UNITED
STATES SECURITIES AND EXCHANGE COMMISSION


Washington, D.C.
20549


____________________




Form 10-K


(Mark One)


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




Commission
File Number 1-4874
 
 Colorado
Interstate Gas Company


(Exact Name of
Registrant as Specified in Its Charter)


Delaware
              84-0173305(State or
      Other Jurisdiction of
              (I.R.S.
      EmployerIncorporation
      or Organization)
              Identification
      No.)El
      Paso Building
              770021001
      Louisiana Street
              (Zip
      Code)Houston,
      Texas(Address of
      Principal Executive Offices)
  Telephone
Number: (713) 420-2600
  Securities
registered pursuant to Section 12(b) of the Act:
  Title of each
      class
              Name of each
      exchange on which registered6.85% Senior
      Debentures, due 2037
              New York Stock
      Exchange
  Securities
registered pursuant to Section 12(g) of the Act: None


Indicate by check mark if the
registrant is a well-known seasoned issuer, as defined in Rule 405 of the
Securities Act. Yes o No þ
  Indicate by check mark if the
registrant is not required to file reports pursuant to Section 13 or Section
15(d) of the Act. Yes o No þ
  Indicate by check
mark whether the registrant (1) has filed all reports required to be filed by
Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding
12 months (or for such shorter period that the registrant was required to file
such reports), and (2) has been subject to such filing requirements for the past
90 days. Yes þNo o
  Indicate by check mark if disclosure
of delinquent filers pursuant to Item 405 of Regulation S-K is not contained
herein, and will not be contained, to the best of registrant’s knowledge, in
definitive proxy or information statements incorporated by reference in Part III
of this Form 10-K or any amendment to this Form 10-K. þ
  Indicate by check
mark whether the registrant is a large accelerated filer, an accelerated filer,
a non-accelerated filer, or a smaller reporting company. See the definitions of
“large accelerated filer,” “accelerated filer” and “smaller reporting company”
in Rule 12b-2 of the Exchange Act. (Check one):
  Large accelerated filer o
              Accelerated filer o
              Non-accelerated filer þ
                (Do not check
      if a smaller reporting company)
              Smaller Reporting Company o
  Indicate by check mark whether the
registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes o No þ
  State
the aggregate market value of the voting stock held by non-affiliates
of the registrant: None
  Documents
Incorporated by Reference: None








COLORADO
INTERSTATE GAS COMPANY




TABLE
OF CONTENTS




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




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




/d
            =
            per
      day
            MDth
            =
            thousand
      dekathermsBBtu
            =
            billion
      British  thermal units
            MMcf
            =
            million cubic
      feetBcf
            =
            billion cubic
      feet
            NGL
            =
            natural gas
      liquidDth
            =
            dekatherm




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




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


i


PART
I




ITEM
1. BUSINESS




Overview
and Strategy




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




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




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




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




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




•
            Successfully
      executing on our backlog of committed expansion
  projects;




•
            Focusing on
      efficiency and synergies across our
system;




•
            Ensuring the
      safety of our pipeline system and
assets;




•
            Successfully
      recontracting expiring transportation capacity;
  and




•
            Providing
      outstanding customer service.




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




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




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


1


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





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


____________








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





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





Markets
and Competition




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




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




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




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




2


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




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




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




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




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




Regulatory
Environment




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




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




•
            certification
      and construction of new facilities;




3


•
            extension or
      abandonment of services and
facilities;




•
            maintenance
      of accounts and records;




•
            relationships
      between pipelines and certain
affiliates;




•
            terms and
      conditions of service;




•
            depreciation
      and amortization policies;




•
            acquisition
      and disposition of facilities; and




•
            initiation
      and discontinuation of services.




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




Environmental




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




Employees




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




4


ITEM
1A. RISK FACTORS




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


THE
PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995




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




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




Risks
Related to Our Business




Our
success depends on factors beyond our control.




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




•
            service area
      competition;




•
            price
      competition;




•
            expiration or
      turn back of significant contracts;




•
            changes in
      regulation and actions of regulatory
bodies;




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




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




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




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




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




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


5


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




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




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




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




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




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




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




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




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




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




•
            legislative
      and/or regulatory actions.




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




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




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




Fluctuations
in energy commodity prices could adversely affect our
business.
  Revenues generated
by our transportation and storage contracts depend on volumes and rates, both of
which can be affected by the price of natural gas. Increased prices could result
in a reduction of the volumes transported by our customers, including power
companies that may not dispatch natural gas-fired power plants if natural gas
prices increase. Increased prices could also result in industrial plant
shutdowns or load losses to competitive fuels as well as local distribution
companies’ loss of customer base. The success of our transmission and storage
operations is subject to continued development of additional gas supplies to
offset the natural decline from existing wells connected to our system, which
requires the development of additional oil and natural gas reserves and
obtaining additional supplies from interconnecting pipelines, primarily in the
U.S. Rocky Mountain region. A decline in energy prices could cause a decrease in
these development activities and could cause a decrease in the volume of
reserves available for transmission and storage through our system. 6




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




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




•
            regional,
      domestic and international supply and
demand;




•
            availability
      and adequacy of transportation
facilities;




•
            energy
      legislation and regulation;




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




•
            abundance of
      supplies of alternative energy sources;
and




•
            political
      unrest among countries producing
oil.




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




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




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




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


7


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




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




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




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




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




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




•
            discovering
      new sites or additional information at existing
  sites;




•
            receiving
      regulatory approval for remediation
programs;




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




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




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




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




8


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




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




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




Our
operations are subject to operational hazards and uninsured
risks.




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




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




9


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




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




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




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




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




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




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




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




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




•
            the lack of
      transportation, storage or throughput
  commitments.




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




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




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




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




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




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


10


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




We
are subject to financing and interest rate risk.




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




•
            our credit
      ratings;


•
              the
      structured and commercial financial
markets;




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




•
            market prices
      for hydrocarbon products.




Risks
Related to Our Affiliation with El Paso and the MLP




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




We
are a majority owned subsidiary of El Paso.




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




•
            decisions on
      our financing and capital raising
activities;




•
            mergers or
      other business combinations;




•
            our
      acquisitions or dispositions of assets;
and




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




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




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




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




11


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




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




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




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




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




ITEM
1B. UNRESOLVED STAFF COMMENTS




We have not
included a response to this item since no response is required under Item 1B of
Form 10-K.




ITEM
2. PROPERTIES




A description of
our properties is included in Item 1, Business, and is incorporated herein by
reference.




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




12


ITEM
3. LEGAL PROCEEDINGS




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




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




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




None.














13


PART
II




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


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




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




ITEM
6. SELECTED FINANCIAL DATA




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




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
















14


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


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




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




Overview




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




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


____________




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




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




15


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




BBtu/d
            
            
            Percent of
      Total
              Contracted
      Capacity
            
            
            Reservation
              Revenue
            
            
            Percent of
      Total
              Reservation
      Revenue(In
      millions)2009
            
            
            95
            
            
            
            2
            
            
            $
            8
            
            
            
            32010
            
            
            329
            
            
            
            8
            
            
            
            13
            
            
            
            42011
            
            
            317
            
            
            
            8
            
            
            
            19
            
            
            
            62012
            
            
            491
            
            
            
            12
            
            
            
            45
            
            
            
            152013
            
            
            1,082
            
            
            
            26
            
            
            
            81
            
            
            
            272014 and
      beyond
            
            
            1,827
            
            
            
            44
            
            
            
            133
            
            
            
            45Total
            
            
            4,141
            
            
            
            100
            
            
            $
            299
            
            
            
            100




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




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




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




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




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


16


Results
of Operations





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





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





EBIT Analysis:





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


____________





(1)
            Consists of
      individually insignificant
items.





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


17


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




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




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




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




Interest
and Debt Expense




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




Affiliated
Interest Income, Net




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




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




Income
Taxes




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




18


Liquidity
and Capital Resources




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




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




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




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




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




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




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




19


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





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


____________





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


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


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




Contractual
Obligations




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




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




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




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




20
 
 Operating
Leases.For a further discussion of these obligations, see Item 8,
Financial Statements and Supplementary Data, Note 7.


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




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




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




Commitments
and Contingencies




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




Off-Balance
Sheet Arrangements




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




Critical
Accounting Policies and Estimates




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




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




21


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




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




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




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




New
Accounting Pronouncements Issued But Not Yet Adopted




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




ITEM
7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
RISK




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




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


December 31,
      2008Expected
      Fiscal Year of Maturity of Carrying
      Amounts
              
              
              
              
              
              
              
              December 31,
      20072009
              
              2010
              
              2011
              
              2012
              
              2013
              
              Thereafter
              
              Total
              
              Fair
      Value
              
              Carrying
      Amount
              
              Fair
      Value(In
      millions, except for rates)Long-term debt and other
      financing obligations(1),
      including current portion — fixedrate.
              
              $
              3
              
              $
              3
              
              $
              3
              
              $
              3
              
              $
              3
              
              $
              568
              
              $
              583
              
              $
              502
              
              $
              575
              
              $
              598Average interest
      rate
              
              
              15.5
              %
              
              15.4
              %
              
              15.0
              %
              
              14.6
              %
              
              14.2
              %
              
              7.3
              %


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


22


ITEM
8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA




MANAGEMENT’S
ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING




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




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




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




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




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


23


Report
of Independent Registered Public Accounting Firm




To The Partners of
Colorado Interstate Gas Company




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




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




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




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






/s/
Ernst & Young LLP




Houston,
Texas


February 26,
2009





24


COLORADO
INTERSTATE GAS COMPANY


CONSOLIDATED
STATEMENTS OF INCOME


(In
millions)





Year Ended December 31,2008
            
            
            2007
            
            
            2006Operating
      revenues
            
            $
            323
            
            
            $
            317
            
            
            $
            305Operating
      expensesOperation and
      maintenance
            
            
            120
            
            
            
            126
            
            
            
            120Depreciation
      and amortization
            
            
            33
            
            
            
            31
            
            
            
            30Taxes, other
      than income taxes
            
            
            17
            
            
            
            15
            
            
            
            12170
            
            
            
            172
            
            
            
            162Operating
      income
            
            
            153
            
            
            
            145
            
            
            
            143Other income,
      net
            
            
            11
            
            
            
            5
            
            
            
            2Interest and
      debt expense
            
            
            (38
            )
            
            
            (49
            )
            
            
            (47
            )Affiliated
      interest income, net
            
            
            23
            
            
            
            50
            
            
            
            41Income before
      income taxes
            
            
            149
            
            
            
            151
            
            
            
            139Income
      taxes
            
            
            —
            
            
            
            44
            
            
            
            52Income from
      continuing operations
            
            
            149
            
            
            
            107
            
            
            
            87Discontinued
      operations, net of income taxes
            
            
            —
            
            
            
            42
            
            
            
            48Net
      income
            
            $
            149
            
            
            $
            149
            
            
            $
            135








See accompanying
notes.





25


COLORADO
INTERSTATE GAS COMPANY


CONSOLIDATED
BALANCE SHEETS


(In
millions)





December 31,2008
            
            
            2007ASSETSCurrent
      assetsCash and cash
      equivalents
            
            $
            —
            
            
            $
            —Accounts and
      notes receivableCustomer
            
            
            8
            
            
            
            —Affiliates
            
            
            119
            
            
            
            181Other
            
            
            1
            
            
            
            1Materials and
      supplies
            
            
            7
            
            
            
            5Regulatory
      assets
            
            
            18
            
            
            
            —Other
            
            
            2
            
            
            
            1Total current
      assets
            
            
            155
            
            
            
            188Property,
      plant and equipment, at cost
            
            
            1,675
            
            
            
            1,413Less
      accumulated depreciation and amortization
            
            
            413
            
            
            
            392Total
      property, plant and equipment, net
            
            
            1,262
            
            
            
            1,021Other
      assetsNotes
      receivable from affiliates
            
            
            76
            
            
            
            503Other
            
            
            50
            
            
            
            57126
            
            
            
            560Total
      assets
            
            $
            1,543
            
            
            $
            1,769LIABILITIES
      AND PARTNERS’ CAPITALCurrent
      liabilitiesAccounts
      payableTrade
            
            $
            11
            
            
            $
            14Affiliates
            
            
            10
            
            
            
            8Other
            
            
            30
            
            
            
            15Taxes
      payable
            
            
            10
            
            
            
            10Regulatory
      liabilities
            
            
            29
            
            
            
            12Accrued
      interest
            
            
            7
            
            
            
            5Contractual
      deposits
            
            
            8
            
            
            
            7Other
            
            
            9
            
            
            
            8Total current
      liabilities
            
            
            114
            
            
            
            79Long-term
      debt and other financing obligations, less current
    maturities
            
            
            580
            
            
            
            575Other
      liabilities
            
            
            66
            
            
            
            72Commitments
      and contingencies (Note 7)Partners’
      capital
            
            
            783
            
            
            
            1,043Total
      liabilities and partners’ capital
            
            $
            1,543
            
            
            $
            1,769




See accompanying
notes.


26


COLORADO
INTERSTATE GAS COMPANY


CONSOLIDATED
STATEMENTS OF CASH FLOWS


(In
millions)




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






See accompanying
notes.


27


COLORADO
INTERSTATE GAS COMPANY


CONSOLIDATED
STATEMENTS OF PARTNERS’ CAPITAL/STOCKHOLDER’S EQUITY


(In
millions, except share amounts)




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








See accompanying
notes.


28


COLORADO
INTERSTATE GAS COMPANY




NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS




1.
Summary of Significant Accounting Policies




Basis
of Presentation and Principles of Consolidation




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




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




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




Use
of Estimates




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




Regulated
Operations




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




Cash
and Cash Equivalents




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




29


Allowance
for Doubtful Accounts




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




Materials
and Supplies




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




Natural
Gas Imbalances




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




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




Property,
Plant and Equipment




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




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




When we retire
property, plant and equipment, we charge accumulated depreciation and
amortization for the original cost of the assets in addition to the cost to
remove, sell or dispose of the assets, less their salvage value. We do not
recognize a gain or loss unless we sell or retire an entire operating unit. We
include gains or losses on dispositions of operating units in operating
income.




At December 31,
2008 and 2007, we had $106 million and $109 million of construction work in
progress included in our property, plant and equipment.




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


30


Asset
and Investment Impairments




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




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




Revenue
Recognition




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




Environmental
Costs and Other Contingencies




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




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




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


31


Income
Taxes




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




Accounting
for Asset Retirement Obligations




We account for our
asset retirement obligations in accordance with SFAS No. 143, Accounting
for Asset Retirement Obligationsand Financial Accounting Standards Board
(FASB) Interpretation (FIN) No. 47,
Accounting for Conditional Asset
Retirement Obligations.We record a liability for legal obligations
associated with the replacement, removal or retirement of our long-lived assets
in the period that obligation is incurred. Our asset retirement liabilities are
recorded at their estimated fair value with a corresponding increase to
property, plant and equipment. This increase in property, plant and equipment is
then depreciated over the useful life of the long-lived asset to which that
liability relates. An ongoing expense is also recognized for changes in the
value of the liability as a result of the passage of time, which we record as
depreciation and amortization expense in our income statement. We have the
ability to recover certain of these costs from our customers and have recorded
an asset (rather than expense) associated with the depreciation of the property,
plant and equipment and accretion of the liabilities described
above.




We have legal
obligations associated with our natural gas pipeline and related transmission
facilities and storage wells. We have obligations to plug storage wells when we
no longer plan to use them and when we abandon them. Our legal obligations
associated with our natural gas transmission facilities relate primarily to
purging and sealing the pipeline if it is abandoned. We also have obligations to
remove hazardous materials associated with our natural gas transmission
facilities if they are replaced. We accrue a liability for legal obligations
based on an estimate of the timing and amount of their settlement.




We are required to
operate and maintain our natural gas pipeline and storage system, and intend to
do so as long as supply and demand for natural gas exists, which we expect for
the foreseeable future. Therefore, we believe that the substantial majority of
our natural gas pipeline and storage system assets have indeterminate lives.
Accordingly, our asset retirement liabilities as of December 31, 2008 and 2007
were not material to our financial statements. We continue to evaluate our asset
retirement obligations and future developments could impact the amounts we
record.




Postretirement
Benefits




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




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


32


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




New
Accounting Pronouncements Issued But Not Yet Adopted




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




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




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




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




2.
Acquisitions and Divestitures




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





33


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




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




3.
Income Taxes




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




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




2007
            
            
            2006(In
      millions)CurrentFederal
            
            $
            33
            
            
            $
            43State
            
            
            3
            
            
            
            536
            
            
            
            48DeferredFederal
            
            
            7
            
            
            
            4State
            
            
            1
            
            
            
            —8
            
            
            
            4Total income
      taxes
            
            $
            44
            
            
            $
            52




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




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




34


4.
Financial Instruments




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




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




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




5.
Regulatory Assets and Liabilities




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




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


35


6.
Long-Term Financing Obligations




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




2008
            
            
            2007(In
      millions)5.95% Senior
      Notes due March 2015
            
            $
            35
            
            
            $
            756.80% Senior
      Notes due November 2015
            
            
            340
            
            
            
            4006.85% Senior
      Debentures due June 2037
            
            
            100
            
            
            
            100Total
      long-term debt
            
            
            475
            
            
            
            575Other
      financing obligations
            
            
            108
            
            
            
            —Total
      long-term debt and other financing obligations
            
            
            583
            
            
            
            575Less: Current
      maturities
            
            
            3
            
            
            
            —Total
      long-term debt and other financing obligations, less current
      maturities
            
            $
            580
            
            
            $
            575




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




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




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




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




7.
Commitments and Contingencies




Legal
Proceedings




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




36


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




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




Environmental
Matters




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




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




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




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




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




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




37


Regulatory
Matters




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




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




Purchase
Obligations, Commitments and Other Matters




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




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




Year
      Ending

              December
      31,
            
            
            (In
      millions)2009
            
            $
            22010
            
            
            1Total
            
            $
            3




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




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




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




38


8.
Retirement Benefits




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




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




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




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




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





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


____________





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





39


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




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




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


Year
      Ending
                December 31,2009
              
              $
              12010
              
              
              12011
              
              
              12012
              
              
              12013
              
              
              12014 -
      2018
              
              
              3


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




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


____________




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


40


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




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




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




9.
Transactions with Major Customer




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




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




10.
Supplemental Cash Flow Information




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




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


____________




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




11.
Investment in Unconsolidated Affiliate and Transactions with
Affiliates




Investment
in Unconsolidated Affiliate




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




Transactions
with Affiliates




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




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


41


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




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




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




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




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




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




42


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




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




12.
Supplemental Selected Quarterly Financial Information (Unaudited)




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




Quarters
      EndedMarch
      31
            
            
            June
      30
            
            
            September
      30
            
            
            December
      31
            
            
            Total(In
      millions)2008Operating
      revenues
            
            $
            90
            
            
            $
            73
            
            
            $
            71
            
            
            $
            89
            
            
            $
            323Operating
      income
            
            
            50
            
            
            
            26
            
            
            
            26
            
            
            
            51
            
            
            
            153Net
      income
            
            
            50
            
            
            
            26
            
            
            
            25
            
            
            
            48
            
            
            
            1492007Operating
      revenues
            
            $
            84
            
            
            $
            75
            
            
            $
            67
            
            
            $
            91
            
            
            $
            317Operating
      income
            
            
            40
            
            
            
            32
            
            
            
            28
            
            
            
            45
            
            
            
            145Income from
      continuing operations
            
            
            25
            
            
            
            21
            
            
            
            20
            
            
            
            41
            
            
            
            107Discontinued
      operations, net of income taxes
            
            
            8
            
            
            
            14
            
            
            
            12
            
            
            
            8
            
            
            
            42Net
      income
            
            
            33
            
            
            
            35
            
            
            
            32
            
            
            
            49
            
            
            
            149


43


SCHEDULE
II




COLORADO
INTERSTATE GAS COMPANY


VALUATION
AND QUALIFYING ACCOUNTS




Years
Ended December 31, 2008, 2007 and 2006


(In
millions)




Description
            
            Balance
      at
              Beginning
              of
      Period
            
            
            Charged
      to
              Costs
      and
              Expenses
            
            
            Deductions(1)
            
            
            Charged
      toOther
              Accounts
            
            
            Balance
              at End
              of
      Period2008Environmental
      reserves
            
            $
            15
            
            
            $
            1
            
            
            $
            (3
            )
            
            $
            —
            
            
            $
            132007Legal
      reserves
            
            $
            —
            
            
            $
            3
            
            
            $
            (3
            )
            
            $
            —
            
            
            $
            —Environmental
      reserves
            
            
            17
            
            
            
            1
            
            
            
            (3
            )
            
            
            —
            
            
            
            152006Allowance for
      doubtful accounts
            
            $
            1
            
            
            $
            —
            
            
            $
            —
            
            
            $
            (1
            )
            
            $
            —Environmental
      reserves
            
            
            23
            
            
            
            2
            
            
            
            (8
            )
            
            
            —
            
            
            
            17


____________




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







































44


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




None.




ITEM
9A. CONTROLS AND PROCEDURES




Evaluation
of Disclosure Controls and Procedures




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




Changes
in Internal Control Over Financial Reporting




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




ITEM
9A(T). CONTROLS AND PROCEDURES




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




ITEM
9B. OTHER INFORMATION




None.




45


PART
III




ITEM
10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT




Management
Committee and Executive Officers




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




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




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




Name
            
            Age
            
            PositionJames J.
      Cleary
            54
            President and
      Management Committee MemberJohn R.
      Sult
            49
            Senior Vice
      President, Chief Financial Officer and ControllerJames C.
      Yardley
            57
            Management
      Committee MemberDaniel B.
      Martin
            52
            Senior Vice
      President and Management Committee MemberThomas L.
      Price
            53
            Vice
      President and Management Committee
Member




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




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





46


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




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




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




Audit
Committee, Compensation Committee and Code of Ethics




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




ITEM
11. EXECUTIVE COMPENSATION




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




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


47


ITEM
12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT




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




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





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


____________





*
            Less
      than 1%.


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


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





ITEM
13. CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS





El Paso Master Limited Partnership
(MLP)





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





Guarantee
of WYCO Purchases of Natural Gas from Anadarko Energy Services





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





CIG Operating
Agreements





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


48


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




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




Transportation
Agreements




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




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




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




Interconnection
and Operational Balancing Agreements and Other Inter-Affiliate
Agreements




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




49


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




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




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




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




Other
Agreements and Transactions




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




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




ITEM
14. PRINCIPAL ACCOUNTANT FEES AND SERVICES




Audit
Fees




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




All
Other Fees




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




Policy
for Approval of Audit and Non-Audit Fees




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


50


PART
IV




ITEM
15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES




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




1. Financial
statements




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




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




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




3.
Exhibits




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




Undertaking




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





51


SIGNATURES




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






COLORADO
      INTERSTATE GAS COMPANYBy:
                /s/James
      J. ClearyJames J.
      ClearyPresident
  Pursuant to the
requirements of the Securities Exchange Act of 1934, this report has been signed
below by the following persons on behalf of Colorado Interstate Gas Company and
in the capacities and on the dates indicated:
 Signature
              
              Title
              
              Date/s/James
      J. Cleary
              
              President and
      Management Committee Member
              
              March 2,
      2009James J.
      Cleary
              
              (Principal
      Executive Officer)/s/John
      R. Sult
              
              Senior Vice
      President, Chief Financial
              
              March 2,
      2009John R.
      Sult
              
              Officer and
      Controller (Principal Accounting and Financial
      Officer)/s/
      James C. Yardley
              
              Management
      Committee Member
              
              March 2,
      2009James. C. Yardley/s/Daniel
      B. Martin
              
              Senior Vice
      President and Management Committee Member
              
              March 2,
      2009Daniel B.
      Martin/s/ Thomas
      L. Price
              
              Vice President and Management
      Committee Member
              
              March 2,
      2009Thomas L.
      Price


52


COLORADO
INTERSTATE GAS COMPANY




EXHIBIT
INDEX


December
31, 2008




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




Exhibit
              Number
            
            Description3.A
            Certificate
      of Conversion (Exhibit 4.A to our Current Report on Form 8-K
      filed with the SEC on November 7, 2007).3.B
            Statement of
      Partnership Existence (Exhibit 4.B to our Current Report on
      Form 8-K filed with the SEC on November 7,
  2007).3.C
            General
      Partnership Agreement dated November 1, 2007 (Exhibit 4.C to our
      Current Report on Form 8-K filed with the SEC on November 7,
      2007).3.D
            First
      Amendment to the General Partnership Agreement of Colorado Interstate Gas
      Company, dated September 30, 2008 (Exhibit 3.A to our Current Report on
      Form 8-K filed with the SEC on October 6, 2008).4.A
            Indenture
      dated as of June 27, 1997, between Colorado Interstate Gas Company
      and The Bank of New York Trust Company, N.A. (successor to Harris Trust
      and Savings Bank), as Trustee (Exhibit 4.A to our Annual Report on
      Form 10-K for the year ended December 31, 2004, filed with the SEC on
      March 29, 2005); First Supplemental Indenture dated as of June 27,
      1997, between Colorado Interstate Gas Company and The Bank of New York
      Trust Company, N.A. (successor to Harris Trust and Savings Bank), as
      Trustee (Exhibit 4.A.1 to our Annual Report on Form 10-K for the year
      ended December 31, 2004, filed with the SEC on March 29, 2005); Second
      Supplemental Indenture dated as of March 9, 2005 between Colorado
      Interstate Gas Company and The Bank of New York Trust Company, N.A., as
      Trustee (Exhibit 4.A to our Current Report on Form 8-K filed
      with the SEC on March 14, 2005); Third Supplemental Indenture dated
      as of November 1, 2005 between Colorado Interstate Gas Company and
      The Bank of New York Trust Company, N.A., as trustee (Exhibit 4.A to
      our Current Report on Form 8-K filed with the SEC on November 2,
      2005); Fourth Supplemental Indenture dated October 15, 2007 by and
      between CIG and The Bank of New York Trust Company, N.A., as trustee
      (Exhibit 4.A to our Current Report on Form 8-K filed with the
      SEC on October 16, 2007); Fifth Supplemental Indenture dated
      November 1, 2007 by and among CIG, Colorado Interstate Issuing
      Corporation, and The Bank of New York Trust Company, N.A., as trustee
      (Exhibit 4.A to our Current Report on Form 8-K filed with the
      SEC on November 7, 2007).10.A
            No-Notice
      Storage and Transportation Delivery Service Agreement Rate
      Schedule NNT-1, dated October 1, 2001, between Colorado
      Interstate Gas Company and Public Service Company of Colorado
      (Exhibit 10.G to our Quarterly Report on Form 10-K for the period
      ended March 31, 2005, filed with the SEC on May 11,
  2005).10.B
            Purchase and
      Sale Agreement, By and Among CIG Gas Supply Company, Wyoming Gas Supply
      Inc., WIC Holdings Inc., El Paso Wyoming Gas Supply Company and Wyoming
      Interstate Company, Ltd., dated November 1, 2005 (Exhibit 10.B
      to our Current Report on Form 8-K filed with the SEC on
      November 2, 2005).10.C
            First Tier
      Receivables Sale Agreement dated November 3, 2006 between Colorado
      Interstate Gas Company and CIG Finance Company L.L.C. (Exhibit 10.A
      to our Current Report on Form 8-K filed with the SEC on
      November 9, 2006).10.D
            Second Tier
      Receivables Sale Agreement dated November 3, 2006 between CIG Finance
      Company L.L.C. and CIG Funding Company L.L.C. (Exhibit 10.B to our
      Current Report on Form 8-K filed with the SEC on November 9,
      2006).10.E
            Receivables
      Purchase Agreement dated November 3, 2006 among CIG Funding Company
      L.L.C., as Seller, Colorado Interstate Gas Company, as Servicer, Starbird
      Funding Corporation, as the initial Conduit Investor and Committed
      Investor, the other investors from time to time parties thereto, BNP
      Paribas, New York Branch, as the initial Managing Agent, the other
      Managing Agents from time to time parties thereto, and BNP Paribas, New
      York Branch, as Program Agent (Exhibit 10.C to our Current Report on
      Form 8-K filed with the SEC on November 9,
  2006).




53


10.F
            Amendment
      No. 1 dated as of November 2, 2007 to the Receivables Purchase
      Agreement dated as of November 3, 2006, among CIG Funding Company,
      L.L.C., a Delaware limited liability company, Colorado Interstate Gas
      Company, a Delaware corporation, as initial Servicer, Starbird Funding
      Corporation and the other funding entities from time to time party hereto
      as Investors, BNP Paribas, New York Branch, and the other financial
      institutions from time to time party hereto as Managing Agents, and BNP
      Paribas, New York Branch, as Program Agent (Exhibit 10.H.1 to our Annual
      Report on Form 10-K for the year ended December 31, 2007, filed with the
      SEC on March 5, 2008).*10.G
            Amendment No.
      2, dated as of October 31, 2008, to the Receivables Purchase Agreement
      dated as of October 6, 2006 among CIG Funding Company, L.L.C., Colorado
      Interstate Gas Company, as initial Servicer, Starbird Funding Corporation
      and other funding entities from time to time party hereto as Investors,
      BNP Paribas, New York Branch, and the other financial institutions from
      time to time party hereto as Managing Agents, and BNP Paribas, New York
      Branch, as Program Agent.10.H
            Lease
      Agreement dated December 17, 2008, and effective on November 1, 2008, by
      and between WYCO Development LLC, a Colorado limited liability company,
      and Colorado Interstate Gas Company, a Delaware corporation
      (Exhibit 10.A to our Current Report on Form 8-K filed with the
      SEC on December 22, 2008).*21
            Subsidiaries
      of Colorado Interstate Gas Company.*31.A
            Certification
      of Principal Executive Officer pursuant to Section 302 of the
      Sarbanes-Oxley Act of 2002.*31.B
            Certification
      of Principal Financial Officer pursuant to Section 302 of the
      Sarbanes-Oxley Act of 2002.*32.A
            Certification
      of Principal Executive Officer pursuant to Section 906 of the
      Sarbanes-Oxley Act of 2002.*32.B
            Certification
      of Principal Financial Officer pursuant to Section 906 of the
      Sarbanes-Oxley Act of 2002.


























54