcharges, fuel and gas lost and unaccounted for), operating terms and conditions of service; (ii) the types of services we may offer to our customers; (iii) the contracts for service entered into with our customers; (iv) the certification and construction of new facilities; (v) the integrity, safety and security of facilities and operations; (vi) the acquisition of other businesses; (vii) the acquisition, extension, disposition or abandonment of services or facilities; (viii) reporting and information posting requirements; (ix) the maintenance of accounts and records; and (x) relationships with affiliated companies involved in various aspects of the natural gas and energy businesses.

Should we fail to comply with any applicable statutes, rules, regulations, and orders of such regulatory authorities, we could be subject to substantial penalties and fines. Furthermore, new laws or regulations sometimes arise from unexpected sources. For example, the Department of Homeland Security Appropriation Act of 2007 required the issuance of regulations establishing risk-based performance standards for the security of chemical and industrial facilities, including oil and gas facilities that are deemed to present “high levels of security risk.” New laws or regulations, or different interpretations of existing laws or regulations, including unexpected policy changes, applicable to us or our assets could have a material adverse impact on our business, financial condition and results of operations.

The FERC may establish pipeline tariff rates that have a negative impact on us. In addition, the FERC or our customers could file complaints challenging the tariff rates charged by our pipeline, and a successful complaint could have an adverse impact on us.

The profitability of our regulated pipeline is influenced by fluctuations in costs and our ability to recover any increases in our costs in the rates charged to our shippers. To the extent that our costs increase in an amount greater than what the FERC allows us to recover in our rates ~~or in our “negotiated rate” contracts~~, or to the extent that there is a lag before we can file and obtain rate increases, our operating results, cash flows and financial position can be negatively impacted.

Our existing rates may also be challenged by complaint. ~~Regulators~~Under certain circumstances prescribed by applicable regulations, regulators and shippers on our pipeline have rights to challenge, and have challenged, the rates we charge. Further, ~~under~~the ~~certain~~FERC ~~circumstances~~may ~~prescribed~~initiate byinvestigations ~~applicable~~to ~~regulations~~determine whether some interstate natural gas pipelines have over-collected on rates charged to shippers. Any successful challenge could materially adversely affect our future earnings, cash flows and financial condition.

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Energy commodity transportation and storage activities involve numerous risks that may result in accidents or otherwise adversely affect our operations.

There are a variety of hazards and operating risks inherent to natural gas transmission and storage activities such as leaks, explosions and mechanical problems that could result in substantial financial losses. In addition, these risks could result in serious injury and loss of human life, significant damage to property and natural resources, environmental pollution and impairment of operations, any of which could also result in substantial financial losses. For pipeline and storage assets located near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas, the level of damage resulting from these risks may be greater. Incidents that cause an interruption of service, such as when unrelated third party construction damages a pipeline or a newly completed expansion experiences a weld failure, could negatively impact our revenues and earnings while the affected asset is temporarily out of service. In addition, losses in excess of our insurance coverage could have a material adverse effect on our business, financial condition and results of operations.

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Increased regulatory requirements relating to the integrity of our pipeline may require us to incur significant capital and operating expense outlays for compliance.

We are subject to extensive laws and regulations related to pipeline integrity. There are, for example, federal guidelines for the ~~United~~U.S. ~~States~~ Department of Transportation (DOT) and pipeline companies in the areas of testing, education, training and communication. The ultimate costs of compliance with the integrity management rules are difficult to predict. The majority of compliance costs are pipeline integrity testing and the repairs found to be necessary. Changes such as advances of in-line inspection tools, identification of additional threats to a pipeline's integrity and changes to the amount of pipeline determined to be located in High Consequence Areas can have a significant impact on testing and repairs costs. We plan to continue our integrity testing programs to assess and maintain the integrity of our existing and future pipelines as required by the ~~United~~U.S. ~~States~~ DOT rules. The results of these tests could cause us to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipeline.

Further, additional laws and regulations that may be enacted in the future or a new interpretation of existing laws and regulations could significantly increase the amount of these expenditures. There can be no assurance as to the amount or timing of future expenditures for pipeline integrity regulation, and actual future expenditures may be different from the amounts we currently anticipate. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not deemed by regulators to be fully recoverable from our customers, could have a material adverse effect on our business, financial position, results of operations and prospects.

We may face competition from other pipelines and other forms of transportation into the areas we serve.

Any current or future pipeline system or other form of transportation that delivers natural gas into the areas that our pipelines serve could offer transportation services that are more desirable to shippers than those we provide because of price, location, facilities or other factors. To the extent that an excess of supply into these areas is created and persists, our ability to re-contract for expiring transportation capacity at favorable rates or otherwise to retain existing customers could be impaired. We also could experience competition for the supply of natural gas from both existing and proposed pipeline systems. Several pipelines access many of the same areas of supply as our pipeline systems and transport to destinations not served by us.

Cost overruns and delays on our expansion and new build projects could adversely affect our business.

We could expand our existing assets and construct new build projects, including joint venture projects. We may conduct from time to time alone or with others what are referred to as “open seasons” to evaluate the potential customer interest for new construction projects. A variety of factors outside of our control, such as weather, natural disasters and difficulties in obtaining permits and rights-of-way or other regulatory approvals, as well as performance by third-party contractors, has resulted in, and may continue to result in, increased costs or delays in construction. Significant cost overruns or delays in completing a project could have a material adverse effect on our return on investment, results of operations and cash flows.

We must either obtain the right from landowners or exercise the power of eminent domain in order to use most of the land on which our pipelines are constructed, and we are subject to the possibility of increased costs to retain necessary land use.

We obtain the right to construct and operate our pipeline on other owners' land for a period of time. If we were to lose these rights or be required to relocate our pipelines, our business could be negatively affected. In addition, we are subject to the possibility of increased costs under our rental agreements with landowners, primarily through rental increases and renewals of expired agreements.

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Our interstate natural gas pipeline has federal eminent domain authority. However, we must compensate landowners for the use of their property and, in eminent domain actions, such compensation may be determined by a court. Our inability to exercise the power of eminent domain could negatively affect our business if we were to lose the right to use or occupy the property on which our pipeline is located.

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Our business, financial condition and operating results may be affected adversely by increased costs of capital or a reduction in the availability of credit.

Adverse changes to the availability, terms and cost of capital, interest rates or our credit ratings could cause our cost of doing business to increase by limiting our access to capital, limiting our ability to pursue acquisition opportunities and reducing our cash flows. Our credit ratings may be impacted by our leverage, liquidity, credit profile and potential transactions. Also, ~~continuing~~ disruptions and volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance our operations on favorable terms. A significant reduction in the availability of credit could materially and adversely affect our business, financial condition and results of operations.

In addition, due to our relationship with KMI, our credit ratings, and thus our ability to access the capital markets and the terms and pricing we receive therein, may be adversely affected by any impairment to KMI's financial condition or adverse changes in its credit ratings. Additionally, our credit ratings will generally affect the market value of our debt instruments.

Our substantial debt could adversely affect our financial health and make us more vulnerable to adverse economic conditions.

As of December 31, ~~2012~~2013, we had $~~647~~644 million of consolidated debt. This level of debt could have important consequences, such as (i) limiting our ability to obtain additional financing to fund our working capital, capital expenditures, debt service requirements or potential growth or for other purposes; (ii) limiting our ability to use operating cash flow in other areas of our business or to pay distributions because we must dedicate a substantial portion of these funds to make payments on our debt; (iii) placing us at a competitive disadvantage compared to competitors with less debt; and (iv) increasing our vulnerability to adverse economic and industry conditions.

Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, many of which are beyond our control. If our operating results are not sufficient to service our indebtedness, or any future indebtedness that we incur, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity capital. We may not be able to affect any of these actions on satisfactory terms or at all. For more information about our debt, see Note 54 to our consolidated financial statements ~~included elsewhere in this report~~.

A breach of the covenants applicable to our debt and other financing obligations could affect our ability to borrow funds and could accelerate repayment of our debt and other financing obligations.

Our debt and other financing obligations contain restrictive covenants and require us to maintain certain financial ratios, including debt to earnings before interest, income taxes, depreciation and amortization (EBITDA) and EBITDA to interest expense in our note purchase agreements and contain cross default provisions. Volatility in the financial markets and a reduction in access to capital could cause these covenants to become more restrictive over time. A breach of any of these covenants could accelerate our debt and other financing obligations. If this were to occur, we may not be able to repay such debt and other financing obligations.

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 financing costs to increase. For more information about our interest rate risk, see Item 7A “Quantitative and Qualitative Disclosures about Market Risk.”

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We may not be able to generate sufficient cash to service all of our indebtedness, and we may be forced to take other actions to satisfy our obligations under our indebtedness, which may not be successful.

Our ability to make scheduled payments on or to refinance our debt obligations depends on our financial and operating performance, which is subject to prevailing economic and competitive conditions and to certain financial, business and other factors beyond our control. We cannot assure the noteholders that we will maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness. If our cash flows and capital resources are insufficient to fund our debt service obligations, we may be forced to reduce or delay capital expenditures, sell assets or operations, seek additional capital or restructure or refinance our indebtedness, including the notes. We cannot assure the noteholders that we would be able to take any of these actions, that these actions would be successful and would permit us to meet our scheduled debt service obligations or that these actions would be permitted under the terms of our existing or future debt agreements and the indenture that will govern the notes. In the absence of such cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet our debt service and other obligations. ~~Our revolving credit facility contains restrictions on our ability to dispose of assets.~~ We may not be able to consummate those dispositions or to obtain the proceeds that we could realize from them, and any proceeds may not be adequate to meet any debt service obligations when due.

Our pipeline depends on certain key customers for a significant portion of its revenues and the loss of any of these key customers could result in a decline in our revenues. In addition, 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 of our counterparties failing to make payments to us, which may include payments not being received 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 system relies on a limited number of customers for a significant portion of our system revenues. For the year ended December 31, ~~2012~~2013, our four largest customers accounted for approximately 66% of our respective 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 all or a portion of the contracted volumes of these customers, as a result of competition, creditworthiness, inability to negotiate extensions, or replacements of contracts, could have a material adverse effect on us. Our credit procedures and policies that are governed by the FERC 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 during and after insolvency proceedings involving a customer. For additional information regarding our major customers, see Note 1110 to our consolidated financial statements ~~included elsewhere in this report~~.

We could experience difficulty integrating and constructing new operations, and we may not be able to achieve the expected benefits from any future acquisitions.

Our business strategy could include acquisition of additional businesses, expanding existing assets and constructing new facilities. If we do not successfully integrate acquisitions, expansions or newly constructed facilities, we may not realize anticipated operating advantages and cost savings. The integration of companies that have previously operated separately involves a number of risks, including (i) demands on management related to the increase in our size after an acquisition, expansion or completed construction project; (ii) the diversion of management's attention from the management of daily operations; (iii) difficulties in implementing or unanticipated costs of accounting, estimating, reporting and other systems; (iv) difficulties in the assimilation and retention of necessary employees; and (v) potential adverse effects on operating results.

We may not be able to maintain the levels of operating efficiency that acquired companies have achieved or might achieve separately. Successful integration of each acquisition, expansion or construction project will depend upon our ability to manage those operations and to eliminate redundant and excess costs. Because of difficulties in combining and expanding operations, we may not be able to achieve the cost savings and other size-related benefits that we hoped to achieve after these acquisitions, which would harm our financial condition and results of operations.

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Environmental, health and safety laws and regulations could expose us to significant costs and liabilities.

Our operations are subject to federal, state, provincial and local laws, regulations and potential liabilities arising under or relating to the protection or preservation of the environment, natural resources and human health and safety. Such laws and regulations affect many aspects of our present and future operations, and generally require us to obtain and comply with various environmental registrations, licenses, permits, inspections and other approvals. Liability under such laws and regulations may be incurred without regard to fault under the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), the Resource Conservation and Recovery Act, the Federal Clean Water Act or analogous state laws for the remediation of contaminated areas. Private parties, including the owners of properties through which our pipeline passes, also may have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with such laws and regulations or for personal injury or property damage. Our insurance may not cover all environmental risks and costs and/or may not provide sufficient coverage in the event an environmental claim is made against us.

Failure to comply with these laws and regulations also may expose us to civil, criminal and administrative fines, penalties and/or interruptions in our operations that could influence our business, financial position, results of operations and prospects. For example, if an accidental leak, ~~release or spill of liquid petroleum products, chemicals or other hazardous substances~~ occurs at or from our ~~pipelines~~pipeline or our storage or other facilities, we may experience significant operational disruptions and we may have to pay a significant amount to clean up or otherwise respond to the leak, release or spill, pay for government penalties, address natural resource damage, compensate for human exposure or property damage, install costly pollution control equipment or undertake a combination of these and other measures. The resulting costs and liabilities could materially and negatively affect our level of earnings and cash flows. In addition, emission controls required under the Federal Clean Air Act and other similar federal, state and provincial laws could require significant capital expenditures at our facilities.

We own and/or operate properties that have been used for many years in connection with our business activities. While we have utilized operating, handling and disposal practices that were consistent with industry practices at the time, hydrocarbons or other hazardous substances may have been released at or from properties owned, operated or used by us or our predecessors, or at or from properties where our or our predecessors' wastes have been taken for disposal. In addition, many of these properties have been owned and/or operated by third parties whose management, handling and disposal of hydrocarbons or other hazardous substances were not under our control. These properties and the hazardous substances released and wastes disposed on them may be subject to laws such as CERCLA, which impose joint and several liability without regard to fault or the legality of the original conduct. Under such laws and implementing regulations, we could be required to remove or remediate previously disposed wastes or property contamination, including contamination caused by prior owners or operators. Imposition of such liability schemes could have a material adverse impact on our operations and financial position.

Further, we cannot ensure that such existing laws and regulations will not be revised or that new laws or regulations will not be adopted or become applicable to us. There can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, could have a material adverse effect on our business, financial position, results of operations and prospects. For more information, see Note 87 to our consolidated financial statements ~~included elsewhere in this report~~.

Climate change regulation at the federal, state, or regional levels could result in significantly increased operating and capital costs for us.

Methane, a primary component of natural gas, and carbon dioxide, which is naturally occurring and also a byproduct of the burning of natural gas, are examples of greenhouse gases. The ~~United States~~ Environmental Protection Agency ~~(EPA)~~regulates ~~began regulating the~~ greenhouse gas emissions ~~requiring~~and requires the reporting of greenhouse gas emissions in the U.S. for emissions from specified large greenhouse gas emission sources, fractionated natural gas liquids and ~~from~~ certain stationary sources.

Because our operations, including our compressor stations and natural gas processing plant, emit various types of greenhouse gases, primarily methane and carbon dioxide, such regulation could increase our costs related to operating and maintaining our facilities and may require us to install new emission controls equipment at our facilities, acquire allowances for our greenhouse gas emissions, pay taxes related to our greenhouse gas emissions and/or administer and manage a greenhouse gas emissions program. We are not able at this time to estimate such increased costs; however, they could be significant. Recovery of such increased costs from our customers is uncertain in all cases and may depend on events beyond our control, including the outcome of future rate proceedings before the FERC. Any of the foregoing could have adverse effects on our business, financial position, results of operations or cash flows.

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Increased regulation of exploration and production activities, including hydraulic fracturing, could result in reductions or delays in drilling and completing new natural gas wells, which could adversely impact our revenues by decreasing the volumes of natural gas transported on our natural gas pipelines.

The natural gas industry is increasingly relying on natural gas supplies from unconventional sources, such as shale, tight sands and coal bed methane. Natural gas extracted from these sources frequently requires hydraulic fracturing. Hydraulic fracturing involves the pressurized injection of water, sand, and chemicals into the geologic formation to stimulate gas production and is a commonly used stimulation process employed by natural gas exploration and production operators in the completion of certain natural gas wells. Recently, there have been initiatives at the federal and state levels to regulate or otherwise restrict the use of hydraulic fracturing. Adoption of legislation or regulations placing restrictions on hydraulic fracturing activities could impose operational delays, increased operating costs and additional regulatory burdens on exploration and production operators, which could reduce their production of natural gas and, in turn, adversely affect our revenues and results of operations by decreasing the volumes of natural gas transported on our ~~or our joint venture's~~ natural gas pipelines, several of which gather natural gas from areas in which the use of hydraulic fracturing is prevalent.

Terrorist attacks or “cyber security” events, or the threat of them, may adversely affect our business.

The ~~United~~U.S. ~~States~~ government has issued public warnings that indicate that pipelines and other assets might be specific targets of terrorist organizations or “cyber security” events. These potential targets might include our pipeline systems or operating systems and may affect our ability to operate or control our pipeline assets, our operations could be disrupted and/or customer information could be stolen. The occurrence of one of these events could cause a substantial decrease in revenues, increased costs to respond or other financial loss, damage to reputation, increased regulation or litigation and or inaccurate information reported from our operations.

There is no assurance that adequate sabotage and terrorism insurance will be available at rates we believe are reasonable in the near future. These developments may subject our operations to increased risks, as well as increased costs, and, depending on their ultimate magnitude, could have a material adverse effect on our business, results of operations and financial condition.

Future business development of our pipeline is dependent on the supply of and demand for the commodities transported by our pipeline.

Our pipeline depends on production of natural gas in the areas served by our pipeline. Without reserve additions, production will decline over time as reserves are depleted and production costs may rise. Producers may shut down production at lower product prices or higher production costs, especially where the existing cost of production exceeds other extraction methodologies. Producers in areas served by us may not be successful in exploring for and developing additional reserves, and our gas plants and pipelines may not be able to maintain existing volumes of throughput. Commodity prices and tax incentives may not remain at a level that encourages producers to explore for and develop additional reserves, produce existing marginal reserves or renew transportation contracts as they expire.

Changes in the business environment, such as a decline in natural gas prices, an increase in production costs from higher feedstock prices, supply disruptions, or higher development costs, could result in a slowing of supply from natural gas producing areas. In addition, changes in the regulatory environment or governmental policies may have an impact on the supply of natural gas. Each of these factors impact our customers shipping through our pipeline, which in turn could impact the prospects of new transportation contracts or renewals of existing contracts.

Throughput on our natural gas pipeline also may decline as a result of changes in business conditions. Over the long term, business will depend, in part, on the level of demand for natural gas in the geographic areas in which deliveries are made by pipelines and the ability and willingness of shippers having access or rights to utilize the pipelines to supply such demand.

The implementation of new regulations or the modification of existing regulations affecting the natural gas industry could reduce demand for natural gas, increase our costs and may have a material adverse effect on our results of operations and financial condition. We cannot predict the impact of future economic conditions, fuel conservation measures, alternative fuel requirements, governmental regulation or technological advances in fuel economy and energy generation devices, all of which could reduce the demand for natural gas.

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Our operating results may be adversely affected by unfavorable economic and market conditions.

Economic conditions worldwide have from time to time contributed to slowdowns in several industries, including the natural gas industry and markets in which we operate, resulting in reduced demand and increased price competition for our products and services. Our operating results in one or more geographic regions also may be affected by uncertain or changing economic conditions within that region, such as the challenges that are currently affecting economic conditions in the ~~United States~~U.S. Volatility in commodity prices might have an impact on many of our customers, which in turn could have a negative impact on their ability to meet their obligations to us. If global economic and market conditions or economic conditions in the ~~United~~U.S. ~~States~~ or other key markets, remain uncertain or persist, spread or deteriorate further, we may experience material impacts on our business, financial condition and results of operations.

Earthquakes and other natural disasters could have an adverse effect on our business, financial condition and results of operations.

Some of our pipeline and other assets are located in areas that are susceptible to earthquakes and other natural disasters. These natural disasters could potentially damage or destroy our pipeline and other assets and disrupt the supply of the products we transport through our pipeline. Natural disasters can similarly affect the facilities of our customers. In either case, losses could exceed our insurance coverage and our business, financial condition and results of operations could be adversely affected.

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 ~~United~~U.S. ~~States~~ GAAP for nonregulated entities. For example, we are required to record certain regulatory assets on our balance sheet that would not be recorded 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, our pipeline system has regulatory assets recorded on the balance sheets. If we determine that future recovery is no longer probable for our pipeline system, then we could be required to write off the regulatory assets in the future. In addition, we capitalize a carrying cost (an allowance for funds used during construction or AFUDC) on equity funds related to our construction of long-lived assets. Equity amounts capitalized are included as "Other income, net" on our Consolidated Statements of Income and Comprehensive Income. 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 and our future earnings could be impacted.

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

We are managed and operated by KMI and its affiliates. Such operations and management require the retention and recruitment of a skilled workforce including engineers, technical personnel and other professionals. KMI competes with other companies in the energy industry for this skilled workforce. In addition, many of our current employees are retirement eligible, which have significant institutional knowledge that must be transferred to other employees. If KMI is unable to (a) retain their current employees, (b) successfully complete the knowledge transfer and/or (c) recruit new employees of comparable knowledge and experience, our business could be negatively impacted. In addition, we could experience increased allocated costs to retain and recruit these professionals.

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Risks Inherent in Our Structure and Relationship with KMI

We are controlled by EPB, which is in turn controlled by its general partner, which is indirectly owned by KMI. KMI also indirectly owns the common stock of the general partner of Kinder Morgan Energy Partners, L.P. (KMP), which may result in conflicts of interest.

KMI owns EPB’s general partner and as a result controls EPB and us. KMI also owns the common stock of the general partner of KMP, a publicly traded partnership with which we and EPB compete in the natural gas gathering, processing and transportation business. The directors and officers of EPB’s general partner and its affiliates have fiduciary duties to manage EPB’s general partner in a manner that is beneficial to KMI, its ultimate parent corporation. At the same time, EPB’s general partner has fiduciary duties to manage EPB in a manner that is beneficial to EPB’s unitholders. Therefore, EPB’s general partner’s duties to EPB and us may conflict with the duties of its officers and directors to KMI. As a result of these conflicts of interest, EPB’s general partner may favor its own interest or those of KMI, KMP, or their owners or affiliates over the interests of EPB’s unitholders or us.

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~~ITEM~~Item 1B. Unresolved Staff Comments.

Not applicable.

~~ITEM~~Item 3. Legal Proceedings.

See Note 87 to our consolidated financial statements ~~included elsewhere in this report~~.

~~ITEM~~Item 4. Mine Safety Disclosures.

Not applicable.

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PART II

~~ITEM~~Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

Our member interest is indirectly owned by EPB and, accordingly, is 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 $~~161~~198 million, in$161 ~~2012~~million, and $155 million in ~~2011~~2013, 2012 and ~~$170~~2011, ~~million~~respectively, ~~in 2010~~ to our members.

~~ITEM~~Item 6. Selected Financial Data.

Information has been omitted from this report pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.

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~~ITEM~~Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.

The information required by this Item is presented in a reduced disclosure format pursuant to General Instruction I to Form 10-K. The following discussion and analysis should be read in conjunction with our consolidated financial statements and the notes thereto ~~included elsewhere in this report~~. Additional sections in this report which should be helpful to the reading of our discussion and analysis include the following: (i) a description of our business strategy found in Items 1 and 2 "Business and Properties" and (ii) a description of risk factors affecting us and our business, found in Item 1A "Risk Factors."

Inasmuch as the discussion below and the other sections to which we have referred you pertain to management's comments on financial resources, capital spending, our business strategy and the outlook for our business, such discussions contain forward-looking statements. These forward-looking statements reflect the expectations, beliefs, plans and objectives of management about future financial performance and assumptions underlying management's judgment concerning the matters discussed, and accordingly, involve estimates, assumptions, judgments and uncertainties. Our actual results could differ materially from those discussed in the forward-looking statements. Factors that could cause or contribute to any differences include, but are not limited to, those discussed below and elsewhere in this report, particularly in Item 1A "Risk Factors"."

General

Our business model, through our ownership and operation of energy related assets is built to support the principal ~~component~~objective of helping customers by providing safe and reliable transportation and storage of natural gas. To achieve this objective, we focus on providing fee-based services to customers from a business portfolio consisting of natural gas pipelines and related storage facilities.

Our revenues are primarily received under contracts with terms that are fixed for various and extended periods of time. To the extent practicable and economically feasible in light of our strategic plans and other factors, we generally attempt to mitigate risk of reduced volumes and prices by negotiating contracts with longer terms, with higher per-unit pricing and for a greater percentage of our available capacity. Our long-term transportation contracts are typically structured with a fixed-fee reserving the right to transport natural gas and specify that we receive the majority of our fee for making the capacity available, whether or not the customer actually chooses to utilize the capacity. As contracts expire, we have additional exposure to the longer term trends in supply and demand for natural gas.

Our Business

We are a Delaware limited liability company, originally formed in 1927 as a corporation. We are wholly owned by EPPOC, a wholly owned subsidiary of EPB, a master limited partnership of KMI. Our primary business consists of interstate transportation, storage and processing of natural gas. Our pipeline operations are rate-regulated and accordingly we generate profit based on our ability to earn a return in excess of our costs through the rates we charge our customers.

Factors influencing profitability

Our long-term profitability will be influenced primarily by the following factors:


•	Developing growth projects in our market and supply areas;


•	Contracting and recontracting pipeline capacity with our customers;


•	Maintaining or obtaining approval by the FERC of acceptable rates, terms of service and expansion projects; and

• ~~Improving~~Maintaining a high level of operating efficiency.

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Types of Revenue

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 consist of the following types:

Type	Description	Percent of Total Revenues in ~~2012~~2013 (1a)
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.	9392%
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.	78%

~~_________________________~~__________

(1a) Excludes liquids revenues associated with our processing plant.

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. 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 contracts mature at various times and in various amounts of 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 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~~We ~~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. As of December 31, ~~2012~~2013, the remaining weighted average contract life on our natural gas transportation contracts was approximately seven years.

Results of Operations

We previously reported earnings before interest expense and income taxes as our performance measure. As a result of KMI's acquisition of El Paso, management now assesses our performance based on our earnings before depreciation and amortization (EBDA), which excludes depreciation and amortization, general and administrative expenses and interest expense, net. Certain general and administrative expenses have been excluded from EBDA such as employee benefits, legal, information technology and other costs that are not controllable by operating management and thus are not included in the measure of performance for which they are accountable. Our management uses EBDA as a measure to assess the operating results and effectiveness of our assets. We believe providing EBDA to our investors is useful because it is the same measure used by management to evaluate our performance and allows investors to evaluate our operating results without regard to our financing methods. EBDA may not be comparable to measures used by other companies. Additionally, EBDA should be considered in conjunction with net income and other performance measures such as operating income or operating cash flows.

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Below is athe ~~reconciliation~~contract ofexpiration ~~our~~portfolio ~~EBDA~~and tothe ~~net~~associated ~~income~~revenue expirations for ~~2012~~our firm transportation contracts on our system as ~~compared~~of December to31, ~~2011~~2013, (including those with terms beginning in ~~millions).~~2013 or later:

	2012				2011
	ContractedCapacity			Percent of TotalContracted Capacity			Reservation Revenue		Percent of TotalReservation Revenue
EBDA(1)	$	301			$	293
	(BBtu/d)			(%)			(In millions)		(%)
Depreciation and amortization	(45		)		(46		)
2014	270			6	%		$	7	2	%
General and administrative expenses(2)	(38		)		(41		)
2015	428			9	%		16		5	%
Interest and debt expense, net	(62		)		(62		)
2016(a)	1,689			37	%		119		37	%
Net income	$	156			$	144
2017	191			4	%		13		4	%
2018	178			4	%		12		4	%
2019 and beyond	1,855			40	%		152		48	%
Total	4,611			100	%		$	319	100	%

~~____________________~~_____________

(1a) ~~2012~~Includes ~~includes~~contracts aof 1,301 BBtu/d for $294 million ~~increase~~that were extended in ~~EBDA~~conjunction ~~for~~with ~~certain~~CIG's ~~items~~rate ascase ~~follows:~~settlement approved by the FERC in August 2011.

Results of Operations

Non-GAAP Measures

The non-GAAP financial measure, earnings before depreciation and amortization (EBDA) before certain items, is presented below under Earnings Results. Certain items are items that are required by GAAP to be reflected in net income, but typically either do not have a cash impact, or by their nature are separately identifiable from our normal business operations and in our view are likely to occur only sporadically.

Our non-GAAP measure described below should not be considered as an alternative to GAAP net income, operating income or any other GAAP measure. EBDA before certain items is not a financial measure in accordance with GAAP and has important limitations as an analytical tool. You should not consider this non-GAAP measure in isolation or a substitute for an analysis of our results as reported under GAAP. Our EBDA before certain items excludes some but not all items that affect net income and may not be comparable to measures used by other companies. Management compensates for the limitations of this non-GAAP measure by reviewing our comparable GAAP measures, understanding the differences between the measures and taking this information into account in its analysis an its decision making process.

Earnings Results

Management assesses our performance based on our EBDA, which excludes depreciation and amortization, general and administrative expenses and interest expense, net. Certain general and administrative expenses have been excluded from EBDA such as employee benefits, legal, information technology and other costs that are not controllable by operating management and thus are not included in the measure of performance for which they are accountable. Our management uses EBDA as a measure to assess the operating results and effectiveness of our assets. We believe providing EBDA to our investors is useful because it is the same measure used by management to evaluate our performance and allows investors to evaluate our operating results without regard to our financing methods. EBDA may not be comparable to measures used by other companies. Additionally, EBDA should be considered in conjunction with net income and other performance measures such as operating income or operating cash flows.

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Below are the components of EBDA for the periods presented (in millions):



	Year Ended December 31,
	2013			2012
Revenues	$	397		$	398
Operating Expenses
Operation and maintenance	(105		)	(118		)
General and administrative expenses	20			38
Operation and maintenance, excluding general and administrative expenses	(85		)	(80		)
Taxes, other than income taxes	(19		)	(20		)
Operating Expenses	(104		)	(100		)
Other, net	2			3
EBDA	$	295		$	301

Below is a reconciliation of our EBDA to net income, our throughput volumes and an analysis and discussion of our operating results for the periods presented (in millions, except operating statistics):



	Year Ended December 31,
	2013			2012
EBDA(a)	$	295		$	301
Depreciation and amortization	(44		)	(45		)
General and administrative expenses(b)	(20		)	(38		)
Interest expense, net	(61		)	(62		)
Net income	$	170		$	156
Throughput volumes (BBtu/d)	2,200			2,159

__________


(a)	2012 includes a $2 million increase in EBDA for certain items as follows:


•	$4 million charge to operating expenses attributable to a canceled software implementation project, and

• $6 million non-cash reduction to operating expenses for an out of period correction to reduce environmental liabilities for certain environmental projects.

(2b) ~~Includes~~2012 includes severance costs of $10 million ~~in 2012~~ allocated to us from El Paso as a result of KMI's acquisition of El Paso.

Below are the components of EBDA, our throughput volumes and an analysis and discussion of our operating results for 2012 as compared to 2011 (in millions, except operating statistics).

	2012			2011
Revenues	$	398		$	415
Operating expenses	(100		)	(126		)
Other income, net	3			4
EBDA	$	301		$	293
Throughput volumes (BBtu/d)	2,159			2,128

EBDA

The items described in footnote (1a) above increased our EBDA by $2 million for the year ended December 31, 2012 ~~as compared to 2011~~. After adjusting for these items, EBDA ~~increased~~decreased by $64 million for the year ended December 31, ~~2012~~2013 as compared to ~~2011~~2012. Our ~~primarily~~EBDA was impacted by lower transportation revenues of $11 million largely due to the ~~items~~nonrenewal ~~described~~of ~~below~~expiring contracts and the restructuring of certain contracts at lower volumes or discounted rates. Offsetting this unfavorable impact were storage gas sales of $5 million and higher revenues of $6 million attributable to the revenue surcharge mechanism (which enables us to make estimated customer billing surcharge accruals with certain customers when realized revenue is less than the annual threshold amounts as established in our August 2011 rate case settlement). Additionally, our operating expenses were further impacted by a $1 million unfavorable revaluation of our system inventory due to changes in natural gas prices from prior year and $1 million higher property taxes due to a favorable adjustment made in 2012.

We benefited from favorable property tax adjustments of $4 million, lower pipeline maintenance, payroll and contractor costs of $10 million and increased reservation revenue of $7 million related to an expansion project placed in service in October 2011. Partially offsetting these favorable impacts were lower transportation revenues of approximately $15 million primarily resulting from the nonrenewal of expiring contracts, the restructuring of certain contracts at lower volumes or discounted rates and lower usage and interruptible revenues due to milder weather.

General and Administrative Expense

After adjusting for ~~the allocated~~ severance costs ~~attributable~~discussed ~~to KMI's acquisition of El Paso described~~ in footnote (2b) above, our general and administrative expenses were $138 million lower in ~~2012~~2013 as compared to ~~2011~~2012 primarily due to lower ~~employee~~corporate ~~benefit~~allocations ~~costs~~ resulting from ~~merger-related~~realization ~~headcount~~of ~~reductions~~synergies and cost savings associated with KMI's acquisition of El Paso.

~~Inflation~~Rate Case Settlement

WeSee ~~believe~~Item ~~that~~15. ~~inflation~~Financial ~~has caused~~Statements, ~~and~~Note ~~may~~9 ~~continue~~"Accounting tofor ~~cause,~~Regulatory ~~increases~~Activities" ~~in certain operating expenses, and will continue~~ to ~~require~~our ~~higher~~consolidated ~~capital~~financial ~~replacement~~statements ~~and~~for ~~construction~~information ~~costs. We~~related ~~continually review the adequacy of our rates in relation~~ to ~~such increasing costs of providing services, the inherent regulatory lag experienced in adjusting~~ our ~~rates~~August ~~and~~2011 ~~the~~rate ~~rates~~case ~~we are actually able to charge in our markets~~settlement.

1819

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~~ITEM~~Item 7A. Quantitative and Qualitative Disclosures About Market Risk.

Note Receivable

AtAs of December 31, ~~2012~~2013, we had an interest bearing note receivable from EPB of approximately $3633 million, with a variable interest rate of 21.29% 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.

Long-Term Debt

All of our debt has fixed rates. However, changes in these fixed interest rates generally affect the fair value of the debt instrument, but not our earnings or cash flows. We do not have an obligation to prepay any of our debt prior to maturity and, as a result, interest rate risk and changes in fair value should not have a significant impact on our fixed rate debt unless we refinance such debt.

As of December 31, ~~2012~~2013 and ~~2011~~2012, the carrying values of our debt obligations were $~~647~~644 million and $~~652~~647 million, respectively. These amounts compare to, as of December 31, ~~2012~~2013 and ~~2011~~2012, fair values of $~~733~~701 million and $~~702~~733 million, respectively. Fair values were determined using quoted market prices, where applicable, or future cash flow discounted at market rates for similar types of borrowing arrangements.

For additional information related to our debt obligations, see Note 54 to our consolidated financial statements ~~included elsewhere in this report~~.

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~~ITEM~~Item 8. Financial Statements and Supplementary Data.

The information required in this Item 8 is included in this report as set forth in the "Index to Financial Statements" on page

2324.

~~ITEM~~Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

None.

~~ITEM~~Item 9A. Controls and Procedures.

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

As of December 31, ~~2012~~2013, our management, including our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon and as of the date of the evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the design and operation of our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in the reports we file and submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported as and when required, and is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

Management's Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control - Integrated Framework(1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on ~~our~~this ~~evaluation under the framework in Internal Control - Integrated Framework~~assessment, our management concluded that our internal control over financial reporting was effective as of December 31, ~~2012~~2013.

Changes in Internal Control Over Financial Reporting

~~Subsequent~~There tohas ~~KMI's~~been ~~acquisition~~no ofchange ~~El Paso~~ in ~~May 2012,~~ our internal ~~controls~~control over financial reporting ~~were~~during ~~impacted by changes made to conform our entity-level controls, monitoring activities and disclosure controls and procedures to~~ the ~~existing~~fourth ~~controls,~~quarter ~~activities and procedures~~ of ~~KMI.~~2013 ~~We also converted certain key accounting information systems. There were no other changes in internal controls over financial reporting~~ that ~~have~~has materially affected, or ~~are~~is reasonably likely to materially affect, our internal ~~controls~~control over financial reporting.

~~ITEM~~Item 9B. Other Information

None.

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PART III

Item 10, "Directors, Executive Officers and Corporate Governance;" Item 11, "Executive Compensation ;" Item 12, "Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters;" and Item 13, "Certain Relationships and Related Transactions, and Director Independence" have been omitted from this report pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.

~~ITEM~~Item 14. Principal Accounting Fees and Services

In connection with KMI's acquisition of El Paso, the audit committee of our general partner approved the engagement of PricewaterhouseCoopers LLP (“PwC”) to audit our consolidated financial statements for the year ended December 31, ~~2012~~2013. PwC replaced Ernst & Young (“E&Y”), which was dismissed as our independent auditor effective May 25, 2012. ~~Because~~PwC ~~our~~is ~~financial statements will be consolidated with those of~~ KMI,'s ~~PwC,~~and ~~which~~subsidiaries' ~~is the~~ independent auditor; ~~of KMI and its subsidiaries~~therefore, ~~was~~PwC ~~chosen~~has tobecome be our independent auditor ~~as well~~.

The reports of E&Y on our consolidated financial statements for the year ended December 31, 2011 did not contain any adverse opinion or a disclaimer of opinion, and were not qualified or modified as to uncertainty, audit scope or accounting principles.

In connection with the audit of our consolidated financial statements for the year ended December 31, 2011 and reviews for the subsequent interim period through May 24, 2012, there were no disagreements between us and E&Y on any matters of accounting principles or practices, financial statement disclosure, auditing scope or procedures which, if not resolved to the satisfaction of E&Y, would have caused E&Y to make reference to the matter in its reports.

We did not consult with PwC during the ~~year ended December 31, 2011 or any subsequent~~ interim ~~period~~periods through May 24, 2012.

Audit Fees

The fees billed for the audit services provided by PwC for the year ended December 31, 2013 and 2012 were $451,000 and $681,000, respectively. The fees billed for the audit services provided by E&Y for the years ended December 31, 2012 ~~and 2011~~ were $181,429 ~~and $538,000, respectively~~. Our audit fees include amounts for the audit of annual financial statements, reviews of the related quarterly financial statements, and reviews of documents filed with the Securities and Exchange Commission.

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, ~~2012~~2013 and ~~2011~~2012.

Policy for Approval of Audit and Non-Audit Fees

We are a wholly 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, ~~2012~~2013.

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PART IV

~~ITEM~~Item 15. Exhibits and Financial Statement Schedules.


(a)	(1) and (2) Financial Statements and Financial Statement Schedules

See "Index to Financial Statements" set forth on page

2324.

(~~a)(~~3) Exhibits

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

3.1*		Certificate of Formation of Colorado Interstate Gas Company, L.L.C., dated August 31, 2011 (incorporated by reference to Exhibit 3.1 to Colorado Interstate Gas Company, L.L.C's 2012 Annual Report on Form 10-K filed with the SEC on March 1, 2013).

3.2*		Second Amended and Restated Limited Liability Company Agreement of Colorado Interstate Gas Company, L.L.C. dated May 24, 2012 (incorporated by reference to Exhibit 10.2 to El Paso Pipeline Partners, L.P.'s Current Report on Form 8-K filed with the SEC on May 24, 2012).

4*		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).

10.1*		Amended and restated No-Notice Storage and Transportation Delivery Service Agreement Rate Schedule NNT-1, dated May 1, 2012, between Colorado Interstate Gas Company and Public Service Company of Colorado. (incorporated by reference to Exhibit 10.1 to Colorado Interstate Gas Company, L.L.C's 2012 Annual Report on Form 10-K filed with the SEC on March 1, 2013).

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

31.1		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

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

32.1		Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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

101		Interactive data files pursuant to Rule 405 of Regulation S-T: (i) our Consolidated Statements of Income and Comprehensive Income for the years ended December 31, 2013, 2012 and 2011; (ii) our Consolidated Balance Sheets as of December 31, 2013 and 2012; (iii) our Consolidated Statements of Cash Flows for the years ended December 31, 2013, 2012 and 2011; (iv) our Consolidated Statements of Members' Equity for the years ended December 31, 2013, 2012 and 2011 and (v) the notes to our Consolidated Financial Statements.

ExhibitNumber		Description
*3.1		Certificate of Formation of Colorado Interstate Gas Company, L.L.C., dated August 31, 2011.
3.2		Second Amended and Restated Limited Liability Company Agreement of Colorado Interstate Gas Company, L.L.C. dated May 24, 2012 (incorporated by reference to Exhibit 10.2 to El Paso Pipeline Partners, L.P.'s Current Report on Form 8-K (File No. 001-33825) filed with the SEC on May 24, 2012).
4		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).
*10.1		Amended and restated No-Notice Storage and Transportation Delivery Service Agreement Rate Schedule NNT-1, dated May 1, 2012, between Colorado Interstate Gas Company and Public Service Company of Colorado.
10.2		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		Omitted pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.
*31.1		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*31.2		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*32.1		Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

* Asterisk indicates exhibit incorporated by reference as indicated; all other exhibits are filed herewith as, except as noted otherwise.

*32.2		Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*101		Interactive data files pursuant to Rule 405 of Regulation S-T: (i) our Consolidated Statements of Income and Comprehensive Income for the years ended December 31, 2012, 2011 and 2010; (ii) our Consolidated Balance Sheets as of December 31, 2012 and 2011; (iii) our Consolidated Statements of Cash Flows for the years ended December 31, 2012, 2011 and 2010; (iv) our Consolidated Statements of Members' Equity for the years ended December 31, 2012, 2011 and 2010 and (v) the notes to our Consolidated Financial Statements.

Table of Contents

	Page Number
Reports of Independent Registered Public Accounting Firms	24
Consolidated Statements of Income and Comprehensive Income for the years ended December 31, 2012, 2011 and 2010	26
Consolidated Balance Sheets as of December 31, 2012 and 2011	27
Consolidated Statements of Cash Flows for the years ended December 31, 2012, 2011 and 2010	28
Consolidated Statements of Members' Equity for the years ended December 31, 2012, 2011 and 2010	29
Notes to Consolidated Financial Statements	30

Table of Contents

COLORADO INTERSTATE GAS COMPANY, L.L.C.

INDEX TO FINANCIAL STATEMENTS



	Page Number
Reports of Independent Registered Public Accounting Firms	25

Consolidated Statements of Income and Comprehensive Income for the years ended December 31, 2013, 2012 and 2011	27

Consolidated Balance Sheets as of December 31, 2013 and 2012	28

Consolidated Statements of Cash Flows for the years ended December 31, 2013, 2012 and 2011	29

Consolidated Statements of Member's Equity as of and for the years ended December 31, 2013, 2012 and 2011	30

Notes to Consolidated Financial Statements	31

Table of Contents

Report of Independent Registered Public Accounting Firm

To the Member of Colorado Interstate Gas Company, L.L.C.:

In our opinion, the accompanying consolidated balance ~~sheet~~sheets ~~as of December 31, 2012~~ and the related consolidated statements of income and comprehensive income, ~~members~~member's equity and of cash flows ~~for the year ended December 31, 2012~~ present fairly, in all material respects, the financial position of Colorado Interstate Gas Company, L.L.C. and its subsidiaries (the “Company”) at December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the ~~year~~two ~~then~~years in the period ended December 31, 2013 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company'’s management. Our responsibility is to express an opinion on these financial statements based on our ~~audit~~audits. We conducted our ~~audit~~audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our ~~audit~~audits ~~provides~~provide a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

~~March~~February 121, ~~2013~~2014

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Report of Independent Registered Public Accounting Firm

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

We have audited the ~~accompanying~~ consolidated balance sheet of Colorado Interstate Gas Company, L.L.C. (the Company) as of December 31, 2011 (not presented separately herein), and the related consolidated statements of income and comprehensive income, ~~members~~member's equity, and cash flows for each of the ~~two~~year ~~years in the period~~ ended December 31, 2011. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our ~~audits~~audit.

We conducted our ~~audits~~audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company's internal control over financial reporting. Our ~~audits~~audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our ~~audits~~audit 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 (not presented separately herein), and the consolidated results of its operations and its cash flows for ~~each of~~ the ~~two~~year ~~years in the period~~ ended December 31, 2011, in conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young LLP

Houston, Texas

February 27, 2012

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COLORADO INTERSTATE GAS COMPANY, L.L.C.

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(In Millions)

	Year Ended December 31,
	2012			2011			2010
	2013			2012			2011
Revenues	$	~~398~~397		$	~~415~~398		$	~~410~~415
Operating Costs and Expenses
Operation and maintenance	~~118~~105			~~144~~118			~~154~~144
Depreciation and amortization	4544			4645			4246
Taxes, other than income taxes	2019			2320			2023
Total Operating Costs and Expenses	~~183~~168			~~213~~183			~~216~~213
Operating Income	~~215~~229			~~202~~215			~~194~~202
Other Income (Expense)
Other income, net	2			3			8
Interest expense, net	(61		)	(62		)	(62		)
Interest and debt expense, net	(62		)	(62		)	(60		)
Affiliated interest income, net	—			1			1
Affiliated interest income, net	1			1			1
Other, net	2			2			3
Total Other Expense	(59		)	(58		)	(51		)
Total Other Income (Expense)	(59		)	(59		)	(58		)
Net Income	~~156~~170			~~144~~156			~~143~~144
Other Comprehensive Income
Adjustments to postretirement benefit plan liabilities	1—			91			—9
Comprehensive Income	$	~~157~~170		$	~~153~~157		$	~~143~~153

The accompanying notes are an integral part of these consolidated financial statements.

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COLORADO INTERSTATE GAS COMPANY, L.L.C.

CONSOLIDATED BALANCE SHEETS

(In Millions)

	December 31,
	2012		2011
	2013		2012
ASSETS
Current assets
Cash and cash equivalents	$	1—	$	21
Accounts and note receivable, net	40		23
Accounts receivable, net	36		38
Inventories	8		8
Regulatory assets	69		36
Other current assets	4		4
Natural gas imbalance receivable	5		2
Total current assets	59		40
Other current assets	3		4
Property, plant and equipment, net	1,385		1,408
Total current assets	61		59
Note receivable from affiliate	36		61
Property, plant and equipment, net	1,367		1,385
Other	45		46
Note receivable from affiliate	33		36
Total Assets	$	1,525	$	1,555
Deferred charges and other assets	44		45
LIABILITIES AND MEMBERS' EQUITY
Total Assets	$	1,505	$	1,525
LIABILITIES AND MEMBER'S EQUITY
Current liabilities
Current portion of debt	$	5	$	5
Accounts payable	1217		3311
Accrued interest	4		4
Accrued taxes	15		17
Accrued taxes, other than income	15		15
Regulatory liabilities	92		9
Contractual deposits	47		84
Accrued other current liabilities	2		5
Other current liabilities	6		3
Total current liabilities	5156		8151
Long-term liabilities and deferred credits
Long-term debt	~~642~~639		~~647~~642
Other long-term liabilities and deferred credits	1420		1814
Total long-term liabilities and deferred credits	656		665
Total Liabilities	715		707
Total Liabilities	707		746
Commitments and contingencies (Note 7)
Commitments and contingencies (Note 5 and 8)
Member's equity	780		808
Members' equity	808		800
Accumulated other comprehensive income	10		10
Accumulated other comprehensive income	10		9
Total Member's Equity	790		818
Total Members' Equity	818		809
Total Liabilities and Member's Equity	$	1,505	$	1,525
Total Liabilities and Members' Equity	$	1,525	$	1,555

The accompanying notes are an integral part of these consolidated financial statements.

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COLORADO INTERSTATE GAS COMPANY, L.L.C.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Millions)

	Year Ended December 31,
	2012			2011			2010
	2013			2012			2011
Cash Flows From Operating Activities
Net income	$	~~156~~170		$	~~144~~156		$	~~143~~144
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	4544			4645			4246
Non-cash asset write-down on long-lived asset	—			—			21
Other non-cash items	(4		)	2			21
Other non-cash income items	2			21			7
Changes in components of working capital:
Accounts receivable	~~(22~~2		)	1(22		)	162
Change in deferred purchase price from accounts receivable sales	—			1			(15		)
Other current assets, including inventories	(2		)	—			—
Accounts payable	~~(19~~5		)	1(17		)	(61		)
Accrued taxes	(2		)	—			—
Accrued taxes, other than income	—			(2		)	3
Regulatory liabilities	(24		)	(192		)	(1719		)
Other, net	(6		)	4			(2		)
Other current liabilities	2			(8		)	3
Other long-term assets and liabilities	(76		)	(67		)	(56		)
Net Cash Provided by Operating Activities	~~145~~219			~~193~~145			~~184~~193
Cash Flows From Investing Activities
Capital expenditures	(2724		)	(6927		)	(8469		)
Net change in note receivable from affiliates	314			(431		)	71(4		)
Other	2			(2		)	2
Other, net	2			2			(2		)
Net Cash Provided by (Used in) Investing Activities	6			(75		)	(11		)
Net Cash (Used in) Provided by Investing Activities	(18		)	6			(75		)
Cash Flows From Financing Activities
Payments of debt, including other financing obligations	(4		)	(4		)	(4		)
Payments of debt	(4		)	(4		)	(4		)
Distributions to members	(~~161~~198		)	(~~155~~161		)	(~~170~~155		)
Contributions from members	13—			4213			—42
Net Cash Used in Financing Activities	(~~152~~202		)	(~~117~~152		)	(~~174~~117		)
Net increase (decrease) in Cash and Cash Equivalents	(1		)	1			(1		)
Net (decrease) increase in Cash and Cash Equivalents	(1		)	(1		)	1
Cash and Cash Equivalents, beginning of period	21			12			21
Cash and Cash Equivalents, end of period	$	1—		$	21		$	12
Supplemental cash flow information
Non-cash Investing Activities
Cash paid during the period for interest (net of capitalized interest)	$	60		$	59		$	57
Increase (decrease) in property, plant and equipment accruals and contractor retainage	$	2		$	(3	)	$	(8	)
Supplemental Cash Flow Information
Cash paid during the period for interest (net of capitalized interest)	$	59		$	60		$	59

The accompanying notes are an integral part of these consolidated financial statements.

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COLORADO INTERSTATE GAS COMPANY, L.L.C.

CONSOLIDATED STATEMENTS OF ~~MEMBERS~~MEMBER'S EQUITY

(In Millions)

January 1, 2010	$	796
January 1, 2011	$	769
Net income	143
Distributions	(170		)
December 31, 2010	769
Net income	144
Contributions	42
Distributions	(155		)
Other comprehensive income	9
December 31, 2011	809
Net income	156
Contributions	13
Distributions	(161		)
Other comprehensive income	1
December 31, 2012	$818	~~818~~
Net income	170
Distributions	(198		)
December 31, 2013	$	790

The accompanying notes are an integral part of these consolidated financial statements.

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COLORADO INTERSTATE GAS COMPANY, L.L.C.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. General

Organization

We are a Delaware limited liability company, originally formed in 1927 as a corporation. We are an interstate pipeline system serving the Rocky Mountain region. ~~When~~Unless wethe ~~refer~~context otherwise requires, references to "us," "we," "our," "ours," "the Company," or "CIG" we are describing Colorado Interstate Gas Company, L.L.C. and its consolidated subsidiaries. We are wholly owned by El Paso Pipeline Partners Operating Company, L.L.C. (EPPOC), a wholly owned subsidiary of El Paso Pipeline Partners, L.P. (EPB), a master limited partnership ofindirectly Elcontrolled ~~Paso~~by ~~LLC~~Kinder ~~(formerly~~Morgan, ElInc. ~~Paso Corporation~~ (~~El Paso~~KMI)). ~~El Paso indirectly owns EPB's general partner, El Paso Pipeline GP Company, L.L.C.~~ On May 24, 2012, EPB acquired the remaining 14% interest in us from aan indirect wholly owned subsidiary of ElKMI, ~~Paso. El~~and ~~Paso~~we became aan indirect wholly owned subsidiary of ~~Kinder Morgan Inc~~EPB. ~~(KMI) when it was acquired by KMI on May 25, 2012.~~

~~Out~~Immaterial ~~of Period Adjustment~~Correction

During the second quarter of 2012, we determined that certain accrued environmental liabilities established in periods prior to 2008 were overstated by approximately $6 million. We corrected this error in June 2012 by reducing accrued liabilities ~~by approximately $6 million,~~ with an offsetting reduction in operating expenses.

We evaluated the impact of the error and determined that it was not material to our previously reported consolidated financial statements. Additionally, we determined that the correction of the error was not material to our 2012 consolidated financial statements.

2. Summary of Significant Accounting Policies

Basis of Presentation

We have prepared our accompanying consolidated financial statements under the rules and regulations of the ~~United~~U.S. ~~States~~ Securities and Exchange Commission. These rules and regulations conform to the accounting principles contained in the Financial Accounting Standards Board's Accounting Standards Codification, the single source of GAAP and referred to in this report as the Codification. Under such rules and regulations, all significant intercompany items have been eliminated in consolidation. Additionally, certain amounts from prior years have been reclassified to conform to the current presentation. In ~~this report, we refer to the Financial Accounting Standards Board as the FASB and the FASB Accounting Standards Codification as the Codification.~~

Additionally, our financial statements are consolidated into the consolidated financial statements of ~~KMI;~~EPB ~~however, our financial statements reflect amounts on a historical cost basis,~~ and, ~~accordingly, do not reflect any purchase accounting adjustments related to~~ KMI~~'s May 25, 2012 acquisition of El Paso~~. Also, except for the related party transactions described in Note 76, EPB and KMI isare not liable for, and its assets are not available to satisfy, the obligations of us. Responsibility for payments of obligations reflected in our, EPB's or KMI's financial statements is a legal determination based on the entity that incurs the liability. Furthermore, the determination of responsibility for payment is not impacted by the consolidation of our financial statements into the consolidated financial statements of EPB and KMI.

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.

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Use of Estimates

Certain amounts included in or affecting our financial statements and related disclosures must be estimated, requiring us to make certain assumptions with respect to values or conditions which cannot be known with certainty at the time our financial statements are prepared. These estimates and assumptions affect the amounts we report for certain assets and liabilities, our revenues and expenses during the reporting period, and our disclosure of contingent assets and liabilities at the date of our financial statements. We evaluate these estimates on an ongoing basis, utilizing historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from our estimates. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known.

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In addition, we believe that certain accounting policies are of more significance in our financial statement preparation process than others. Below are the principal accounting policies we apply in the preparation of our consolidated financial statements.

Cash Equivalents

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

Accounts Receivable

The amounts reported as "Accounts ~~and note~~ receivable, net" on our accompanying Consolidated Balance Sheets at December 31, ~~2012~~2013 and ~~2011~~2012 primarily consist of amounts due from third party payors (unrelated entities). For information on receivables due to us from related parties, see Note 76.

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. The allowance for doubtful accounts as of December 31, 2013 and ~~related~~2012 ~~provision~~and ~~for~~the bad debt expense ~~was not significant~~ for the years ended December 31, ~~2012~~2013, ~~2011~~2012 and ~~2010~~2011 were not significant.

Inventories

Our inventories, which consist of materials and supplies, are valued at the lower of cost or market value with cost determined using the average cost method.

Natural Gas Imbalances

Natural gas imbalances occur when the amount of natural gas delivered from or received by a pipeline system differs from the scheduled amount of gas delivered or received. We value these imbalances due to or from shippers and operators at current index prices. Imbalances are settled in cash or made up in-kind, subject to the terms of our FERC tariff. Imbalances due from others are reported in the Consolidated Balance Sheets as "~~Accounts~~Natural ~~and~~gas ~~note~~imbalance receivable~~, net~~." Imbalances owed to others are reported in the Consolidated Balance Sheets as "~~Accounts~~Other ~~payable~~current liabilities." We classify all imbalances as current as we expect them to be settled 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 constructed assets, we capitalize all construction-related direct labor and material costs, as well as indirect construction costs. Our indirect construction costs primarily include an interest and equity return component (as more fully described below) and labor and related costs of departments associated with supporting construction activities. The indirect capitalized labor and related costs are based upon estimates of time spent supporting construction projects.

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We use the composite (group) method to depreciate property, plant and equipment. Under this method, assets with similar lives and characteristics are grouped and depreciated as one asset. The FERC-accepted depreciation rate is applied to the total cost of the group until the net book value equals the salvage value. For certain general plant, the asset is depreciated to zero. We re-evaluate depreciation rates each time we redevelop our transportation and storage rates to file with the FERC for an increase or decrease in rates. When property, plant and equipment is retired, accumulated depreciation and amortization is charged for the original cost of the assets in addition to the cost to remove, sell or dispose of the assets, less salvage value. We do not recognize gains or losses unless we sell or retire 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 Consolidated Statements of Income and Comprehensive Income.

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 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, net" on our Consolidated Statements of Income and Comprehensive Income. The equity portion is calculated based on the most recent FERC approved rate of return. Equity amounts capitalized are included in "Other income, net" on our Consolidated Statements of Income and Comprehensive Income.32

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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 expense, net" on our Consolidated Statements of Income and Comprehensive Income. The equity portion is calculated based on the most recent FERC approved rate of return. Equity amounts capitalized are included in "Other, net" on our Consolidated Statements of Income and Comprehensive Income.

Asset Retirement Obligations

We record liabilities for obligations related to the retirement and removal of long-lived assets used in our businesses. We record, as liabilities, the fair value of asset retirement obligations on a discounted basis when they are incurred and can be reasonably estimated, which is typically at the time the assets are installed or acquired. Amounts recorded for the related assets are increased by the amount of these obligations. Over time, the liabilities increase due to the change in their present value, and the initial capitalized costs are depreciated over the useful lives of the related assets. The liabilities are eventually extinguished when the asset is taken out of service.

We are required to operate and maintain our natural gas pipelines and storage systems, and intend to do so as long as supply and demand for natural gas exists, which we expect for the foreseeable future. Therefore, we believe that we cannot reasonably estimate the asset retirement obligation for the substantial majority of our natural gas pipeline system assets because these assets have indeterminate lives.

We continue to evaluate our asset retirement obligations and future developments could impact the amounts we record. Our asset retirement obligations were not significant as of December 31, ~~2012~~2013 and ~~2011~~2012.

Asset and Investment ~~Divestitures/~~Impairments

We evaluate our 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, which is a determination that involves judgment, 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.

Equity Method of Accounting

We account for investments, which we do not control but do have the ability to exercise significant influence, by the equity method of accounting. Under this method, our equity investments are carried originally at our acquisition costs, increased by our proportionate share of the investee's net income and by contributions made, and decreased by our proportionate share of the investee's net losses and by distributions received. ~~We have a 50% equity method investment in WYCO.~~

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Revenue Recognition

Our revenues are primarily generated from natural gas transportation, storage and processing services and include estimates of amounts earned but unbilled. We estimate these unbilled revenues based on contract data, regulatory information, and preliminary throughput and allocation measurements, among other items. 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 services and storage services, we recognize reservation revenues on firm contracted capacity ratably over the contract period regardless of the amount of natural gas that is transported or stored. For interruptible or volumetric-based services, 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. Gas not used in operations is based on the volumes we are allowed to retain relative to the amounts of gas we use for operating purposes. 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. We~~ had no reserves for potential refunds atas of December 31, 2013 and 2012.

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Environmental Matters

We expense or capitalize, as appropriate, environmental expenditures that relate to current operations. We expense expenditures that relate to an existing condition caused by past operations, which do not contribute to current or future revenue generation. We generally do not discount environmental liabilities to a net present value, and we record environmental liabilities when environmental assessments and/or remedial efforts are probable and we can reasonably estimate the costs. Generally, our recording of these accruals coincides with our completion of a feasibility study or our commitment to a formal plan of action. We recognize receivables for anticipated associated insurance recoveries when such recoveries are deemed to be probable.

We routinely conduct reviews of potential environmental issues and claims that could impact our assets or operations. These reviews assist us in identifying environmental issues and estimating the costs and timing of remediation efforts. We also routinely adjust our environmental liabilities to reflect changes in previous estimates. In making environmental liability estimations, we consider the material effect of environmental compliance, pending legal actions against us and potential third-party liability claims. Often, as the remediation evaluation and effort progresses, additional information is obtained, requiring revisions to estimated costs. These revisions are reflected in our income in the period in which they are reasonably determinable. For more information on our environmental disclosures, see Note 87.

Legal

We are subject to litigation and regulatory proceedings as the result of our business operations and transactions. We utilize both internal and external counsel in evaluating our potential exposure to adverse outcomes from orders, judgments or settlements. When we ~~identify~~determine ~~specific~~a ~~litigation~~loss ~~that~~is probable of occurring and is ~~expected~~reasonably toestimable, ~~continue~~we accrue an undiscounted liability for asuch ~~significant~~litigation ~~period~~based ofon ~~time,~~our isbest ~~reasonably~~estimate ~~possible~~using toinformation ~~occur~~available ~~and~~at ~~may~~that ~~require~~time. If ~~substantial~~the ~~expenditures,~~estimated weloss ~~identify~~is a range of ~~possible~~potential ~~costs~~outcomes ~~expected~~and tothere beis ~~required~~no tobetter ~~litigate~~estimate within the ~~matter~~range, towe aaccrue ~~conclusion~~the oramount ~~reach~~at anthe ~~acceptable~~low ~~settlement,~~end ~~and~~of wethe ~~accrue for such amounts~~range. To the extent that actual outcomes differ from our estimates, or additional facts and circumstances cause us to revise our estimates, our earnings will be affected. ~~In general, we expense legal costs as incurred and all recorded legal liabilities are revised as better information becomes available.~~ For more information on our legal disclosures, see Note 87.

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 aan undiscounted 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.

Postretirement Benefits

We maintain a postretirement benefit plan covering certain of our former employees. The plan requires us to make contributions to fund the benefits to be paid out under the plan. These contributions are invested until the benefits are paid out to plan participants. The net benefit cost of this plan is recorded in our Consolidated Statements of Income and Comprehensive Income 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. For a further discussion of our policies with respect to our postretirement benefit plan, see Note 65.

33In accounting for our postretirement benefit plan, we record an asset or liability based on the difference between the fair value of the plan's assets and the plan's benefit obligation. Any deferred amounts related to unrecognized gains and losses or changes in actuarial assumptions are recorded as "Other comprehensive income," until those gains or losses are recognized on the Consolidated Statements of Income and Comprehensive Income.

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In accounting for our postretirement benefit plans, we record an asset or liability based on the overfunded or underfunded status. Any deferred amounts related to unrecognized gains and losses or changes in actuarial assumptions are recorded as "Other comprehensive income," until those gains or losses are recognized on the Consolidated Statements of Income and Comprehensive Income.

Income Taxes

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

Regulated Operations

Our interstate natural gas pipeline and storage operations are subject to the jurisdiction of the FERC and follow the FASB’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 apply regulatory accounting requirements include certain postretirement benefit plan costs, losses 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 non-taxable entity, and certain costs related to gas not used in operations and other costs included in, or expected to be included in, future rates.

3. 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 on our Consolidated Statements of Income and Comprehensive Income 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 on our Consolidated Statements of Income and Comprehensive Income of approximately $21 million to write down the net property, plant and equipment associated with the sale since it was 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.

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4.Regulated ~~Property, Plant and Equipment~~Operations

3. Property, Plant and Equipment

Classes of Assets and Depreciation Rates

As of December 31, ~~2012~~2013 and ~~2011~~2012, our property plant and equipment consisted of the following (in millions, except for %):

	Depreciation Rates	December 31.
	Annual Depreciation Rates	December 31.
	(%)	~~2012~~2013			~~2011~~2012
Transmission and storage facilities	1.85 - 6.67	$	1,~~778~~789		$	1,~~761~~778
Products extraction	1.85	2829			28
General plant	3.0 - 25.0	3937			4039
Intangible plant	10.0 - 23.0	2220			22
Other		3128			31
Accumulated depreciation and amortization(1)		(530		)	(496		)
Accumulated depreciation and amortization (a)		(563		)	(530		)
		1,368			1,386
		1,340			1,368
Land		6			6
Construction work in progress		1121			1611
Property, plant and equipment, net		$	1,~~385~~367		$	1,~~408~~385

~~_______________~~__________

(1a) The composite weighted average depreciation rates for the years ended December 31, ~~2012~~2013, ~~2011~~2012 and ~~2010~~2011 were 2.3932%, 2.5239% and 2.4752%, respectively.

Capitalized Costs During Construction

The allowance for debt interest amounts capitalized during each of the years ended December 31, ~~2012~~2013, ~~2011~~2012 and ~~2010~~2011 were less than $1 million~~, $1 million and $2 million, respectively~~. The allowance for equity amounts capitalized during each of the years ended December 31, ~~2012,~~2013 ~~2011~~ and ~~2010~~2012 were less than $1 million, respectively, and $1 million ~~and~~during $6the ~~million~~year ended December 31, ~~respectively~~2011.

5. Debt

We classify our debt based on the contractual maturity dates of the underlying debt instruments. We defer costs associated with debt issuance over the applicable term. These costs are then amortized as interest expense in our Consolidated Statements of Income and Comprehensive Income. The following table summarizes the net carrying value of our outstanding debt (in millions):

	December 31,
	2012		2011
Senior Notes, 5.95%, due 2015	$	35	$	35
Senior Notes, 6.80%, due 2015	340		340
Senior Debentures, 6.85%, due 2037	100		100
Other financing obligations	172		177
	647		652
Less: Current maturities	5		5
Total long-term debt and other financing obligations, less current maturities	$	642	$	647

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~~Debt~~4. ~~Maturities~~Debt

~~The~~We ~~scheduled~~classify ~~maturities~~our debt based on the contractual maturity dates of ~~our~~the ~~outstanding~~underlying debt asinstruments. We ofdefer ~~December~~costs ~~31,~~associated ~~2012~~with debt issuance over the applicable term. These costs are ~~summarized~~then amortized as ~~follows~~interest expense in our Consolidated Statements of Income and Comprehensive Income. The following table summarizes the net carrying value of our outstanding debt (in millions):

Year		Commitment
	December 31,
~~2013~~	2013	$	5	2012
2014		5
Senior Notes, 5.95%, due 2015	$	35		$	35
2015		380
Senior Notes, 6.80%, due 2015	340			340
2016		5
Senior Debentures, 6.85%, due 2037	100			100
2017		5
Other financing obligations	169			172
Thereafter		247
Total debt and other financing obligations	644			647
Total long-term debt and other financing obligations		$	647
Less: Current portion of debt	5			5
Total debt and other financing obligations, less current maturities	$	639		$	642

Debt Covenants

Under our various financing documents, we are subject to a number of restrictions and covenants. The most restrictive of these include limitations on the incurrence of liens and limitations on sale-leaseback transactions. For the years ended December 31, ~~2012~~2013 and ~~2011~~2012, we were in compliance with our debt-related covenants.

Other Financing Obligations

In conjunction with the construction of Totem and High Plains, our joint venture partner in WYCO funded 50% of the construction costs. We reflected the payments made by our joint venture partner as other long-term liabilities on our balance sheet during construction and, upon project completion, the advances were converted into a financing obligation to WYCO. Upon placing these projects in service, we transferred our title in the projects to WYCO and leased the assets back. Although we transferred the title in these projects to WYCO, the transfer did not qualify for sale leaseback accounting because of our continuing involvement through our equity investment in WYCO. As such, the costs of the facilities remain on our balance sheets and the advanced payments received from our 50% joint venture partner were converted into a financing obligation due to WYCO.

As of December 31, ~~2012~~2013, the principal amounts of ~~our~~the ~~obligations related to~~ Totem and High Plains financing obligations were $75 million and $9794 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. The ~~annual~~effective interest rate on these obligations is 15.5%, payable on a monthly basis.

6.Maturities ~~Retirement~~of ~~Benefits~~Debt

~~Pension~~The ~~and~~scheduled ~~Retirement~~maturities ~~Savings~~of ~~Plans~~our outstanding debt as of December 31, 2013 are summarized as follows (in millions):

KMI maintains a pension plan and a retirement savings plan covering substantially all of its United States employees, including our former employees. The benefits under the pension plan are determined under a cash balance formula. Under its retirement savings plan, KMI contributes an amount equal to 5% of participants' eligible compensation per year. KMI is responsible for benefits accrued under its plans and allocates the related costs to its affiliates.



Year	Commitment
2014	$	5
2015	380
2016	5
2017	5
2018	5
Thereafter	244
Total debt and other financing obligations	$	644

Postretirement Benefits Plan

We provide postretirement medical benefits for a closed group of retirees. These benefits may be subject to deductibles, co-payment provisions, and other limitations and dollar caps on the amount of employer costs and are subject to further benefit changes by KMI, the plan sponsor. 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 2013, and there were no contributions made in 2012, 2011 and 2010.

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5. Retirement Benefits

Pension and Retirement Savings Plans

KMI maintains a pension plan and a retirement savings plan covering substantially all of its U.S. employees, including our former employees. The benefits under the pension plan are determined under a cash balance formula. Under its retirement savings plan, KMI contributes an amount equal to 5% of participants' eligible compensation per year. KMI is responsible for benefits accrued under its plans and allocates the related costs based on a benefit allocation rate applied on payroll charged to its affiliates.

Postretirement Benefits Plan

We provide postretirement medical benefits for a closed group of retirees. These benefits may be subject to deductibles, co-payment provisions, and other limitations and dollar caps on the amount of employer costs and are subject to further benefit changes by KMI, the plan sponsor. 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 2014, and there were no contributions made in 2013, 2012 and 2011.

Accumulated Postretirement Benefit Obligation, Plan Assets and Funded Status

In accounting for our postretirement benefit plan, we record an asset or liability based on the overfunded or underfunded 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~~Member's equity," until those gains and losses are recognized in our Consolidated Statements of Income and Comprehensive Income. 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 (in millions).:

	December 31,
	2012			2011
	2013			2012
Change in accumulated postretirement benefit obligation:
Accumulated postretirement benefit obligation — beginning of period	$	43		$	54
Participant contributions	—			—
Benefits paid(1)	(1		)	(1		)
Benefits paid(a)	—			(1		)
Accumulated postretirement benefit obligation — end of period	$	3		$	43
Change in plan assets:
Fair value of plan assets — beginning of period	$	1516		$	15
Actual return on plan assets	21			12
Benefits paid	(1—		)	(1		)
Fair value of plan assets — end of period	$	1617		$	1516
Reconciliation of funded status:
Fair value of plan assets	$	1617		$	1516
Less: accumulated postretirement benefit obligation	3			43
Net asset at December 31(2)	$	13		$	11
Net asset at December 31(b)	$	14		$	13

~~_____________~~__________

(1a) Amounts shown net of a subsidy of less than $1 million for each of the years ended December 31, ~~2012~~2013 and ~~2011~~2012 related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.

(2b) Net asset amounts are included in "~~Other"~~Deferred ~~noncurrent~~charges and other assets" in our Consolidated Balance Sheets.

Components of Accumulated Other Comprehensive Income

The amount recognized in "Accumulated other comprehensive income" as of December 31, ~~2012~~2013 and ~~2011of~~2012 of $10 million ~~and~~for $9each ~~million,~~period ~~respectively,~~ is primarily related to unrecognized gains. We anticipate that approximately $1 million of "Accumulated other comprehensive income" will be recognized as part of net periodic benefit income in ~~2013~~2014.

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% equity and 35% 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.

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WePlan ~~use~~Assets various methods to determine the fair values of the assets in our 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 market data and the significance of non-observable data used to determine the fair value of these assets. As of December 31, 2012, assets were comprised of an exchange-traded mutual fund with a fair value of approximately $1 million and common/collective trust funds with a fair value of approximately $15 million. As of December 31, 2011, assets were comprised of an exchange-traded mutual fund with a fair value of approximately $1 million and common/collective trust funds with a fair value of approximately $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% equity and 35% 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. There have been no changes in the methodologies used at December 31, 2012 and 2011.

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 the targeted allocations, the target allocations of our postretirement plan’s assets are 70% equity and 30% fixed income securities.

We use various methods to determine the fair values of the assets in our 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 market data and the significance of non-observable data used to determine the fair value of these assets. As of December 31, 2013, assets were comprised of a fixed income mutual fund with a fair value of $5 million and limited partnership funds with equity strategies with a fair value of $12 million. For the mutual fund and $6 million of the limited partnership funds, the fair value (which is considered a Level 1 measurement) is determined based on the price quoted for the investment in actively traded markets. Approximately $6 million of the limited partnership balance is comprised of a limited partnership fund for which the fair value (which is considered a Level 2 measurement) is determined primarily based on the net asset value reported by the issuer, which is based on similar assets in active markets. As of December 31, 2012, assets were comprised of a mutual fund with a fair value of approximately $1 million and common/collective trust funds with a fair value of approximately $15 million. The 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. The common/collective trust funds are invested in approximately 65% equity and 35% 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 the limited partnerships and 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. The plan does 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. There have been no changes in the methodologies used at December 31, 2013 and 2012.

Expected Payment of Future Benefits

As of December 31, ~~2012~~2013, we expect the future benefit payments under our plan to be less than $1 million for each of the years ending December 31, ~~2013~~2014 through December 31, ~~2017~~2018 and $1 million for years ending December 31, ~~2018~~2019 through December 31, ~~2022~~2023. ~~The expected subsidy related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003 for years 2013 through 2022 is insignificant.~~

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.

	2012	2011	2010
	2013	2012	2011
	(%)
Assumptions related to benefit obligations at December 31:
Discount rate	24.7513	42.1375	4.5213
Assumptions related to benefit costs for the year ended December 31:
Discount rate(1)(2)	3.98	4.52	5.06
Discount rate(a)(b)	3.21	3.98	4.52
Expected return on plan assets(3)	7.50	7.75	7.75
Expected return on plan assets(c)	7.50	7.50	7.75

______________

(1a) 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.

(2b) The discount rates related to benefit costs were 4.13% for the period from January 1, 2012 to May 24, 2012 and 3.88% for the period from May 25, 2012 to December 31, 2012.

(3c) 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 with a weighted average rate of 2224% for ~~2012~~2013 and a rate of 3522% for ~~2011~~2012 and ~~2010~~35% for 2011.

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%, gradually decreasing to 5% 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, 2012 and 2011.

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Components of Net Benefit Income

For each of the years ended December 31, the components of net benefit cost (income) are as follows (in millions):

	2012			2011			2010
	2013			2012			2011
Interest cost	$	—		$	—		$	—
Expected return on plan assets	(12		)	(1		)	(1		)
Net benefit (income) expense	$	(1	)	$	(1	)	$	(1	)
Net benefit income	$	(2	)	$	(1	)	$	(1	)

76. Related Party Transactions

Distributions and Contributions

WePursuant to our limited liability company agreement, we are required to make distributions to our owners ~~as defined in our limited liability company agreement~~ on a quarterly basis. During ~~2012~~2013, ~~2011~~2012 and ~~2010~~2011, we paid cash distributions of approximately $~~161~~198 million, $~~155~~161 million and $~~170~~155 million, respectively. During 2012 and 2011, we received cash contributions of approximately $13 million and $42 million, respectively, from our owners to fund our expansion projects.

Affiliate Balances

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. Employees of KMI and its affiliates provide services to us. We are managed and operated by ~~officers of~~ KMI and its affiliates. Under an omnibus agreement with El Paso and other policies with KMI and its affiliates, we reimburse KMI and its affiliates without a profit component for the provision of various general and administrative services for our benefit and for direct expenses incurred by KMI or its affiliates on our behalf. KMI bills us directly for certain general and administrative costs and allocates a portion of its general and administrative costs without a profit component to us. Prior to KMI's May 25, 2012 acquisition of El Paso Holdco, LLC, we were 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 allocated 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 were 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 summarizes our balance sheet affiliate balances (in millions):

	December 31,
	2012		2011
Accounts receivable	$	2	$	2
Accounts payable	4		19
Notes receivable (1)	36		67
Contractual deposits	—		7
Financing obligations (2)	172		177

____________

(1) 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. The interest rate on this note is variable and was 2.2% and 2.3% at December 31, 2012 and 2011, respectively.

(2) We have financing obligations payable to WYCO related to Totem and High Plains. See Note 5 for a further discussion of these obligations.

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The following table ~~shows~~summarizes ~~revenues, expenses and reimbursements from~~ our ~~affiliates~~balance ~~for~~sheet ~~each~~affiliate ofbalances ~~the three years ended December 31, 2012, 2011 and 2010~~ (in millions).:

	2012		2011		2010
	December 31,
Revenues	$	5	$	12	$	12
	2013		2012
Operation and maintenance expenses (1)	86		97		86
Accounts receivable	$	—	$	1
Reimbursements of operating expenses	8		9		11
Natural gas imbalance receivable	3		1
Accounts payable	6		4
Natural gas imbalance payable(a)	2		—
Note receivable (b)	33		36
Financing obligations (c)	169		172

~~___________~~____________

(1a) ~~The~~ ~~year~~Included ~~ended~~in ~~December~~"Other ~~31,~~current ~~2012~~liabilities" ~~includes~~on ~~severance~~our ~~costs~~Consolidated ofBalance ~~$10 million allocated to us from El Paso as a result of KMI's acquisition of El Paso~~Sheets.

8(b) 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. ~~Litigation~~EPB uses the cash management program to settle intercompany transactions between participating affiliates. The interest rate on this note is variable and was 1.9% and 2.0% as of December 31, ~~Environmental~~2013 and ~~Other~~2012, ~~Contingencies~~respectively. These amounts are included in "Note receivable from affiliate" on our Consolidated Balance Sheets.

~~Legal~~(c) ~~Proceedings~~Represents financing obligations payable to WYCO related to Totem and High Plains, of which $5 million is included in "Current portion of debt" on our Consolidated Balance Sheets for each period. See Note 4 for a further discussion of these obligations.

WeThe ~~and~~following ~~our~~table ~~affiliates~~shows ~~are~~revenues, ~~named~~expenses ~~defendants in numerous legal proceedings~~ and ~~claims~~reimbursements ~~that~~from ~~arise in the ordinary course of~~ our ~~business.~~affiliates ~~For~~for each of ~~these matters, we evaluate~~ the ~~merits~~three ofyears ~~the~~ended 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, ~~2012. It is possible~~2013, ~~however,~~2012 ~~that new information or future developments could require us to reassess our potential exposure related to these matters~~ and ~~establish~~2011 ~~accruals~~(in ~~accordingly, and these adjustments could be material.~~millions):

__________


(a)	The year ended December 31, 2012 includes severance costs of $10 million allocated to us from El Paso as a result of KMI's acquisition of El Paso.

7. Litigation, Environmental and Other Contingencies

We are party to various legal, regulatory and other matters arising from the day-to-day operations of our business that may result in claims against us. Although no assurance can be given, we believe, based on our experiences to date and taking into account established reserves, that the ultimate resolution of such items will not have a material adverse impact on our business, financial position, results of operations or cash flows. We believe we have meritorious defenses to the matters to which we are a party and intend to vigorously defend these matters. When we determine a loss is probable of occurring and is reasonably estimable, we accrue an undiscounted liability for such contingencies based on our best estimate using information available at that time. If the estimated loss is a range of potential outcomes and there is no better estimate within the range, we accrue the amount at the low end of the range. We disclose contingencies where an adverse outcome may be material, or in the judgment of management, we conclude the matter should otherwise be disclosed. We had no accruals for any outstanding legal proceedings as of December 31, 2013 and 2012.

Environmental Matters

We are subject to environmental cleanup and enforcement actions from time to time. Our operations are subject to federal, state and local laws and regulations ~~governing~~relating ~~environmental~~to ~~quality~~protection ~~and~~of ~~pollution~~the ~~control~~environment. Although ~~These~~we ~~laws~~believe ~~and~~our ~~regulations~~operations ~~require~~are usin tosubstantial ~~remove~~compliance orwith ~~remedy~~applicable ~~the~~environmental ~~effect~~law ofand ~~the~~regulations, ~~disposal~~risks ~~or release~~ of ~~specified~~additional ~~substances~~costs ~~at current~~ and ~~former~~liabilities ~~operating~~are ~~sites.~~inherent Atin ~~December 31~~our operations, ~~2012~~ and ~~2011,~~there ~~our~~can ~~accrual~~be ~~was~~no ~~approximately~~assurance $3that ~~million~~we ~~and~~will ~~$10~~not ~~million,~~incur ~~respectively,~~significant ~~for~~costs ~~environmental~~and ~~matters~~liabilities. ~~Our~~Moreover, ~~accrual~~it ~~includes~~is ~~amounts~~possible ~~for~~that ~~expected~~other ~~remediation~~developments, ~~costs~~such ~~and~~as ~~associated~~increasingly ~~onsite~~stringent environmental laws, ~~offsite~~regulations and ~~groundwater~~enforcement ~~technical~~policies ~~studies~~under ~~and~~the ~~for~~terms ~~related~~of ~~environmental~~authority ~~legal~~of ~~costs.~~those ~~At December 31~~laws, ~~2012~~ and ~~2011~~claims ~~our~~for ~~accrual~~damages ~~includes~~to $1property ~~million~~or ~~and~~persons $6resulting ~~million,~~from ~~respectively~~operations, ~~for~~could ~~environmental~~result ~~contingencies~~in ~~related~~substantial tocosts ~~properties~~and weliabilities ~~previously~~to ~~owned~~us.

For 2013, we estimate that our total remediation expenditures will be approximately $1 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 $4 million in the aggregate for 2013 through 2017, including capital expenditures associated with the impact of the United States 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.

Our recorded environmental liabilities reflect our current estimates of amounts we will expend on remediation projects in various stages of completion. 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.

Clean Air Act Emission Regulation

On April 17, 2012, the United States EPA issued regulations pursuant to the federal Clean Air Act to reduce various air pollutants from the oil and natural gas industry. These regulations will limit emissions from certain equipment including compressors, storage vessels and natural gas processing plants. Based on our evaluation of the regulations and their impact on our operations and our financial results, we do not anticipate a material impact on our operations or financial results.

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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.General

Although it is not possible to predict the ultimate outcomes, we believe that the resolution of the environmental matters, and other matters to which we are a party, will not have a material adverse effect on our business, financial position, results of operations or cash flows. As of December 31, 2013 and 2012, we had approximately $2 million and $3 million, respectively, accrued for our environmental matters.

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.

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~~Currently, our obligations under these easements are not material to our results of operations.

Transportation and Storage Commitments

We have entered into transportation commitments and storage capacity contracts totaling approximately $~~145~~115 million at December 31, ~~2012~~2013, of which $8679 million is related to storage capacity contracts with our affiliate, Young Gas Storage Company, Ltd. and $4535 million is related to transportation commitments with our affiliate, WIC. Our annual commitments under these agreements are $2116 million in ~~2013~~2014, $1612 million in ~~2014~~2015, $1412 million in ~~2015~~2016, $1411 million in ~~2016~~2017, $1311 million in ~~2017~~2018, and $6753 million in total thereafter.

Operating Leases

We lease property, facilities and equipment under various operating leases. Our minimum future annual rental commitments under our operating leases at December 31, ~~2012~~2013, were as follows (in millions):

Year Ending December 31,
2014	$	2
2013	$	2
2015	2
2014	2
2016	2
2015	1
2017	2
Thereafter	—
2018	2
Total minimum lease payments	$	5
Thereafter	38
Total minimum lease payments	$	48

Rental expense on our lease obligations for the years ended December 31, ~~2012~~2013, ~~2011~~2012, and ~~2010~~2011 was $31 million, $3 million and $23 million, respectively, and is reflected in "Operation and maintenance" expense on our Consolidated Statements of Income and Comprehensive Income. While we hold the contractual obligations for the operating leases, the rent expense, which is considered a shared services cost and allocated to various KMI subsidiaries, is administered and funded by our parent, KMI. Our share of the rent expense is approximately six percent of the total KMI obligation.

9. Fair Value

The following table reflects the carrying amount and estimated fair values of our financial instruments (in millions):

	As of December 31,
	2012				2011
	CarryingAmount		FairValue		CarryingAmount		FairValue
Long-term debt and other financing obligations, including current maturities	$	647	$	733	$	652	$	702

As of December 31, 2012 and 2011, the carrying amounts of cash and cash equivalents, accounts receivable and accounts payable represent fair values based on the short-term nature of these instruments. The carrying amount of our affiliate note receivable approximates its fair value due to the note being due on demand and the market-based nature of the interest rate.

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~~At December 31, 2012 and 2011, our financial instruments measured at fair value consist of our long-term debt and other financing obligations~~8. We ~~separate~~Fair the fair values of our financial instruments into levels based on our assessment of the availability of observable market data and the significance of non-observable data used to determine the estimated fair value. We estimate the fair values of our long-term debt and other financing obligations primarily based on quoted market prices for the same or similar issues, a Level 2 fair value measurement. Our assessment and classification of an instrument within a level can change over time based on the maturity or liquidity of the instrument and this change would be reflected at the end of the period in which the change occurs. During the years ended December 31, 2012 and 2011, there were no changes to the inputs and valuation techniques used to measure fair value, the types of instruments or the levels in which they are classified.Value

The following table reflects the carrying amount and estimated fair values of our debt, excluding total other financing obligations (in millions):



	As of December 31,
	2013				2012
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
Total debt, excluding total other financing obligations (a)	$	475	$	532	$	475	$	561

————————


(a)	Our other financing obligations were $169 million and $172 million as of December 31, 2013 and 2012, of which $5 million was reported as "Current portion of debt" on our Consolidated Balance Sheets for each period.

We separate the fair values of our financial instruments into levels based on our assessment of the availability of observable market data and the significance of non-observable data used to determine the estimated fair value. We estimated the above fair values of debt, excluding total other financing obligations, primarily based on quoted market prices for the same or similar issues, a Level 2 fair value measurement. Our assessment and classification of an instrument within a level can change over time based on the maturity or liquidity of the instrument and this change would be reflected at the end of the period in which the change occurs. During the years ended December 31, 2013 and 2012, there were no changes to the inputs and valuation techniques used to measure fair value of these instruments or the levels in which they were classified.

As of December 31, 2013 and 2012, the carrying amounts of cash and cash equivalents, accounts receivable and accounts payable represent fair values based on the short-term nature of these items. The carrying amount of our affiliate note receivable approximates its fair value due to the note being due on demand and the market-based nature of the interest rate.

9. Accounting for Regulatory Activities

Regulatory assets and liabilities represent probable future revenues or expenses associated with certain charges and credits that will be recovered from or refunded to customers through the ratemaking process. As of December 31, 2013, the regulatory assets are being recovered as cost of service in our rates over a period of approximately 1 year to 27 years. Below are the details of our regulatory assets and liabilities as of December 31 (in millions):



	2013		2012
Current regulatory assets
Difference between gas retained and gas consumed in operations	$	—	$	4
Other	9		2
Total current regulatory assets	9		6
Non-current regulatory assets
Taxes on capitalized funds used during construction	10		10
Unamortized loss on reacquired debt	1		3
Other	1		1
Total non-current regulatory assets(a)	12		14
Total regulatory assets	$	21	$	20
Current regulatory liabilities
Difference between gas retained and gas consumed in operations	$	1	$	8
Other	1		1
Total current regulatory liabilities	2		9
Non-current regulatory liabilities
Property and plant retirements	9		9
Postretirement benefits	1		1
Total non-current regulatory liabilities(b)	10		10
Total regulatory liabilities	$	12	$	19

————————


(a)	Included in "Deferred charges and other assets" on our Consolidated Balance Sheets.


(b)	Included in "Other long-term liabilities and deferred credits" on our Consolidated Balance Sheets.

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10. 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 as of December 31 (in millions):

	2012		2011
Current regulatory assets
Difference between gas retained and gas consumed in operations	$	4	$	—
Other	2		3
Total current regulatory assets	6		3
Non-current regulatory assets
Taxes on capitalized funds used during construction	10		10
Unamortized loss on reacquired debt	3		4
Other	1		1
Total non-current regulatory assets(1)	14		15
Total regulatory assets	$	20	$	18
Current regulatory liabilities
Difference between gas retained and gas consumed in operations	$	8	$	8
Other	1		1
Total current regulatory liabilities	9		9
Non-current regulatory liabilities
Property and plant retirements	9		9
Postretirement benefits	1		1
Total non-current regulatory liabilities(1)	10		10
Total regulatory liabilities	$	19	$	19

_____________

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

Substantially all of our regulatory assets as of December 31, 2012 are being recovered as cost of service in our rates. These assets are expected to be recovered in rates over a period of approximately 1 year to 28 years.

Our 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~~Amounts represent 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~~Amounts ~~represents~~represent 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.

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Postretirement benefits

~~Represents~~Amounts represent the differences in postretirement benefit amounts expensed and the amounts previously recovered in rates, prior to our rate case settlement in ~~September~~August 2011. 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 retirements

Amounts represent the deferral of customer-funded amounts for costs of future asset retirements.

~~11.~~Rates ~~Transactions~~and ~~with~~Regulatory ~~Major Customers~~Matter

~~Our~~In ~~non~~August 2011, the FERC approved an uncontested pre-~~affiliate~~filing ~~trade~~settlement ~~accounts~~of ~~receivable~~a asrate case required under the terms of ~~December~~a ~~31,~~previous ~~2012~~settlement. The ~~and~~settlement ~~2011~~generally ~~was~~provides ~~$37~~for ~~million~~(i) ~~and~~our $current tariff rates to continue until our next general rate case which will be effective no earlier than October 1, ~~million~~2014 but no later than October 1, ~~respectively. Our~~2016, ~~other~~(ii) ~~non-affiliate~~contract ~~accounts~~extensions ~~receivable~~to asMarch 2016, (iii) a revenue sharing mechanism with certain of ~~December~~our ~~31,~~customers ~~2012~~for ~~and~~certain ~~2011~~revenues ~~was~~above $1annual ~~million~~threshold amounts and ~~$14~~(iv) ~~million,~~a ~~respectively. Our~~revenue ~~affiliate~~surcharge ~~receivables~~mechanism ~~are~~with ~~discussed~~certain inof ~~Note~~our 7customers to charge for certain shortfalls of revenue less than an annual threshold amount.

10. Transactions with Major Customers

Our non-affiliate trade accounts receivable as of December 31, 2013 and 2012 was $35 million and $37 million, respectively. Our affiliate receivables are discussed in Note 6.

The following table shows customers with revenues greater than 10% of our operating revenues, which we refer to as major customers, for each of the three years ended December 31 (in millions):

	2012		2011		2010
	2013		2012		2011
PSCo and subsidiary	$	~~168~~169	$	~~169~~168	$	~~168~~169
Pioneer Natural Resources USA, Inc.	40		4640		*46

~~_____________~~At December 31, 2013, we have transportation and storage agreements with PSCo for capacity on High Plains through 2029 and Totem through 2040 each with annual firm revenue of $39 million.

* Less than 10% of operating revenues43

AtTable ~~December 31, 2012, we have transportation and storage agreements with PSCo for capacity on High Plains through 2029 and Totem through 2040 each with annual firm revenue~~ of ~~$39 million.~~Contents

1211. Accounts Receivable Sales Program

We participated in an accounts receivable sales program where we sold receivables in their entirety to a third party financial institution (through a wholly-owned special purpose entity). On June 20, 2012, we terminated the accounts receivable sales program and paid $19 million to the third party financial institution, which consisted of sales proceeds received up front and servicing fees. The sale of these accounts receivable (which were short-term assets that generally settled within 60 days) qualified for sale accounting. The third party financial institution involved in our accounts receivable sales program acquired interests in various financial assets and issued commercial paper to fund those acquisitions. We did not consolidate the third party financial institution because we did not have the power to control, direct, or exert significant influence over its overall activities since our receivables did not comprise a significant portion of its operations.

In connection with our accounts receivable sales, we received a portion of the sales proceeds up front and received an additional amount upon the collection of the underlying receivables, (which we referred to as a deferred purchase price). ~~Our~~During ~~ability~~2012, towe ~~recover~~sold $168 million of accounts receivable to the third-party financial institution, for which we received $102 million of cash up front and had a deferred purchase price ~~was~~of ~~based~~$66 ~~solely~~million. We onreceived ~~the~~$68 ~~collection~~million of cash when the underlying receivables were collected during 2012. Losses ~~The~~recognized ~~tables~~on ~~below~~the ~~contain~~sale ~~information~~of ~~related~~accounts toreceivable ~~our~~were immaterial for the years ended December 31, 2012 and 2011. There were no deferred purchases as of December 31, 2012 since all the balances were settled in June 2012 when the accounts receivable sales program ~~(in~~were ~~millions)~~terminated.

	Year Ended December 31,
	2012		2011
Accounts receivable sold to the third-party financial institution(1)	$	168	$	415
Cash received for accounts receivable sold under the program	102		235
Deferred purchase price related to accounts receivable sold	66		180
Cash received related to the deferred purchase price	68		181

The deferred purchase price related to the accounts receivable sold was reflected as "Accounts receivable, net" on our Consolidated Balance Sheets. Because the cash received up front and the deferred purchase price related to the sale or ultimate collection of the underlying receivables, and were not subject to significant other risks given their short term nature, we reflected all cash flows under the accounts receivable sales program as "Cash Provided by Operating Activities" in our Consolidated Statements of Cash Flows. Under the accounts receivable sales program, we serviced 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, 2012, and 2011.

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(1) During the years ended December 31, 2012, 2011 and 2010 losses recognized on the sale of accounts receivable were immaterial.

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	December 31, 2011
Accounts receivable sold and held by third-party financial institution	$	36
Uncollected deferred purchase price related to accounts receivable sold (2) (3)	14

Supplemental Selected Quarterly Financial Information (Unaudited)

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	Quarters Ended
	March 31		June 30		September 30		December 31
	(In millions)
2013
Revenues	$	108	$	91	$	88	$	110
Operating income	66		50		48		65
Net income	51		34		34		51
2012
Revenues	$	109	$	93	$	89	$	107
Operating income	63		38		49		65
Net income	48		24		34		50

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

(3) There were no balances outstanding as of December 31, 2012 since all balances were settled in June 2012 when the accounts receivable sales program was terminated.

The deferred purchase price related to the accounts receivable sold was reflected as "Accounts and note receivable, net" in our Consolidated Balance Sheet at December 31, 2011. Because the cash received up front and the deferred purchase price related to the sale or ultimate collection of the underlying receivables, and were not subject to significant other risks given their short term nature, we reflected all cash flows under the accounts receivable sales program as "Cash Provided by Operating Activities" in our Consolidated Statements of Cash Flows. Under the accounts receivable sales program, we serviced 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, 2012, 2011 and 2010.

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Supplemental Selected Quarterly Financial Information (Unaudited)

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

	Quarters Ended
	March 31		June 30		September 30		December 31		Total
	(In Millions)
2012
Revenues	$	109	$	93	$	89	$	107	$	398
Operating income	63		38		49		65		215
Net income	48		24		34		50		156
2011
Revenues	$	116	$	100	$	92	$	107	$	415
Operating income	63		44		41		54		202
Net income	48		29		28		39		144

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

COLORADO INTERSTATE GAS COMPANY, L.L.C Registrant (A Delaware limited liability company) By: /s/ ~~KIMBERLY~~DAVID AP. ~~DANG~~MICHELS ~~Kimberly~~David AP. ~~Dang~~Michels Vice President and Chief Financial Officer (principal financial and accounting officer)

Date: ~~March~~February 121, ~~2013~~2014

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

Signature	Title	Date
/s/ KIMBERLY A. DANG	Chief Financial Officer	March 1, 2013
/s/ DAVID P. MICHELS	Vice President and Chief Financial Officer	February 21, 2014
Kimberly A. Dang
David P. Michels	(principal financial and accounting officer)
/s/ C. PARK SHAPER	Director and Chief Executive Officer	March 1, 2013
/s/ MARK A. KISSEL	President	February 21, 2014
C. Park Shaper
Mark A. Kissel	(principal executive officer)
/s/ JOSEPH LISTENGART	Director, Vice President and Secretary	March 1, 2013
/s/ STEVEN J. KEAN	Director and Executive Vice President	February 21, 2014
Joseph Listengart
Steven J. Kean
/s/ DAVID R. DEVEAU	Director and Vice President	February 21, 2014
David R. Deveau

4746

Operating expenses (a)

Reimbursements of operating expenses